Explainer: what is a ‘low emissions target’ and how would it work?

How-a-LET-might-work_smokestacks Depending on the policy settings, 
a low-emissions target could conceivably award carbon credits to coal plants.
AAP Image/Dan Himbrechts

The main job of the Finkel Review, to be released this week, is to set out ways to reform the National Electricity Market (NEM) to ensure it delivers reliable and affordable power in the transition to low-carbon energy. Yet most of the attention has been focused on what type of carbon-reduction scheme Australia’s chief scientist, Alan Finkel, will recommend.

The expectation is that he will advocate a “low emissions target” (LET), and it looks like industry is getting behind this.

That would be instead of an emissions intensity scheme (EIS), which had been supported by much of industry as well as regulators and analysts, but the government rejected this.

Both types of scheme are second-best approaches to a carbon price. They can have similar effects depending on their design and implementation, although an EIS would probably be more robust overall.

How a LET might work

A LET would give certificates to generators of each unit of electricity below a threshold carbon intensity. Electricity retailers and industry would be obliged to buy the certificates, creating a market price and extra revenue for low-emission power generators.

How many certificates get allocated to what type of power generator is an important design choice. Government would also determine the demand for the certificates, and this defines the overall ambition of the scheme.

At its core, the scheme would work rather like the existing Renewable Energy Target, which it would replace. But the new scheme would also include some rewards for gas-fired generators, and perhaps even for coal-fired generators that are not quite as polluting as others. The question is how to do this.

A simple but crude way of implementing a LET would be to give the same number of certificates for every megawatt hour (MWh) of electricity generated using technologies below a benchmark level of emissions intensity. In practice, that would be renewables and gas. In principle, the scheme could include nuclear power as well as coal plants with carbon capture and storage, but neither exists in Australia, nor are they likely to be built.

Such a simple implementation would have two drawbacks. One, it would create a strong threshold effect: if your plant is slightly above the benchmark, you’re out, slightly below and you’re in. Two, it would give the same reward to gas-fired generators as to renewables, which is inefficient from the point of view of emissions reduction.

A better way is to scale the amount of certificates issued to the emissions intensity of each plant.

If the benchmark was 0.7 tonnes of carbon dioxide per MWh of electricity (as some media reports have predicted), then a gas plant producing 0.5 tonnes of CO₂ per MWh would get 0.2 certificates per MWh generated. A wind or solar farm, with zero emissions, would receive 0.7 certificates per MWh generated.

The benchmark could also be set at a higher level, potentially so high that all power stations get certificates in proportion to how far below the benchmark they are. For example, a benchmark of 1.4 tonnes CO₂ per MWh would give 1.4 certificates to renewables, 0.9 certificates to the gas plant, 0.5 certificates to an average black coal plant and 0.2 certificates to a typical brown coal plant.

Including existing coal plants in the LET in this way would create an incentive for the sector to move towards less polluting generators. It would thus help to reduce emissions from the coal fleet, and perhaps pave the way for the most polluting plants to be retired earlier. But the optics would not be good, as the “low emissions” mechanism would be giving credits to coal.

Whichever way certificates are distributed, the government also has to specify how many certificates electricity retailers need to buy. Together with the benchmark and with how electricity demand turns out, this will determine the emissions intensity of overall power supply. The benchmark would need to decline over time; alternatively, the amount of certificates to be bought could be increased.

The price of LET certificates would depend on all of these parameters, together with the cost of energy technologies, and industry expectations about the future levels of all of these variables. As the experience of the RET has shown, these can be difficult to predict.

Low emissions target vs emissions intensity scheme

An emissions intensity scheme (EIS) is the proposal that in recent times had the broadest support in the policy debate. Finkel’s preliminary report referenced it and the Climate Change Authority earlier put significant emphasis on it. But it got caught in the internal politics of the Liberal-National Coalition and was ruled out.

Under an EIS, the government would set a benchmark emissions intensity, declining over time. Generators below the benchmark would be issued credits, whereas those running above the benchmark would need to buy credits to cover their excess emissions. Supply and demand set the price in this market.

Depending on how the parameters are set, the effects of a LET and an EIS on the power mix and on power prices would differ, but not necessarily in fundamental ways.

There are some key differences though. Under a LET, electricity retailers will need to buy certificates and not all power plants may be covered by a low-carbon incentive. Under an EIS, the higher-polluting plants buy credits from the cleaner ones, and all types of plants are automatically covered. The EIS market would be closely related to the wholesale electricity market, with the same participants, whereas a LET market would be separate and distinct, like the RET market now.

Further, the benchmark in an EIS directly defines the emissions intensity of the grid and its change over time. Not so for the benchmark in a LET. A LET will also require assumptions about future electricity demand in setting the total amount of credits that should be purchased – and bear in mind that the estimates used to calibrate the RET were wildly off the mark.

What’s more, an EIS might present a chance to circumvent the various special rules and exemptions that exist in the RET, and which might be carried over to the LET.

Politics vs economics

Neither a LET nor an EIS provides revenue to government. Since the demise of Australia’s previous carbon price this has often been considered desirable politically, as it avoids the connotations of “carbon tax”. But economically and fiscally it is a missed opportunity.

Globally, most emissions trading schemes generate revenue that can be used to cut other taxes, help low-income households, or pay for clean energy research and infrastructure.

An economically efficient system should make carbon-based electricity more expensive, which encourages energy consumers to invest in energy-saving technology. Both a LET and an EIS purposefully minimise this effect, and thus miss out on a key factor: energy efficiency.

Ambition and confidence

More important than the choice of mechanism is the level of ambition and the political durability of the policy.

Bringing emissions into line with the Paris climate goals will require fundamental restructuring of Australia’s power supply. Coal would need to be replaced well before the end of the lifetime of the current plants, probably mostly with renewables.

To prompt large-scale investment in low-carbon electricity, we need a reliable policy framework with a genuine and lasting objective to reduce emissions. And investors need confidence that the NEM will be governed by rules that facilitate this transition.

Of any policy mechanism, investors will ask the hard questions: what will be its actual ambition and effects? Would the scheme survive a change in prime minister or government? Would it stand up to industry lobbying? Investor confidence requires a level of predictability of policy.

If a LET were supported by the government and acceptable to the Coalition backbench, and if the Labor opposition could see it as a building block of its climate policy platform, then the LET might be a workable second best, even if there are better options. Over the longer term, it could be rolled into a more comprehensive and efficient climate policy framework.

This article was written by:
Image of Frank Jotzo Frank Jotzo – [Director, Centre for Climate Economics and Policy, Australian National University]

 

 

 

 

This article is part of a syndicated news program via the Conversation

 

Explainer: why we should be turning waste into fuel

Why we should be turning waste into fuel Converting waste into fuel or energy 
should be part of Australia’s recycling and rubbish reduction plan.

The federal government recently announced that it is giving recycling company ResourceCo a loan of A$30 million to build two waste-to-fuel plants producing “solid waste fuel”.

Waste-to-energy is an important part of the waste industry in Europe. Significant demand for heat means efficient and tightly controlled waste incinerators are common. However, Australia lacks an established market, with low levels of community acceptance and no clear government policy encouraging its uptake.

But the federal announcement, coupled with an uptake in state funding, a New South Wales parliamentary inquiry and several new projects in the pipeline, signals a growing interest in waste-to-energy and waste-to-fuels.

But what is solid waste fuel, and where does it fit in a sustainable future for Australian waste management?

What are solid waste fuels?

Australians are becoming more wasteful. The amount of rubbish we produce is growing more rapidly than both our population and our economy.

Recycling has been the main approach for recovering resources and reducing landfill over the past 20 years, but a lot more needs to be done.

One part of the solution is “waste-to-energy”: using a range of thermal or biological processes, the energy embedded in waste is captured, making it available for the direct generation of heat and electricity, or for solid fuel production (also known as “processed engineered fuel”).

Briquettes or fuel pellets can be made out of paper, plastic, wood waste or textiles
Briquettes or fuel pellets can be made out of paper,plastic, 
wood waste or textiles

Waste-to-fuel plants produce fuels from the combustible (energy-rich) materials found in waste from households and industry. Suitable materials include non-recyclable papers, plastics, wood waste and textiles. All of these typically end up in landfill.

These materials are preferably sourced from existing recycling facilities, which currently have to throw out contaminated matter that can’t be recycled.

Solid waste fuels are produced to specified qualities by different treatment methods. These include drying, shredding, and compressing into briquettes or fuel pellets. Fuels can be specifically tailored for ease of transportation and for different uses where industrial heat is required. This make them suitable alternatives to fossil fuels.

What are solid waste fuels used for?

As a replacement for coal and gas, solid waste fuel can be burned to generate electricity with a smaller carbon footprint than fossil fuels.

In addition to the power sector, other industries requiring high-temperature heat use solid waste fuels – for example, in cement works in Australia and around the world. There may also be scope to expand their use to other energy-intensive industries, such as metals recycling and manufacturing industrial chemical products.

Fuel pellets made from waste can be burned for energy
Fuel pellets made from waste can be burned for energy. tchara/shutterstock

What are the key benefits?

The primary environmental benefit of solid waste fuel comes from the reductions in landfill emissions and fossil fuel use.

Biodegradable carbon sources decompose in landfill, creating methane. This is a greenhouse gas with a warming potential 25 times that of carbon dioxide. Technology already exist for capturing and converting landfill gases to energy, but waste-to-fuel is a complementary measure that limits landfill in the first instance.

Waste-derived fuel can also have a smaller carbon footprint than fossil fuels. This depends on the carbon content of the fuel, and whether it is derived from biological sources (such as paper, wood or natural fibres). Even though carbon dioxide is emitted when the fuel is burned, this is partly offset by the carbon dioxide captured by the plants that produced the materials in the first place.

In these cases, solid waste fuels are eligible for renewable energy certificates. More advanced closed-loop concepts achieve even better carbon balances by capturing the carbon dioxide released when the fuel is used. This can used for other processes that require carbon dioxide as an input, such as growing fruit and vegetables.

Further environmental benefits can come from the management of problem wastes such as treated timbers, car tyres, and e-plastics. Converting them into fuel prevents the leaching of harmful substances into the environment, and other potential problems.

 Arma banchang/shutterstock

What are the challenges?

Communities are legitimately concerned about energy recovery from waste owing to public health risks. Without appropriate emission control, burning solid fuel can release nitrous oxides, sulphur dioxides, particulate matter and other harmful pollutants. But, with solid regulation and the best available pollution-control technology, these emissions can be managed.

The recycling industry is also worried that energy recovery has the potential to undermine existing recycling by diverting waste flows. Famously, solid waste fuel is so important to Sweden it actually imports garbage from other European countries.

These challenges point to the importance of investing in the appropriate infrastructure at the right size, and creating regulations that balance the needs of existing recycling processes. With careful planning, waste-to-fuel can be an important part of a broad strategy for transitioning towards a zero-landfill future.

This article was co-authored by:
Nick Florin 
Nick Florin – [Research Director at the Institute for Sustainable Futures, University of Technology Sydney]
and
Ben Madden

 

 

 

 

Want to boost the domestic gas industry? Put a price on carbon

 With the right power policies, gas can have a brighter future

Australia’s gas industry is under scrutiny from the competition watchdog after apparently failing to deliver on its pledge to bring down domestic prices and ease the east coast gas supply crisis.

The current domestic supply squeeze will be over soon enough. But other, longer-term factors threaten the role of gas in Australia’s energy mix.

Gas producers claim that gas is a vital fuel in the transition to a low-carbon economy (although not everyone agrees). But to achieve this they need to ensure that coal is replaced by gas in the generation of electricity. It is increasingly unlikely that this will happen in Australia, unless the industry can persuade the government to reinstate a price on carbon.

At the moment, the idea of gas as a transition fuel seems academic anyway. Gas is now in such short supply on the east coast that any policy aimed at increasing demand seems ludicrous. The shortage has driven gas prices to unprecedented levels, which has in turn has driven up electricity prices. In the gas industry, the talk is mainly about finding new supplies, not new customers.

But the present east coast gas shortage may well be shortlived, because there is currently an oversupply of gas on the international market. With prodding from government, this could bring about a drop in domestic prices in various ways.

For example, the liquid natural gas (LNG) exporters in Queensland who are sucking up so much of Australia’s gas might find it profitable to meet some of their international contract commitments by buying LNG on the international market and shipping it direct to their customers. This would release gas they have contracted to buy in Australia into the local market, thereby saving the (not inconsiderable) cost of liquefaction. This is the strategy of the gas swaps currently being touted as a solution to the domestic supply squeeze.

Alternatively, shiploads of LNG bought on the open market could be brought to southeast Australia, re-gasified, and then fed into the gas transmission system relatively close to the point of consumption, thus reducing transmission costs. This idea has been floated by gas producer AGL.

The government has not yet prodded hard enough to make these things happen, but a worsening gas crisis may stiffen its resolve.

Finally, extra supplies of Northern Territory gas will become available on the east coast when the Northern Gas Pipeline is completed next year.

None of these strategies depends on increasing the production of unconventional gas on the east coast, although that too, if it happened, might ease the domestic supply problem.

Crisis over?

In summary, there are grounds for thinking that in the reasonably short term we will see a significant increase in gas supply on the east coast, and a corresponding drop in price. As soon as that happens, the gas industry will again be interested in stimulating demand, particularly in the electricity sector. But by then it may be too late. Here’s why.

Without a national strategy that puts a price on carbon, the states will continue to go it alone with renewable energy targets. As the new renewable energy generators come online, they will push the most expensive generators out of business. Unfortunately for gas, even with more reasonable gas prices, coal-fired electricity will remain cheaper.

So, to the extent that the market can rely on renewables and coal alone, gas will be out of business. As large-scale battery storage becomes a reality, gas may not even be needed to cope with spikes in demand. Meanwhile, the current high price of power means the quiet revolution in rooftop solar panels is set to continue. The most recent data shows new installations are up 43% on a year ago.

There is, however, hope for gas in the medium term if the government legislates to impose a price on carbon in the electricity sector. One way to do this has already been widely proposed: an emissions intensity scheme.

Such a scheme would impose penalty payments on the most carbon-intensive emitters, such as coal-fired power stations and pay subsidies to lower-emitting industries such as renewables and gas.

This would put gas in a much better position to compete with coal, especially if the penalties were ratcheted up over time. Under modelling done for the Climate Change Authority, this would see brown coal power stations disappear within three years, while black coal would follow suit in little more than a decade.

Coal’s place would be taken mainly by wind and by new, efficient, gas-fired power stations. If by that time gas-fired power stations are able to capture and store their carbon dioxide emissions, then we would truly have arrived in a golden age for gas. If not, the gas industry will at least have had some profitable years before going into decline.

A price on carbon would let gas win the battle with coal and step in to take its place. Eventually, however, renewables will sweep away all fossil fuel power generation, so of course the long-term future for gas in this sector is bleak (as befits a transition fuel). But without a price on carbon, coal will be around for longer, undermining whatever market there may be for gas.

It is therefore in the gas industry’s interest to lobby hard for a price on carbon in the electricity sector, as part of the upcoming government review of climate policy. Other industry groups are virtually unanimous in their support for carbon pricing, but the oil and gas industry’s peak body, the Australian Petroleum Production and Exploration Association, has been rather more equivocal. While in theory it supports a carbon price, it qualifies this support so extensively that in practice it opposes every pricing proposal that is placed on the table.

If the peak oil and gas body could be persuaded to join with the rest of industry on this matter, it might just make the difference. Pricing carbon is not only good for the environment, in the medium term it is good for gas too.

This article was written by:
Andrew Hopkins – [Emeritus Professor of Sociology, Australian National University]

 

 

Australian gas: between a fracked rock and a socially hard place

 Protesters rally against coal seam gas in Melbourne, February 2016

Prime Minister Malcolm Turnbull’s response to the looming east coast gas shortage has been to secure a promise from gas producers to increase domestic supply.

In a televised press conference last month, he said:

We must continue the pressure on state and territory governments to revisit the restrictions on gas development and exploration.

But if an onshore gas boom is indeed in the offing, my research suggests that gas companies should tread carefully and take more seriously the social context of their operations.

Shell chief executive Erik van Beurden, one of the big players in the Australian gas industry, recently admitted that “social acceptance [for our industry] is just disappearing”, while Shell Australia’s chairman Andrew Smith last year urged the industry to be less hubristic and more willing to collaborate.

Industrial developments have social consequences, particularly in the case of unconventional gas extraction. But my analysis of the social research done by gas firms in the Darling Downs – Queensland’s coal seam gas heartland – indicates a lack of rigorous research to identify community attitudes.

I looked specifically at the “social impact assessments” carried out for Arrow Energy’s Surat Gas Project. I evaluated this assessment against the academic literature on best-practice methods and the results of my own anthropological fieldwork on coal seam gas developments in the Darling Downs, including interviews and participant-observations among a broad variety of residents. This included farmers with and without gas wells on their land, town residents, Indigenous people, activists, and those who viewed the industry favourably.

In my experience, the industry’s social impact assessments do not generally meet the benchmark of good social anthropological research. They are largely completed using computer surveys, with limited amounts of direct local fieldwork and relatively little real attention paid to the particular issues raised by vulnerable groups or what actually matters to local communities.

Social impact assessments should be participatory and take into account the unequal distribution of the impacts among local populations. Some people will feel the impacts more than others – this means that in-depth research in the region is required.

A desktop analysis of census data, complemented with information obtained during a few “consultation” meetings, is unlikely to reveal the variety of impacts caused by industrial projects. The conclusion is that such studies, combined with a regulatory agenda that prioritises economics, have created problematic “silences in the boom”.

Conflicting priorities

In Australia, policies governing extractive industries such as onshore gas are mostly viewed in terms of economic cost and benefit – or to use the current mantra, jobs and growth. The projects themselves, meanwhile, are seen chiefly as a series of technical challenges to be overcome by scientists and engineers.

Public concerns about the effect on quality of life or uncertainties about underground impacts are commonly dismissed as irrational, emotional or uninformed. But the main problem faced by onshore gas producers is not an engineering one.

Social research has shown that the fundamental problems include lack of trust between gas producers and local communities, as well as differing views on livelihoods, culture and the environment.

In the coal seam gas fields of the Darling Downs – a rural and agricultural area – the effects on the ground, including concerns about extraction techniques such as fracking really matter. While individual gas wells typically have a relatively small footprint of about one hectare, the cumulative regional footprint of numerous connected gas fields and associated infrastructure is considerable.

The management of the impacts is negotiated in individual agreements with landholders as well as indigenous groups with traditional connections to country. Dealing with this social world is relatively new to many oil and gas companies that have previously focused mainly on offshore projects.

 Satellite view of a coal seam gas field in Queensland. 
 

Unconventional gas and fracking developments have led to demonstrations, blockades, and the rise of vocal anti-fracking groups both in Australia and around the world. Gas producers in Colorado, for example, seem to have been shocked and surprised at the level of protest against fracking, a technique they have used for decades.

Instead of dismissing public concerns as irrational or ill-informed, politicians and gas producers could look carefully at why their proposals provoke these reactions. Just calling for more gas, more science, and less red tape is unlikely to diminish anti-fracking sentiment.

Invisible gas

Gas can be scary. It is everywhere and nowhere. You can’t feel it, see it, hear it or smell it unless you add something to it or measure it with an expensive device. Gas doesn’t have the same cultural symbolism as coal, the black gold of our settler history, or the Snowy Mountains, scene of the great “nation-building” hydroelectric project that Turnbull has pledged to make even bigger.

Anti-fracking activists, meanwhile, have sought to imbue gas with a cultural symbolism that draws on the underground world of demons and danger. Footage of burning tapwater is a potent example of “matter out of place”. No matter that methane is sometimes found naturally in water. Cultural anxieties are rarely be eased by natural science.

So while the federal government and industry figures call on states and territories to ease restrictions on gas exploration, they should bear in mind that unconventional gas can provoke strong anxiety and opposition. The architects of Queensland’s coal seam gas boom were slow to recognise this.

Energy is fundamental to our ways of life, and social support is crucial for the companies that provide this energy. Such support is not earned with desktop studies or by dismissing non-economic concerns. It is earned with genuine engagement and social policies that take seriously the experiences and diverse views of people now on fractured and uncertain ground.

This article was written by:

Hazelwood power station: from modernist icon to greenhouse pariah

Hazelwood in happier times

The roar of the furnaces, the rattle of the conveyors, and the occasional whoop of a siren marked out both day and night at Hazelwood. The pungent smell of brown coal permeates the air, and the fine particles would work their way into your clothes, hair and shoes.

On quiet evenings you could hear it all the way over in the nearby town of Churchill, seven kilometres away. That distant hum has been a comforting one as the station produced power in all weathers, day and night, for more than five decades. For many in Churchill and the other coal towns of Victoria’s Latrobe Valley, the noise also represented continuity of employment for more than 450 workers.

Those old certainties are now disappeared. The eight units that make up the 1,600 megawatt power station were progressively decommissioned this week, all now shut off ahead of Hazelwood’s official closure on March 31. While some 250 workers will remain, the distant hum has settled to a whisper.

Noisy no longer: the turbine hall.
When the brand new Hazelwood power station was officially opened on March 12, 1971, it represented a new and confident future for the Latrobe Valley region and the state of Victoria. Plans for this major infrastructure project were first made in 1956 and the first contracts signed in 1959. Victorian Premier Sir Henry Bolte spoke of the Latrobe Valley as the “Ruhr of Australia”.

The first six generating units were constructed between 1964 and 1967, and the plant was eventually expanded to include another two. All eight were operational by the time of the official opening in 1971. The station was fed by the Morwell open cut brown coal mine, and was built right next door to the mine’s open-cast pit. The Morwell mine eventually grew to such mammoth proportions that the nearby Morwell River had to be diverted three times. Each day, the mine fed more than 55,000 tonnes of brown coal into Hazelwood’s eight furnaces.

Noisy no longer: the turbine hall.
When the brand new Hazelwood power station was officially opened on March 12, 1971, it represented a new and confident future for the Latrobe Valley region and the state of Victoria. Plans for this major infrastructure project were first made in 1956 and the first contracts signed in 1959. Victorian Premier Sir Henry Bolte spoke of the Latrobe Valley as the “Ruhr of Australia”.

The first six generating units were constructed between 1964 and 1967, and the plant was eventually expanded to include another two. All eight were operational by the time of the official opening in 1971. The station was fed by the Morwell open cut brown coal mine, and was built right next door to the mine’s open-cast pit. The Morwell mine eventually grew to such mammoth proportions that the nearby Morwell River had to be diverted three times. Each day, the mine fed more than 55,000 tonnes of brown coal into Hazelwood’s eight furnaces.

 

A postwar coal community

These power stations, along with the Morwell and Yallourn coal mines, defined the industrial heart of the Latrobe Valley as part of a postwar push to create entire communities in the region, centred on the coal industry. The SECV and then the state government had a meticulously planned vision, deciding on the location of new developments and entire new towns. By 1981 electricity generation and mining employed more than 10,000 workers in an overwhelmingly male-dominated workforce.

It had not all been plain sailing. Completion of the Morwell power station was delayed by financial constraints and then technical problems. Coal from the Morwell mine proved to be unsuitable for briquette manufacture and so the SECV reverted to using Yallourn coal in the briquette furnaces. The SECV also met with considerable local criticism over its decision to close the planned township of Yallourn so as to dig out the coal underneath it. Polluted though it was, many Yallourn residents had no desire to leave their tree-lined community.

The new town of Churchill, built to house the industrial workforce and their families, would accompany the Hazelwood development. Churchill was a model town located to avoid the prevailing winds from existing power stations, perched on a hill with views across the Latrobe valley, the distant Baw Baw ranges, and newly created lakes of Hazelwood Pondage. Churchill joined other new public housing developments in nearby Moe and Morwell to house the expanding workforce.

Yet life in the coal heartland came with its own problems. Issues with air quality began to become evident as early as the 1970s, while the privatisation of Hazelwood and the other power stations from 1996 led to 8,000 job losses. A 2004 WWF report named Hazelwood as the dirtiest power station in Australia, producing the most greenhouse emissions per megawatt of energy.

Hazelwood became a powerful political symbol and rallying cry for those concerned about the impact of carbon dioxide emissions on global warming. It has been credited with producing 5% of the nation’s power and 3% of its carbon dioxide emissions.

The symbolic face of brown coal power.
The media image of Hazelwood today, its eight stacks standing as a visual image of greenhouse emissions and industrial pollution, was forged in the decade since the WWF report. Worse was to come when it became the site of a coalmine fire that blazed for 45 days in February-March 2014, showering Morwell with smoke and ash and creating a major public health disaster.

The confident, modernist image of 1970s Hazelwood went up in smoke, but this image has not been forgotten by many in the Latrobe Valley who lived through it.

This article was written by Erik Eklund [Professor of History, Federation University Australia]


Federation University, through the Centre for Gippsland Studies, is planning to take part in a project to record the memories and experiences of Hazelwood workers. The author thanks Engie, who approved a site visit to research this article, and Mark Richards, a Hazelwood worker and CFMEU delegate who acted as a tour guide.

Hazelwood closure: what it means for electricity prices and blackouts

Hazelwood’s closure does not mean imminent blackouts for Victoria

Victoria’s Hazelwood power station shut down this week after nearly 50 years of supplying electricity.

The closure has led to concerns about blackouts, raised most recently by Deputy Prime Minister Barnaby Joyce, and rising electricity prices.

So what does the evidence suggest?

Blackouts ahead?

Last week The Age reported that Victoria is facing “72 days of possible power supply shortfalls over the next two years”. While that sounds bad, it does not mean the state is facing imminent blackouts.

This was based on a report from the Australian Energy Market Operator (AEMO), which is in charge of making sure that Australia’s energy markets work.

Every week, AEMO produces something called the Medium Term Projected Assessment of System Adequacy. This report assesses the expected supply and demand of electricity for the next two years.

In a recent report, AEMO did indeed forecast a “reserve shortfall” for 72 days in Victoria in the coming two years. AEMO has actually been forecasting many days of reserve shortfall, since early November last year when Engie announced the closure of Hazelwood.
AEMO has also been forecasting an even greater number of days of reserve shortfalls in South Australia for well over a year.

The shortfall forecast is based on a combination of factors. This includes the amount of local energy supply, the import and export of electricity from other states, the maximum daily demand for electricity, and the “reserve requirement”. The reserve requirement is essentially “spare” capacity that can be used to maintain a reliable supply if something goes wrong.

If there is not enough supply to meet this requirement, there is a reserve shortfall.

Forecasting maximum demand is incredibly challenging and uncertain. AEMO does it by using probabilities. This gives us a measure of the probability of a particular demand forecast being exceeded in a year.

For example, a 10% chance would be expected to be exceeded one year in ten. A 50% chance would be expected to be exceeded one year in two.

To illustrate the point, AEMO forecast that demand over the past summer in Victoria had a 10% chance of exceeding 9,900 megawatts. In reality, the maximum demand was only 8,747MW. That’s not to say the forecast was wrong, but rather that it was not an exceptional (one year in ten) summer.

In the recent outlook, AEMO has found 72 days on which a reserve shortfall might occur. The likelihood of this happening on any one of those days is low. For a reserve shortfall to actually occur 72 times over two years is incredibly unlikely.

However, AEMO still plans for this possibility. Indeed, this is largely the point of producing these forecasts: signalling potential capacity shortfalls so the market and operator can respond.

What will happen when Hazelwood closes?

Another way of illustrating the role of Hazelwood and the effect of its closure on the broader Victorian energy system is shown below.

In this figure, I’ve plotted the 10% and 50% thresholds for exceeding maximum demand in the coming summer, and also the “load duration curve” for previous years. This curve shows that the periods of greatest demand are also the least common (the left side of the graph). The vast majority of demand is much lower, and the “base load” is about 4,000MW.
† Interconnection capacity (from other states) at times of peak demand is much less than the total theoretically possible. ‡ Firm wind is about 7.5% of total rated capacity in Victoria. Author

I’ve also included “firm capacity” (the minimum power we know we can get) with and without Hazelwood, to the right.

As can be seen, there is more than enough capacity in Victoria to meet the base load. There is even enough local firm capacity to meet the peak load and reserve requirements for the one-in-two-year maximum demand event. For the one-in-ten-year event, power needs to be imported from other states to ensure secure supply at the peaks.

AEMO reaffirmed security of supply in a media statement last week. As noted, Victoria and other states have available power generation resources that are not switched on or are operating at less than full capacity. This electricity can be made available to replace the power that Hazelwood supplies.

What about prices?

The question of what replaces Hazelwood brings us to prices. Many, including AEMO, expect to see increased generation from currently underused power plants. These include New South Wales’ black coal power plants. Last year NSW’s black coal was used at 56% of its total capacity. Bumping up these stations’ output would also reduce NSW’s reliance on Victorian exports.

Reducing the capacity of brown coal will mean logically that Victoria relies on more expensive forms of generation such as black coal or gas. This is particularly so if the availability of cheap imports is limited, and more expensive local generation such as gas is needed.

Black coal power stations generate electricity comparatively cheaply. Even so electricity prices are already so high that an increase in black coal generation may not have a dramatic impact on prices. With NSW prices averaging A$137 per megawatt hour this year, it is clear that the cost of coal is not determining electricity prices.

The Victorian wholesale market will also become a more concentrated market. As a result, there may be more opportunities for market power to be exercised. Perhaps the recently announced ACCC inquiry into power prices will put generators on their best behaviour.

Any price rise may be short-lived. The Australian Energy Market Commission, which sets the rules for the energy market, has reported that more renewable energy supply is expected to reduce wholesale electricity prices.

Hazelwood’s closure should not compromise the security of the Victorian electricity system over the next few years. This is not to say that there definitely won’t be a blackout. A one-in-50-year storm, a plant failure, a flooded mine pit, an interconnector outage – any of these events could strain the system beyond what is manageable.

At this stage, what ultimately happens to prices is anyone’s guess. Whatever the case, it is clear that Victoria has plenty of supply to meet the state’s base load. New capacity might be required to meet the maximum demand – and that new capacity could take the form of energy storage
.

This article was written by Dylan McConnell – [Researcher at the Australian German Climate and Energy College, University of Melbourne]

Gas crisis? Energy crisis? The real problem is lack of long-term planning

The long view: energy policy needs to stay firmly focused on the horizon

If you’ve been watching the news in recent days, you’ll know we have an energy crisis, partly due to a gas crisis, which in turn has triggered a political crisis.

That’s a lot of crises to handle at once, so lots of solutions are being put forward. But what do people and businesses actually need? Do they need more gas, or cheaper prices, or more investment certainty, or all or none of the above? How do we cut through to what is really important, rather than side details?

The first thing to note is that what people really care about is their energy costs, not energy prices. This might seem like a pedantic distinction, but if homes and businesses can be helped to waste less energy, then high prices can be offset by lower usage.

The second thing to note is that energy has become very confusing. A host of short- and long-term problems have developed over decades of policy failure, meaning that there is no single solution.

Take gas prices, which were indirectly responsible for South Australia’s blackouts last month. Last week, SA Premier Jay Weatherill responded by unveiling a A$550-million plan including a new state-owned gas power station, while Prime Minister Malcolm Turnbull claimed to have secured a promise of secure domestic supply from gas producers.

Short-term thinking

It is crucial to keep the ultimate goals in focus, or else our short-term solutions could exacerbate long-term problems.

For electricity, we want to avoid blackouts and limit prices and overall costs. We need to do this in ways that allow us to meet our climate constraints, so we need solutions with zero or very low greenhouse emissions.

For gas, we need to ensure enough supply for local demand, at reasonable prices, and give large consumers the opportunity to negotiate contracts over reasonable time frames.

This means we need to allocate more of our gas to local consumers, because increasing overall gas production would just add to our long-term climate problems.

Peak gas and electricity prices are entangled. In our electricity markets, the most expensive generator needed to maintain supply in a given period sets the price for all the generators. So if an expensive gas generator sets a high price, all of the coal and renewable energy generators make windfall profits – at the consumer’s expense.

So either we need to ensure gas generators don’t set the price, or that they charge a reasonable price for the power they generate.

Quick fixes

Demand management and energy storage are short-term fixes for high peak prices. Paying some electricity or gas consumers to use less at peak times, commonly called “demand response”, frees up electricity or gas, so prices don’t increase as much.

Unfortunately, policymakers have failed to introduce effective mechanisms to encourage demand response, despite the recommendations of numerous policy reviews over the past two decades. This is a serious policy failure our politicians have not addressed. But it could be fixed quickly, with enough political will.

Energy storage, particularly batteries and gas storage, can be introduced quickly (within 100 days, if Tesla’s Elon Musk is to be believed). Storage “absorbs” excess energy at times of low demand, and releases it at times of shortage. This reduces the peak price by reducing dependence on high-priced generators or gas suppliers, as well as reducing the scope for other suppliers to exploit the shortage to raise prices.

The same thinking is behind Turnbull’s larger proposal to add new “pumped hydro” capacity to the Snowy Hydro scheme, although this would take years rather than weeks.

Thus South Australia’s plan, which features battery storage and changes to the rules for feeding power into the grid, addresses short-term problems. Turnbull’s pumped hydro solution is longer-term, although his handshake deal with gas suppliers may help in the short term.

The long view

When we consider the long term, we must recognise that we need to slash our carbon emissions. So coal is out, as is any overall expansion of natural gas production.

Luckily, we have other affordable long-term solutions. The International Energy Agency, as well as Australian analysts such as ClimateWorks and Beyond Zero Emissions, see energy efficiency improvement as the number-one strategy – and in many cases, it actually saves us money and helps to offset the impact of higher energy prices. Decades of cheap gas and electricity mean that Australian industry, business and households have enormous potential to improve energy efficiency, which would save on cost.

We can also switch from fossil gas to biogas, solar thermal and high-efficiency renewable electricity technologies such as heat pumps, micro-filtration, electrolysis and other options.

Renewable energy (not just electricity) can supply the rest of our needs. Much to the surprise of many policymakers, it is now cheaper than traditional options and involves much less investment risk. Costs are continuing to fall.

But we need to supplement renewable energy with energy storage and smart demand management to ensure reliable supply. That’s where options such as pumped hydro storage, batteries and heat-storage options such as molten salt come in.

This is why the crisis is more political than practical. The solutions are on offer. It will become much more straightforward if politicians free themselves from being trapped in the past and wanting to prop up powerful incumbent industries.

This article was written by Alan Pears[Senior Industry Fellow, RMIT University]

South Australia makes a fresh power play in its bid to end the blackouts

SA energy minister Tom Koutsantonis outlines his plan to make his state more energy-independent

South Australia’s government has unveiled its keenly anticipated new energy plan, with the aim of making itself more self-sufficient.

Against the backdrop of repeated crises such as the blackouts of last month and September last year, and a dramatic offer from Tesla founder Elon Musk to fix the state’s energy security problems, the new plan proposes a range of measures to fix what Premier Jay Weatherill has described as the “failures” of national electricity regulation.

Battery storage
First, as almost universally anticipated, there will be a tender for 100 megawatts of battery storage, to be funded from a A$150 million Renewable Technology Fund. The plan document says this project will “modernise South Australia’s energy grid and begin the transformation to the next generation of renewable-energy storage technologies”.

Neither the National Electricity Market rules nor any other federal policy provides any specific mechanism to encourage battery installation. Nor do the existing regulations allow battery operators to be rewarded for other services they could provide, including responding rapidly to price spikes or to sudden drops in voltage on the grid.

Large battery installations, if appropriately configured, would be capable of providing large injections of energy to the grid over short periods, as a way to offset extreme volatility. Both SA and Queensland have been plagued by such volatility in recent months, causing a rash of short-term price spikes indicative of markets without enough competition.

The Australian Energy Market Commission (AEMC) is currently considering a Rule change, termed the 30 minute/5 minute trading interval change, proposed by a large electrolytic zinc smelter in Townsville. The change is ferociously opposed by established generators, but supported by almost everyone else. If and when the AEMC ever gets around to approving the rule change, large battery installations would be able to compete directly with generators, thereby both gaining a new source of revenue and helping to keep wholesale prices within reasonable limits.

Taking back control
The second component of the plan is to introduce legislation that would allow the state government to override the NEM’s market dispatch process for generation in the event of an emergency such as the demand peaks that triggered last month’s blackouts.

This is an obvious response to what is widely seen, at least in SA, as the reluctance of the federal regulator to use its powers to suspend the market. Many observers consider that such reluctance was most evident in the morning of the statewide blackout last September, and believe that earlier intervention could have prevented it, despite the massive storm damage to the state’s transmission infrastructure.

The new proposal could be interpreted as a challenge to the federal government over who controls SA’s electricity.

Energy security
Third, the plan will require all new generators with more than 5MW of capacity to demonstrate how they will contribute to the state’s energy security, by providing what are called ancillary services, such as frequency control, so-called inertia, or short-term storage. This is another clear statement that the state government believes the NEM rules, which establish markets for some frequency control services but not the other services mentioned above, fail to offer the state enough of a guarantee of reliable power supply.

Build a new gas plant
The government plans to become a power station owner, 20 years after the Liberal state government sold off the last publicly owned plant, by building a new open cycle (peaking) gas turbine plant. This decision is most obviously a reaction to the load-shedding blackout amid last month’s heatwave, when the operators of the Pelican Point gas power station were either unable or unwilling to increase output. Had they done so, load shedding could have been avoided.

At A$360 million, this seems a rather expensive way to avoid another load-shedding blackout, presumably justified on the basis of avoided political cost. It could be seen as a missed opportunity to provide more support for a far more innovative (though well proven in other countries) project to integrate solar thermal generation, gas generation and molten salt storage.

Solar thermal generation may gain support from the tender for new generation to supply the government’s own electricity requirements, and possibly some from the Renewable Technology Fund, but that remains to be seen.

Energy security target
Finally, the government will introduce a requirement, called an energy security target, requiring electricity retailers to source a minimum percentage of their wholesale requirements from local generators, rather than from Victorian coal-fired stations.

This will provide a guaranteed amount of revenue to local generators, thus reducing dependence on supply through the interconnectors with Victoria, with their associated security risks.

In a direct, though entirely unsurprising confrontation with the Commonwealth, the plan document states that “South Australia’s energy security target will transition to an EIS or Lower Emissions Target (LET) if or when national policy changes in the future”.

The wider context

In the policy document, Weatherill writes that the NEM is “failing South Australia and the nation”. Taken together, the various elements of the plan can be read as a list of how exactly the SA government considers it to be failing, and what powers the state proposes to assume in order to get it fixed.

Although the plan’s objectives are not stated explicitly, it is clear that they are threefold, and seen of equal priority:

 

  • suppress retail price rises by introducing more competition into the wholesale market
  • enhance the physical security of electricity supply
  • encourage renewable generation and reduce greenhouse gas emissions.

These priorities neatly match the three components of what the preliminary report of the forthcoming Finkel Review calls the “energy trilemma”, which is the need to “simultaneously provide a high level of energy security and reliability, universal access to affordable energy services, and reduced emissions.”

With the review’s final version set to be delivered to the Commonwealth government in the coming months, it remains to be seen whether federal energy policy will become similarly proactive in the future.


This article was written by Hugh Saddler [Honorary Associate Professor, Centre for Climate Economics and Policy, Australian National University]

 

The case for renationalising Australia’s electricity grid

Australia’s electricity grid is no longer fit for purpose

The public debate over the problems of electricity supply displays a curious disconnect. On the one hand, there is virtually universal agreement that the system is in crisis.

After 25 years, the promised outcomes of reform – cheaper and more reliable electricity, competitive markets and rational investment decisions – are further away than ever.

On the other hand, proposals to change the situation range from marginal tweaks to politically motivated mischief-making. The preliminary report of the Independent Review into the Future Security of the National Electricity Market, released last year, canvasses such options as the introduction of capacity markets for reserve power, which have done little to resolve problems overseas.

Meanwhile, the Turnbull government has used recent failures to score points against renewable energy (hated, for obscure historical-cultural reasons, by its right-wing base) and to promote the absurd idea of new coal-fired power stations.

A sorry state

This debate might make sense if the system had worked well in the past. In reality, however, the National Electricity Market (NEM) never produced lower prices or more reliable power for households.

In the early years of the NEM, reductions in maintenance spending concealed this failure. When new investment became necessary in the early 2000s, the result was a dramatic upsurge in prices. This was primarily because the NEM regulatory system allowed rates of return on capital far higher than those needed to finance the system under public ownership.

Until the 1990s state governments owned and controlled Australia’s electricity grids from power stations to poles and wires. The expansion of interconnections between state networks created the possibility of a truly national network. The Commonwealth and the states could have jointly owned such a network, following the highly successful model of Snowy Hydro.

The creation of the NEM broke this system into pieces. Ownership of generation was separated from transmission, distribution and retail, while maintaining effectively separate state systems. The only national component was at the regulatory level, where two separate national regulators (the Australian Energy Market Operator and the Australian Energy Regulator) overlap with the continuing regulatory operations of state governments.

Most state governments have sold their electricity enterprises wholly or partly. Victoria and South Australia fully privatised their systems by the early 2000s. NSW partially privatised its network business after 2015. Queensland privatised the retail sector but maintained public ownership of the network and some electricity generation.

Contrary to the hopes of the market designers, breaking up these integrated systems has delivered no benefits, while incurring huge costs. Power prices have continued to rise.

These costs have been on display, in dramatic form, in recent system failures in South Australia, Victoria and Tasmania. Everyone has blamed everyone else, and no real change has emerged.

The tragedy is that all this could have been avoided if we had seized the opportunity in the 1990s to build a unified national grid, with a single authority running transmission networks and the interconnectors between them. This would still allow competition in generation, but would abandon the idea of market incentives in the provision of network services.

Electricity networks are considered to be natural monopolies. Unlike other industries, where it makes sense for lots of businesses to compete and drive costs lower, the cost and importance of supplying electricity means it make sense for one business to control the market.
Given this status, this authority should not be a privatised firm or even a corporatised government enterprise. Instead, it should be a statutory authority with a primary mission of delivering energy security at low cost.

This failure was not confined to electricity. Our telecommunications network was also privatised in the 1990s, with the promise that competition would deliver better services. In reality, investment and innovation stagnated. It got to the point where the government was forced to re-enter the market with the National Broadband Network (NBN).

As the NBN example suggests, unscrambling the egg of failed reform will be a complex and messy business. It will have to be done gradually, perhaps beginning with South Australia and Tasmania, the states worst affected by recent disasters. But there is no satisfactory alternative.
Public appetite, lack of political will

An obvious question is whether renationalising the electricity network is politically feasible. While the political class on both sides views privatised infrastructure as an unchallengeable necessity, the general public has a very different view. With only a handful of exceptions, voters have rejected privatisation whenever they have had a chance to do so.

The question of reversing past privatisations is more difficult, and there is less evidence. However, none of the privatisations of the reform era, even those that took place decades ago, commands majority support in Australia.

The question has been addressed by pollsters in Britain, which provided the model for Australia’s energy reforms. The results show overwhelming public support for renationalisation, even though the electricity industry has been in private ownership for decades. Even a majority of Conservative voters support public ownership.

The issue will have its next electoral test in Western Australia, where the Barnett government is proposing to sell its majority interest in its electricity distribution enterprise Western Power. While nothing is ever certain in politics, current polls suggest the government is headed for defeat.


This article was written by John Quiggin
[Professor, School of Economics, The University of Queensland]

Australia’s electricity market is not agile and innovative enough to keep up

The rules were written at a time when coal and gas were the only major options

On the early evening of Wednesday, February 8, electricity supply to some 90,000 households and businesses in South Australia was cut off for up to an hour. Two days later, all electricity consumers in New South Wales were warned the same could happen to them.

It didn’t, but apparently only because supply was cut to the Tomago aluminium smelter instead. In Queensland, it was suggested consumers might also be at risk over the two following days, even though it was a weekend, and again on Monday, February 13. What is going on?

The first point to note is that these were all very hot days. This meant that electricity demand for air conditioning and refrigeration was very high. On February 8, Adelaide recorded its highest February maximum temperature since 2014. On February 10, western Sydney recorded its highest ever February maximum, and then broke this record the very next day. Brisbane posted its highest ever February maximum on February 13.

That said, the peak electricity demand in both SA and NSW was some way below the historical maximum, which in both states occurred during a heatwave on January 31 and February 1, 2011. In Queensland it was below the record reached last month, on January 18.

Regardless of all this, shouldn’t the electricity industry be able to anticipate such extreme days, and have a plan to ensure that consumers’ needs are met at all times?

Much has already been said and written about the reasons for the industry’s failure, or near failure, to do so on these days. But almost all of this has focused on minute-by-minute details of the events themselves, without considering the bigger picture.
The wider issue is that the electricity market’s rules, written two decades ago, are not flexible enough to build a reliable grid for the 21st century.

Vast machineIn an electricity supply system, such as Australia’s National Electricity Market (NEM), the amount of electricity supplied must precisely match the amount being consumed in every second of every year, and always at the right voltage and frequency. This is a big challenge – literally, considering that the NEM covers an area stretching from Cairns in the north, to Port Lincoln in the west and beyond Hobart in the south.

Continent-sized electricity grids like this are sometimes described as the world’s largest and most complex machines. They require not only constant maintenance but also regular and careful planning to ensure they can meet new demands and incorporate new technologies, while keeping overall costs as low as possible. All of this has to happen without ever interrupting the secure and reliable supply of electricity throughout the grid.

Until the 1990s, this was the responsibility of publicly owned state electricity commissions, answerable to their state governments. But since the industry was comprehensively restructured from the mid-1990s onwards, individual states now have almost no direct responsibility for any aspect of electricity supply.

Electricity is now generated mainly by private-sector companies, while the grid itself is managed by federally appointed regulators. State governments’ role is confined to one of shared oversight and high-level policy development, through the COAG Energy Council.

 
This market-driven, quasi-federal regime is underpinned by the National Electricity Rules, a highly detailed and prescriptive document that runs to well over 1,000 pages. This is necessary to ensure that the grid runs safely and reliably at all times, and to minimise opportunities for profiteering.

The downside is that these rules are inflexible, hard to amend, and unable to anticipate changes in technology or economic circumstances.

Besides governing the grid’s day-to-day operations, the rules specify processes aimed at ensuring that “the market” makes the most sensible investments in new generation and transmission capacity. These investments need to be optimal in terms of technical characteristics, timing and cost.

To borrow a phrase from the prime minister, the rules are not agile and innovative enough to keep up. When they were drawn up in the mid-1990s, electricity came almost exclusively from coal and gas. Today we have a changing mix of new supply technologies, and a much more uncertain investment environment.

Neither can the rules ensure that the closure of old, unreliable and increasingly expensive coal-fired power stations will occur in a way that is most efficient for the grid as a whole, rather than most expedient for individual owners. (About 3.6 gigawatts of capacity, spread across all four mainland NEM states and equalling more than 14% of current coal power capacity, has been closed since 2011; this will increase to 5.4GW and 22% when Hazelwood closes next month.)

Finally, one of the biggest drivers of change in the NEM over the past decade has been the construction of new wind and solar generation, driven by the Renewable Energy Target (RET) scheme. Yet this scheme stands completely outside the NEM rules.

The Australian Energy Markets Commission – effectively the custodian of the rules – has been adamant that climate policy, the reason for the RET, must be treated as an external perturbation, to which the NEM must adjust while making as few changes as possible to its basic architecture. On several occasions over recent years the commission has successfully blocked proposals to broaden the terms of the rules by amending the National Electricity Objective to include an environmental goal of boosting renewable energy and reducing greenhouse emissions.

Events in every state market over the past year have shown that the electricity market’s problems run much deeper than the environmental question. Indeed, they go right to the core of the NEM’s reason for existence, which is to keep the lights on. A fundamental review is surely long overdue.

The most urgent task will be identifying what needs to be done in the short term to ensure that next summer, with Hazelwood closed, peak demands can be met without more load shedding. Possible actions may include establishing firm contracts with major users, such as aluminium smelters, to make large but brief reductions in consumption, in exchange for appropriate compensation. Another option may be paying some gas generators to be available at short notice, if required; this would not be cheap, as it would presumably require contingency gas supply contracts to be in place.

The most important tasks will address the longer term. Ultimately we need a grid that can supply enough electricity throughout the year, including the highest peaks, while ensuring security and stability at all times, and that emissions fall fast enough to help meet Australia’s climate targets.

This article was written by Hugh Saddler

[Honorary Associate Professor, Centre for Climate Economics and Policy, Australian National University]