Updated and corrected 4th April With a run of recent summers of below par temperatures, energy pundits have been eagerly awaiting a good summer heat wave to see just how our electricity system would stand up. The big question was what would happen when all those newly installed air conditioners finally got ramped up, once the la Nina cycle broke and we got a good roasting? Would a return to hotter conditions finally break the trend of declining electricity demand over the last four or five years?

Well it looks like we got the summer that would answer these questions, and the answers are no doubt causing a fair bit of head scratching amongst the pundits.

Since the last hot summer in 2010, our electricity system has seen a lot of changes. For one thing, almost 2 gigawatts of distributed generation has been added in the form of domestic solar PV. To put that in context, 2 gigawatts represents a touch under 10% of average summer demand, though of course solar PV only produces at near maximum levels for a few hours in the middle of a sunny summer day. However, when solar PV is producing it takes away from the demand for electricity that otherwise would be dispatched across the poles and wires via our National Electricity Market – or NEM.

So with this summer just past setting new records for extreme heat, it’s a good time to point the summer sun on the NEM and see how it is standing up.

With blistering summer heat, particularly across New South Wales and Queensland, there was an expectation we might see new records in peak demand. But despite the weather and the supposed new air-conditioning load, the NEM doesn’t seem to have been pushed very hard at all during this last summer.

In Queensland peak demand was the lowest in 5 years, down 360 megawatts on 2012 levels.

In New South Wales peak demand was up a massive 1.6 gigawatts from the previous summer but that was no great achievement, since the 2012 peak was the lowest since 2002. In fact the New South Wales peak this summer was almost 700 megawatts below 2011, and came in at only the third highest on record.

In Victoria, peak demand came in at 9.1 gigawatts, some 12% lower than the 2009 record of 10.4 gigawatts.

To put these numbers in context we need to take step back in time. Up until about 2008, peak demand was growing at around 3% each year. So back then the expectation was for peak demand to rise another 15% or so by 2013. In Victoria that meant planning for a 2013 peak demand of around 12 gigawatts, some 25% higher than we actually achieved.

The situation is not much different for average summer demand. In Victoria average demand was down 150 megawatts to levels not seen since before 2005. New South Wales was down 120 megawatts to levels not seen since before 2003. Queensland summer demand was up 30 megwatts on last year but still down 390 megawatts on the high of 2010, and was only the 4th highest average summer demand on record.

One obvious contributor to the general decline in demand for electricity dispatch by the NEM, and the lack of extreme peaks, is solar PV. Because domestic solar PV is used locally, it reduces demand for electricity dispatched by the NEM across the poles and wires. And because solar PV capacity has been ramped up so quickly, the way it is impacting is readily assessed by comparing this summer daily average demand profile to that of a few years ago. When we do so, the signal of solar PV becomes blindingly obvious, especially in South Australia and Queensland where the domestic solar PV penetration is highest.

As shown below, the parabolic day-time reduction in demand centred on midday is a strong signal of the way solar PV is impacting by cutting more than 10% off midday summer demand in South Australia compared with the summer of 2010. It is also skewing the average demand profile, making it more peaky in the late afternoon, as air-conditioning adds load while PV diminishes in output. It is also clear that solar PV has helped shave some of the peak load, which up until a few years ago was occurring at around 3 pm, and is now pushed back to lower levels, later in the afternoon.

In South Australia, where about one in four houses now have solar PV installed, there is still capacity for a lot more. It’s salient to ask what would happen to electricity demand if solar PV penetration reached 50% of houses. What it would do, as indicated in the Figure below, is take midday demand down to near the lowest in the 24-hour cycle, effectively creating a second off-peak demand regime.

Catering for two off-peak periods would make for a big change to our current thinking about how we supply affordable poles and wires electricity to meet the needs of just a few hours of high demand at the beginning and end of each day.

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Further notes added March 13, 2013

While the 2013 Summer has not pushed the NEM very hard despite warmer than average conditions, Autumn has begun to do so, at least in Victoria, where peak demand on March 12th reached almost 9.6 gigawatts. That is the sixth highest daily peak-demand on record in Victoria, and occurred on a midweek day (Tuesday) with a peak temperature of around 36.2, at the termination of a record run of nine days with maximum temperatures above 30 degree for Melbourne.

The plots below show some salient features.

The first plot below shows 2013 has (so far) the second highest Autumn peak demand recorded for Victoria (behind 2008). It is just the third time Autumn peak demand has exceeded the preceding Summer peak demand. It is however, the first time since 2000 that the Summer peak demand lagged both the preceding Spring and the following Autumn.

The second plot illustrates the way in which peak demand is changing as a function of daily maximum temperature (for Mondays through Fridays only) for the period January 15th through March. Up until around 2007, there was an increase in peak demand across all comparable temperature conditions. Since then there has been a marked reduction in peak demand on comparable cool working-weekdays. On comparable high temperature days, peak demand continued to grow until around 2010. Since then, peak demand has held relatively steady for comparable high temperature days. Of course, as highlighted in the comments to this piece, the peak demand is not just a function of daily temperature maximum, but also the time of year and week, and the temperature in the prior few days.

The CO2-emission intensity for electrical power production fueled by natural gas is about half that of coal. Consequently, natural gas is mooted as a potential transitional or bridging fuel to a cleaner energy future. In the local context, it is suggested Australia could meet its 2020 emission reductions targets simply by replacing a significant fraction of its coal-fired electrical power with gas. Doing so could provide additional benefits. For example, in halving the volumes of CO2 emitted per unit of electrical power, it would make the challenge of commercialising Carbon Capture and Storage significantly less daunting than for coal.

However, methane is a very much more powerful greenhouse agent than CO2. So significant leakage of methane during gas production and distribution would compromise its emission intensity advantage relative to coal. At timescales of 100 years, methane has a global warming potential around 30 times greater than that of CO2 [1]. Over a 20-year period the potential is more than 100 times higher than CO2.

The caveat on the coal to gas “clean energy” argument is that natural gas fugitive emissions are not significantly higher than those associated with coal mining, on an energy equivalent basis. For conventional gas technologies, fugitive emissions are estimated at about 2.5% of total production [2]. On an energy equivalent basis, that is about the same as the fugitive emissions expected from coal mining [2,3].

On that basis we would expect a coal to gas transition will eventually lead to a significant reduction in emissions, relative to the business as usual case. But the real question is how would it impact climate?

This question has been addressed by Tom Wigley [3], and the results are sobering. Wigley’s analysis indicates that:

1) any such cooling is likely to be very modest, amounting to only a few tenths of a degree cooling relative to business as usual over timescales of 100 years or more, and

2) long-term cooling will follow a period of about 40 years where cooling is more than offset by a warming penalty incurred by concomitant reductions in sulphur-emissions.

In emphasising the paradoxical complexity of the climate system, Wigley’s findings show that any climate benefit of a coal to gas transition is neither significant in sum, nor apparent in the near-term.

More worrying still is that this analysis is only appropriate for a transition that involves conventional gas resources. Because conventional gas resources are limited, the option that gas provides as a transitional fuel is more dependent on technologies that allow economic production from unconventional resources, for which the fugitive emissions profiles are poorly understood.

Developments in technologies such as horizontal drilling and “fracking” have opened a raft of unconventional resources, allowing commercial production from coal-seam gas, tight gas and shale gas resources. In the US, the Department of Energy predicts that by 2035 total domestic production will grow by 20%, with unconventional gas providing 75% of the total [4]. The greatest growth is predicted for shale gas, predicted to grow from 16% of total production in 2009 to 45% in 2035.

As noted earlier, because the global warming potential of methane is so high compared to CO2, any advantage of natural gas over coal in meeting emissions targets would be completely offset if fugitive emissions were as little as a few percent above the baseline of conventional resources. Consequently, the fugitive emission profile of unconventional resources is crucial to any prospect that natural gas can act as a route to meeting emissions targets, let alone positive climate outcomes.

The key issue is that the fugitive emissions profile for unconventional gas technologies is extremely poorly constrained. In a recent study, Howarth et al. [5] conclude that the fugitive emission profile of shale gas could be 3 times higher than for conventional gas. On the 20-year horizon, that would mean its greenhouse gas footprint could be as much as 100% greater than coal on an energy equivalent basis.

Not surprisingly, the Howarth study has been hotly contested. Industry advocates have been keen to debunk the risk. In another study, Hultman et al. [6] argue that fugitive emissions for shale gas are very likely only about 11% higher than those of conventional gas. However, in a salutory byline Hultman and coauthors are at pains to emphasise that ”it is extremely important to note that (their) results derive from uncertain estimates of fugitive emissions from unconventional gas well development”.

Uncertainty is a key issue as Australia seeks to take advantage of its formidable unconventional gas resource.

For example, Wigley has shown that for the fugitive emission scenarios proposed by the Howarth study, a coal to gas transition will likely warm the climate at a faster rate than business for at least the next 100 years. Under such circumstances a transition to gas would be in no way beneficial to meeting any reasonable global climate objectives. Even for a 2.5% fugitive emission standard, the climate will likely warm relative to a business as usual case out to around 2050. That is because replacing coal with gas will significantly reduce sulphur-emissions which currently act to suppress climate warming on short time-scales.

It is very likely that unconventional gas extraction will result in varied emission profiles depending on the technology and the site-specific attributes of the individual production fields. It is also clear that there is currently very little understanding of the spectrum of fugitive emissions profiles for unconventional gas resources, either internationally or in Australia. Currently in Australia there is virtually no publicly available, independently verifiable fugitive emission data relevant to any specific unconventional production fields.

These issues raise fundamental concerns that need to be addressed by industry and government if the broader community is to have confidence that a coal to gas transition is to help, rather than hinder, meeting climate targets.

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[1] Shindell, D.T., Faluvegi, G., Koch, D.M., and Schmidt, G.A., 2009, Improved Attribution of Climate Forcing to Emissions: Science. V 326, p.717-718, doi: 0.1126/science.1174760

[2] Hayhoe, K., Kheshgi, H.S., Jain, A.K., and Wuebbles, D.J., 2002, Substitution of Natural Gas for Coal: Climatic Effects of Utility Sector Emissions – Springer: Climatic Change, v. 54, no. ½, p. 107–139, doi: 10.1023/A:1015737505552.

[3] Wigley, T.M.L., 2011, Coal to gas: the influence of methane leakage: Climatic Change, v. 108, no. 3, p. 601–608, doi: 10.1007/s10584-011-0217-3.

[4] EIA (2010) Annual energy outlook 2011 early release overview. DOE/EIA-0383ER(2011). Energy Information Agency, U.S. Department of Energy. http://www.eia.gov/forecasts/aeo/pdf/ 0383er(2011).

[5] Howarth, R.W., Santoro, R., and Ingraffea, A., 2011, Methane and the greenhouse-gas footprint of natural gas from shale formations: Climatic Change, v. 106, no. 4, p. 679–690, doi: 10.1007/s10584-011-0061-5.

[6] Hultman, N., Rebois, D., Scholten, M., and Ramig, C., 2011, The greenhouse impact of unconventional gas for electricity generation: Environmental Research Letters, v. 6, no. 4, p. 044008, doi: 10.1088/1748-9326/6/4/044008. See also, Cathles, L.M., Brown, L., Taam, M., and Hunter, A., 2012, A commentary on “The greenhouse-gas footprint of natural gas in shale formations” by R.W. Howarth, R. Santoro, and Anthony Ingraffea: Climatic Change, v. 113, no. 2, p. 525–535, doi: 10.1007/s10584-011-0333-0. and for a response, Howarth, R.W., Santoro, R., and Ingraffea, A., 2012, Venting and leaking of methane from shale gas development: response to Cathles et al.: Climatic Change, v. 113, no. 2, p. 537–549, doi: 10.1007/s10584-012-0401-0.

Three months into the brave new world of carbon pricing, and we can see some dramatic trends in the latest data from the National Electricity Market – or NEM. In particular, the latest data shows the demand for electricity is continuing to collapse in spectacular fashion.

In the 3 months since the carbon tax was introduced at beginning July, demand for electricity dispatched on the NEM is down some 600 megawatts compared to the equivalent period one year ago. It is now down 2000 megawatts on the record levels for the same period in 2008.

Amounting to a real reduction of about 9% over the four-year period, these are extraordinary changes. They must be deeply worrying the industry especially in NSW where the collapse in market demand is most profound.

Average demand in NSW for the last three months is down almost 500 megawatts on where it was just a year ago, and almost 1200 megawatts on 2008 levels. Continuing on its current trajectory of about -3.2% per annum, NSW winter demand will be down next year to levels not seen since the 1990’s. The impact is all the more significant because it is the winter months for which average demand for electricity is highest.

With planning for electricity generation investment needing long lead times, the magnitude of these changes are arguably better framed in terms of previous forward growth projections.

As recently as 2008 the utilities would have been banking on 2% per annum growth. Compared with that demand is now down almost 15%.

Interestingly, it is not just average demand that is down. NSW winter peak demand is down even more, having fallen an average of 4.5% per annum since 2008. Compared with the forward projections, winter peak demand is down a massive 25%. Across the NEM peak winter demand has been falling at 3.2% per annum since 2008, and is now down to levels not seen since 2003.

These are simply horrendous numbers for our electric power utilities who, until recently, have been discounting the downward trend in demand since 2008 as a temporary inconvenience. It seems now though that they maybe wakening to the awful prospect that demand for their prodcut may not return.

Anyone paying attention to national energy policy will have noticed how the established utilities seemed to have recently “upped the ante” in the national energy debate. A particular focus has been the federal government’s Renewable Energy Target (RET) that mandates that at least 20% of our electricity should come from renewable sources by 2020.

The industry beef is with the target. Instead of being framed in terms of 20% of plausible actual demand it was framed in terms of a total amount of electricity – nominally 45 thousand gigawatt hours or an average of about 5.2 gigawatts. That was an estimate based on a forward projection, already hopelessly out of kilter with reality.

With renewables contributing only about 2 gigawatts of our electricity demand, the prospect of adding another 3 gigawatts of mandated supply to the already saturated market is the stuff of nightmares for the owners of existing power generation assets.

And so with their industry under threat, incumbent utilities such as Origin, and TruEnergy are now taking every opportunity to lobby the government to water down the RET. Not suprisingly the Australian Coal Industry’s Nikki Williams has come out swinging at the RET, with such ludicrous propositions as the “RET merely adds to the cost of achieving our abatement target rather than lowering our greenhouse emissions”.

Of course the challenge for industry and government alike is to understand where demand is headed over the next five to ten year period. And to do so requires an understanding of why demand is collapsing in such spectacular and unpredictable fashion, despite sustained GDP growth.

Many pundits have been blaming our recent spate of cool summers as key factor in demand reduction, but that clearly cannot be relevant to plummeting winter demand.

So there must be other much more important factors.

As discussed in my last post, domestic solar PV is clearly a big driver in reducing market demand in South Australia and Queensland. In those states demand outside daylight hours has not changed significantly since 2008, whereas midday demand is down almost 10%.

In NSW and Victoria the story is different. In both, winter demand has been reduced through both day and night. So factors such as better insulation (“pink batts”), solar water heating (especially in Victoria), structural changes in industry (less manufacturing, more services) are all playing a role. The big unknown is whether pricing elasticity is finally manifesting.

Has it got anything to do with the carbon tax?

Perhaps only indirectly. Simply by raising awareness of electricity as a commodity, the carbon tax debate is highlighting the blindingly obvious. We can use much less electricity without materially impacting our quality of life. Energy efficiency measures are clearly impacting on the demand side and arguably they have only just begun. A $3 billion question for industry is just how much slack is left in the efficiency equation.

My guess is we could easily reduce demand another 15% or so without any material impact on our quality of life or inconvenience. If so, that would take demand back to the levels not seen since the mid 90’s and leave us with an excess capacity on the generation side of around 4 gigawatts. Throw in the additional 3 gigawatts of new renewable genaration mandated under the RET, and suddenly we don’t need the generation equivalent of the entire Latrobe Valley, for example, where the current capacity is about 6.5 gigawatts.

Perhaps it’s understandable why the incumbent industry is beginning to squeal!

The recent take-up of domestic solar photo-voltaic (PV) panels in Australia has been quite phenomenal. Across 2010 and 2011, the installed capacity increased seven fold to about 1.4 gigawatts, doubling every 9 months.

By the end of this year we will probably have in excess of 2 gigawatts of solar PV capacity installed. All fired up at the same time it is enough to produce about 8% of the average daytime electricity demand.

Of course, a characteristic of solar PV is that it doesn’t fire up for much of the time at all. With a capacity factor of about 18%, 2 gigawatts capacity would be expected to output an average of no more than 360 megawatts or about 1.5% of our average demand. At those levels you might ask if solar PV is having any impact on our demand for mains electricity.

Judging by the numbers, the answer is a definitive “yes”. In fact, so much so that it wouldn’t surprise if it is beginning to worry some utility managers.

Since solar PV production rises and falls in a characteristic pattern through the daylight hours, any substantive impact should be evident in a distinct reduction in demand for mains electricity in the middle of the day. With PV penetration having risen so dramatically since 2009, that pattern should be apparent in comparisons of demand over the last 12 months with equivalent periods prior to 2009.

In fact when we do this, the PV signature is blindingly obvious, especially in the states of South Australia and Queensland where PV penetration is highest. It is also showing itself in the revenues generated by electricity sold on the wholesale market.

In South Australia, midday to early afternoon demand was down over the financial year 2011-12 by about 8% on the average for the period spanning mid- 2007 through mid-2009. That contrasted with a negligible change in demand outside daylight hours.

In Queensland the story is very similar, although the proportional impact is lower with midday 2011-12 demand down only about 4% on 2007-09 levels.

Given the extent to which PV has been rolled out in the last few years, the characteristic signature of demand reduction in the middle of the day is not particularly surprising. What is more interesting is the signature of PV penetration in the wholesale electricity market.

As pointed out in this column a few weeks back, demand reduction is creating oversupply in the wholesale electricity market and causing prices to collapse.

And it is the afternoon and early evening when the wholesale market makes its money, because that is when demand is highest. So any decline in demand in the afternoon will take much of the cream out of the market.

In the period prior to significant PV penetration, hourly revenues on the South Australian wholesale market typically peaked at 3-4 pm in the afternoon at 5 times above base revenues. By 2011-12 those peaks were gone. Even though PV generation is tailing off significantly by 4 pm, the demand reduction was still enough to reduce peak hourly revenues by almost 90% between 2007-09 and 2011-12, contributing to a 30% decline in the annual wholesale revenue.

In Queensland, 2011-12 midday revenues were down 50% on 2007-09 averages, contributing to an annual revenue fall of about 18%.

Across the National Electricity Market, 2011-12 revenues were down 35%, or some $3.3 billion, on the annual $9.6 billion for the two years prior to mid-2009.

These represent massive impacts on the business of electricity. With PV being a major causal factor, things are are only likely to get worse if solar PV deployment continues at the recent frenetic pace.

It will only take several more doublings in capacity, or about 18 months if recent history is any guide, to reduce midday demand to current midnight levels. That would render the midday to early afternoon period akin to the current overnight ‘off-peak’. In such a scenario, the window of opportunity for healthy margin on mains electricity supply will shrink to just a few hours during the evening peak. With that need best supplied by gas “peakers” such a scenario must be making for some anxiety amongst the managers of our base-load coal generation fleet.

In such a scenario, the cost of delivering mains power will have to rise. That is because while the distribution network needs to be scaled to the size of peak demand, it recoups investment over the total amount of electricity supplied through day and night. With solar PV biting into the daytime demand but barely shaving peak demand, the unit cost of distribution will inevitably rise. Distribution is already the major factor in retail electricity prices.

The problematic feedback is evident. Rising retail prices will further incentivise take up of domestic PV, which in turn drives retail prices even higher. Meanwhile, further deployment of PV helps reduce its costs making it even more attractive, and so on ad infinitum, at least until most household roofs are covered.

A potential nightmare facing the mains electricity industry has recently been acknowledged by the AGL economists Paul Simshauser and Tim Nelson in their paper “The Energy Market Death Spiral – Rethinking Customer Hardship”. In that paper the “death spiral" scenario for the Australian power industry is framed by a quote from a US study by Craig Severance.

‘The unspoken fear of all utility managers is the “Death Spiral Scenario”. In this nightmare, a utility commits to build new equipment. However, when electric rates are raised to pay for the new plant, the rate shock moves customers to cut their kWh use. The utility then raises its rates even higher – causing a further spiral as customers cut their use even more… In the final stages of that death spiral, the more affluent customers drastically cut purchases by implementing efficiency and on-site power, but the poorest customers have been unable to finance such measures…’

It is not hard to imagine how utility managers here in Australia are worrying about just how PV is going to impact their business.

In the electricity game, the “poles and wires” have become the big issue. Even the Prime Minister has starting pointing the finger at excessive investment in the electrical power grid.

So what is it with the grid that has suddenly got the Prime Minister, and just about everyone else in the electricity game, so fired up?

The background to the debate is provided by the rising cost of retail electricity. Retail electricity prices have been rising much faster than inflation over the past few years.

With the carbon tax now in place, the cost of electricity is a very hot political issue, so reducing pressures on electricity price rises is a key objective of the government’s offensive. In emphasizing the “pole and wires” the Prime Minister is pointing the finger at the grid as a key driver of recent price rises. It is the way we distribute electricity, rather than generate it, that dominates retail prices, so the argument goes.

In particular, the Prime Minister and others have begun to highlight policies that have encouraged over-investment in, or gold-plating, the electricity grid. With utilities receiving a guaranteed rate of return, grid investment has been something of a “no-brainer” for them, even if demand hasn’t fully justified it.

And now electricity demand is changing the way we utilize the grid in quite unprecedented ways.

To get some sense of the challenges, we need to look at those changes in the context of past forward projections that have guided recent and current investments. From 2000 to 2006 average demand on the National Electricity Market – or NEM – grew at about 2.2% annually. Growth varied by state, lower than average in the south (1.7% in Victoria) and higher in the north (3.8 % in Queensland).

That all changed about 2007, when the rate of growth in demand started to decline. By 2009, actual demand started to decline. In real terms, demand for electricity has fallen across the NEM by 900 megawatts or 4%. Compared to forward projections of 5 years ago, demand is down 3 gigawatts, or about 14%.

That demand reduction necessarily means our grid is now distributing far less electrical power than had been planned for as recently as 2009. It necessarily means our grid is being utilized less productively. To understand by just how much it is necessary to look at the expectations for peak demand growth.

Compared with average demand, peak demand has grown faster, more erratically and for longer. Across the NEM peak demand growth averaged about 2.7% between 2000 and 2009 when it culminated at 34 gigawatts. There was considerable variability by jurisdiction. In Victoria peak demand grew at a rate of 3.4% or about twice the average demand. In Queensland, peak demand growth was higher at 4.4%, but only 15% greater than average demand growth.

Peak demand is quite sensitive to seasonal weather effects, so there is considerably more variability from year to year when compared to average demand. Nevertheless, the ratio of average to peak demand remained relatively constant at about 70-73% through the period 2000-2007. Notably, the ratio was significantly lower in the south (50-55% in South Australia) and higher in the north (73-75% in Queensland).

Like average demand, annual peak demand has also fallen in the last few years. In 2011-12, peak demand across the NEM was down over 10% on the record 34 gigawatt high of 2008-09. The lower peak demand in the last few years can be attributed in part to the La Nina weather cycle, which has resulted in relatively cool and wet summers, with few extended heat waves.

Since the grid must be scaled to carry peak power loads, the ratio of average demand to peak demand provides one metric of how effectively we are using the grid. The higher the ratio, the higher the utilization rate.

In reality, the grid utilization rate depends the capacity of the grid, which varies in both space and time. The grid must be sized to carry the highest past peak, and each year it is extended to meet any anticipated growth in peak.

Wary of the risk of blackouts, governments have provided conducive conditions for network operators to make the necessary investments in grid capacity. That worked well for governments when demand was growing, but is now proving to be something of a nightmare.

Who knows just how many air conditioners there are out there in suburbia that have never been turned on? And that’s the rub for government and utilities. When our weather cycle breaks back into the El Nino conditions and summer temperatures start to soar, who knows what demand we will likely expect?

So how efficiently are we using our grid, and how has it changed?

The ratio of average demand in a given year to the past peak demand gives an upper limit on how effectively we are using the grid. That ratio has fallen by around 9% over the five years since 2006-07.

The ratio of average demand to projected peak growth gives a measure that accounts for likely grid investment in recent years. That ratio has fallen even faster, by a total of about 12% since 2006-07, and by about 2.5% in the last financial year.

Comparing average to expected peak demand provides only one relatively crude measure of just how we are utilizing our grid. A more comprehensive view is provided by looking into the details. For example, by asking how much of the time are we using the grid above a certain proportion of its capacity?

In Victoria, where we have seen projected peak demand rise at almost twice average demand, such an analysis leads to some worrying insights. Back in 1999-00 the grid was utilized for around 210 days at the 65% capacity level and above. In the last financial year, it was only being utilized at that level of projected capacity for about 6 days. That is a fall in utilization at that level of 97%. At the 75% capacity level, utilization of the Victorian grid has fallen over the same period from almost 71 days to about ¼ of a day.

It is important to note these numbers are based on an estimated projected growth scenario, and will necessarily remain just estimates until the grid is next pushed to its limits. That is not likely until the next record breaking summer heat wave occurs, and in the face of falling average demand may not occur for many years to come.

With the caveat that we don’t have an absolute gold standard measure of the present capacity, these estimates do however confirm we are witnessing quite staggering reductions in the way we utilize the grid. And we are necessarily paying an increasing price to maintain the capacity of the grid in the expectation of what are very rare and increasingly uncertain peak demand events.

With all the trends heading in the wrong way, further falls in demand will necessarily reduce our utilization of the grid. So too will any further investment in grid capacity in the expectation of further peak demand growth.

It is fair to say this fall in average demand has blind-sided the power utilities, governments and market operators alike. None anticipated it, and all have taken a long time to acknowledge it, given it is now into its fourth or fifth year.

There is little to be done to turn around absolute demand, but various measures are available to curb peak demand growth. They include time-of-use pricing and distributed generation within the grid. More efficient standards on air conditioning will be essential. We will need to recognise that the cost of measures that push up peak loads, such as air conditioning, necessitate a grid upgrade. The cost of that upgrade is paid by all electricity consumers, and not just those who buy the air conditioners.

Perhaps there is hope in the reinvention of the power utilities themselves. In the face of falling demand, the utilities will need to realign their business models around energy services, rather than just electrical power. In an energy service model, managing the flow of electricity across the poles and wires will be crucial to enhancing profit margins. Gold-plating will be out of the question.

Such measures will provide the tools necessary to get some productivity back into the grid. If we don’t, then the problems in the grid will only get worse.

With several weeks having passed since the introduction of the carbon tax, the place to look for the most immediate effect is in the national wholesale electricity market known as the NEM.

It’s early days yet, but NEM prices are certainly up. To what extent can we attribute the rises to the carbon tax? And will the sky fall in?

If we compare the NEM prices over the first two weeks of July with previous years we see a surprisingly large rise. For instance, in Victoria the early July 2012 prices were up by about $60 on the same time period for each of the previous three years.

New South Wales and Queensland prices were also up, but not quite so much at about $40 each.

With wholesale prices varying for a range of reasons, on timescales from the seasonal to the hourly, a better comparison maybe between time periods immediately pre- and post- carbon tax implementation.

Victorian prices in the first two weeks of July were up about $50 on the first two weeks in June in 2012. In both New South Wales and Queensland the price differential was about $35. In South Australia it was almost $60.

Given that about one tonne of CO2 is generated for about each megawatt-hour of coal-fired power, these price jumps are significantly more than expected for a $23 per tonne carbon price.

So what gives?

To work out what is going on, it’s useful to look at how average daily prices have changed over the last two months.

Up until June 6th, daily prices averaged between $25 and $30 per megawatt-hour across the NEM. On June 6th prices jumped by around $10 across all NEM jurisdictions.

That price jump was largely due to the reduction in output at TRUenergy’s Yallourn power station following the Morwell River diversion collapse on June 6th. The flooding in the open-cut mine and damage to the conveyor system that delivers coal to the power station caused power output to reduce by over one gigawatt.

You might think the effect would have been largely limited to Victoria. However, interstate power flows allow the price signals of such outages to propagate right across the NEM. In fact, there was little difference in the price impact of the Yallourn outage between Victoria and the other mainland states connected to the NEM.

If we factor out the price impact of Yallourn, we see the price hike in early July was initially about $35-40 per megawatt-hour. However prices have dropped back considerably since the first week of July and are now only about $25 above late June prices. And the trend still appears to be heading downwards.

The initial carbon price hike at the beginning of July seems to have been a bit of an overshoot. Perhaps the generators were being somewhat “conservative” in their bidding strategy in the brave new world of carbon pricing. If so, market forces appear to be quickly pulling them back into line.

If and when Yallourn comes back to full prodcution, we could expect prices to drop back another $10 or so, and settle at around $50-$55 per megawatt hour. In a historical context, that not much more than the $47 annual wholesale price averaged over the last 10 years when adjusted to 2012 dollar terms.

In the bigger picture, the overall impact of the carbon tax will have been significantly cushioned by the very low wholesale prices over the last few years. Those low prices reflect the general state of oversupply on the NEM as discussed in my last post.

In spite of the issues at Yallourn, and the impost of the carbon tax, wholesale prices have not yet reached the heights of the winter of 2007, and do not look like doing so. The sky didn’t fall in 2007 and won’t be doing so now. Unless of course we have another Yallourn-like incident on the NEM.

Wholesale prices are up, but the trend in prices since early July suggests they will stabilise at only a few dollars above the long-term average adjusted wholesale prices. And that is with the cost of the carbon tax.

Just how much would it cost electricity generators if I reduced my electricity consumption by turning off just one light? You would think the answer is half of bugger all, and you’d be almost right.

In an attempt to be a bit more precise, let’s quantify exactly what “half of bugger all” amounts to. Assume that the light I stop using is a 75 watt globe and that I was only using it for about 3 hours a day. So turning it off reduces my average electricity consumption by about 10 watts and saves me about 85 kilowatt-hours over the year.

With my generator expecting to get about 5 cents for every kilowatt hour traded on the wholesale market, the lost income due to my action is a touch over 4 dollars for the year. So “half of bugger all” comes in at about 1 cent each day. It means even less to the generator’s bottom line, because it no longer has to cover the cost of making the electricity that I no longer want.

So you wouldn’t expect the generator to give two hoots about my action. But there are reasons why the generators might be concerned, and they are all about multipliers.

Firstly, demand reduction has a significant multiplier on generator income. Not only does my not using electricity cost the generator a lost sale, it also reduces the price of all other sales on the wholesale market. And in theory, that directly impacts the generator’s profit, since that is on electricity that still has to be delivered.

In reducing my demand, I effectively create an oversupply in the market. And, as with any efficient market, prices respond with a signal to reduce supply. In fact recent market trends show that in addition to reducing the revenue in electricity sold by about $4, my turning off one 75 watt globe reduces the revenues of all other electricity sold by more than $10 across the year. So the net impost on the generator’s revenue is more than $14, most of which is profit.

Still not too much of a worry, unless of course I am not alone. Multiply my action by 7 million, or about 1 in every 3 Australians, and generator revenue would be down more than 100 million dollars on a net reduction in demand of 65 megawatts. That is about 1% of expected annual wholesale market bottom line, but a much higher percentage of generation profits. Multiply that again by a factor of 10, and we are talking of losses in the billions, and a potential bankrupting of some leading industry players.

And it is already happening.

Over the last few years, demand for electricity traded on the National Electricity Market – or NEM – has collapsed by over 900 megawatts and over twice that on forward projections. And wholesale electricity prices on the NEM have plummeted to record lows, down some 40% on just a few years ago.

Until early 2009 the demand for electricity traded on the market grew fairly consistently at around 2% each year. Although there was some slackening in demand before 2009, most industry analysts put it down to the GFC and thought it inevitable we would need another gigawatt or thereabouts of supply to meet 2012 demand.

That is the equivalent of one big new coal-fired power station, about 3 gigawatts of installed wind power capacity or 6 gigawatts of PV.  

But instead, in 2009/10 demand actually fell in real terms by 140 megawatts, fell again in 2010/11 by 290 megawatts and again in the last 12 months by 500 megawatts. Compared to 2009, demand is now down by about 930 megawatts, or almost 4%. Compared to the forward projections of just three years ago demand is down by about 2.2 gigawatts or 10%. That is the equivalent of two big power stations we thought we would need, but no longer do.

And since 2010, wholesale prices have collapsed. The average price in the last financial year was a touch under $30 per megawatt hour. That is the lowest average annual price recorded on the market since 1999 and is about 40% lower than the long-term average of around $47, adjusted to 2012 dollar terms. Market revenue was down almost $3.5 billion on the yearly average of $9 billion in adjusted terms, and more than $5 billion on forward growth projections.

These figures give a direct measure of how the electricity market values demand reduction in terms of its impact on wholesale prices or, in other words, the price signal of oversupply. In fact the market is valuing a demand reduction of 1 watt on the forward projection at about $1.40 over the year. That compares to the expected wholesale value for 1 watt-year of electricity of 44 cents.

And so we get an estimate of our multiplier, of 140/44 or 3.2. Factoring in some other price effects such as the prevailing la Niña weather cycle, and a more conservative estimate of the price signal multiplier is probably a bit lower at around 2.5.

That is a very strong price signal, and testifies to the effectiveness of an efficient market. It may explain why generators are less than enamoured by schemes, such as energy efficiency and distributed PV, that take market share away from their business.

Of course, in the face of plummeting wholesale prices, consumers should be asking if they are seeing any of the benefit. Near record increases in retail prices would seem to suggest not and raise a raft of questions such as what exactly is the function of the wholesale market?

If you are like me, and concerned about the possibility that rising CO₂ levels in the atmosphere are jeopardising climate stability, the latest BP Statistical Review of World Energy makes for sobering reading.

BP’s Statistical Review provides a comprehensive update on energy resource production and consumption by country, region and the world. In the latest update released mid June, BP estimates that global energy consumption grew by 2.5% in 2011. That is pretty much in keeping with the long-term trend, so nothing exceptional in that.

However, the figures on coal production are truly mind-boggling.

BP estimates that in 2011 global coal production increased by an extraordinary 440 million tonnes. In absolute terms, that is the biggest annual increase on record. At 6% over the year, it comes on top of a 5% increase in 2010, and tops off what has been a phenomenal 10-year increase in annual production of almost 3 billion tonnes at an annual average growth rate of 4.6%.

In 2011 global coal production was 7.7 billion tonnes. To put that in context, it is only slightly less than the amount of rock moved from mountain to sea each year over geological time by rivers and glaciers. In energy terms it is equivalent to almost 4 billion barrels of oil.

On an energy basis, oil only just edged out coal as king of the energy resources by the equivalent of 40 million barrels, or about 4 days of production.

But with oil production growing at only about 1% last year, coal is set to surpass it as the most important energy commodity sometime this year. In fact, it probably has already.

This marks a phenomenal turn around for the fortunes of coal.

Coal first replaced bioenergy as king of energy resources in the late 19th century. In 1966 it was displaced by oil. Relatively speaking, coal then headed rapidly south. Between 1989 and 1993 coal production actually declined in real terms. Despite mild growth in the mid-late 90’s, coal continued to lose ground to oil, and as recently as 2000 coal provided as little as ⅔ the energy of oil.

That all changed in 2002 with the awakening of the Asian giant, turning the fortunes of the coal barons and coal-exporting countries alike.

Where does Australia stand?

Australia was the third largest producer in 2011 at 415 million tonnes, or a bit under 6% of global production. Australia’s production was dwarfed by China which produced half of all the world’s coal, and ¾ of its growth in 2011. In fact, last year Australia’s production was marginally down on 2010 levels. In 2011, Australia’s production was about 42% that of the US, and marginally more than both India and Indonesia.

Where Australia stands out is in its per capita production. At 18.6 tonnes per person, it outstrips other top producers by a huge margin. China and US per capita production stands at 2.6 and 3.2 tonnes per person, respectively.

Where to from here?

In its latest update, BP estimates the global coal reserve at about 860 billion tonnes. With a reserve to production ratio of about 110 years, we are not set to run out of coal soon. Not at least using it at current rates. However, if we were to continue to increase production at the historical growth rates of about 2.5%, the current reserve would last only about 50 years.

Such calculations have motivated some talk of ‘peak coal’. However, as with any resource, we can expect scarcity will breed desire and the reserve pie will be topped up for years to come. A doubling of the reserve is entirely possible.

In our own back yard, in the Latrobe Valley, the demonstrated brown coal reserve is about 40 billion tonnes, representing about 5% of the global reserve. But the inferred resource is estimated at a staggering 100 billion tonnes, some or all of which could conceivably become economic at some future time.

That is a truly phenomenal amount of coal. At the current production rates of around 70 million tonnes per year there is enough coal in the Latrobe for 1500 years.

Of course, mining it all would turn the entire valley into a 100m deep pit, some 15kms wide and extending over 70kms from Moe in the west, eastwards to beyond Sale.

If you are worried about keeping mean global temperatures within safe limits, then pray that we don’t end up burning the global coal reserve.

If we did, and released the CO₂ to the atmosphere as we do today, then we would push atmospheric CO₂ levels to well above 550ppm, up from present level of 395ppm and pre-industrial levels of 290ppm.

That would give us an almost negligible chance of keeping global average temperatures below 2°C above pre-industrial, and would ultimately drive our climate to a state the world not seen for over 3 million years, since the Pliocene.

By looking back at that time we can get a glimpse of where our climate is headed. At that time there was a whole lot less ice on our planet. So much so in fact that sea levels stood more than 25 meters higher than today.

It is looking like it’s back to the future, both for coal and for the climate.