The recent focus on retail electricity price rises has obscured the big story being played out in the wholesale electricity market.
With demand falling, wholesale prices are collapsing and governments should be wary of rent seeking while the market plays its hand.
National wholesale prices have fallen by 20 per cent in each of the last 2 years. Adjusted for inflation, they are now a staggering 30 per cent lower than any time prior to 2011.
NEM-wide volume weighted prices (left) and traded revenues (right) for 12-month periods to the end of autumn, adjusted to 2012 dollar terms. Ignoring the two anomalous years of 2000/01 and 2007/08, the mean adjusted price up until 2008 was $47 per megawatt hour (blue line on left). Projected revenues for observed 2000-2008 demand growth and mean adjusted price shown in blue light on the right.
Although wholesale electricity prices are notoriously volatile, such changes are unprecedented. Spot prices can range from negative $1,000 to as much as $12,500 for every megawatt hour. Across the national market, daily revenues can range from less than $10 million to as much as $800 million.
Despite this, wholesale prices have proved fairly stable when averaged across 12 month periods. For most of the last decade, annual prices have been close to the average of $47 per megawatt hour when adjusted for inflation.
The big exception was 2007/08 when prices rose to 70 per cent above trend, partly because severe drought conditions impacted the generation capacity. With a windfall of around $6 billion for the year, the power generating utilities must have been delighted.
History now shows any such joy was premature. Since 2010, wholesale prices have collapsed. The average price for the 12 months to the end of autumn this year was just $29 per megawatt hour. Market revenue was down a staggering $3.5 billion on expected revenue for the actual demand, and an incredible $5 billion on forward demand projections. Wholesale prices are now down to 37 per cent of 2007/08 prices.
Revenue deficits as a function of actual demand (left) and 2008 projected demand (right), assuming average price of $47 per megawatt hour. Green lines show the revenue deficits as a consequence of the actual and projected power deficits over 4 years since 2008 in terms of dollars per watt-year ($1 per watt-year is equal to about 11 cents per kilowatt-hour.)
On a seasonal basis, summer prices have fallen the most, by more than 50 per cent, partly due to the few extended heat waves during the recent La Nina weather cycle. However, with winter, spring, and autumn prices also down some 30-35 per cent, weather is just a minor factor in driving prices down.
The key factor is an unexpected decline in demand and to understand why we need only look back a few years.
From the time the national market was established in 1998 until early 2008, the demand for electricity traded on the market grew consistently at about 2.7 per cent each year. By 2008 it seemed inevitable we would need another 2.5 gigawatts of supply to meet projected 2012 demand. Put in context that is the equivalent of two big new coal-fired power stations, about 8 gigawatts of installed wind power capacity or 14 gigawatts of PV.
Most pundits saw a stalling of growth in 2008/09 as a minor hiccup due entirely to the global financial crisis. As recently as 2010 the industry expected demand would return to trend growth as the economy recovered. But even then the market was proving them wrong.
NEM wide average demand in gigawatts (left) and as a deficit relative to projected growth based on the 2.7 per cent average annual growth rate recorded between 2000 and 2008 (right).
In 2009/10, demand fell in real terms by 140 megawatts, in 2010/11 by 250 megawatts and in the last 12 months by 480 megawatts. Compared to 2008, demand is now down by 930 megawatts, or almost 4 per cent. Compared to the forward projections of just four years ago, demand is down by a whopping 3.5 gigawatts or 14 per cent. That is the equivalent of three big power stations we thought we would need, but no longer do.
Demand is falling because of a range of factors.
Energy efficiency programs are biting. Distributed generation such as PV is taking share from the market and there is growing awareness amongst consumers that we can reduce energy consumption significantly with little effort or discomfort, and save money. In the face of rising retail prices, we are finally seeing some pricing elasticity.
From the point of view of the market it doesn’t matter what the cause, the impact is the same. With significant oversupply the market is doing exactly what it is designed to. It is sending a price signal to reduce supply.
In fact, using the figures quoted above we can easily quantify just how the market values the excess supply. With revenues down $3.5 billion, and projected demand down 3.5 gigawatts, the market is valuing a demand reduction of 1 watt on expectation at $1 over the year. That is equivalent to 11.5 cents for each kilowatt-hour of saving, or a multiplier of 2.5 on the long-term wholesale price.
That is a very strong price signal and one that helps quantify the value of some recent government clean energy schemes.
The much maligned $1.4 billion ‘pink batt’ scheme has helped reduce electricity demand by about 200 megawatts, giving a net saving of about $200 million on wholesale revenues this year over and above the avoided energy consumed. A 15 per cent effective annual rate of return on investment is pretty remarkable in the current economic climate and surely must put it in the running for one of the best ever investments by an Australian government.
The price signal also gives us a way to calibrate incentives for schemes that contribute to the reduction in market-traded demand through small-scale distributed production, such as feed-in-tariffs. Adding the wholesale value of such distributed generation (2.9 cents) to the demand reduction impact (11.5 cents), gives us a reference feed-in-tariff of about 14.4 cents per kilowatt hour. Set lower than this, then the feed-in-tariff should have benefited all consumers, independently of any other considerations such as emissions reduction. This puts paid to the notion that feed-in-tariffs are necessarily a regressive form of taxation. It all depends on the level.
Only recently have our utilities started to acknowledge there will be no need for further base-load generation until about 2020. Not surprisingly, they are not yet publicly acknowledging the market signal to shed about one gigawatt of existing base-load capacity.
Why would they? If demand continues to decline on the post-2008 trend of 1 per cent each year, it will put further downward pressure on already catastrophically low wholesale prices. That is hardly a message to encourage financiers. Small wonder that utilities rarely baulk at the chance to talk down incentives that will further reduce demand, such as domestic PV.
And then there is the government’s commitment to supply ‘contracts for closure’ for two gigawatts of coal-fired generation by 2020. Framed on the expectation that demand must inevitably grow, it is a policy that is already out of touch with reality. The utilities must be rubbing their collective hands with glee at the chance of socialising any remaining debt for assets the market has already rendered essentially worthless.
With the current prices there will be much debate about how well the wholesale market is serving us. There are questions about how much, if any, of the reduction in wholesale prices are being passed through to consumers.
In the meantime, don’t be surprised if generators start advocating the need to change the wholesale market design. Indeed, there are already murmurings about changing from the current energy-only market to a capacity market.
The pretext will be about preserving energy security, and while security is important government should be a bit skeptical about any apparent outbreak of altruism. After all, history records that generators have not been too strong on the idea of upgrading interstate interconnect capacity as a way to ensuring security.
Having experienced the good times of undersupply in 2007/08, generators are now feeling a pinch to their bottom line. That they failed to predict the oversupply is a business risk, and has little to do with failings in the current market design. Still it wouldn’t surprise if the generators were to engage in a bit of rent seeking to relieve their pain.
That’s not to say the wholesale market doesn’t warrant some reform. As a regulated market it is required to do a range of things, from protecting consumers from excessive prices, to ensuring a stable, secure and environmentally benign supply of electricity. And all the while providing appropriate incentive for investment to meet future needs. This is not a trivial task.
The existing wholesale market has done well on most of these issues with the obvious exception of the environmentally benign bit, as we now understand it. The need for investment is not now about capacity, but about emissions. With wholesale prices at rock bottom due to oversupply, an energy-only market will provide no incentive for any investment in generation, let alone for the key technologies that could significantly impact emission intensity, such as nuclear, renewables or CCS. Notwithstanding the implementation of a carbon price, the redesign of the market to best facilitate such investment will be an ongoing challenge.
In the face of rising retail prices and the toxic debate about the carbon tax, the political rhetoric on electricity prices has missed a great news story now being played out on the wholesale market. In an expanding economy, falling electricity demand means a reduction in energy intensity. Even if it leads to some short-term hardship for, and inevitable rent seeking by, our utilities, the energy markets are telling us that in energy terms we are now producing more from less.
As a key to the challenge of boosting national productivity, that is surely a story that warrants bipartisan applause.
Professor Mike Sandiford is the Director of the Melbourne Energy Institute at the University of Melbourne.