Chapter 6 - Supply side responses - Alternative fuels from gas, coal and shale
While exploring for more oil in Australian territory may find new
resources that will increase self sufficiency in liquid transport fuels, this
cannot be guaranteed. Australia is fortunate however in having available a
range of other options for meeting transport requirements.
To some extent, fuel substitution is already taking place. Liquid
petroleum gas (LPG) has achieved substantial market penetration in the motor
vehicle fleet (currently six per cent of volume), and some biofuels,
particularly ethanol, are now marketed as blends with conventional fuels. Overall
though, alternative fuels, with the exception of LPG, make an insignificant
contribution to Australia's transport energy mix, less than 1 per cent of transport
Submissions and evidence drew the committee's attention to a wide range
of possible alternative fuels, some derived from fossil sources (gas and coal),
and some from biomass. There is also an extensive literature on alternative
fuels, including a range of government and independent research reports
prepared in Australia and overseas over the past decade or longer that have
identified options which could be applied in Australia if required, or if
appropriate market conditions existed. Yet with some minor exceptions,
in Australia, little has changed. Fossil derived petrol
is still the fuel of choice in the light vehicle market, and similarly produced
diesel powers heavy transport and off road applications, as it has for decades.
Most alternative fuel options have already been well canvassed in expert
reports such as Alternative Fuels in Australian Transport, a report
prepared by the then Bureau of Transport and Communications Economics in 1994;
in the recent significant report of the biofuels taskforce, and in a range of
other publications, all of which are readily available.
In evaluating alternative fuel options for Australia, the committee is
conscious of its limitations in this task. It is not possible for a
parliamentary committee with limited expertise and resources to come to a
definitive position on such a complex subject. Rather, the aim in the rest of
this chapter is to canvass a range of transport fuel options that were particularly
drawn to the committee's attention during this inquiry, highlight those options
that appear most viable and to discuss the broad advantages, disadvantages and
obstacles to implementation of each, within the framework laid down by the
terms of reference.
In preparing this material, the committee acknowledges and draws on a
range of diverse material including submissions, evidence, a selection of the
many comprehensive reports referred to in the preceding paragraphs, and some of
the research literature that is available on the subject.
The options the committee has elected to canvass in the remainder of
this chapter include:
- substituting gaseous fuels such as LPG, natural gas (methane) or
hydrogen for conventional liquid fuels;
- producing fuels by liquefying natural gas or coal; and
- producing oil from oil shales.
In the following chapter, the committee examines the option of producing
a proportion of fuel requirements from biomass.
In relation to alternative fuels, the terms of reference for this inquiry
ask the committee to report on 'the potential of... alternative transport fuels
to meet a significant share of Australia's fuel demands, taking into account
technological developments, environmental costs and economic costs'.
Economic considerations (which may or may not include carbon costs) will
ultimately decide whether any or all of the alternative fuels options are
eventually developed and brought to production. Governments may provide
incentives or tax breaks which may encourage the development of particular
options, but ultimately, companies will make decisions to invest what must be
substantial sums (if there are to be any real inroads made on replacing
imported supply) based on their assessments of longer term risks and returns.
As with petroleum exploration, financial risks associated with unknown
future costs and prices (e.g. the long term oil price, the cost of feedstocks,
a possible price on carbon) inhibit investment until potential investors
consider that risks are sufficiently quantified and returns likely to be realisable
before they are willing to proceed. This can mean that action may be delayed
past the point where it would be timely, as many of these potential
technologies have long lead times. Some point to this as a market failure.
The long term oil price appears to be the most significant risk factor
for companies contemplating alternative fuels developments. Conventional oil
has long been cheap energy, and alternatives to it are inevitably more costly
than pumping oil out of the ground. These alternatives must compete against oil,
and many are only viable if the long term oil price is maintained over a
certain level. For example, in the case of coal to liquids (CTL), Dr Brian Fisher
of ABARE told the committee that CTL was viable at an oil price of $US40.
Similarly, alternatives such as ethanol and biodiesel can only be competitive
on an open market if they can be produced and marketed at rates which are
competitive with or better than the price of conventional petroleum products. A
prime example of this is LPG, the price of which is now sufficiently attractive
to provide strong substitution incentives even after the costs of converting
vehicles are taken into account, stimulating the development of this energy
In the weeks leading up to the tabling of this report, the long standing
issue of climate change associated with the emission of greenhouse gases,
particularly carbon dioxide (CO2), has also received intensified attention.
While transport currently contributes only 14.4 per cent of Australian
greenhouse gas emissions,
this is relative and appears of minor importance only because of Australia's
large scale use of coal for stationary energy (electricity generation) – it
would be higher if more stationary energy was derived from renewables such as
hydro, or from gas. Transport sector emissions of CO2 are also growing rapidly,
in line with the strong growth of demand for transport. The Bureau of Transport
and Regional Economics (BTRE) projects that under a 'business as usual'
scenario, transport sector emissions will have risen by 47 per cent in the
period 1990 – 2010, and be 68 per cent above 1990 levels in 2020.
The Australian Government has stated that Australia 'will play an active
role in developing an effective global response to climate change'.
While a smaller part of the problem, there are possible opportunities in what
may be an evolving transport fuels mix to contribute to reducing Australia's emissions.
There are also possible pitfalls that must be considered. Different fuel
choices can lead to quite different CO2 outcomes, and increasingly, it is
becoming clear that this factor may need to be considered as part of any
decision making process on future fuel supply options, particularly in relation
to any incentives that the Government may decide to provide to encourage the
development of alternative fuel options. The committee notes that this is a
core message in the IEA's World Energy Outlook 2006.
Several of the alternative fuel sources to be considered, such as coal
to liquids and gas to liquids, require substantial energy inputs (and
consequently produce CO2 emissions) during manufacture, in addition to that
released when they are used. Technologies such as carbon capture and storage
are under active development to address this issue and have the potential to reduce
the adverse greenhouse implications of some of these technologies if they can
be proven viable at a large, commercial scale. The Government has provided
substantial funding for this research.
Other options, such as natural gas, are commonly promoted on the basis
that they release less CO2 when used in place of petrol or diesel, and while
this is generally true in the use phase, a 'well to wheels' or lifecycle analysis,
(that is, an examination of the total CO2 or CO2 equivalents released from the
original production phase right through to final consumption), shows that this is
not always so.
If a policy decision is taken by Government to encourage the development
of a particular alternative fuel source, it would appear prudent to consider
the CO2 consequences, not just because of how it might affect emissions
targets, but also because of possible future carbon pricing and effects this
will have on future economic viability of companies developing the resources.
In a similar vein, biofuels proponents commonly argue that fuels such as
ethanol and biodiesel result in substantially lower greenhouse gas emissions
because they are derived from renewable biomass. This is true in some cases, however,
closer examination reveals that for some biofuels, almost as much or more
fossil fuel energy is consumed to produce the fuel as is made available in the
fuel itself. This is because of factors such as the use of fertilisers derived
from fossil resources (natural gas is used to produce some common fertilisers
for example) and conventional diesel to operate tillage and harvesting
equipment. Here, consideration of the 'energy return on energy invested' is important.
Gaseous fuels – LPG, natural gas and hydrogen
Naturally occurring gases such as natural gas, propane and butane, and
synthetic gases such as dimethyl ether (DME), can be used in appropriately
converted petrol and diesel internal combustion engines as a substitute for
liquid petroleum fuels. As such, they offer another option for replacing liquid
fuels, should oil supplies become constrained or governments choose to
encourage their use for economic reasons such as import replacement or supply
While Australia has limited and declining supplies of conventional oil,
it has large reserves of natural gas, which is principally methane. Natural gas
wells frequently also contain a range of heavier hydrocarbons, ranging from
gases such as propane and butane (the components of Liquid Petroleum Gas, or
LPG) to light liquids described as condensate.
The committee received evidence from a number of witnesses that
advocated the use of these gaseous fuels as a substitute for imported oil.
Natural gas was also suggested as a bridging fuel to a hydrogen-based transport
Proponents argue that using locally produced gaseous fuels could have
significant economic benefits by reducing the impact on the balance of payments
that will otherwise result from the inevitable decline in oil self-sufficiency.
Proponents also argue that using domestically produced gaseous fuels would improve
longer-term energy security by reducing dependence on oil produced in the Middle
Further, they point to environmental benefits of using these fuels, as
they generally burn cleaner than oil products and produce less CO2 for each
unit of energy supplied.
The three principal gaseous fuels commonly discussed are natural gas,
liquid petroleum gas (LPG) and hydrogen.
DME is also a gaseous fuel with similar properties to LPG (ie: liquefies
readily and at relatively low pressure, without the need to reduce its
temperature, unlike LNG) that is suited to use in suitably configured diesel
engines, as it has a high cetane number, but as far as the committee is aware,
it has not been suggested as an alternative fuel in this country. It can be
produced from natural gas, coal or biomass. Considerable work has however been
done on this fuel in Scandinavian countries, and in China.
Natural gas (which is predominantly methane) is used as a transport fuel
in two possible forms:
- a compressed gaseous form (typically stored at between 16 and 25
megapascals) known as compressed natural gas or CNG; and
- a refrigerated liquid form (cooled to -163C and stored in
cryogenic tanks) known as liquified natural gas or LNG.
Natural gas can be used in both diesel and petrol engines. Both require
extensive modification, but the technology is regarded as mature. Cummins Australia
told the committee that it now has in excess of 12,000 gas engines (ie: heavy
diesel engines built specifically to operate on gas) in operation around the
Natural gas has both advantages and disadvantages as a transport fuel.
Its advantages include its ready availability, gas being reticulated to 70 per
cent of Australian urban areas; the extensive pipeline system for distributing
it now in place; its relative abundance (although this is disputed); relative price
stability; and environmental advantages.
Disadvantages include the weight and size of cylinders necessary to
store the gas on board which in the case of trucks reduce load capacity;
limited range (particularly for light vehicles which normally operate on CNG
rather than LNG); a considerable energy cost associated with compressing and
liquifying gas (where used as liquid natural gas or LNG) and the cost of
conversion. For potential users of the fuel, a nationwide lack of refuelling
infrastructure appears to be the single greatest obstacle to wider use,
particularly for heavy vehicles.
Natural gas use as a transport fuel in Australian light and heavy
vehicles is minimal, although the committee notes that a number of companies
are trialling the use of natural gas trucks and several public authorities
operate natural gas buses. Gas is, however, extensively used in some other
countries as a transport fuel, and some countries are planning to expand this
The Asia Pacific Natural Gas Vehicles Association (ANGVA) told the committee
that in Brazil, there are in excess of 1 million natural gas vehicles (NGVs) on
the road; and that the European Union had set a target for 10 per cent of
vehicles to run on this fuel by 2020.
In Europe, there are reportedly 575,000 NGVs, of which 375,000 are in Italy,
which has used gas as a fuel since the 1930s.
Similarly, Motive Energy stated that the market penetration of NGVs was up to
30 per cent in some countries.
In Argentina for example, there are reportedly 800,000 CNG vehicles.
While the committee received a number of submissions advocating the
wider use of natural gas as a transport fuel, other evidence cast doubt on
whether available reserves are sufficiently large to meet transport fuel
Natural gas supply
So, is there enough gas in Australia for it to be used on a large scale
as a transport fuel? Natural gas reserves are estimated to be substantial,
although there was a wide variation in estimates given to the committee in
submissions and evidence, some claiming that reserves are sufficient for over
100 years use. According to Geoscience Australia, which the committee regards
as an authoritative source, current and recoverable reserves total 146 trillion
cubic feet (Tcf) or 4085.46 billion cubic metres.
At current rates of production, this corresponds to a resource life of 65 years.
These reserves do not include coal seam methane, which is an emerging
and potentially large natural gas resource. Coal seam methane resources on the
Eastern Seaboard alone have been estimated at up to 400Tcf.
The coal seam methane industry is developing rapidly, particularly in Queensland,
where it now reportedly supplies 30 per cent of the state's gas requirements.
If coal seam methane estimates are correct and a significant proportion of the
resource is readily recoverable, then Geoscience's estimate may be conservative.
With the exception of coal seam methane, the bulk of Australia's
reserves are on the North-West shelf of Western Australia. As such, they are
currently inaccessible to the eastern seaboard, where most of the population
lives. A large proportion of the WA reserves are also considered 'stranded' –
it is not currently economic to recover and use them.
A further possible obstacle to the wider use of natural gas is doubt
about the long-term price. Unlike oil and LPG, which are readily transportable
and therefore priced at world parity, natural gas is much less amenable to long
distance transport and consequently is not subject to international pricing.
Nonetheless, the development of LNG tankers has meant that a world trade in
natural gas has developed, and indeed most of the output of the North West
shelf is for export. According to some commentators, declining natural gas
production in Europe and North America and rapidly increasing demand in China
has stimulated a boom in LNG exports. World LNG export/import capacity as been
estimated to double by 2010.
This has led to concerns that the price will rise substantially and
international natural gas pricing may emerge – that is, the Australian price
will track the international price.
Dr Kelly Thambimuthu, CEO of the Centre for Low Emission Technology and
Chair of the IEA greenhouse gas R&D program, told the committee that
international pricing for natural gas was possible in the near term:
In relation to the situation with gas that you mentioned, certainly
Australia has a lot of gas, but I would argue that a lot of the vast deposits
of gas that we have is currently earmarked as LNG exports. Once LNG becomes a
tradable international commodity in the world in a big way—and by all estimates
the International Energy Agency is estimating that the gas rate is going to
grow phenomenally through countries like China, India and the United States,
for example, picking up the demand—it will command international prices. We
would be left behind in a sense in terms of our own domestic users relying upon
traditional sources of gas, on a land based source. How long are we going to be
immune from international gas prices? I do not know. But I think it will be a
short period of time before we start competing at international levels.
Others however dismiss concerns about future gas pricing, pointing out
that there is not yet an international price for gas, and unlike petroleum, the
price of natural gas in many parts of the world is reliable and relatively
Mr Kevin Black, representing the Natural Gas Vehicles Group, maintained
that the price of gas was much more stable than other fuels, and compared it to
the price of diesel:
... natural gas is the only one of the gaseous hydrocarbon type
fuels that does not operate on world parity pricing. Indeed, a lot of the cost
of natural gas is regulated by government. For instance, the transmission cost
through pipelines is regulated. The retail price of natural gas today is 52c
per cubic metre, which is equivalent to 52c a litre for diesel, 47c a litre for
petrol and 32c a litre for LPG. The price has gone up since 1996 from 38c to
52c. That is 4.4c for the GST inclusion and the rest is CPI adjustments, and
that is all that happens with the price of gas. Sydney Buses, as an example,
who are a huge buyer of natural gas for their buses, have a 10 year fixed price
contract, which is only adjustable for CPI, and they know today what their fuel
is going to cost them in 10 years time. Ask any operator on diesel, ‘What are
you going to be paying in 10 years time?’ and they will just roll their eyes.
Similarly, the ANGVA said that pricing is stable, and that fleet
operators in some cases have fixed pricing contracts as much as ten years in
advance. The ANGVA maintained that extensive use of natural gas as a fuel would
provide an effective buffer to the effects of international crude oil pricing.
Mr Blythe of Advanced Fuels Technology Pty Ltd told the committee that
stability of pricing was one of the most attractive features of the fuel for
fleet users. He thought though that the prospect of excise posed a risk:
One of the big selling opportunities to the LNG and CNG markets
is that the gas companies are able to offer five- and seven-year fixed term
price contracts with CPI escalation. That is extraordinarily attractive to a
fleet operator who is running on margins of less than 1c per kilometre. The big
risk right now, I would say, is the excise regime; that is No. 1. What is
helping the industry right now is the Alternative Fuels Conversion Program. It
certainly does de-risk it from a fleet-user perspective.
Natural gas vehicles in Australia
Much of the committee's evidence on natural gas vehicles in Australia
focussed on heavy vehicles, concerning which there seems to have been the most
operational experience. There was also comprehensive discussion of natural gas
vehicles in general.
In relation to light vehicles and cars, the committee notes that a
fledgling light vehicle natural gas industry showed signs of developing in Australia
some years ago, but it did not develop. The two largest factors that have
prevented development appear to be a lack of vehicle range, and a lack of
refuelling infrastructure. These are problems common to both light and heavy
Ford Australia told the committee that it did a number of trials with
compressed natural gas cars, but found that the size of the tanks that were
necessary to give adequate range significantly intruded on luggage space, and
range was limited.
Similarly, Honda's dedicated natural gas Civic, which is now sold in several
states in the USA, has a range of only 200 miles (320km).
In Australia, Boral Transport Ltd is one of a number of companies that is
using natural gas to power some of its shorter haul trucks such as concrete
agitators as part of a demonstration project under the auspices of the
Government's Alternative Fuels Conversion Program, which is administered by the
Australian Greenhouse Office.
Similarly, the Murray-Goulburn Co-operative (MGC) has converted 33 of
its heavy transport prime movers to LNG, advising the committee that 21 of
these conversions attracted 50 per cent funding from the Federal Government
Alternative Fuels Grant Scheme, the remaining 12 being fully funded by MGC.
The MGC, which stated in its submission that it has the largest
privately owned fleet of LNG vehicles in Australia, told the committee that it considered
that LNG offered significant potential benefits to both light and heavy vehicle
The benefits to transport operators are real and many, and
Economic - reduced diesel costs and operational cost per kilometre,
oil change frequency reduced, fuel filter changes reduced, greater export sales
and being able to compete at a sustainable level.
Environmental - reduced particulate emission, reduced noise,
reduced greenhouse gas emissions.
Social - improved business viability means greater job security
and the flow on effects throughout the wider community are potentially very
However, the MGC expressed a number of concerns about its continued use
of the fuel, stating that the company is exposed to a significant risk of
changing availability and price for the fuel, and the possibility of taxation
changes. The MGC also expressed concern that there is currently only one LNG
supplier on the Eastern seaboard. The lack of distribution infrastructure
appears to be of a lesser concern to MGC as its trucks are depot based, but the
lack of infrastructure would severely limit operations over a wider area:
If however, we were a general freight carrier not operating
specific routes, we would be unable to operate freely through any of the normal
and highly used transport routes without an extensive infrastructure rollout
most particularly at strategic locations up and down the Eastern and across the
The MGC listed a number of issues that it thought needed to be addressed
if the fuel was to be used more in the heavy vehicle industry, including future
availability, price and excise on LNG; lack of refuelling infrastructure; and chassis
length and weight limits. The MGC listed the following possible incentives that
State Governments and the Commonwealth could introduce to encourage the wider
use of LNG as a heavy transport fuel:
- vehicle length and weight concessions [to compensate for reduced
load carrying capacity caused by the weight of the tank]; and
- continued supportive funding of conversions, technology
development, education and training support.
Boral Transport's experience with natural gas is with CNG powered heavy
vehicles, as distinct from LNG. Boral's view was far less optimistic than that
Boral told the committee that the cost of converting trucks was high (in
the case of concrete agitators, 25 per cent more expensive than the standard
and that it was not an attractive proposition from an economic perspective
unless fuel consumption and mileage were very high.
Mr Rowlands of Boral told the committee that in the case of the concrete
agitators used by his company, the payback period was estimated to be 7½ years.
He also highlighted how the lack of refuelling infrastructure acted as a
disincentive to the wider market penetration of gas trucks:
Potential customers, like ourselves, are very reluctant to
invest in alternate fuel technology unless they can get the fuel. You would
really have to ask why a small operator would go out and put a CNG engine in
his truck now. He just has nowhere to fill up. Unless you have a lot of trucks,
you cannot amortise the cost of your own in-house refuelling station, and you
are just going to burn money.
Boral representatives also confirmed that the extra weight of tanks
makes it more difficult for gas fuelled trucks to operate profitably:
If it costs more to buy the truck and it is heavier, you have
higher costs to overcome and the vehicle is going to earn less because it can
carry less. That, in many cases, far outweighs the fuel cost, so you are not
going to get people wanting to change. It is a simple equation in the transport
industry. The more you can carry, the more you get paid.
Like MGC, Boral called for changes to the allowable mass limits for
alternate fuel trucks, identifying this as the 'best incentive':
The best incentive for take-up of an alternate fuel, including
natural gas, is to simply increase the allowable mass limit for trucks using
alternate fuels to conventional diesel engine trucks.
The requirement for new distribution infrastructure is a major barrier
to the introduction of any alternative fuel that cannot be blended with existing
fuels. This creates an economic 'chicken and the egg' dilemma in that
companies are reluctant to invest in infrastructure unless assured of a
customer base and reasonably secure supply; and potential customers will not
buy gas cars and trucks if there are no refuelling facilities available.
In some cases, refuelling issues can be addressed to a limited extent by
depot refuelling (such as described by Boral Transport in its submission) or in
the case of cars, home refuelling devices such as that marketed by the
Fuelmaker corporation of Canada.
However, for natural gas to make major inroads into the fuels market,
particularly for heavy haulage, much more widely available facilities would
almost certainly be required.
The Commonwealth has previously conducted a number of programs to
encourage the take-up of natural gas as a fuel. These include the Alternative
Fuels Conversion Program (AFCP) and the Compressed Natural Gas Infrastructure
Program (CNGIP). Mr Kevin Black of the Natural Gas Vehicles Group submitted
that these programs, particularly the CNGIP, had failed to achieve their aims
... constant Government policy changes and inappropriate AGO
[Australian Greenhouse Office] policy and administration settings... effectively
killed off the industry in Australia. No sensible investor was prepared to fund
the infrastructure without a secure and supportive policy environment and since
2004, most of the infrastructure that was in place has been wound back or
Mr Black argued that one factor that had contributed to the program's
lack of success was what he considered to be the AGO's flawed administration of
the program, which had included a requirement that the refuelling stations put
in place had to remain open for three years:
... so three years and one day later they were gone. Through some
financial partners in Singapore, we were prepared to buy all of their natural
gas vehicle infrastructure. They had five refuelling stations—three in Sydney,
one in Goulburn and one in Canberra—they [AGL] had 50 depot based refuelling
stations for a courier company and forklifts and what have you. We said, ‘We’re
happy to buy that in a single package and continue to operate it,’ and they
[AGL] broke it up piecemeal and sold it off for export.
A report prepared for Envestra Pty Ltd by Mr O. Clark OAM also said that
the Commonwealth's announcements to introduce excise on LGP and natural gas
when used as a transport fuel 'put paid to the level of interest that had been
generated over many years' in the fuel.
The committee asked Mr Black what it would take to revitalise a natural
gas vehicles program in Australia. He argued that the most effective strategy
would be a variant of the previous policy:
The most effective strategy, I believe, is a variant of what they
did before, but instead of paying up-front, providing some form of subsidy for
the refuelling infrastructure post installation and requiring them to operate
not for three years but for 10 years. The life of a natural gas refuelling
facility, be it CNG or LNG, is a minimum of 15 years. Within 10 years of having
a comprehensive roll-out of refuelling sites, the calculations we have done
indicate that for eastern Australia, Tasmania and South Australia—we have not
taken Western Australia and the Northern Territory into consideration at this
stage, simply because we do not have enough information—you would need around
800 refuelling sites. That would provide sufficient security of supply to
encourage people to buy vehicles, both as fleet operations and as private
Advanced Fuels Technology also put forward a detailed set of
recommendations to increase the use of natural gas as a transport fuel:
a minimum target for the conversion of a percentage of the diesel fleet to
operate on Natural Gas (10-15% of all new commercial vehicles being by 2010).
the development of a strategic corridor of LNG refuelling stations along the Adelaide
– Melbourne – Sydney – Brisbane corridor.
the introduction of new gas engine technology to the Australian market.
to support end-users via the Alternative Fuels Conversion Programme (AFCP)
funding of 50% of the conversion cost of a diesel vehicle to enable it to
operate on gas.
a long-term view of fuel excise to ensure fleet users can confidently invest in
new fleets that have a typical life of 5 years or more.
the development of small LNG and CNG depot based refuelling stations.
an Import Duty Regime that will enable products imported for use in the gaseous
transport fuels industry to have zero duty.
Environmental impacts of natural
gas as a transport fuel
Natural gas is frequently claimed to be amongst the most environmentally
friendly fossil fuels. For example, Advanced Fuels Technology Pty Ltd submitted
that natural gas vehicles:
- are up to 30% quieter;
- reduce oxides of nitrogen by up to 90%;
- reduce particulate matter by as much as 99%; and
- reduce Greenhouse gas emissions by up to 17%.
Some of the published literature confirms that emissions resulting from
its use are typically lower than petrol or diesel, particularly in relation to
CO2, non-methane hydrocarbons and particulates.
The reason it is associated with lower CO2 emissions is because of the physical
make up of methane, which is the lowest carbon weight of all fossil fuels. The combustion
of one megajoule (MJ) of natural gas will result in the emission of about 40
grams of CO2, compared to 67 from petrol. However, well-to-wheels analysis or
full fuel cycle analysis shows a somewhat less favourable outcome. This shows
a reduction in CO2 of 16 per cent for natural gas compared to petrol.
These statistics will vary according to the configuration of engines and their
A 2004 study conducted by the CSIRO for the Australian Greenhouse Office
showed that on a full fuel cycle basis, for light vehicles, CNG vehicles have lower
emissions than petrol or 'second generation' LPG vehicles, but emit more CO2
per kilometre than Euro 4 diesels. Diesels however emit more particulates than
any other vehicle class. The following table graphically illustrates the
findings of this study.
Figure 6.1 – Exbodied greenhouse gas emissions from family-sized vehicles
A similar study conducted by CSIRO in relation to heavy vehicles shows
that the total greenhouse gas emissions for LNG powered heavy vehicles may be
worse than for vehicles powered by conventional diesel. The following graph
illustrates the findings in relation to non-bus heavy vehicles:
Figure 6.2 – Total greenhouse gas emissions (CO2 equivalents) in g/km for
non-bus heavy vehicles
There are a number of other issues that also need to be considered in
relation to the environmental impact of natural gas as a transport fuel. First,
energy has to be expended to compress or refrigerate natural gas to make it
useable for a transport fuel. In the case of LNG, as the study cited above
shows, this energy expenditure apparently cancels out any CO2 advantage over
Secondly, methane itself is a powerful greenhouse gas, so any
inadvertent release, for example from fuel tanks or distribution systems, will
detract from its advantages over conventional petroleum transport fuels. The
Department of Environment and Heritage (DEH) advised the committee that on a
life cycle analysis, natural gas has the potential to offer greenhouse gas
emissions reductions of up to 20 per cent, but cautioned on the effects of
However, natural gas is primarily composed of methane, which has
a global warming potential 21 times that of carbon dioxide. This means that if
not managed, fugitive methane emissions may cancel out the greenhouse gas
reductions from the lower carbon content of natural gas and in some cases may
give rise to a negative greenhouse outcome.
Thirdly, natural gas wells themselves frequently contain substantial
quantities of CO2 which is generally released in the production process. The Cooper
Basin fields for example are 35 per cent by weight and 12.7 per cent by volume
Gorgon field (production from which is planned to include CO2 re-injection and
geo-sequestration) contains 13 per cent CO2.
These findings do not mean that natural gas should be dismissed as a
transport fuel on environmental grounds. In some situations, it does appear to
offer advantages, but the picture is not as clear or unequivocal as sometimes
painted by proponents.
Conclusions on natural gas as a
The committee has altered its view expressed in the interim report, that
it would be prudent to put in place measures to encourage the rapid take-up of
natural gas in the transport fuels mix.
From the perspectives of the beneficial impacts on the terms of trade
and energy security and as an indigenous replacement for depleting conventional
oil stocks, the fuel must be considered, particularly from the perspective of
its relative abundance. There are potential economic benefits from using gas
for transport. The committee considers that better use can be made of the
resource than is currently the case, where most gas is exported.
The committee is not persuaded by those arguments that supplies are
insufficient to make a significant contribution to the transport fuels mix. New
and unconventional sources of gas are becoming available (eg coal seam methane)
and availability does not appear to be a significant limiting factor within the
medium term. Nonetheless, the committee is of the view that consideration
should be given to establishing a national domestic gas strategy, to ensure
that supplies are sufficient for domestic purposes well into the future.
From an environmental perspective, consideration is required about
whether the gas will be used as fuel, and if so, in what form. Appropriate
safeguards would also need to be put in place to minimise possible adverse
There are, however, significant obstacles to the wider use of gas for
transport. These include a lack of distribution infrastructure, incompatibility
with most of the transport fleet, economic penalties for some users if
appropriate adjustments are not made, a slow return on investment for some
users, and possible consumer resistance from limited range and a lack of a
clear price differential from LPG.
Liquefied Petroleum Gas (LPG)
LPG is comprised of varying proportions of propane and butane. It can be
produced as a result of the oil refining process, but also occurs naturally in
oil and gas wells, where it can be readily separated out from other gases.
LPG has several significant advantages over other alternative fuels in
that there is a high degree of market acceptance of the fuel; vehicle range is
between 75 and 100 per cent of that attainable for petrol vehicles
(ie: comparable and superior to CNG); and extensive distribution infrastructure
is already in place. Unlike natural gas however, LPG is parity priced, and
rapid and large fluctuations in the autogas price have been observed.
Australia is the world's largest per capita user of automotive LPG,
and over 500,000 LPG vehicles are now on the roads in Australia
and this figure is increasing rapidly, spurred by the Government's recently introduced
fitting subsidy. The committee notes the recent Government initiatives to
encourage motorists to take up this fuel by paying a subsidy of $2000 for a
conversion and $1000 towards the cost of a new vehicle with LPG fitted. This is
a major program, which is expected to cost a total of $766.1 million over 8
The Government's LPG fitting subsidy is expected to substantially
increase the use of this fuel, and media reports suggest that there are now
long waiting lists for vehicles to be converted. Before the introduction of the
subsidy, about 30,000 vehicles per year were converted.
The Department of Industry Tourism and Resources expects that 28,800 extra
vehicles [ie: a total of about 58,200] will be converted this financial year
(2006-07) and 7,200 new LPG fuelled vehicles sold. In 2007-08, this is expected
to rise to a total of 42,900 extra vehicles converted over the base rate and
10,700 new LPG vehicles sold, and the number is expected to peak in 2008-09 at
64,000 extra conversions and 16,000 new vehicles sold.
Ford report having sold 50,000 dedicated LPG Falcons since 2000.
The availability of a well developed distribution infrastructure is also
a major advantage for this fuel. Over 3,500 filling stations are now available,
and there are now sufficient refuelling stations in place for a motorist to
drive around Australia.
Questions have been raised however about whether Australian LPG resources
are sufficiently abundant for LPG to meet a significant proportion of the
transport fleet's fuels requirements for an extended period. For example, Michael
Gutteridge and others have written that after 2008, the bulk of LPG will come
from imported crude oil and from NW Shelf gas fields. He points out that these
fields contain a relatively small proportion of propane and butane (around 5
per cent) and that they are propane deficient, requiring the export of excess
butane and the importation of propane. Mr Gutteridge pointed out that based on
ABARE statistics, Australia produced 107 PJ of LPG in 2001, which compares to a
975PJ energy requirement. He suggests that LPG cannot be produced in sufficient
quantities to meet transport energy requirements:
There is little scope to expand indigenous supplies of LPG
especially to meet the quantities required to replace our current demand of
975PJ/a, principally derived from oil, for road transport energy.
The CSIRO also sounds a note of caution about LPG reserves, submitting
If the Australian oil supply becomes more scarce, then it will
be more difficult to source LPG from oil. Thus one would need to look to the
gas fields to produce LPG. However, the difficulty with this is that the supply
of LPG from gas fields depends on how "wet" or "dry" the
gas is. It is possible to estimate present LPG reserves, but not what they
would be in the future.
Others claim that Australian LPG resources are relatively abundant. The
Australian Liquefied Petroleum Gas Association (ALPGA) told the committee that it
considered that reserves are sufficient to fuel around 1.1 million vehicles, or
around 10 per cent of the vehicle fleet.
ABARE estimates that Australia's demonstrated LPG reserves are currently
210 gigalitres, less than the estimated condensate reserves of 247 gigalitres.
Economically demonstrated resources have been estimated to be sufficient to
last 34 years at the 2004 production rate.
It seems reasonable to suggest that these reserves will diminish more rapidly
as more and more people take up the LPG conversion incentives.
Environmental impacts of LPG as a
Like natural gas, LPG is claimed to be an environmentally friendly
transport fuel. The ALPGA claims a saving of up to 20 per cent on CO2 emissions
over conventional petrol.
Independent evaluation of these statistics broadly confirms these claims.
While LPG can be used in conjunction with diesel in diesel engines, it is
generally considered to be most suited to use in spark ignition petrol type
engines rather than diesels, so a comparison with CNG is appropriate. As shown
in the graphs produced by the CSIRO in Figure 6.1, greenhouse gas emissions
associated with the latest third generation LPG vehicles, which employ more
advanced technology than previous conversions, are comparable with CNG. LPG
also liquefies more readily than LNG, requiring much less energy in the
production and storage processes.
The picture in relation to other emissions such as carbon monoxide,
nitrous oxides and other pollutants is far less clear. CSIRO research has shown
wide variations across older and newer vehicles, which were built to different
Australian design rules. In relation to the latest Euro-3 petrol engines, the
The data show that LPG is not the easy clean fuel it was in the
time of high emission 'no control' cars. To meet Euro 3, and especially Euro 4,
emission specifications requires vehicle and catalytic converter technology to
be very tightly designed for optimum performance and minimum emissions. A
vehicle designed for optimum petrol performance is very unlikely to be
optimised to minimise emissions under LPG use.
The committee notes that analysis of these issues, in relation to both
LPG and natural gas, is extraordinarily complex, and do not lend themselves to
either verifying or refuting blanket claims about environmental advantages and disadvantages
of various fuels, particularly in relation to non-CO2 emissions.
The committee commends interested readers to the CSIRO paper, Life-cycle
Emissions Analysis of fuels for light vehicles, Report to the Australian
Greenhouse Office, May 2004
for a thorough and up-to-date evaluation of environmental impacts of various
fuels; and to the BTCE's paper 39, Alternative Fuels in Australian Transport,
which contains a thorough if somewhat dated evaluation of a range of other
pertinent issues in relation to the use of LPG, natural gas and other fuels.
Conclusions on LPG as a transport
The committee agrees that LPG has the potential to provide an
alternative fuel for a proportion of the Australian transport fleet, probably
not exceeding 10 per cent. It has a number of clear advantages, not least of
which is a well developed distribution infrastructure and apparently good
acceptance by consumers.
Its use has a number of economic advantages for both users, who enjoy
substantial fuel cost savings (although parity pricing can influence these),
and more broadly in relation to directly substituting an indigenous fuel for
one that will increasingly be imported.
There are some doubts about the extent of future supplies of LPG,
although these appear to be adequate for at least a number of decades,
depending on the proportion of the vehicle fleet that is converted to operate
Environmental advantages are reasonably clear, at least in relation to
CO2, particularly in the case of modern, third generation conversion
technology. The picture in relation to non-CO2 pollutants is less clear.
Government initiatives to encourage the take-up of this fuel appear to
have been extremely successful, and do not need to be expanded.
Hydrogen is often put forward as an alternative transport fuel, although
it is more correctly described as an energy carrier. Theoretically, a vehicle
fuelled by hydrogen would have zero emissions. However, what is often
overlooked is that hydrogen does not occur naturally and must be produced as
part of a manufacturing process. It can be produced by reforming natural gas,
coal or biomass, or by electrolysis, but currently, substantial CO2 emissions
accompany all of these methods of producing this fuel. Geosequestration may alter
However, hydrogen is generally not regarded as a near-term transport
fuel, as there are formidable technical issues to be overcome before it could
be widely used. These include:
- the very large amounts of energy required to convert it to a
liquid and maintain it in a liquid state, or compress it sufficiently to make
it suitable for transport fuel use;
- storage problems arising from its propensity to leak through and
embrittle the walls of metal pipes and tanks;
- in cars, large heavy tanks that limit luggage space and provide
very limited range;
- in trucks, similar issues to LNG and CNG in relation to weight
and volume of tanks and reduced cargo carrying capacity;
- the lack of a source of supply (although it could be produced in
volume by reforming natural gas); and
- a complete lack of distribution infrastructure.
In the committee’s view, hydrogen is a fuel that might be considered in
the distant future, but is not a useful option to consider in Australia’s
current or medium term transport fuels mix. Mr Black of the NGVG summed up the
argument in relation to hydrogen very well:
Everybody seems to pinning their hopes on hydrogen, which is
still, frankly, pie in the sky. We do a lot of work with the CSIRO and we talk
to them fairly frequently. I am on a hydrogen panel with the CSIRO. The
greatest fear of hydrogen researchers in this country is that governments and
the media will hype it up so much that people will have expectations that will
never be met.
Synthetic fuels derived from coal or gas
Technologies have been readily available for several decades for
synthesising liquid transport fuels from either natural gas or from coal.
During the apartheid era, South Africa produced all its liquid fuels from coal
using the Fischer-Tropsch (F-T) process and still produces 40 per cent of its
fuel needs though this process.
A range of direct substitutes for conventional oil can be produced from
coal or natural gas, using a variety of processes and conversion routes. These
include synthetic diesel, light hydrocarbons suitable for producing petrol or
which can be used as chemical feedstocks, and kerosene.
It is also possible to produce a range of other hydrocarbons which can be used
as fuels including methanol, dimethyl ether (also known as DME - a gaseous fuel
with similar properties to LPG which is suitable for use in appropriately
configured diesel engines), and hydrogen.
Gas to liquids
A number of companies, including Sasol-Chevron, Shell, and ExxonMobil,
have either constructed pilot or commercial plants exploiting variations of this
technology. Shell operates a 12,500 barrels per day plant in Bintulu, Malaysia
and is reportedly planning to construct a 140,000 barrels per day plant in Qatar.
Sasol Chevron, whose representatives made a submission and gave evidence
to the inquiry, advised the committee that it is close to bringing a 34,000
barrels a day plant into operation, also in Qatar, and has a plant under
construction in Nigeria, to be commissioned in 2009.
The Sasol Chevron company advocated
the construction of a FT-GTL diesel plant in Western Australia. While the committee
is aware that there have been other GTL proposals (for example, the now abandoned
Methanex proposal to produce methanol in Western Australia) the committee has
elected to devote most of its discussion to GTL diesel, as unlike others, this
product appears to be most suited to seamless introduction into the Australian
market, without modification of infrastructure or vehicles. It is also a
proposal about which the committee received detailed evidence.
Sasol Chevron argued that a GTL industry would have a number of benefits
for Australia. Among these, it would:
- create a new value adding market for Australia’s natural gas
- develop strategically important gas infrastructure;
- bring new technology and new jobs to Australia;
- reduce Australia’s dependence on imported transport fuels;
- reduce diesel air pollution in Australia’s urban centres; and
- become a foundation for the emerging global synthetic fuels
GTL diesel produced from natural gas has the major advantages as an
alternative fuel that it is compatible with existing distribution
infrastructure, can be blended with conventional diesel, and does not require
any modification of diesel engines in the existing vehicle and machinery stock.
It also does not require any further refining to make it ready for use. Its
zero sulphur content and high cetane rating also facilitate the introduction of
higher efficiency diesel engines which are currently emerging in Europe.
However, the capital cost of constructing a large scale GTL plant is
high, with attendant difficulties in attracting the necessary capital. Sasol
Chevron told the committee that building a plant to produce 200,000 barrels per
day of oil equivalent from natural gas would require an investment of
approximately $20 billion.
ABARE estimates a capital cost of US$25-40,000 per barrel of daily capacity for
a gas-to-liquids plant, compared with US$15,000 for a conventional oil
According to the CSIRO, GTL does appear to be economically viable, at
least in places where the gas price is low. The gas price, and in particular
returns that gas producers are able to achieve for LNG, appears to be one of
the major factors preventing the establishment of a GTL plant in Australia:
With the current robust LNG market climate and LNG’s long
history, GTL must offer a more compelling value proposition to the gas resource
holders to be successful. In Qatar and Nigeria, this has been achieved. In Australia,
this has not yet happened.
Representatives of the Department of Industry, Tourism and Resources
confirmed that GTL projects so far have tended to be built where there are low
It is very difficult for us to produce at a rate that is
comparable with the Middle East—or Qatar in particular. So gas to liquids, some
of those other sorts of downstream users, are more likely to go to those sites
where they have a much lower cost feedstock.
Uncertainty about the longer term oil price also appears to be a factor
holding back investment in this country and elsewhere.
Sasol Chevron submitted that the taxation regime that currently applies
to natural gas does not favour large scale, long term investments such as its
... the current tax and PRRT regime does not facilitate such
large, long term capital investments. The Australian fiscal regime is not
internationally competitive with regards to capital depreciation and the
facilitation of strategic, Greenfield investment. There are a number of
mechanisms available which could allow a more competitive payback for the
investor without compromising the value return to the nation. These should be
considered if there is a desire to better attract GTL investment.
Establishing a gas to liquids industry may present economic opportunities
for Australia by allowing the use of gas resources which are currently
uneconomic. A significant proportion of Western Australia's gas reserves are
off-shore, and are considered to be 'stranded', in that it is not currently
economic to bring the gas on-shore for processing using current technology. The
CSIRO points out that if such gas could be brought ashore by converting it into
a more easily transported product, then this could result in significant
economic benefits. However, the CSIRO noted that there are difficulties
relating to the large physical size of FT–GTL diesel plants which make them
less suitable for constructing off-shore on gas platforms. Other GTL
technologies with a smaller physical footprint may be better suited for this
purpose. CSIRO advised the committee that it is currently working on a new
process involving methane pyrolysis, which will produce synthetic petrol rather
A number of commentators have cast doubt on the future of GTL in Australia,
arguing that the price of gas feedstock will be prohibitive, as natural gas
becomes subject to international pricing. (see paragraph 6.36ff above).
From an environmental perspective, GTL products have both advantages and
disadvantages. GTL diesel is claimed to be a superior product to conventional
diesel, in that it has virtually zero sulphur and aromatics content and a very
high cetane number.
The principal environmental disadvantages of the fuel are that considerable
energy is consumed producing it, and it is still a fossil fuel with comparable greenhouse
gas (GHG) emissions to conventional diesel in most applications.
The extent of CO2 emissions associated with GTL is somewhat disputed. Sasol
Chevron claimed that on a well-to-wheels basis, its technology for producing
GTL diesel is on a par with conventional oil:
Sasol Chevron, ConocoPhillips and Shell International Gas
commissioned a study by Five Winds International to report on the Life Cycle
Analysis of GTL production. The study found that production and use of GTL fuel
can contribute less greenhouse gas and reduced emissions to the atmosphere than
production and use of conventional diesel fuel.
The Five Winds study quoted by Sasol Chevron acknowledges that higher
GHG emissions are associated with the production phase of GTL, but says that
these are offset in the use phase.
However, other evidence conflicts with this view. For example, a well-to-wheels
study conducted by the Mizuho Information and Research Institute for Toyota in Japan
showed somewhat higher GHG emissions for FT diesel than conventional diesel,
although this was still below the emissions from conventional petrol.
Similarly, information provided by the CSIRO shows that the production
process (using natural gas as a feedstock) results in the emission of about
1.87 tonnes of CO2 for each tonne of hydrocarbon produced, or 233 kg per barrel,
or 1.46 kg per litre, before the fuel is used.
The committee asked the CSIRO to calculate what a theoretical carbon tax
of $40 a tonne of CO2 would amount to per barrel of fuel produced. In the case
of FT-GTL, this amounts to $9.20 per barrel.
Given the potential importance of the possible price being placed on carbon
dioxide emissions to the future competitiveness of GTL and CTL projects, the committee
has included the CSIRO's letter at Appendix 3.
Coal, of which Australia has vast, accessible resources, can be used to
produce a similar range of liquids as the GTL processes described in the
previous section. Indeed, some of the processes to produce liquids from coal
are very similar to the GTL processes, for example conversion of the feedstock
to syngas (a mixture of carbon monoxide and hydrogen) and subsequent F-T
conversion using a catalytic process to the desired end products.
Like GTL, coal-to-liquids (CTL) is established technology,
and it is seen by a number of groups within Australia
and overseas as a viable method of producing liquid fuels on a large scale in
the near future.
In the United States in particular, the Government has been active in encouraging
the development of CTL fuel and has established a fuel tax credit of US 50
cents per gallon (US$21/barrel) for diesel fuel produced from coal using the
ABARE advised the committee that by 2025, up to 10 per cent of liquid fuels used
in the USA will be produced from coal.
Arguments advanced by CTL proponents include:
- potential to reduce reliance on imported fuel;
- quality of the product – a synthetic diesel which is high cetane
and low sulphur;
- the process of conversion is versatile, and a range of other
valuable products ranging from fertiliser to hydrogen can be produced if
- development of the technology can also provide technologies for
reducing CO2 emissions from the electricity industry;
- a large, accessible feedstock; and
- feedstock resources are much larger than natural gas, which may
be substantially depleted by 2050.
According to ABARE, these processes become commercially viable once the
long-term oil price is above $US40-45 per barrel.
Like GTL, the capital investment required for building plants to produce
fuels from coal is large. ABARE suggests a capital cost of $US50-70,000 per
barrel of daily capacity, which is somewhat higher than a GTL plant.
The Monash Energy project submission states that it would cost about $A5
billion to construct a plant capable of producing 60,000 barrels of synthetic hydrocarbon
liquids a day, 80 per cent of which would be diesel.
Critics of CTL technology point out however that from an environmental
perspective CTL fuels have very high well-to-wheels CO2 emissions compared to
most other fuels. Additionally, in terms of greenhouse gas emissions CTL diesel
is equivalent to conventional diesel, as confirmed by Dr Kelly Thambimuthu, CEO
of the Centre for Low Emission Technology and Chair of the IEA greenhouse gas
Senator MILNE—To finish that off, even if you got this up and
produced it as a transport fuel, its CO2 omissions are going to be equivalent
to conventional oil?
Dr Thambimuthu—Yes, that is true, if you use the coal...
Should a price be placed on carbon dioxide emissions at some
point in the future, this could affect the price at which the fuel could be
produced, and thus the viability of this option for producing fuels.
It is important to quantify the nature of this potential problem. Information
provided to the committee by the CSIRO shows that 3.9 tonnes of CO2 will be
produced in the gasification phase, and a further 1.2 tonnes at the FT liquids
production phase, a total of 4.3 tonnes of CO2 for each tonne, or 537kg of CO2
per barrel of liquid hydrocarbon fuel produced. Calculations prepared for the committee
by the CSIRO show that if a carbon tax was ultimately introduced at $40 per
tonne of CO2 emitted, the level of tax applied would be $22.60 per barrel.
In Australia, CTL proponents are obviously aware of and sensitive to the
emissions issue and its potential cost implications. Monash Energy (Monash), a
wholly owned subsidiary of Anglo-American, proposes to build a 60,000 barrels
per day CTL plant in the Latrobe Valley in Victoria. Monash submitted that this
plant is planned to be the first CTL project predicated on carbon capture and
storage. The first stage of the plant is scheduled to be commissioned in 2016.
The project is based on the availability of the very large brown coal deposits
in the Latrobe Valley, and the proximity of the depleting oil and gas
reservoirs in the Gippsland basin, where the captured CO2 is to be stored.
The company claims that this project would have significant economic
benefits, including avoiding $80 billion in oil imports over 50 years, spending
$20 billion on goods and services (mainly within Australia), and paying $15
billion in corporate income tax.
The company is understandably concerned about the risks involved, not
just in relation to possible carbon pricing, but a range of other factors
including the oil price and the legislative environment in which it will
It is a large-scale investment. One of the things that comes
with a large-scale investment is that to manage the risks of that large amount
of capital you need to have as much certainty about the future as you possibly
can. That includes not just country risk but things such as legislative risk.
In being able to install this facility the investors are looking at a very
long-term plant. We are talking about something that will run for 50 to 100
years, so it is a very long-term investment project. It has a very high level
of capital, but it is reliant on having a long-term understanding of such
things as oil price, exchange rate and other effects that might come into
play—carbon, carbon pricing.
For us that means that having some certainty about the policies
that are going forward is critical to being able to manage the risk of the
investment, and it certainly helps to have a firm view on what the legislative
environment will be.
The Monash Energy project incorporates a detailed plan to capture and
store the CO2 generated. Monash stated that 'this would be the largest carbon
capture and storage project in the world when it is up and running'.
It follows that if this feature is part of the project, it would reduce
pricing risks associated with carbon pricing, assuming that the capture and
storage technology is demonstrated as successful on a large scale. Equally however,
if no price is ultimately put on carbon, the project would be placed at a
disadvantage to potential competitors unencumbered by this cost.
The committee sought information about whether this technology has been
successfully demonstrated, and what the likely costs of implementing it would
Monash advised the committee that there is a successful project in Norway
that captures and stores 2 million tons of CO2 a year,
that re-injection is commonly used as an enhanced oil recovery tool in the USA,
and that the activities associated with capture and storage have been used
routinely by the oil industry for a number of years. Monash also advised the committee
that it is participating in a trial CO2 capture and storage exercise in the Otway
Dr Kelly Thambimuthu, CEO of the Centre for Low Emission Technology and
Chair of the IEA greenhouse gas R&D program also told the committee that
the process is well on the way to being proven:
In fact, it has been practised in many different ways over about
20 years in relation to enhanced oil recovery. Currently, there are three major
projects in the world that are actually capturing and storing in the order of
three million tonnes per year of CO2
underground. It is well on the path of being proven.
The Cooperative Research Centre for Greenhouse Gas Technologies
(CO2CRC), which researches the capture and geological storage of carbon dioxide
for the purposes of greenhouse gas abatement, also told the committee that this
technique has been used in a range of large-scale projects in Norway, Canada
and Algeria and is planned for other projects such as the Gorgon project in
Western Australia. Representatives also informed the committee that it is in
the process of establishing a geosequestration research project in the Otway Basin
in western Victoria, which is intended to sequester 50 million tonnes per year
of CO2 over a 40 year project life.
CO2CRC representatives told the committee that their research had shown
that in the chosen site, the costs of CO2 capture and storage would be in the
range of $8.50 to $10.90 per tonne of CO2 avoided.
Comments on GTL and CTL
The committee considers that from a technical perspective, both GTL and
CTL technologies are capable of supplementing Australia's future transport fuels
requirements, on a large scale if required. Both use technologies that are
proven on a commercial scale – there are few unknowns, at least in relation to
the gasification and liquids production processes. The resource base for both
also appears to be sufficiently large for both to have a place, although this
is less certain in relation to GTL. Nonetheless, even for gas, there are large
undeveloped resources of stranded gas that may well lend themselves to
developments of this kind, if technical obstacles such as processing gas in situ
on offshore platforms can be overcome.
Both technologies offer the prospect of economic advantages,
particularly in relation to adding value to resources, trade balances, employment
and taxation revenue.
Further, the products they would produce are compatible with the current
vehicle and machinery stock, and with existing distribution infrastructure. The
synthetic diesel which both CTL and GTL proponents intend to produce is an
ultra low sulphur product and thus has significant environmental advantages
over conventional diesels, is ready for use, requires no further refining, and
can be blended with conventional diesel. These are major advantages over other
alternative fuel options.
Either technology will require very large capital investments if it is
to provide a product stream of sufficient volume to replace fuels that would
otherwise have to be imported. The difficulty associated with raising the
capital required for such projects in the face of risks that are hard to predict
and manage, such as the longer term price of oil, or in the case of GTL, the
gas feedstock price, and the possibility of carbon pricing, should not be
underestimated. However, this is probably true of any large scale fuel
Large scale projects of this type also require very long planning and
construction lead times, of at least a decade. There are questions about
whether market forces would be sufficient to enable the timely development of
such projects, if for example oil supplies were constrained unpredictably by
supply-demand imbalances or instability in oil producing countries.
Both technologies, but CTL in particular, suffer from a number of
environmental disadvantages in relation to greenhouse gas emissions. Emissions
at the conversion phase are higher than conventional fuels, and in a world that
is becoming increasingly concerned about climate change, this cannot be
disregarded. The committee notes that a great deal of work is being done on
carbon capture and storage in this country and overseas, which if successfully
implemented on a large commercial scale, may address this issue.
On the basis of the evidence the committee received, it appears that
there are grounds for cautious optimism that carbon capture and storage technology
has good prospects for success. However, the committee also notes the comments
in the recently released IEA World Energy Outlook 2006 that carbon
capture and storage has not yet been demonstrated on a commercial basis.
The committee notes that the Government is providing financial support for
developing and demonstrating this technology, which is likely to be of critical
importance if CTL and GTL industries are to proceed in a CO2 constrained world.
Demonstration on a commercial scale is essential, and must proceed as soon as
Oil shale is a 40 to 50-million year old sedimentary rock which contains
a range of organic matter called kerogen. Kerogen is a precursor to oil that
has not been subjected to the pressure and temperature regimes over geologic
time that are required to transform it into crude oil. Some of the largest
deposits of oil shale are located in the United States (in the upper Colorado River
Basin), Brazil, Scotland, China, Estonia and Australia.
Deposits of oil shale exist in the coastal strip between Proserpine and
Bundaberg in Queensland. The Queensland Government and others have estimated
that this area alone could possibly yield more than 4,629 gigalitres (or
approximately 27.774 billion barrels) of oil – which is around 46 times Australia's
initial crude oil reserves.
There are, however, a number of economic, technological and
environmental impediments to the commercialisation of oil shale as a future
source of oil. Oil shale is surface-mined, and in its natural state does not
contain any liquid hydrocarbons. It requires heating and distillation before
the shale yields an oil-like product. This process is energy intensive,
resulting in a high level of greenhouse gas emissions and other air pollutants
such as hydrogen sulphide. The process is also reportedly water intensive.
Although a number of attempts have been made to produce economically
viable oil from shale, so far none have proved successful. The latest attempt
to trial commercially viable oil-from-shale was by Southern Pacific Petroleum
and its sister company, Central Pacific Minerals. Working on the Stuart oil
deposits, the project produced trial quantities of shale oil using a new
process developed by a Canadian company, Suncor, a company active in tar sands
The Stage 1 pilot plant began construction in 1998 and was designed to
produce 4,500 barrels per day from 6,000 tonnes of shale (1.33 tonnes per
barrel). The pilot project involved the shale being mined, crushed and fed into
a four stage process which incorporated rotary kilns, similar to those used to
manufacture cement. The process involved:
- a flash dryer operating at 150 degrees centigrade to reduce the
moisture content to 8-10 per cent;
- heating to 250 degrees centigrade in a rotary kiln;
- heating to 500 degrees centigrade in another furnace to crack the
kerogen to yield hydrocarbons as gases that are then distilled into products as
in a normal refinery; and
- the remaining carbonised rock is ignited with oxygen to 750
degrees centigrade in another furnace that provides the heat for the preceding
A major impediment to the commercial viability of oil shale production
is that the volume of overburden removed to access the shale is comparable to
the volume of shale mined. In addition, the waste shale from the furnaces
expands by approximately 10 per cent and the mine site is not large enough to
receive the spent shale and returned overburden. If the project is operated on
a large scale, this becomes a large and costly problem.
Southern Pacific Petroleum, until quite recently, has been having
difficulty raising the required funds and the project has effectively been on
hold. In November 2006 however, a United States based company, Sandefer Capital
Partners, indicated a willingness to advance A$51 million to the project:
The money is earmarked for both working
capital needs and upping the Stage 1 plant to its 4,500-bbl/d design capacity,
as well as advancing design and development of Stage 2 – the 'commercial' stage
– which would expand productive capacity to some 15,000 bbl/d (as per
Suncor's original schedule).
The committee sought information from several sources about the
economics of shale oil production. Dr Brian Fisher, Executive Director of ABARE
said that if CO2 emissions are internalised, the cost of producing shale oil is
'about $US70-$US95 a barrel, so shale oil is a long way out of the money at
Mr Lex Creemers, however, said that:
... world wide only some 5-10 shale oil reserves could be
considered economically viable at a price of $US40 per barrel back at 1986
prices... the good news for Australia was that four of those reserves are located
in Queensland, so if there were to be any serious development of shale oil,
chances are, it would take place here.
Committee comments on shale oil
The committee notes that shale oil could theoretically make a
significant contribution towards meeting Australia's transport fuel
requirements. However, there are formidable technical issues to be resolved
before this is likely to take place. The committee particularly notes Dr Brian Fisher's
assessment that shale oil is 'well out of the money at this stage'.
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