Options for the retirement of coal fired power stations
Evidence to the inquiry highlighted that Australia's coal fired power
stations will need to be retired in the medium term in order to make way for
lower-emissions sources of power generation. Various options could be utilised
to facilitate this process, and are discussed through this chapter.
Broadly, the options for facilitating the retirement of coal fired power
stations include the following:
leave retirement decisions solely to industry and market forces
(without any further changes to government policy settings);
directly regulate closures (i.e. government directs particular power
stations to shut down through regulation, with the plant owner bearing the cost
introduce a government payment-for-closure scheme, where the
government pays high emissions intensity plant operators to shut down (with the
taxpayer sharing the cost of closure);
market mechanisms introduced by regulation, creating incentives
for closure (or disincentives for continued operation) with the market
ultimately deciding which power stations retire and when. Possible market
a carbon pricing mechanism, causing higher-emitting plants to
incur greater costs, making them less competitive and more likely to cease
an emissions intensity scheme, whereby the government sets a
baseline emissions intensity target, with below-baseline producers rewarded and
above-baseline producers penalised via a tradable permits mechanism;
a regulated market mechanism for closure (e.g. the Jotzo model),
whereby payments are made by the industry as a whole to shut down the power
stations which are the most cost effective to close.
'Barriers to exit' and need for policy certainty
Much of the policy discussion in this area focusses on whether there are
'barriers to exit' which impact on the decision-making of coal plant operators
when determining if (and when) to close.
The question is not merely whether any barriers to exit exist, but
whether these barriers are significant enough to prevent an 'efficient' or
'orderly' restructuring of the market to occur (with older, high-emissions
plant capacity retiring first). As explained by the AEMC:
A barrier to exit is any cost or foregone profit that a firm
must bear if it leaves an industry. While these costs therefore represent
barriers to exit for individual generators they are only a problem if they are
a barrier to efficient exit decisions.
For example, based on this definition, it will not always be
efficient for generators with the highest variable cost to exit the market
first. Where generators with high variable costs have high shut down costs, it
can be an optimal outcome for them to exit the market after generators with low
variable costs but low shut down costs.
Several barriers to exit for coal fired power stations have been
identified in the Australian context, which can be summarised broadly as
First-mover disadvantage: If one plant exits the market,
the remaining plants will receive higher revenues, which acts as a disincentive
to closure as every operator has an incentive to defer closure in the hope that
another plant will close.
Low operating costs of older coal plants: Brown coal fired
power stations generally carry lower short-run marginal costs of production
than other power generators, meaning they may have a greater capacity to
continue functioning at low cost even as they approach or exceed their expected
Closedown and site remediation costs: The cost of shutting
down a power plant permanently (even as opposed to 'mothballing' a plant or
moving to seasonal rather than full-time production) is high, with site
remediation costs estimated as being between $100‑$300 million for
Policy uncertainty: This uncertainty has the effect of
making it difficult for plant operators to predict what the cost of exiting the
market will be now, as opposed to in the future. Hence, this uncertainty may
cause inefficient investment and closure decisions.
This final factor, policy uncertainty, was identified by numerous stakeholders
to the inquiry as a key issue creating instability in industry decisions—along
with the corollary observation that introducing more policy stability in this
area would promote better outcomes for investors and market participants. For
example, Associate Professor Frank Jotzo argued:
Australia's energy sector has been exposed to significant
investment uncertainty due to pervasive policy uncertainty and climate policy
reversals for over a decade. Such uncertainty has detrimental effects on the
investment climate and potentially on the cost effectiveness of investment...For
an effective and efficient low-carbon transition, stable and predictable policy
settings are needed.
The Australian Energy Council argued similarly:
A benefit of the market is that it can discover what the real
economic life of a power station is and when it is worthwhile to invest in
refurbishing a plant to extend its operating life. Stable carbon policy is
needed to inform this investment decision making, and potentially signal that
coal-fired power station emissions intensity may lead them to close earlier
than without a carbon policy.
AGL Energy submitted:
The transition to a decarbonised and modernised generation
sector requires large scale investment, recent AGL analysis estimates this at
$23 billion in renewables alone to achieve an emission reduction consistent
with a 27% reduction in [greenhouse gas] emissions by 2030.
Such investment will be supported by policy that provides
macro level certainty as to the timeframe and operating life of incumbent
Such certainty has the potential to benefit a range of
factors contributing to the efficient transition including new investments,
management of existing capital stock, policy development, community transition
and energy market development.
Leaving retirement decisions solely to industry and market forces
The status quo approach would leave any retirement decisions on the
closure of coal fired power stations up to the plant owners themselves, with no
external changes in government policy settings to assist this process. This
approach was endorsed by the COAG Energy Council in December 2014, which
The Council considers it is for the market to provide signals
for investment and de-investment for generation, and opposes the transferral of
the costs of retiring assets onto consumers or taxpayers.
Advocates for this position argue that plant operators will choose to cease
operations as necessary, in accordance with existing market conditions, and
that there are no barriers to exit that are significant enough to warrant
government intervention. The AEMC undertook work in 2015 to identify barriers
to generators exiting the NEM, and found that 'there is nothing in the National
Electricity Law or Rules which would constitute a barrier to efficient exit
decisions by generators'.
The AEMC stated that recent experience shows that generators are not
being prevented from leaving the market under current policy settings:
While it is possible the uncertainty around exit costs is
creating a barrier to efficient exit, a number of generators have announced
exit decisions in recent years. The evidence suggests that any barriers to exit
have not deterred generators from commencing various stages of exit or the full
retirement of plant. This would support leaving it to the market to determine
which plant should exit.
In particular, the AEMC pointed to the closure in May 2016 of the
Northern and Playford B coal power stations in South Australia and the
announced closure of the Hazelwood plant as examples of generator exit without
further policy intervention.
The AEMC stated further in its submission to the inquiry:
The decision of a generator to retire should be a commercial
Investment and divestment decisions are based on a range of
factors. A decision to retire a generator can take a number of years and
requires intimate knowledge of the commercial and operating structures of that
generator as well as clear expectations about future revenues and costs.
Generators are best placed to manage the risk of their own investment or
divestment decisions. The added benefit of this approach is that the risks of
poor investment decisions are borne by generators rather than taxpayers or
electricity consumers (as would be the case if a government were to intervene).
Other stakeholders have maintained that existing barriers to exit do
risk distorting the process of market transition, arguing that additional
policy intervention may be required in order to facilitate the phased closures
of older, higher-emissions generators. The imperative to reduce Australia's
carbon emissions in line with our international commitments is also cited as a
reason for implementing policies that would have the effect of curbing
emissions in the electricity sector, even if a consequent result of such
policies is to force coal powered generators to close sooner than they
otherwise would have.
In its submission, AGL Energy stated:
There is a role for governments to establish policy that
facilitates 'orderly' rather than 'disorderly' exit of emissions intensive aged
power stations. Such policy could be based upon age (e.g. Canadian rule which
requires power stations to be closed or retrofitted with carbon capture and
storage when they turn 50), emissions intensity or a market mechanism (as
proposed by Jotzo and Mazouz). Ultimately, policy makers should view such a
closure policy as not only an important means of securing energy supplies from
modern generation equipment; but also an effective way of systemically reducing
greenhouse gas emissions and providing communities the certainty they deserve
to plan for such a transition.
Mr Andrew Stock of the Climate Council told the committee that without a
coordinated closures policy, it is difficult for generators to properly plan
and announce plant retirement decisions:
Planning for closure is actually quite problematic at an
individual operator level for some quite difficult commercial reasons—that is,
the electricity market operates much like another financial market would in
that people selling electricity not only trade in the physical product on a
day-to-day basis where they dispatch but they also trade financially in the
futures market to support their physical retail contract positions. So when a
decision for closure is made, it is very hard to telegraph that because if you
are doing that you are trading with inside information potentially. This is one
of the reasons why closure announcements come in the current market in the way
they do. If the owners of power stations make a final decision before they
announce that decision to the market, they are potentially trading with inside
information, and that has quite serious consequences.
Various policy mechanisms have been discussed as potentially aiding the
transition away from coal fired power generation and towards lower emissions
generation. These approaches are discussed further below. Several of these
proposed mechanisms have been investigated by the Climate Change Authority
(CCA) as part of its Special Review of Australia's climate action, initiated in
2014 and completed in August 2016.
As part of this special review, the CCA commissioned two sets of modelling on
the effects of different carbon pricing policy options on the electricity
Policy mechanisms based on direct regulation
Policy options based on direct regulatory responses by government (as
opposed to market-based mechanisms implemented by government) considered by
stakeholders to the inquiry included payment-for-closure schemes and several
other models for regulating the closure or ongoing operations of coal power
Under this model, governments agree to pay certain power station owners
to close, encouraging an orderly exit of older and high-emission coal power
stations from the market. The Australian Government previously announced a 'contracts
for closure' scheme in 2011, as part of its clean energy package that also
included the introduction of a carbon price.
Dr Jenny Riesz summarised the outcome of the proposed scheme as follows:
This scheme aimed to permanently close around 2000 MW of
highly emissions intensive generation capacity by 2020 via payments to
particular plant owners from the Federal Government. The amount paid was to be
determined by negotiation...
Closure proposals were received by the Government from all
eligible generators in early 2012. Negotiations ceased on 5 September 2012 with
the announcement that no agreement had been reached. Again, there were
differing views on the reason for this outcome. However, the expectation of a
low carbon price, high gas price and high black coal price appear to have
pushed up the asking price of brown coal generators beyond that which the
Government was prepared to pay.
A variant of this kind of scheme to retire brown coal power stations is
due to be implemented in Germany: starting from October 2016, a capacity of 2.7GW
of power from three brown coal plant operators will be taken out of production,
with payments of 230 million euros per year made to the operators over a seven
year period. The cost of these payments is borne by electricity consumers
(increasing costs to consumers by 0.05 euro cents per kilowatt hour).
Direct payment-for-closure schemes have been criticised for a number of
reasons in the Australian context. Professor Frank Jotzo and Mr Salim Mazouz argued
in their 2015 paper on the retirement of coal fired power stations:
...payments-for-closure schemes can lead to unhealthy
expectations of future industry subsidies from government and therefore a
deferral of plant closure decisions with associated emissions.
Secondly, the politics of paying significant sums of
taxpayers' money to the owners of old, highly emissions intensive power
stations would be highly problematic. It also does not fit the narrative of the
present Emissions Reduction Fund (ERF) mechanisms, which is one of subsidising
businesses taking positive actions to move to cleaner production processes, not
of compensation payments to sunset industries.
The COAG Energy Council expressed the view in December 2014 that it does
not support assistance to generators to exit the market.
Alinta Energy, which closed its Flinders coal mine and power station in
South Australia in May 2016, submitted that no government payments or
incentives to close are required. It argued that the market 'understand[s] and
price[s] the cost of closure into the long term planning', and ultimately the
public purse should not pay for private closure.
Direct regulation of power station closures
Another set of options available to government would be to introduce
regulatory measures that directly police the emissions performance of power
stations, or mandate the retirement of coal fired power stations based on
specified criteria. Direct regulatory responses could include:
introducing standards for the emissions performance of new or
existing power stations, creating industry-wide standards;
facility-level absolute emissions baselines for high-emission
generators (i.e. where each plant has a baseline for their total emissions
that they must not exceed); and
mandated closure of power stations over time, on the basis of age
or emissions intensity.
The Australian Energy Council commented on regulatory closure options in
Regulatory closure, or even the requirement to give an
extended closure notice, may prejudice both financing arrangements and supply
contracts of power plants. This may then precipitate a disorderly closure if
loans are called in early or suppliers terminate contracts. However, all of
this depends on the type of regulatory closure.
Emissions standards for power
Mandating emissions performance standards for any new power generators
would prevent any new high-emitting coal fired stations from being built.
Canada has implemented an emissions standard for new and existing coal fired
generators, meaning that no new coal fired power stations can be built without
carbon capture and storage (CCS) technology.
Similar to Canada, the United States has adopted emissions standards for
new coal generators, which effectively require CCS to be implemented in any new
Emissions standards of this type have been considered by the Australian
and state governments in the past, and have been implemented only to be
subsequently withdrawn in some Australian jurisdictions.
Absolute emissions baselines for
This model would set a baseline constraint on emissions output of each
incumbent generating facility, without any market-based certificate trading
The emissions baselines for each plant can be decreased over time to steadily
increase the level of emissions reductions required and force generators to
adopt low emissions technology (e.g. implementing CCS retrofit for coal plants)
or exit the market.
The potential impact of a version of this policy in Australia was
modelled by Jacobs Group (Jacobs) in 2016 for the Climate Change Authority,
which found that its introduction would cause significant electricity price
increases in the 2020s, more so than other policy options.
Regulated closures of coal fired
power stations over time
This policy option involves the regulated closures of coal stations over
time, either on the basis of age or on the basis of emissions intensity. As
explained by Jacobs:
[These schemes] would close existing coal capacity in roughly
linear fashion starting with the oldest or most emissions intensive, with the
order of plant closure publicly announced at the time the policy is introduced.
Each plant identified for closure would be legally required to either close or
CCS retrofit by its closure date.
Modelling conducted for the CCA by Jacobs in 2016 investigated the
option of government mandating the regulated closures of all remaining coal
fired power stations operating in Australia by 2030 on the basis of age. Under
this scenario, coal generators that do not undergo a retrofit to incorporate
CCS technology would be closed on the basis of age, and no new coal capacity
could be built without CCS technology.
This scenario modelling found that pursuing this policy would lead to
less overall emissions reductions by 2050 than other policies modelled (which
are discussed further below).
The CCA also found that regulated closures would be a more expensive means of
reducing carbon emissions than market-based mechanisms:
[The CCA's] analysis of regulated closure indicates that
using it to achieve a large post-2020 emissions reduction goal in the absence
of other measures in the electricity sector would entail higher costs than
other policies and would not offer a direct incentive for new low-emissions
plant to be built.
Choosing plant age as the basis for progressive power station closure
under this model may also not produce the most efficient outcomes. Jotzo and
Mazouz argue that the information asymmetry between governments and plant
owners is a significant drawback to the directly regulated closures model:
Direct regulation suffers from government not having
sufficient information about business cost structures, and therefore it would
be difficult for the regulator to identify which plant would be the most
cost-effective to close and how much to offer in compensation if such
compensation was offered.
Further, they argue that in Australia's current political context 'it
appears unlikely that a government would choose a pure regulatory approach that
singles out power stations and imposes the full cost of early closure on the
owners of that station'.
Associate Professor Jotzo commented further at a public hearing:
The regulated approach, according to a timetable, age or
emissions intensity would obviously give great predictability of the schedule
of exit. In my view, it has the disadvantage of not being the least-cost
pathway. Almost by definition, the least-cost pathway of exit will deviate from
45 years out or whatever it may be. If a government wanted to go down the
regulatory closure pathway, you would want to combine that with flexibility
instruments such as tradeable operation rights.
Doctors for the Environment recommended that the degree of pollution and
its danger to local communities should be a major factor in deciding priority
for closure and in advising community and workers of the need for closure. It
noted that several states in Australia already impose pollution licensing fees
on power plant operators that could in theory drive the closure of
heavily-polluting plants, but argued that these schemes 'have been ineffective
due to the inadequate scale of fees imposed'.
The CCA concluded in a research paper in August 2016 as part of its
Special Review that a market‑based mechanism to reduce carbon emissions
should be implemented in the Australian electricity supply sector:
A market mechanism in the sector would allow Australia to
meet its targets at a lower cost to the community than would be possible
without such a policy in the toolkit. The sector's characteristics (measurable
emissions, relatively small number of large emissions sources, sophisticated
profit-seeking investors operating in generally competitive generation markets)
suggest market mechanisms will be feasible and more cost-effective than the
alternatives. In addition, market mechanisms can be scaled to achieve deep
emission cuts, and are flexible to changing market and technology conditions.
The market-based policies considered as part of the CCA's review
included: a cap and trade scheme; an emissions intensity scheme; a carbon tax;
and a baseline and credit scheme.
Under all the policy scenarios modelled as part of the CCA's review
(including the direct-regulation models discussed above), coal fired generation
would decline significantly in Australia in the medium term. As Jacobs stated
in its final modelling report, all the policy scenarios modelled involve the
entire brown coal fleet and two-thirds of the black coal fleet being
decommissioned by 2030.
Emissions intensity schemes
The CCA ultimately recommended the introduction of an emissions
intensity scheme for the electricity supply sector in Australia.
Jacobs gives an overview of how such a scheme would operate in its modelling
report undertaken for the CCA:
An emission intensity baseline is set for the electricity
supply sector as a whole (based on tonnes of carbon dioxide equivalent per
megawatt hour sent out). All generators are allocated permits (representing one
tonne of carbon dioxide equivalent) equal to their own generation multiplied by
the baseline. At the end of the compliance period all generators surrender
permits for each tonne of carbon dioxide equivalent emitted. This effectively
means that generators with intensity below the baseline have surplus permits to
sell (so receive a subsidy) and generators with intensity above the baseline
need to buy additional permits (so incur an extra cost). Emissions permits can
also be banked indefinitely for future use or borrowed in limited quantities.
Demand for permits available in each year creates an explicit
carbon price, and the relative price of electricity made from more
emissions-intensive sources increases. In contrast to a conventional cap and
trade scheme, there is no absolute emissions cap, so in practice overall
sectoral emissions will vary depending on electricity demand.
Jacobs' modelling on this policy scenario predicts that during the first
decade of implementation (that is, 2020–2030) all coal fired power stations are
shut-down as a result of the imposed policy, with mostly wind generators and
combined cycle gas turbines replacing the retired capacity.
The generation mix for electricity supply in Australia to 2050 under this
scenario is shown in Figure 3.1.
Origin Energy stated its support for a mechanism like this to manage the
transition to a low-carbon electricity sector:
Origin supports the progressive decarbonisation of the
electricity sector in Australia and an eventual goal of net zero emissions by
2050 or earlier. We believe the introduction of a well-designed cost of carbon
abatement for the electricity sector, such as an emissions intensity scheme, is
the key to managing this transition.
Jotzo model for regulated closure
of brown coal power stations
Jotzo and Mazouz advocate for a different type of market-based mechanism
to drive the closure of the most emissions-intensive brown coal station(s) in
They argue that in the absence of any policy intervention, the economics of
Australia's fleet of coal fired power stations is such that black coal stations
may close operations first, before the more emissions-intensive brown coal
This would lead to poorer environmental outcomes in terms of overall carbon
emissions and air pollutants than if brown coal capacity was closed earlier and
black coal generation capacity remained online.
Their suggested model is in effect a hybrid market-based regulated
closures model. It is summarised as follows:
The principle of the proposed mechanism is that government
offer power plants the opportunity to bid for the closure of some amount of
capacity, leaving it to the bidding process to determine which plant(s) will
close and what the magnitude of the payment to the closing plant is. The
remaining plants are then mandated by government to make financial transfers to
the plant that exits the market, in line with their emissions.
Jotzo and Mazouz argue that such a mechanism would: provide emissions
savings from plant closure at least cost; rely on a market mechanism to
identify which plant should close and what magnitude payment is required; avoid
budgetary costs by sourcing the payments for closure from the power stations
remaining in production; and provide some incentives to adjust the power mix to
Competitive bidding process to
identify which stations to close
Under the Jotzo model, relevant plants (most likely Victoria's brown
coal fired power stations) would be invited to submit a bid for the amount of
money they would be willing to accept in return for ceasing operations by a
predetermined date, remediating their plant site and funding an assistance
package to their workers and local communities. A government regulator would
then assess the bids, alongside the likely emissions savings resulting from
each possible closure, and choose the most cost-effective bid.
The generator chosen for closure would then receive the full amount
specified in their bid, in pre-determined instalments, paid for by the other
generators remaining in the market. Under Jotzo's preferred model, the share of
payments each remaining generator would need to contribute would be determined
on the basis of their carbon dioxide emissions during the year following the
closure of the chosen plant, creating further incentives for high-emitting
plants to submit low bids in the bidding process.
Jotzo and Mazouz consider that the cost of such plant closure (and its
capacity exiting the market) would be reflected in some rises to electricity
prices. They estimate an increase of five to 14 per cent in wholesale prices
over the course of one year (and dropping again afterwards), with a
corresponding increase in retail prices in the order of one to two per cent,
over one year.
Associate Professor Frank Jozto discussed this model with the committee
at a public hearing:
Our proposal, in a nutshell, is for a market mechanism
whereby existing power stations submit bids as to financial compensation required
to shut down according to a pre-agreed time line. A government or regulator
would choose the most attractive bid, which may well be the bid that delivers
the greatest expected emission savings per dollar of compensation required.
This is a competitive process—best bid wins—and the money is then levied on the
remaining power generators. The logic behind that is that these are the power
generators that will benefit through increased capacity utilisation of their
plants and, to some extent, through increased prices in the wholesale market.
This would enable for exit according to a timetable. It would create a source
of funding for structural adjustment, and possibly also for improved site
rehabilitation above and beyond the level that is required by law of the
Criticism of Jotzo model
The Jotzo model has been criticised, most notably by Frontier Economics
in a May 2016 paper.
This paper argues that the predicted electricity impacts of a closure of one of
Victoria's brown coal power stations, as advocated for in the Jotzo model,
would be much more significant than Jotzo and Mazouz allow for. Frontier's
estimates are that retail prices would rise by up to 25 per cent in Victoria in
the year immediately following closure, with sustained price rises of 9 per
cent in following years, as well as less severe price rises in New South Wales
and South Australia.
Options for implementation of
policy combinations and need for further research
Stakeholders highlighted the fact that a combination of policies may be
required to effect an orderly exit from the market of coal generators and
concurrent increase in generation capacity from renewable sources.
In particular, some argued that the continuation of a large scale renewable
energy target beyond 2020, when coupled with other policy mechanisms to
constrain emissions from coal generators or regulate their closure, would be
the most effective means of managing this transition.
Associate Professor Jotzo made the point that currently, research on options
to facilitate closure of coal fired power stations in Australia has been
relatively limited. He argued that additional work is required to fully
understand the options and provide input to policy, including by further
how policy mechanisms for power station closure would interact
with other policies, such as baseline-and-credit or the renewable energy
how predictability of exit can be achieved without unduly
compromising cost effectiveness, including the potential role for industry
options to provide effective support for structural adjustment,
and how to raise funds for structural adjustment ideally without relying on
Recent policy announcements by the Australian Government
Throughout January to February 2017, the Australian Government began to
signal a new approach to energy policy. During his speech at the National Press
Club on 1 February 2017, the Prime Minister, the Hon Malcolm Turnbull MP,
indicated that the government was willing to support investment in 'clean coal'
technology. The Prime Minister stated:
Australia is the world's largest exporter of coal, has
invested $590 million since 2009 in clean coal technology research and
demonstration, and yet we do not have one modern High Efficiency Low Emissions
(HELE) coal fired power station let alone one with [carbon capture and
The Prime Minister spoke about the need to secure baseload power
Here's the current picture ‑ old, high emissions coal
fired power stations are closing down, reducing baseload capacity. They cannot
simply be replaced by gas ‑ because it's too expensive ‑ or by wind
or solar because they are intermittent.
Storage has a big role to play, that's true, but we will need
more synchronous baseload power and as the world's largest coal exporter we
have a vested interest in showing that we can provide both lower emissions and
reliable base load power with state of the art clean coal fired technology.
The Prime Minister further noted that future policy should be 'technology
agnostic', and identified security and cost as the guiding principles in the
government's response to the challenges in the energy sector. 
The Prime Minister's statements were echoed on 2 February 2017 by
the Minister for the Environment and Energy, the Hon Josh Frydenberg MP.
Minister Frydenberg stated that the government was committed to ensuring
baseload capacity to deliver energy security, and that they were 'looking at
all their options' in providing that.
Minister Frydenberg noted that the Clean Energy Finance Corporation
(CEFC) did not refer only to renewable energies, and that the government was
open to using the fund to assist in financing production of clean coal power
stations. He pointed to the prevalence of high efficiency, low emission power
stations in Japan as an example of countries using coal technology to provide
energy while meeting their obligations under the Paris Agreement.
During Senate Additional Estimates on 27 February 2017, Mr Oliver Yates,
Chief Executive Officer of the CEFC, confirmed that the agency had received a
proposal requesting a loan in order to build a $1.2 billion coal plant
with carbon capture and storage facilities.
Response from stakeholders
A number of energy companies responded to the propositions of the Prime
Minister and Minister Frydenberg stating that they had no intention of building
any new coal fired power stations, which included 'clean coal' plants.
The Chief Scientist, Dr Alan Finkel AO, stated that such
technologies were not suitable for the Australian energy market. While
Dr Finkel expressed support for carbon capture and storage technology, he
did not support using taxpayer‑funded subsidies to fund these projects.
Dr Finkel further noted that the Japan case study was not applicable in
Australia due to Japan's efforts to phase out nuclear power.
The banking industry also reacted to the government's proposal with
caution. Mr Geoff Summerhayes, Executive Board Member, Australian Prudential
Regulation Authority (APRA), warned that there are significant risks to the
investment sector in funding clean coal. Citing a report from the Centre for
Policy Development and the Future Business Council on the legal issues arising
from climate change, Mr Summerhayes stated:
The opinion found that company directors who fail to properly
consider and disclose foreseeable climate-related risks to their business could
be held personally liable for breaching their statutory duty of due care and
diligence under the Corporations Act.
Some witnesses who gave evidence to the committee were critical of the
government's preference for clean coal, arguing that the cost and complexity of
these technologies make them unviable.
This evidence is discussed later in this chapter.
Announcement of plan to expand the
Snowy Hydro scheme
On 16 March 2017, the Prime Minister announced a plan to expand the
Snowy Hydro scheme, aiming to increase its 4,000 MW output by 50 per cent
through the construction of new tunnels and power stations in the scheme, at a
cost of up to $2 billion. It was announced that a feasibility study for
the project would be completed by the end of 2017, with the new plant aiming to
come online within four years.
The South Australian energy market
On 14 March 2017, South Australian Premier, the Hon Jay Weatherill,
announced a new policy framework to ensure that energy is affordable and
reliable, while ensuring that power is sourced, generated and controlled within
South Australia. The $550 million plan included the construction of the largest
battery in Australia to store wind and solar energy, building a
government-owned gas-fired power station with a 250 MW capacity to secure
back-up resources, and incentivising gas production.
In announcing the plan, Premier Weatherill emphasised the need for a
state energy plan that included renewable technology:
South Australia will now lead our nation's transformation to
the next generation of renewable storage technologies and create an
international reputation for high-tech industries.
Critically, the proposal also seeks to give the South Australian Energy
Minister powers to override the AEMO and direct power stations and utilities to
act in the interests of South Australians. The Energy Minister, the Hon Tom
We can't rely on this broken national market any longer. Our
plan will deliver increased local generation and powers to help prevent outages
and more competition to put downward pressure on power prices for families and
International developments in energy policy and markets
The committee heard evidence at its Sydney public hearing regarding the
dramatic shifts occurring in the way energy policy and markets are being
restructured globally. Mr Tim Buckley, Director of Energy Finance Studies at
the Institute for Energy Economics and Financial Analysis (IEEFA), identified
five key drivers for the transformation occurring internationally away from
coal fired power generation:
continued technology innovation;
economies of scale (particularly with the weight of China taking
a global leadership position in this process) driving renewable costs down;
the rapid build up of global financial sector capacity in
response to rising stranded asset risks;
the global commitment to policy action as agreed at the COP21 in
the critical requirement for countries like China and India to
deal with air, water and particulate pollution.
Mr Buckley highlighted key recent developments in China and India,
China's cancellation of plans to construct a further 100 GW
of new coal fired power plants, as its electricity generation mix rapidly
diversifies away from coal generation towards hydro, renewables and nuclear;
the announcement in December 2016 of India's draft national
electricity plan, which involves not constructing any new coal fired power
plants in the next decade while increasing India's renewable energy stores
fivefold in the same period; and
the outcome in February 2017 of a reverse auction tender in India
which will deliver power from a new 750 MW solar facility at a cost of
US$45 per megawatt hour, the lowest price ever recorded for such a contract.
Providing reliable power through Australia's energy transition
An overarching issue discussed throughout the inquiry was how to ensure
reliability of power supply in Australia while the transition from an energy
system dominated by coal fired generation to a renewables-dominated system is
Various possibilities for promoting reliability of supply were discussed
at the committee's public hearings, including the use of clean coal
technologies, the role of gas fired power generation, and emerging energy
storage solutions, primarily battery storage.
Possibility of utilising 'clean
Various stakeholders to the inquiry commented on the possible role of
'clean coal' technologies; either through implementing carbon capture and
storage technologies (integrated into new coal plants, or retrofitted onto
existing plants), or through building new, more efficient coal fired power
The Minerals Council of Australia argued in its submission that building
new, high‑efficiency, low emissions coal fired power plants in Australia
and deploying carbon capture and storage technologies could be part of the
solution in Australia's transition to a lower-emissions energy mix:
Australia has the opportunity to upgrade its coal generation
fleet as existing plants come to the end of their life. We do not argue that
all coal plant should be replaced by another coal plant. No energy source
should be guaranteed market share. But the option of [high-efficiency, low
emissions] coal must be on the table. It is the most competitive option. It can
deliver baseload power and it can deliver 50 per cent lower emissions with the
promise of further substantial emissions reductions with the deployment of
carbon capture and storage technologies.
New super‑efficient black coal plants are commercially
available and operating throughout the world...Super-efficient brown coal plants
are also planned or already delivering low cost, baseload energy around the
world, including in Germany, Poland, the United States and Thailand. With a
bold vision NSW, Queensland and Victoria and other jurisdictions can invest in
Australia's future by building ultra-supercritical black and brown coal base
load plants here too.
This issue was explored extensively at the committee's two public
hearings held in February 2017, in the context of comments from government
ministers in support of clean coal. Several potential problems with
implementing clean coal technologies were raised with the committee, relating
primarily to the cost and complexity of implementing the technology.
Councillor Martin Rush, Mayor of Muswellbrook Shire Council, expressed
the view that while the possibility of utilising 'clean coal' technologies
should not be summarily dismissed, its potential will likely be overridden by
cost factors which will make coal uncompetitive over time:
The reality is that coal itself as a former fuel for power
generation is becoming relatively more expensive compared with renewables. So
we have to see clean coal within the context of the larger cost. There will
come a time, and it will happen before too long, and it already occurs in some
aspects of the demand for energy—for example, daytime peak—where solar is
overwhelmingly cheaper already than coal. It is true for base load that thermal
coal is still cheaper, but that will not be the case forever. So when we look
at the issue of clean coal it has to be done across the whole of the strata of
cost, not just the externalities. The only thing clean coal is dealing with is
that fraction of the total cost that is the externality of the carbon
footprint. The problem for clean coal, ultimately, is that its relative costs
continues to increase. So I think the practical economic reality is that by
2050 clean coal is certainly not a solution—we have already heard that—and as a
transition it is probably pie in the sky. But let's not rule it out. But if we
are going to make policy decisions based upon whether or not clean coal is a
viable transition pathway, then let's get some science around it first.
Mr Tim Buckley, IEEFA, stated that carbon capture and storage technologies
significantly increase the net cost of energy production compared with current
coal fired generation, and that this makes it unlikely to be competitive into
Mr Barry Ladbrook from Sustainable Energy Now also commented on the
complexity and cost of carbon capture and storage technologies:
It is possible to...strip CO2 out of a variety of sources...The
issue is just the enormous cost that is associated with it. And when I say
'enormous', I mean: basically, you are sticking a chemical process that is
quite expensive onto a power system, so you are adding a whole other degree of
complexity. You are then sticking a transport system onto that. You are then
sticking a geological injection system onto that. So you are sticking three
very different, very complex systems onto one that is already a complex system.
So you have got a whole lot of logistical operational issues to deal with
there...[Y]ou are effectively spending a lot of money to make a power system less
efficient. And, when you add all those costs up together and all that
complexity—never mind the reputational issues, and the security issues about
the geological structure being sound—it really is a minefield.
The Global CCS Institute disputed the claim that carbon capture and
technologies are prohibitively expensive:
[This misconception] stems from simple comparisons to cheap
and intermittent forms of renewable energy, rather than on comparisons of
'value' in providing controllable electricity supply and on a cost per tonne of
CO2 avoided basis. To illustrate this point, the high penetration of
intermittent renewables requires significant additional expenditure on a
combination of backup dispatchable generation, battery storage, transmission
augmentation, demand side management, and other technologies to ensure the
reliability and resilience of the grid. Coal and gas-fired generators with
[carbon capture and storage] do not introduce cost or risks associated with
Dr Bradley Smith, Nature Conservation Council, argued that holding out
the promise of clean coal was misguided, as it is still not viable to implement
despite significant investment in attempts to develop the technology:
Clean coal is a fairytale. It is a distraction, but it is a
very dangerous one because all it does is delay. We know this plant is not
going to get built. What we need are real things that can be built now. This
debate goes back a decade, I think, to when people gave the clean coal thing a
try and found out that it would not work...We cannot afford to waste another 10
years. We need to move forward with our energy transition. We are in the middle
of it now, so we need solutions we can deploy now.
Ms Daisy Barham, Nature Conservation Council, concurred that 'clean
coal' is used as a delay tactic by its proponents that would ultimately make
the inevitable transition to renewable energy more expensive and more painful
for communities currently reliant on coal fired generators.
Role of gas fired power generation
The question of whether gas fired generation could play a more
substantial role as a transitional power source in Australia was discussed at
length during the committee's public hearings.
Mr John Asquith, Community Environment Network, noted that gas fired generation
operates at approximately double the efficiency rate of coal fired power
generation, and argued that gas should be utilised while better energy storage
systems are still in development.
Mr Asquith highlighted that a significant benefit of gas fired generation
over coal fired generation is its ability to respond more quickly to demand
signals, with gas generators able to commence electricity production within one
to two hours' notice, as opposed to a timeframe of 24-48 hours for a coal fired
generator to ramp up to its full production capacity.
Problems with the gas market in Australia that affect its availability
and cost‑effectiveness as a fuel source were also noted by stakeholders
to the inquiry. For example, Mr Buckley of the IEEFA expressed the view that
with gas prices at historically high levels, gas-fired power generation 'is no
longer a low-cost source of supply'.
Ms Blair Palese of 350.org argued that the cost of infrastructure for
expanded gas fired generation, coupled with the unpredictability of gas prices,
worked against utilising it as a transitional energy source:
[T]the price question of gas is a really critical one. It is
quite transient up and down based on international market standards. We cannot
control that even if we try hard. Price-wise it does not compete in anyway with
solar and wind... Secondly, when you look at investing in more gas, you are
looking at 30 to 40 years of fossil fuel infrastructure, and that is expensive.
When you add those two things up, to be honest, if you put a market mechanism
in place, gas would not be in the mix. It would be very quickly moved out
because it is just too costly to install a whole new system and the gas itself
Ms Barham advocated for bypassing gas as a transition fuel altogether,
on the grounds of maximising possible reductions in carbon pollution:
Gas is still a fossil fuel. It does still have significant
carbon emissions whereas we know that renewable energy does not have those
carbon emissions. So we are strongly advocating that we skip straight to
renewable energy, as we have seen so many other parts of the world do, and even
states in Australia are really investing in renewables. We do not need gas.
Emerging energy storage
Technologies which store electricity in order to provide power when it
is not available from renewable energy sources have become an emerging focus in
developing solutions to provide reliability of power supply in a
renewables-dominated system. Battery storage technologies, solar thermal
storage and pumped hydro storage were all discussed during the committee's
Grid level storage
As noted earlier in this chapter, the South Australian Government has
recently committed to building Australia's largest battery storage facility,
via a $150 million renewable technology fund, to create a grid-connected
battery providing 100 MW of storage capacity. The Victorian Government
has also recently announced funding of $25 million to be invested in energy
storage projects, with the aim of creating 100 MW of energy storage
capacity in Victoria by the end of 2018.
Evidence to the committee from solar thermal company SolarReserve and submissions
from Repower Port Augusta made a strong case that solar thermal, with some
government assistance, would be a viable contribution to both storage and new
In February 2017 the Australian Renewable Energy Agency and Clean Energy
Finance Corporation also announced additional funding to be directed towards
accelerating the development of flexible capacity and large-scale storage projects
including battery storage.
The Australian Government's recently announced plan to expand the
capacity of the Snowy Mountains Hydro scheme over the next four years would
also significantly increase the amount of storage-based electricity available to
be fed into the grid during times of peak demand.
Household battery storage solutions
Several witnesses predicted that while household battery storage
solutions are not currently widespread, they will become commercially
competitive and become a significant factor in the overall energy market within
the next few years. Mr Bruce Mountain of Carbon and Energy Markets Australia
told the committee:
[M]y estimate is that a household in Adelaide that installs a
battery and solar combination will outlay around $16,000, and the all-in price
of electricity that they incur, after paying down that investment plus the net
export to the grid and the net purchase from the grid, beats any offer in the
residential retail market. So households would be better off. As a consequence
I expect rapid uptake of battery and solar combinations. I expect that they
will continue to be connected to the grid for backup...It will take time for the
market to adopt, for the installer capacity to develop and so on. I think the
fleetness of foot that we have seen in the installation community with solar is
likely to be replicated in battery. I cannot see a reason why we will not have
a rapid uptake amongst the household consumers. But I think, realistically, it
will be sizeable commercial factor in five years time.
Ms Jemma Green, a Research Fellow at Curtin University, was even more
optimistic about the timeframe for household battery storage units to become
The announcement by Tesla of their Powerwall on 30 April 2015
moved the price of battery storage to around $350 per kilowatt hour. Since then
the price has come down further and it sits at around $275 per kilowatt hour.
What that means in practice is that battery storage is likely to compete with
grid sourced electricity pricing within the next 24 months. It is not really at
that point where you will see mainstream uptake of battery storage, but, when
the delta between grid priced electricity and battery sourced is probably 20
per cent cheaper, then I think you will start to see mainstream uptake.
Ms Green noted research from Morgan Stanley expressing view that the
point at which there would be mainstream uptake of this technology would be
when the price for a combined solar and battery storage household system
decreased to around $10,000, which is forecast to happen within the next
In relation to the cost of household storage systems, Mr Ian Porter from
Sustainable Energy Now stated:
[T]he cost of battery storage is on the same cost-decline
curve as solar PV, which we saw between 2009...and 2014: the cost of solar PV
fell by 80 per cent, and is on the same continuing cost
decline...Battery storage is on the same cost-decline curve. As we know, Tesla in
Nevada, in the US, are opening a plant which will double the capacity of
lithium storage. Lithium is one form of battery. There are many other types of
storage systems under development at this time which we will see come into the
public domain within the next few years, and this will contribute of course to
the disruption technologically, driven by the economics.
In discussing the impact of the increased uptake of household solar and
battery packages on the broader energy market, Mr Mountain predicted it would
create significant challenges for electricity retailers:
I think the impacts will be very significant for retailers.
They would lose almost all of their volume to a customer that installs a
battery and a reasonably-sized solar system. I think there will also be a
significant impact to the network service providers, which, absent regulatory
change, will translate into higher revenues to be got back from the remaining
When asked whether electricity retailers could change their business
model in response to this change by buying power from groups of households with
storage to then on-sell to other consumers, Mr Mountain commented:
Yes. I should think there is no particular trading advantage.
They can either buy wholesale or aggregate up a number of smaller households
with solar and battery that they can buy at a retail level, and that may well
happen. I doubt, though, that it will be anywhere near as profitable as the
existing retail business. In fact, it is not that I doubt; I am absolutely
certain it will not be.
I think the commercial model of electricity retail as we have
today—buying it wholesale, or, in the case of the larger generator retailers,
producing much of what they sell and then on selling to the customer—will
change for many small customers.
Other possible solutions to better integrate household solar and battery
storage systems into the broader grid were also highlighted to the committee.
For example, Ms Green informed the committee of the work of her company Power
Ledger, which has developed technology allowing peer-to-peer trading of electricity
generated by households with rooftop solar systems:
The technology that we have developed uses a blockchain to
enable peer-to-peer trading of electricity. So, if you have solar panels and
you have electricity surplus to your requirements, you can sell that to your
neighbour via the regulated network...It means, if you do not have solar
panels, you are able to procure renewable electricity. Maybe you are in a
rental property or in a building that does not have suitable access to the roof
space, it means you are able to get renewable electricity. If you are a
household you might size your solar and battery system to self supply but you
might have additional roof space and you would like to monetise that. So this
technology enables those transactions to take place.
Ms Green stated that electricity retailers may start utilising these
kinds of technologies in the future to offer peer-to-peer trading as a premium
service to consumers, or may even offer a solar and battery system to consumers
at no up-front cost, with revenue derived from the system then to be shared by
the consumer and the retailer.
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