Wholesale electricity prices have doubled across Eastern Australia in the past couple of years, and the electricity sector is under a lot of pressure to do something about it. In response, generators often say that they would like to construct new capacity or upgrade old generators – but not without greater certainty about the future climate policy framework they face. What are they on about?
What electricity investors know
Electricity supply and energy intensive industries are capital intensive and involve assets with multi-decade lifespans. Many factors will shape the return these assets provide to investors, but the design of the electricity market and of climate policy are fundamentally important. Currently investors know:
- Australia has significant emissions reduction commitments that are likely to deepen. The Commonwealth has pledged to reduce emissions to 26-28% below 2005 levels by 2030, and has signed the Paris Agreement which aims to achieve global net zero emissions in the second half of the century. The Governments of New South Wales, Queensland, South Australia, Tasmania, Victoria and the Australian Capital Territory have committed their jurisdictions to achieve net zero emissions by 2050.
- The electricity sector, as a significant current source of emissions and a potential enabler of decarbonisation in transport and other sectors, will play a critical role in efforts to achieve these ambitions.
- There are many possible policies for reducing emissions in the electricity sector, and they may have sharply different impacts on individual assets or technologies. An existing, upgraded or new coal generator might face sharply higher operating costs under a carbon price or Emissions Intensity Scheme (EIS), or no penalty (or even some revenue) under a Clean Energy Target (CET). An existing wind generator might benefit from higher electricity prices under a carbon price, or payments from dirtier generators under an emissions intensity scheme – but under a CET it might be ineligible for support while facing suppressed wholesale electricity prices.
- Every Federal election since 2007 (and most of the State elections) has threatened or delivered a fundamental reversal of the major energy and climate policies of the incumbent government.
- The current Coalition Commonwealth Government has not yet agreed policies to achieve its long-term targets, but has considered or developed elements of absolute electricity sector emissions limits, best practice performance standards for new generators, an EIS and a CET. The current Labor Opposition has in recent years advocated a cap and trade emissions trading scheme and an EIS, and is now signalling potential openness to a CET. The States have variously advocated, considered or implemented emissions intensity schemes, clean energy targets and contract-for-difference renewable energy auctions.
So substantial climate policy looks inevitable for the electricity sector. But it is totally unclear what exactly that policy will be. Nearly all recent investment has been driven by the current Renewable Energy Target, which will top out in 2020. Any investment in new energy assets beyond the RET looks risky until the future policy framework becomes clearer – as we’ll explore below.
Doing the sums on a new power plant
AGL Energy has announced plans to close the badly ageing Liddell coal-fired power station in 2022 – a decent amount of notice to the market. The plant has two gigawatts (GW) of capacity, though it has operated at less than half of that on average in recent years. Suppose an investor with a cool few billion was interested in replacing Liddell. Before taking the plunge they would try to estimate the return they might make under a range of plausible scenarios. My chart (see below) illustrates – in the roughest, near-enough-is-good-enough way – some of what they would see: a wild spread of possibility from goldmine to bloodbath, with the key variables totally out of their control.
Some explanation follows, but first a warning. This chart is useful for comparing how different policy scenarios change the investor value for different generation options – ‘high efficiency low emissions’ (HELE) black coal plants, combined cycle gas turbine (baseload gas) plants, onshore wind farms and large scale solar farms. It is not adequate for assessing which technologies are actually the most attractive to investors or useful to the power system. It doesn’t incorporate any costs for ‘firming’ variable renewables, or risk premiums and difficulties achieving frequent dispatch for coal, or the practicalities of acquiring large volumes of additional gas to fuel a large new power station. Important as these issues are, they don’t need to be addressed to establish the impact of policy on the value of a potential investment.
The assessment is pretty simple.
- Each assessment is based on a power plant big enough to replace the annual energy production of a 2 GW coal plant operating at high capacity. That translates to 2GW of coal and gas capacity, 4.5GW of wind capacity, and 7.2GW of solar capacity.
- Each technology has an assumed underlying cost to build and run it, levelised over its lifetime. For black HELE coal and baseload gas I’ve used the midrange of cost estimates from the 2015 Australian Power Generation Technology report, around $80/MWh; for renewables I’ve used the contracted costs of recent actual Australian projects (around $60/MWh for wind and $70/MWh for large scale solar).
- An additional carbon cost is imposed in some policy scenarios – see the descriptions below.
- Each technology makes money from selling power into the wholesale market, at prices that vary by policy scenario.
- An additional stream of carbon revenue is available in some policy scenarios.
- Total costs are subtracted from total revenue each year over a thirty year assessment period.
- Future costs and benefits are discounted back to a net present value using a 7% discount rate.
The chart depicts the net present value of generation investments under eight policy scenarios:
- Policy uncertainty. There is no climate policy for the electricity sector, but nor is there a definitive resolution never to have such policies. Wholesale electricity prices remain fairly high due to a lack of investment (as modelled by Jacobs for the base case of the Finkel Review).
- CET 28%. A Clean Energy Target is tuned to deliver a 28% reduction in electricity sector emissions by 2030. The scheme suppresses wholesale electricity prices somewhat due to extra supply and the availability of scheme revenue. Dirty generators face no penalty but new clean ones earn certificate revenue. Price assumptions for wholesale electricity and clean energy certificates are taken from the Jacobs modelling for the Finkel Review CET scenario.
- CET 2C. The scheme is tuned to deliver a deeper emissions cut consistent with a global 2C goal. Similar to B but with more deeply depressed wholesale electricity prices and higher certificate prices. Assumptions taken from Jacobs modelling of a Low Emissions Target for the Climate Change Authority.
- CET 28% ineligible. This scenario is the same as B, but the new plants considered are all ineligible to receive clean energy certificates regardless of their emissions intensity. Generators built prior to the start of a CET are likely to be excluded. There could be a significant gap between 2020, when the current RET targets top out, and the commencement of a CET delayed by political disagreement. Generators built in the gap time would face suppressed wholesale electricity prices without being eligible for offsetting revenue.
- CET 2C ineligible. Same as D but for the more ambitious CET described in scenario C.
- Carbon price 2C. An ambitious carbon pricing scheme consistent with a global 2C goal, with carbon and wholesale electricity prices as modelled by Jacobs for the Climate Change Authority. Generators face carbon costs in line with their emissions.
- EIS 28%. An emissions intensity scheme is tuned to deliver a 28% reduction in electricity sector emissions by 2030. Generators who are above an intensity baseline have to buy credits from generators who are below the baseline. Wholesale and credit prices are as per the EIS scenario in Jacobs’ work for the Finkel Review.
- EIS 2C. The scheme is tuned to deliver a deeper emissions cut consistent with a global 2C goal. Wholesale and credit prices are as per the Emissions Intensity Target scenario in Jacobs’ work for the Climate Change Authority.
Here’s how all these factors shake out. Remember, we’re looking at how the value of a given project changes under different policies, not how the value of different technologies compare.
A HELE black coal plant looks roughly value-neutral in a scenario of continued policy uncertainty. But under a moderately ambitious CET or EIS, operating that plant at high capacity for 30 years would mean losing $2 billion – or $5-$7 billion under more ambitious schemes – even under Clean Energy Targets with no penalty for coal. While there are other barriers to investment in new coal-fired power stations, the scale of losses under any policy scenario makes investment unlikely in the absence of expensive and likely non-credible government guarantees and assistance (for more on what such guarantees could look like, see this recent Ai Group working paper).
A baseload gas plant varies widely in expected value depending on policy. It could be value-neutral under policy uncertainty, or be worth a little more than $1 billion under a moderate CET or an ambitious EIS. But under all other scenarios it loses money – worst of all if it is ineligible for certificate issuance under an ambitious CET. Thus while relatively clean baseload gas is flexible and could play a very helpful role in securing the grid as renewables grow, new builds are very risky without confidence in the exact nature of future climate policy.
Wind and solar plants could do very well under most policy scenarios (noting that the costs of ‘firming’ renewables are not incorporated here). But returns would be slashed or significantly negative if there is a CET from which the wind farm in question is excluded. Thus even though wind could do very well in a ‘no policy’ scenario, investors are very unlikely to build any capacity that falls outside the RET without clarity on future policy.
A bet on just one of these policy scenarios – from ‘no policy’ to ‘ambitious carbon price’ – would be brave indeed.
Governments have largely got out of owning and running power stations, and getting back into it in a big way would require substantial shifts in public finances well beyond the likely public appetite. It is private investors who will have to pony up most of the cash to get new power stations built. And right now there is no business case for investing in anything outside the current RET other than small flexible peaking capacity.
Meanwhile more than 5 gigawatts of coal-fired generation has closed in the National Electricity Market since 2010, of which Hazelwood accounts for just 1.6GW. Liddell is likely going in 2022. The electricity market has gone from surplus to risks of supply inadequacy during summer peaks. This tightening has increased the role of gas-fired generation in setting prices just as fuel prices for those generators have surged. The combination of a tighter market and more expensive gas appears to be the driver of the enormous increase in wholesale electricity prices and futures. New investment in electricity generation, networks and usage (including efficiency and demand response) can ease the tight market and help lower prices.
This is why the electricity sector is so vocal about policy certainty. Unless governments can deliver some kind of policy that investors can take seriously, we are not going to get the investment we need. Prices will remain bad, reliability will decline, and emissions will likely rise. We should expect better.
How important do you think policy certainty is to get new electricity investment? And what should policy look like? Share your thoughts and start a conversation by leaving a comment below.
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