Government intervention in energy markets has grown in recent years, with winners chosen potentially at the expense of consumers.
The debate over Resources Minister Keith Pitt’s decision to reject a $280 million concessional loan for a renewable power project in Far North Queensland highlights how economics and politics can clash.
There was a political backlash against the March decision to decline support through the Northern Australia Infrastructure Facility for French proponent Neoen’s Kaban wind and battery project in the Atherton Tablelands.
But one question which remained unresolved is why Neoen sought the government’s bankrolling of the project, given it proceeded with construction without it in May.
The $373 million development will include a 157-megawatt wind farm and a 100MW battery, with a $40 million transmission line built by Queensland’s government-owned network business, Powerlink Queensland.
The politics and media discussion focused on the federal government’s rejection in the context of significant cash being pumped into the gas industry.
On the economic side, there are two conclusions.
One is that renewables are becoming competitive.
The other is that Neoen’s shareholders would have benefited from taxpayer largesse without any appreciable environmental benefit, given they are building the project anyway.
Neoen said it was unable to comment on the financials of the project. Kaban may not have secured taxpayer funding but there’s no doubt public money is being shovelled towards energy.
About $1 billion was promised for hydrogen production and carbon capture and storage, while changes to lending regulations for the Australian Renewable Energy Agency were discussed and canned.
In May, the government announced its Snowy Hydro business would build a 660MW gas power plant in Kurri Kurri, NSW, costing $600 million.
The power station will fill some of the gap created by the retirement of the Liddell coal plant in 2023.
It will be a peaking station, turning on only when demand is needed.
Speaking at the time, federal Energy Minister Angus Taylor said the government had a 1,000MW target to fill the Liddell gap, with EnergyAustralia’s 316MW Tallawarra B plant contributing the remainder.
But the Kurri Kurri plant could end up supplanting AGL Energy’s own proposal for a nearby gas generator.
In AGL’s case, the company had reportedly delayed a decision because it conflicted with the NSW government’s energy roadmap in December.
That suggests contradictory positions by the federal and NSW governments may have led to a publicly funded gas plant instead of a private development, with taxpayers bankrolling the risk.
University of Western Australia research fellow Peter Hartley said the government’s decision was made to ensure reliability, although he added that government-run businesses were generally not efficient.
“The problem … there’s so much sovereign risk, so much political uncertainty about the electricity system,” Professor Hartley, who is also a chair of economics at Rice University in Texas, told Business News.
“That uncertainty is a deterrent to an investor. “I can see why the government would do it. “It’s not a first-best outcome by any means.”
The Australian Energy Council, which lobbies for the industry, warned against the federal government’s proposal to build a new gas plant when it was floated in September.
Government interventions, or discussions and threats of intervention, act as a deterrent to investment, the council said.
“The government’s earlier plan to underwrite new-generation projects in the market also remains under consideration, and this too contributes to the ongoing uncertainty, together with various and competing state-based renewable energy targets,” AEC chief executive Sarah McNamara said.
“There are no material reliability concerns that would warrant this kind of interventionist approach, and there are already mechanisms in place to address any shortfall identified.
“The Australian Energy Market Operator’s most recent assessment identified a potential shortfall in NSW of only 154MW.”
An ongoing lack of investment in generating capacity contributes to reliability problems and price rises.
Going up
Government intervention in energy markets has increased in recent years, reversing the privatisation and deregulation drive of the 1990s.
At the federal level, that initially included the Renewable Energy Target, two green banks, and a variety of proposed schemes to reduce carbon emissions.
That involvement has grown even further in recent years. Measures included the ‘big stick’ power to break up electricity businesses, the Underwriting New Generation Investments program, and the gas-fired recovery proposals (see table).
Mechanisms vary from subsidies to targets or mandates, and government businesses making investment decisions that may otherwise have been made by private capital.
The two green financiers, Clean Energy Finance Corporation and the Australian Renewable Energy Agency, have been used for an increasing array of purposes.
While CEFC acts as a venture capitalist, ARENA offers grants, particularly to encourage new technology.
CEFC invested $410 million in WA projects in the 2020 financial year. A further $760 million was allocated to fund managers, including private equity.
A December report by the Australian National Audit Office said CEFC had facilitated increased funding into clean energy, although it said the extent was unclear.
The report said the corporation had failed to meet its mandated investment returns and had an unclear plan to do so.
It’s also not clear if use of concessional loans, or the projects that win the support, are the most cost-efficient way to reduce emissions.
The audit report cited two projects – a wind farm and a property fund – with wildly different carbon abatement returns compared to their cost of capital.
And the report highlighted the momentum already behind renewable projects without public financing.
“Investment in large-scale renewable energy projects increased significantly between 2016 and 2019… completed almost entirely by the private sector,” the report said.
“The large-scale market has matured significantly during this period; there is now less demand for the CEFC to provide project finance for these projects as the private sector is directly contributing more finance.”
The Productivity Commission raised concerns about growing use of public financiers such as NAIF and the CEFC in its 2019 Trade and Assistance Review.
“Although the incremental changes are small, the continued growth and development of project financing vehicles has the strong potential to distort the allocation of resources, as well as imposing hidden costs to taxpayers through non-repayment risks and concessional financing subsidies,” the commission said.
Proponents of otherwise profitable projects draw the benefit from the concessional financing, as it adds to their return on investment with no additional emissions impact.
Competitiveness
Critical in the debate over which, if any, projects need support is determining the lowest-cost energy sources. Views differ depending on assumptions.
US investment bank Lazards estimated in 2020 that renewables were competitive with conventional generation in some circumstances, with wind power the best performer.
CSIRO found a similar result. Both assessments, however, are for new build projects, with fully depreciated coal plants usually cheaper.
Reported numbers sometimes don’t consider associated storage costs and the impact on reliability, either.
The argument behind the National Energy Guarantee was that renewable generators should not pass on costs to other generators by affecting network reliability, while fossil fuel generators should be responsible for their emissions.
Intermittent renewables wind and solar put pressure on coal generators, which are not designed to cycle output flexibly but are useful for keeping suitable inertia on the grid.
Professor Hartley has made some calculations based on the lowest cost way to produce emissions-free power in the Texas market, which are a useful guide.
His work found nuclear power and storage was cheaper than wind backed by storage, although wind with gas generation could be cheaper still.
“Roughly speaking, [grids need] twice as much storage capacity for wind as they do nuclear,” Professor Hartley told Business News.
“Wind is cheaper than nuclear, but the problem is storage needs are more expensive.”
That’s because storage is required to balance supply and demand for wind, while nuclear generation is baseload and only requires backup when demand peaks.
Another factor that would complicate analysis was seasonal variation in wind levels.
“If you’re willing to allow gas into the system, even 10 per cent gas could make a difference to the cost,” Professor Hartley said.
Research on the German market had found similar outcomes, he said.
Yandin wind farm in the Mid West. Photo: Gabriel Oliveira
Another challenge for renewables was that while short-term marginal costs were extremely low, renewable generators would typically be on or off at the same time, because they were driven by weather, which impacted their ability to earn revenue.
Professor Hartley said power markets would require better mechanisms to account for these challenges.
Andrew Pickford, who is completing a doctorate at UWA on the history of energy markets in WA, said the use of subsidies or guarantees as a mechanism to drive outcomes in power markets had negative consequences.
One consequence, he said, was that inefficient decisions were locked in for the long term, while another was that they often resulted in higher costs for consumers.
“Subsidies are incredibly popular and create a focal group with a self-interest in perpetuating the arrangement,” Mr Pickford said.
“When considering a proposed subsidy arrangement for a specific environmentally acceptable energy source or technology [EVs or solar panels], the life cycle measurement of emissions should be the metric that is applied to the decision-making process.”
The outcomes often benefited wealthier consumers the most, with Business News recently reporting that household battery uptake had been far greater in the western suburbs of Perth than elsewhere.
“Supporting residents in Nedlands to buy Teslas may not necessarily be the best economic or environmental policy when less visible options are compared,” Mr Pickford said.
Alternative options, such as buying abatements for emissions, might attract less political popularity but could achieve greater carbon reductions for a lower cost, he added.
Solar
The WA government released its Whole of System Plan last year.
It suggests coal power will continue to operate at Collie for the foreseeable future, with one source telling Business News the newest Collie generator was the lowest-cost power producer in the state.
The plan also suggested a new gas plant could be needed north of Perth as early as 2024.
About 384,000 households in WA have installed rooftop solar, about 13.7 per cent of the national total.
That huge uptake of photovoltaic panels has reduced emissions and helped some households lower their power bills, but it’s not clear it is the lowest cost way to reduce carbon.
The panels have created voltage control issues on the grid and their variable output means coal generators wear an added cost by ramping up and down to keep supply in balance.
The grid challenges require extra capital investment for Western Power, while Synergy has incurred a cost through the effect on its coal fleet.
Professor Hartley said households faced a different calculation for installing solar compared to utilities.
About half the cost of providing power to a customer is from the transmission and distribution network, a fixed cost that does not change regardless of use.
But consumers have a low fixed connection cost and are mostly charged on a variable rate. All of that incentivises rooftop solar.
“People are being sent a signal that they’re saving, but they aren’t … someone else has to pay for it,” Professor Hartley said.
“If you generate more than you want you get to sell it back … [previously] with a premium.”
Mr Pickford said support for rooftop solar had initially been a lower-cost mechanism to bring on renewable capacity, which had since grown substantially.
And the cost was spread across the entire electricity user base, he said.
Similarly, large-scale renewables had an implicit subsidy because they could spill costs over to other generators, Mr Pickford said.
In a bid to reduce the generous incentives for rooftop solar, the WA government closed off the Renewable Energy Buyback Scheme last year, replacing it with a Distributed Energy Buyback Scheme, which pays at a different rate in peak times.
There are other hidden transfers in the WA network.
The Tariff Equalisation Contribution is collected from metropolitan consumers to lower prices for regional customers.
There has also been an intermittent campaign to reduce subsidies for Synergy, to better reflect costs and discourage excessive consumption in a network largely fuelled by coal and gas.
The state government announced in May that household power prices would be frozen for the 2021 financial year and has declined requests to clarify if this will be through an increase in operating subsidy for Synergy.
Fossil fuel support
A report released by the Australia Institute earlier this year asserted there were $10.3 billion of spending and tax breaks by governments for fossil fuel industries in the 2021 financial year.
That appears to be substantially overstating taxpayer support, however.
The biggest on the list was the Fuel Tax Credits Scheme, projected to cost $8.1 billion in the year to June 2022.
The credit is subject of much debate.
Taxes on petrol are paid by the producer or importer, with the price generally passed on to consumers or motorists.
The tax is intended to raise revenue from motorists for road maintenance and construction. Manufacturers and businesses that use fuel for other purposes, such as operating vehicles on a mine site, receive the credit when their usage is not for public roads, and a partial credit for heavy vehicles.
One view is that fuel use produces emissions and should be taxed because emissions are an externality.
In contrast, federal Treasury and the Productivity Commission do not consider the rebate a subsidy, according to a briefing note from the Parliamentary Library, because the intention of the tax is to be a charge on road use.
The Henry Tax Review in 2009 gave the tax credit scheme the tick of approval, although it recommended replacement of fuel tax entirely.
Also on the Australia Institute’s list were alleged concessions through the Petroleum Resources Rent Tax, which was the subject of a 2017 review.
Treasury documents suggest some elements of this tax scheme are more generous than the ideal.
At a state level, a series of WA government spending items were labelled subsidies by the Australia Institute.
Thrown in the mix were maintenance costs for Synergy’s gas and coal generation fleet and new power projects in Esperance and Onslow, which would include construction of both gas and renewable generation.
Similarly, Fremantle Ports equipment and electrical upgrades, a new crane at Kimberley Port Authority’s Broome operations, and wharf works at the ports of Ashburton and Dampier were deemed subsidies by the Australia Institute.
But those investments are usually made on a commercial basis by the government’s trading enterprises, where costs are recovered from users.
It’s not clear why they would then be considered subsidies if they are decisions made in the normal course of business.
An item probably better labelled a subsidy is a concessional port charge for LNG-powered vessels refuelling at Pilbara Ports Authority jetties, worth $1.9 million.
All of that demonstrates the complexity of the debate.
Even if the level of taxpayer support is lower than widely reported, there’s one unambiguous benefit given to fossil fuels.
In Australia, there’s no charge for the industry’s emissions, even though such a mechanism is generally recommended by economists to counter the environmental impact.
That effectively means that the rest of society pays the cost of the pollution, rather than industry.
