Delivered by Keith Orchison to a Deloitte client lunch in Adelaide on 17 February 2009
In the years when I ran the Electricity Supply Association, I used to say frequently that the key issues for the industry could be summed up in two four-letter words.
Today, I think we need three four-letter words.
Time. Cost. Risk.
The one I have added is “risk” because I believe the risks in the industry are now at unprecedented levels as Australia grapples with a new energy future – not least because I believe governments and others are under-estimating both the time it will take to achieve the massive change required and the real cost of new model power supply system.
Of course, the risks are also that much greater because Australia and the rest of the world are grappling with the implications of economic and financial turbulence.
I agree with Lew Owens, chief executive of ETSA Utilities, that we have entered “an unprecedented period of complexity, change and uncertainty for the energy sector.”
In this environment, the Australian power sector must deliver some $100 billion worth of infrastructure development in 10 years to meet demand and to meet policy goals.
To put this in context, it is estimated that the current asset value of the industry, built up over decades, is $98 billion.
Here in South Australia, in generation, there is expected to be a substantial outlay on building wind farms to capture a significant share of the new renewable energy target.
Geothermal generation “wannabes” will continue to spend hundreds of millions on pursuing the path to project development and actual production. The expenditure to date is near half a billion dollars and this could be doubled in the next 10 years.
More gas-fired capacity will undoubtedly be required to keep ahead of peaking power demands.
When I joined ESAA in 1991 the peak load in this State was under 2,000 MW.
The last issue of the Energy Supply Association yearbook reported that the 2007-08 peak demand was pushing towards 3,000 MW and it forecast this would rise to 3,600 MW by 2016.
Well, as we now know, a peak of 3,300 MW was reached two days’ running at the end of last month – mirroring substantial rises across the border in Victoria and New South Wales.
Overall, across the national electricity market, demand on 28 January hit an unprecedented 34,483 MW and then rose even higher to 35,487 MW the next day.
This is about 3,000 MW higher than any previous demand spike in the NEM and required $3 billion worth of extra peaking power to be available.
This is the equivalent to Brisbane’s average load.
It was a major challenge and the NEM coped.
The industry and NEMMCo will need to rewrite their projections for peak power in the light of the serious heatwaves we have just experienced on the southern seaboard.
I think it is a given that the VoLL will rise from its present $10,000 per MWh cap to $12,500 – and that means the existing $300/MWh price cap that is imposed when the cumulative cost of wholesale power hits a pre-determined level will need to rise, too.
Here in South Australia, and across the country, the network service providers do not only need to spend to cope with demand growth; they also need to replace a substantial amount of ageing infrastructure, assets constructed in the 1950s and 1960s.
This is not work that can be put off.
Nor can it be done quickly – it is, at the very least, a task for the decade.
There will need to be capital invested in new transmission links from remote areas to the load centres – at least a billion dollars of the national $4.5 billion outlay that has been estimated to be needed for this purpose will be spent in South Australia on my reckoning.
South Australian spending on the distribution network will double in the five years to 2015, totalling $1.5 billion, subject to regulatory approval.
There will no doubt be complaints from various quarters about ensuing higher network charges and higher retail bills for consumers.
I note with interest that ETSA reports that distribution charges for the average home in this State have declined by 23 percent – in inflation-adjusted terms – over the past eight years and the distribution component of the average bill has fallen back from 50 percent to 35 percent.
Significant asset renewal means that comfortable situation – for consumers -- cannot continue.
In this context, there is a quote from last month’s report of the Western Australia Office of Energy to the new Barnett government -- in which they recommend large price increases after a decade-long freeze on retail prices -- that I believe should be written on the wall of every first minister and energy minister in the country: “It is not desirable to require electricity to be supplied at a price where its short-term and long-term reliability is unsustainable.”
Amen to that.
This point is central to the theme that I have been following across eastern Australia in the past week at these Deloitte lunches: there is a considerable need for the power sector to do more to bring home to the body politic, its advisers and the community through the media just how big the electricity infrastructure challenge now is – and how many uncertainties there are on the path to achieving national goals for supply security and reduced greenhouse gas emissions.
Let me touch briefly on just some of the areas of risk and uncertainty.
The generators across Australia will be required, it seems, to deliver three times as much new capacity in the next decade as they built in the one now ending – to meet higher consumption and to compensate for closure of carbon-constrained coal burning plant.
Can such large-scale development be delivered in a timely fashion?
What will be the ensuing wholesale price of power in the NEM?
For the coal generators, a critical issue is compensation for the introduction of emissions trading. They seek about $10 billion. The Rudd government has offered $3.9 billion.
The government’s decision late last week to send the ETS concept to the House of Representatives’ Economics Committee for a report in the second half of this year, of course, throws a whole new cloak of uncertainty over the process, re-igniting the entire debate of the past two years.
Moving down the supply chain, I note that the transmission sector says it will have to spend $16 billion over 10 years on augmentation and upgrading the high voltage network, assets currently worth $12 billion.
As I mentioned, this does not include what has to be spent to bring new, remote renewable power to the load centres.
The overall capex spend on networks, high voltage and distribution, is going to leap.
It averaged $2.5 billion annually in the past five years.
Subject to final regulatory approvals, it will average $4.5 billion in the next five – a rise of 77.5 percent – and probably be about $40 billion for the decade.
Then there is the issue of gas supply.
Under the scenarios for supply now contemplated, it can be expected that annual gas demand across southern and eastern Australia will double to about 400 petajoules by 2016 and reach 500 PJ by 2020.
The major uncertainty is what the wholesale price of gas will be?
On the one hand, very considerable coal seam methane resources keep being added to the Queensland reserves and there is a large, and largely untapped, resource in northern New South Wales.
There is also obviously still more conventional gas to be located and produced from offshore Victoria, while Cooper Basin reserves are in decline.
On the other hand, what will be the impact of development of a substantial gas export industry in Queensland, using CSM?
That eastern seaboard wholesale gas prices will go up seems pretty obvious – the multi-million dollar question is how high?
For would-be gas generators there are a number of other issues.
How far will the enforced growth of renewable generation crowd them out of the market?
How will the subsidies for high-emission coal plant affect development of new gas generation?
There are uncertainties, too, about how much open-cycle gas plant will need to be built to meet peak demand and whether it can be built in time.
The amount of time swallowed by inefficient approvals processes is just one of numerous regulatory problems that remain unresolved in Australian doemstic energy development – and, regrettably, the time taken by policymakers and their advisers to come up with efficient solutions is, if anything, getting longer,
For the pipeliners, there is the important issue of whether they will be able to recover the emissions trading permit costs of gas leakages from pressurised systems?
For all networks, the amount they can charge system users for the cost of their capital is of huge concern and a topic of high dissension between them and the Australian Energy Regulator in 2009.
For the energy retailers, the very big question is whether all the costs associated with carbon policy can be passed through to consumers, notably residential customers and small business.
The sums involved are very large.
My back-of-the-envelope calculation is that the decade-long extra cost for residential customers from emissions trading and the enlarged RET will in aggregate be about $8 billion.
Two Fridays ago, the Ministerial Council on Energy, meeting in Canberra, said it would recommend to first ministers that “all costs associated with carbon policy” be passed through to regulated customers.
However, this is a very political issue and we will have to wait and see the political response from the States.
Can you really envisage – instead of the propaganda we have seen of “only a dollar a day,” which is innacurate anyway – the next CoAG meeting announcing: “The cumulative electricity cost of carbon policies for Australian mums and dads is going to average $800 million over the next 10 years – and this is in addition to what you will pay for higher network charges and the costs of rolling out smart meters and, in all probability, substantially higher wholesale gas prices” ?
To which they would need to add that there will be similar cost burdens for small business, too.
In my view, the power supply industry should be forcing this disclosure. It should be in the marketplace spelling out in dollar terms – because percentage rises are meaningless to the community – what the policies and the capex outlays mean.
Not in order to scare people, but to ensure that Australians go in to this new electricity supply environment with their eyes wide open and that the industry can invest with confidence that the rug will not be pulled from under them when the real cost of decarbonising power becomes apparent.
The potential – I would go so far as to say certain – backlash down the track from surprised and angry users/voters is not just a political problem; it becomes a supplier problem when politicians panic and make bad decisions to allay community anger.
Meanwhile, it should not be overlooked that the pressures for retailers in this unprecedented time of transformation are very large.
In the Australian Energy Market Commission interim report on the impacts of carbon policies on energy markets – released on 23 December – there are two grave statements that should not be ignored:
Finally, for members of the renewable generation sector, the immediate prospect is obviously very good, but not without its risks.
The capex outlay to deliver the enlarged RET is estimated to lie between $20 billion and $30 billion between now and 2020.
A substantial share of that may well be spent in South Australia, and the rewards for successful developers are considerable.
I reckon the value of the RET subsidy alone – to which, of course, you add the market price for green supply retailers are required to buy – will be $12 billion over the period.
However, this outcome depends on the Rudd government’s target of 35,000 GWh a year of new renewable supply being reached in 2020.
The Clean Energy Council has complained this week that the draft framework of the RET legislation will see the 2020 production fall some 14,000 GWh short of the target – that’s a half billion dollar hit for the industry in 2020 alone.
As big an issue for the renewable generators is the impact of carbon constraining policies on demand growth, mainly rising consumption from what the Greens love to call “polluting industries.”
The 35,000 GWh new RET share of the 2020 market is based on a 60,000 GWh growth in demand. The AEMC actually notes that business as usual conditions would deliver demand for 70,000 GWh, requiring 8,000 MW of new capacity.
However, will the carbon costs and the general economic malaise we are now experiencing substantially depress demand?
In this context, it must be remembered that a third of all the power consumed in Australia is used by energy-intensive, trade-exposed manuafcturers, employing more than a million Australians.
The residential share is 28 percent.
The manufacturers’ power use represents some 75,000 GWh a year.
All the current estimates of the renewables target and green capex outlays are based on demand reaching 300,000 GWh in 2020 – will it?
The recent analysis published by the federal government, in fact, says that it will not.
In summary,the challenge we confront is easy to articulate but hard to meet: provide more, affordable, reliable electricity and fewer greenhouse gases.
We are on the brink of a decade of unprecedented change and complexity for the power industry, and the energy industries generally, in which the questions of time, cost and especially risk will loom very large.