August 2012 (chapters added since)
Introduction
The present government interventions in electricity markets, intended to move the industry from coal to renewable energy sources, are responsible for most of the rapidly rising cost of electricity in Australia. These interventions have introduced unanticipated distortions and inefficiencies in the way that electricity is delivered.
Industry experts point to looming problems in supply and even higher price increases.
A 'root and branch' review of these mechanisms is urgently required to prevent ever increasing prices and to prevent further potentially crippling distortions.
If you currently pay an electricity bill or use electricity in your place of employment it is worth gaining an understanding of the key issues surrounding the generation and transportation (transmission) of electricity.
The electricity price we pay our retailer is made up of a number of different components. These are the cost of:
- Transmission and local distribution - local distribution is by far the largest part of the total grid costs - but large transmission projects cause incremental price increases that increase the effective electricity price in your bill;
- wholesale electricity from the National Electricity Market (NEM) - incorporating the cost of fuel and thus the impact of the new carbon tax;
- renewable energy certificates - once known as REC's but now of two kinds: Small-Scale Technology Certificates (STCs) and Large-scale Generation Certificates (LGCs);
- the retailer's costs and overheads (marketing) - this includes additional costs associated with local feed-in generation; principally from rooftop photo-voltaic (PV) solar.
Although some elements of the Australian electricity market operate competitively, there are a number of elements that do not; and some cannot.
In particular, the duplication or multiplication of 'wires and poles' to provide competition in the grid is not considered desirable; both on the grounds of economies of scale and issues around actual physical space required to run competitive wires. This sector is therefore heavily regulated and often in government hands.
The retail sector, while nominally open to multiple competitors, is complicated by one of these retailers usually also being the owner of the local distribution infrastructure.
But generation is generally regarded as a competitive sector, with over 260 large generators contributing to the NEM.
The carbon tax impacts the effective cost of fuel for the largest of these generators. Initial estimates put the tax pass-through cost to consumers at around 2 cents per kWh. But as I will point out this is not presently being felt evenly across all carbon based fuels. There is not a 'level playing field'; because some competitors are enjoying an unfair advantage.
In addition there are distortions introduced by the LGC's. Together with other government interventions, discussed below, these are distorting the marketplace in generation. It is widely reported that investment decisions required for ongoing electricity security have been deferred or even abandoned. Very large plant with long lead-times is involved. This is likely to result in a serious shortfall in capacity in the next decade or two.
Renewable energy certificates are already an important factor in pre-tax price increases and are forecast to become a major part of your electricity bill in future.
Maintaining and expanding local distribution infrastructure is a big part of your bill - as new suburbs are built distribution is increasingly underground raising the overall cost to all consumers.
Transmission grid capital cost and losses are on the increase with the introduction of relatively remote and very variable wind generation and this too pushes up the effective cost of electricity in the NEM.
Mains electricity from the grid comes from a multitude of energy sources. Electricity is simply a convenient way of transporting that energy in a way that is easily converted back to mechanical energy, heat, light, and the motive force to drive electronics.
I argue that it is urgent that the renewable energy target is absorbed into a single carbon reduction initiative, in which no industry sector or consumer is exempt or privileged, similar to that originally proposed by Federal Treasury and the Garnaut committee in 2010.
If you don’t understand where electricity comes from; how it is transmitted or potential technology 'breakthroughs', still in the laboratory, there is a short (simplified) primer on this website.
The ultimate competitor, if the grid fails to supply or if it becomes too expensive, is 'self generation'. I also briefly examine the self generation option in the 'primer'. Read More…
How much have prices risen?
There have been all sorts of interpretations of this issue in the media.
The following chart shows national and interstate differences. Note that Western Australia and the Northern Territory are not supplied by the National Electricity Market.
source: Energy Supply Association of Australia
All sides have recently blamed heavy investment in ‘wires and poles’ as a principal component in the pre-carbon tax increases. But this is only part of the story.
Cost due to the Carbon Tax
The carbon tax was responsible for the greatest proportion of the last round of electricity price increases; around half in NSW and nearly all in Queensland.
Initially the price of a permit for one tonne of carbon is fixed at $23 for the 2012–13 financial year. Only the ‘largest polluters’ need pay. They can buy as many permits as they need at the annual price. The fixed annual price will rise by 2.5% a year, until a transition to an emissions trading scheme in 2015–16, when permits will be limited in line with a pollution cap.
The effect of the carbon tax is to raise the cost of fossil fuel. Obviously it has no direct impact on renewable energy. Indirectly it may raise capital equipment and other input prices slightly.
A carbon price ‘pass-through’ of around 2 cents per kWh in the wholesale price has been estimated by the Australian Energy Market Operator. This is the extra amount paid by retailers due to the carbon tax.
I have previously commented on the economic distortions introduced by the tax and offsetting compensation - read more. And more.
For example as part of the tax implementation ‘dirty’ brown coal generators have been given compensation to help them compete but cleaner black coal generators have not:
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Victoria's dirtiest coal-fired power plants have snared the lion's share of $1 billion in energy industry carbon tax compensation - a concession that will protect jobs but slow the shift to renewable energy… … Latrobe Valley's brown coal stations Hazelwood, Yallourn, Loy Yang A and B, and Energy Brix are the major winners from the government's $1 billion Energy Security Fund, which compensates the most greenhouse-intensive power generators for the loss of value to their assets under the carbon tax, due to start on July 1. |
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David Wroe in The Age March 31, 2012 |
Is this tax to cut carbon or not?
As presently implemented it is a tax to 'rob peter to pay peter'. The money goes 'round but stays in the country. The main damage done is due to the seemingly random or politically motivated distortions it introduces.
But when international trading starts things will change. The price is expected to more than halve, dismantling a good deal of the economic impact that it presently has.
At the same time it is expected that money will start to flow overseas, in search of carbon credits. Some of these will be very dubious like carbon farming; commonplace in Europe and already devastating poor rural communities in Southern Portugal. See my report of our trip there on this website.
The difference between this heavily flawed tax and the renewable energy target is that the target has the potential to actually force investment into renewable alternatives. Unlike a tax that robs you to pay you (read what the Wall Street Journal had to say - here), the renewable energy target has really serious economic consequences.
Costs due to the renewable energy target
It is interesting that all parties have steered well clear of blaming Australia’s mandatory renewable energy target (MRET) for any of the past price increases. Learn more about the MRET here…
Yet, as previously discussed on this website, in 2011 the Independent Pricing and Regulatory Tribunal (IPART), the NSW regulator, blamed the cost of renewable energy certificates for most of that year’s increases.
IPART determines the maximum prices charged for regulated electricity services provided by TRUenergy (formerly EnergyAustralia) and Origin Energy (formerly Country Energy and Integral Energy) in New South Wales.
There are now two kinds of certificates under the MRET. Both are created in response to renewable electricity generation.
Small-Scale Technology Certificates (STCs) are earned by domestic PV solar owners; at a fixed clearing house price of $40 per MWh. There is presently an excess of STCs in the clearing house and they are being discounted by some owners by around $10.
Large scale certificates have renamed Large-scale Generation Certificates (LGCs); previously called RECs in some places on this website. The LGC price presently fluctuates between $35 and $45 depending on time of year.
source: Energy Users Association of Australia http://www.euaa.com.au/green-market-prices/
Energy retailers have a legal responsibility to purchase and surrender a proportion of their annual demand. In 2012 this proportion for LGCs is 9.15%. For STCs the proportion is 23.96%
Using the above crude numbers it can be estimated that the retailers’ average supply price is raised by around 1.2 cents per kWh; equivalent to around 60% of the carbon tax pass-through.
The actual impact on your electricity bill of these certificates is complex. There are also concessions to trade exposed industry that are factored in.
Like the carbon tax the cost to retailers of renewable energy certificates increases in future. As the MRET target rises retailers are bound to buy a larger number of certificates and the price of LGCs is also expected to rise due to higher demand.
The MRET is a fixed energy target by 2020 not on the percentage (20%) generated by renewable energy. The target does not fall with the projected decline in electricity demand as the price rises.
| Annual MRET Targets 2011-2030 (GWh)* | ||||||||||||||||||||||
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* Targets adjusted as per Subsection 40 (1A) of the Act. |
As the table shows, the mandatory target rises fourfold between now and 2020; so that it may be as high as 30% of actual generation by then.
Meeting the target
If you don’t understand where electricity comes from or how it is transmitted there is a short (simplified) primer on this website: Read More…
I suggested in an earlier paper on this site that the present renewable energy target is a ‘stretch goal’; that will be difficult or even impossible to meet without another, less variable, energy source than wind or solar.
The following table shows how some other countries source electrical energy. Compare Australia, 92.7% fossil dependent, with Switzerland, 1.1% fossil dependent.
Electricity Generation 2009
|
Coal |
Gas & oil |
Total fossil |
Nuclear |
Hydro |
Wind |
Solar |
Biofuels and waste |
Other sources |
|
|
Australia |
77.9% |
14.8% |
92.7% |
NIL |
4.7% |
1.5% |
0.1% |
1.1% |
<0.1% |
|
United Kingdom |
28.2% |
45.2% |
73.4% |
18.4% |
2.4% |
2.5% |
<0.1% |
3.3% |
<0.1% |
|
United States |
45.2% |
23.9% |
69.1% |
19.8% |
7.1% |
1.8% |
0.1% |
1.7% |
0.4% |
|
Germany |
43.4% |
14.9% |
58.3% |
22.8% |
4.2% |
6.5% |
1.1% |
6.0% |
1.1% |
|
Spain |
12.6% |
43.0% |
55.7% |
18.0% |
9.9% |
12.9% |
2.1% |
1.4% |
0.1% |
|
France |
5.3% |
5.0% |
10.3% |
75.6% |
11.4% |
1.5% |
<0.1% |
1.1% |
0.1% |
|
Sweden |
1.2% |
1.7% |
2.8% |
38.2% |
48.3% |
1.8% |
<0.1% |
8.9% |
<0.1% |
|
Switzerland |
<0.1% |
1.1% |
1.1% |
40.4% |
54.8% |
<0.1% |
0.1% |
3.5% |
<0.1% |
Source: IEA - International Energy Agency
Notes:
- France has 60 nuclear power-stations and is one of the lowest cost producers in Europe; exporting nearly five percent of its electricity. About a sixth of this is imported by the UK.
- The UK plans to build 10 or more new nuclear power stations over the next 15 years to rectify the growing shortfall and replace old technology - read more
To actually make a significant impact on carbon emissions in Australia we will certainly need a mix of nuclear generation; like almost all developed and most rapidly developing countries.
French domestic consumption is around twice ours in Australia (see the followng table). If we replicated the French we would need around 30 nuclear power-stations.
The quickest way to achieve this would be to first replace our oldest and most carbon intensive generators with nuclear stations; on the same site. The grid is a very costly component in the supply chain and is already in place from these sites.
As I have previously noted local communities would receive major health and environmental benefits and workforce and local economic impacts would be positive. But eight years is an impossibly short time-frame for nuclear power to be implemented and make a difference.
A new hydro-electricity scheme sufficiently large to make a contribution on the East coast (several times larger than the Snowy Mountains scheme) is even more problematic; bordering on impossible. It would involve damming all the high flow-rate coastal and northern rivers, like the Clarence. Even if environmental and community issues could be resolved, the major engineering works involved would take decades.
Several other renewable resources such as geothermal, waves and tides are on the drawing board. Some of them have remained there for over 100 years. But none of these have any chance of making a significant contribution (more than 1%) within eight years; if ever.
This effectively leaves us with wind and solar. I have already explained why wind becomes increasingly uneconomic as it approaches 20% of total energy delivered. South Australia and Tasmania are already approaching this barrier and rely on expensive DC links to Victoria to dispose of excess generation when local demand is low; and the wind is blowing at its optimum. When the wind is not blowing they depend on these links to keep the lights on.
While it has risen to saturation in the smaller southern states wind energy presently supplies little over 6,800 gigawatt hours of electricity annually – around 2.4 per cent of electricity delivered to the NEM in 2011/12.
Investment in wind has been growing at around 25% pa but this has slowed recently as the best opportunities are exploited and the smaller states have become saturated.
There are still some good as yet unutilised wind provinces in Victoria and less in NSW. Some wind farms have been delayed by local environmental objections but these will no doubt be overruled in due course. Good wind provinces close to the grid get less common further north; adjacent to much larger population centres in NSW and Queensland where fossil fuels will need to remain dominant.
Even at current growth rates, unconstrained by resource issues, it would be very optimistic to project wind generation of more than 21 TWh pa by 2020. This would leave a shortfall in the MRET of around 20 TWh to be made up somehow.
Solar energy is even more constrained than wind in terms of the total contribution it can make. This contribution is not related to price but to the capacity factor (the percentage of time that the power-station is able to operate at its nominal peak capacity).
Thus a typical well located wind turbine produces at full power for an average of around 35% a year, whereas well located solar might manage half this. Rates of around 10% are more typical for photo-voltaic (PV) solar in urban locations where shadowing and pollution can be an issue. I have discussed this in more detail elsewhere - read more.
The price of PV solar is falling rapidly, dimming the prospects for solar-thermal technology because good thermal sites, with adequate insolation and a better capacity factor, are generally far from the grid; whereas PV solar can be adjacent to the consumer.
While still more expensive than wind, PV solar is more widely available and can more easily be located in urban areas close to demand. As the price of PV panels falls their relatively poor efficiency, particularly when not optimally located, can be compensated for by simply adding more panels.
It sounds great; or so the solar industry tells us. So why is capacity factor important?
The recent German experience is informative. Germany now has around 30GW of heavily subsidised PV solar capacity; most of it in urban areas. On two or three occasions this year (2012) generation exceeded total German demand. While the excess energy was exported the actual price received in the European energy market was very low.
In that market it is possible for the price to become negative; as experienced by Denmark that has a saturated market for wind power at around 20%. This means that Germans must either pay to have the energy taken away or must shut down excess capacity - this is very hard to do with domestic feed-in generation.
To cope with this Germany has recently heavily cut back incentives for feed-in solar generation - much to the alarm of the solar industry - read more. This has happened as the contribution of solar generation to annual German electricity production approaches just 5.4%.
This suggests that a target for solar any higher than say 6% of total generation, is a formula for massive over-investment and waste. The capacity factor will inevitably be forced down and further incremental growth will simply add unwanted peak generation. These panels cost carbon to make, install and maintain and net carbon released could well be positive as a result.
Theoretically Australia could absorb say 10 TWh of annual PV solar generation. This would take us to around the capacity that is already causing inefficiency and waste in Germany today. But such a massive, and potentially wasteful, investment program in just eight years would still leave us with a shortfall against the present MRET of around 10TWh.
As the Australian renewable energy industry finds it increasingly difficult to meet the MRET generation target the LGC price will rise.
Several industry commentators, including Origin Energy, are already forecasting that this cost will quickly outstrip the carbon tax impost.
Last year IPART also forecast steeper increases in the future due to the projected increase in these proportions to meet the escalating mandatory target.
A steep increase in the LGC price will encourage the building of very marginal, presently unprofitable, wind farms that contribute very little to the overall energy market. It will also hand extraordinary wind-fall profits to existing wind farms.
This will be in no ones interest except the investors in existing farms; and the overseas manufacturers of wind turbines. The only local manufacturers of large (>1MW) turbines have long since closed; due to the small market and high A$.
I have previously argued that Electricity is already doing its ‘fair share’ in the move to renewable low carbon technology through these mandatory renewable energy targets.
On these grounds there is an argument that existing electricity generators should have been exempt from the carbon tax; at least until the Large-scale Renewable Energy Target (LRET) can be absorbed into a full properly structured carbon trading scheme.
If as appears likely, the renewable energy target is unachievable in the proposed time-frame the MRET has potential to:
- spawn remote, poorly located and otherwise uneconomic wind and solar generators - themselves consumers of energy in their construction and support;
- require the construction of highly inefficient and expensive transmission lines to remote generation sites - that are inherently wasteful of energy, capital and materials - and releasing millions of tonnes of carbon in their manufacture, installation and maintenance;
- drive the price of electricity to the top of the world price table;
- further damage the domestic manufacturing sector;
- result in the proliferation of alternative local generation solutions - using fossil fuels less efficiently than at present; and
- still fail to meet the target, that makes no provision for falling energy demand - as a result of the projected steep price increases.
It seems inevitable that the very steep future increase in electricity prices predicted within the industry will quickly become politically unsustainable and a new scheme will need to be devised for more comprehensive carbon reduction well before 2020.
The National Electricity Market
All states except Western Australia and the Northern Territory are connected to the eastern grid and electricity can flow forwards and backwards across state boundaries according to demand and supply. This pool of suppliers, thus created, forms the National Electricity Market (NEM). This functions as a central dispatch system and is managed by the Australian Energy Market Operator (AEMO).
The NEM is a wholesale market through which generators and retailers trade electricity. There are six participating jurisdictions (five states and the ACT) linked by transmission network inter-connectors.
The electricity price in this market place is governed by demand and supply within wide limits.
Based on the generator’s offers to supply and the prevailing demand AEMO’s systems determine the generators required to produce electricity based on the principle of meeting the retailers’ demand in the most cost-efficient way. AEMO then dispatches these generators into production.
The dispatch price between the market and generators is struck every five minutes and averaged to the NEM spot price every half hour for each of five generation regions. This price fluctuates very substantially according to season and time of day with additional variability due to sun, wind, or rain and even what’s on TV.
The Australian Energy Regulator monitors the market to ensure that participants comply with the National Electricity Law and the National Electricity Rules. These rules set a maximum spot price of $12,500 per MWh. The prevailing weekly spot price can be seen on the AEMO website. At the time of writing this is averaging $66.52/MWh in NSW post carbon tax. But this week there were fluctuations as low as $41 and as high as $290.
Electricity consumption
The industry often tells us about new initiatives in terms of how many households they can support. But households consume less than a quarter of the electricity delivered in Australia. Most of the increase in the cost of electricity is borne by industry and commerce. In due course this cost ends up in our wallets in other ways.
| Final Consumption (GWh) |
Residential | Commercial and Public Services |
Industry | Transport | Agriculture Forestry & Other |
Per Capita Consumption (MWh pa) | |
| Australia | 213,773 | 22.7% | 21.4% | 36.0% | 1.1% | 0.7% | 9.43 |
| United States | 3,642,203 | 32.3% | 31.3% | 18.9% | 0.2% | 3.5% | 11.60 |
| Germany | 495,573 | 24.0% | 22.4% | 34.8% | 2.7% | 1.5% | 6.05 |
| France | 423,440 | 33.0% | 23.2% | 22.4% | 2.4% | 1.0% | 6.48 |
| United Kingdom | 322,417 | 32.4% | 23.6% | 25.9% | 2.3% | 1.0% | 5.18 |
| Spain | 255,368 | 24.3% | 27.9% | 33.0% | 1.1% | 3.0% | 5.53 |
| Sweden | 123,374 | 29.0% | 18.9% | 36.4% | 1.7% | 1.3% | 12.99 |
| Switzerland | 57,483 | 27.0% | 26.1% | 27.5% | 4.6% | 1.5% | 7.23 |
Source: IEA - International Energy Agency
Notes:
- Since 2009 several Australian aluminium smelters have closed or reduced production. The proportion or electricity consumed by industry will be less than it was then.
- Final Consumption is electricity delivered to the home market after imports and exports, losses and the electricity industry's own use have been deducted.
Australian losses are amongst the highest in the world due to our long transmission distances and our use of pump-storage for load smoothing.
Costs due to transmission
The cost of energy is a fraction of our electricity bills
As consumers we tend to think of electricity as another utility like gas or water or as a fuel source like petrol.
But it is not. Electricity is not a source of energy; it is simply a means of transporting energy from other sources.
Energy is derived from numerous sources by generators and sold into the National Electricity Market (NEM). This energy is shipped by high voltage transmission to local distributors that deliver it to homes and businesses.
Last week the average wholesale price of electricity in the National Electricity Market was 6.6 cents per kWh.
This is the price your retailer spends on energy component of your bill. You will have noticed that they charge you a lot more than seven cents.
Most of the cost of electricity is due to the transport chain; because energy transport is what you are paying for.
If you don’t understand where electricity comes from or how it is transmitted there is a short (simplified) primer on this website: Read More…
Transmission refers to the high voltage grid, the towers you see in the countryside; as opposed to lower voltage distribution, for example in your street. There are five interlinked state-based transmission grids creating this high voltage backbone.
The state-based transmission networks in all eastern states; the ACT and South Australia are linked by cross-border inter-connectors to form a single grid. In geographical span this has created the largest interconnected power system in the world.
The grid interconnections have an increasing role in enabling renewable energy trading across regions.
Very expensive high voltage DC links connect Victoria to Tasmania and part of South Australia. The remainder of South Australia is linked to Victoria using conventional high voltage AC transmission.
Both Tasmania and South Australia have a high proportion of variable wind power; making these interconnects important to ensure local consumer demand can be met when wind is lower than local demand; and to facilitate export of excess power when local demand is low but the wind is plentiful. These two states consequently have the highest cost electricity in the system.
In addition, consumers are paying for a new 500kV grid backbone linking NSW, Victoria and Queensland.
But transmission costs are less than a fifth of the cost of local distribution.
The great majority is consumed by the thirteen linked distribution networks that take feed from the transmission grids to supply electricity to end-use customers.
Grid costs
The highest historical electricity price rises have been in Tasmania and South Australia, where renewable energy is most dominant.
Industry experts generally agree that one of the factors in the big cost increases in the past decade is previous state government action to suppress prices: both by failing to properly maintain distribution infrastructure built in the 1960’s; and through chronic under-investment by government owned instrumentalities since.
Some also doubt the internal efficiency of these companies; relative to private construction or equipment maintenance companies. But this is hard to confirm given the specialised nature of the industry and unique factors in each state and territory.
Recent and ongoing reforms in the industry have released some of these constraints resulting in a lot of remediation. But there is still significant regulatory oversight. Perhaps the most important of these addresses the potential for monopolistic behaviour; particularly in the ownership of wires and poles.
Obviously it is not practical, or economically efficient, to have multiple sets of electricity services running in every street or to have several duplicated high voltage grids.
Rather than encourage many duplications of expensive infrastructure the sensible decision was therefore made, by all Australian governments, to establish a central regulator to monitor and regulate the investment and the charging behaviour of the owners of distribution infrastructure.
This is the Commonwealth administered Australian Energy Regulator, currently being indirectly accused of not stopping alleged over-investment by state owned instrumentalities or, perhaps, the making of monopolistic profits at the expense of electricity consumers (to the benefit of the same local taxpayers?).
Gold plating
There have been accusations of ‘gold plating’ this network. This is taken to mean that redundancy built in to ensure reliability is unnecessary and that the occasional blackout is acceptable.
Most of the grid costs we pay for are for local distribution.
Local low voltage distribution will inevitably fail occasionally due to storms, fires and so on, bringing down or shorting out lines, workers inadvertently digging them up, as well as local equipment failure.
Distribution in new areas is often underground to minimise these failures and to hide ugly wires and potentially dangerous poles. This is one kind of ‘gold plating’ as it is initially much more expensive. In total cost of ownership terms this differs from place to place and underground conduits and cables may well be competitive in many locations.
Certainly in Sydney you don’t need to look far to see poles, cables and insulators in need of replacement. But are the lines-persons who maintain this infrastructure efficiently managed? Is there excessive management overhead and/or ‘featherbedding’? Is the technology still being deployed the most cost effective?
A good deal of the recent increase has been attributed to upgrades to transmission infrastructure.
Redundancy in the High Voltage grid is more critical. As failures in North America and New Zealand have demonstrated, such a failure can take out an entire city.
I was in New York when this happened in 1977. Try walking up and down a high rise staircase with a candle; to and from an apartment where the toilet no longer flushes; there is no water or lighting; and the food in the refrigerator is going rotten. Trains stop between stations. Lifts, lighting and air-conditioning cease to work in high rise commercial and residential buildings. Petrol pumps stop working; as do ATMs today - back to the cash economy - if you have some.
Sometimes this outage lasts for hours, or days, by which time water supply, sewerage and communications will be compromised. Business computer systems fail as UPS batteries are flattened and even back-up generators run out of fuel.
Lawlessness can erupt. People die.
The costs to the economy of such a failure are measured in hundreds of millions, even billions, of dollars.
Experience has revealed additional risks to electricity grids that were not evident when they were first conceived.
Australians consume more electricity per capita than most other countries and the east Australian high-voltage grid is now one of the largest in the world. As the complexity of the grid increases, so the risks surrounding the failure of a critical link increase.
Each link in the grid needs to have capacity to supply at the maximum demand. As described in the 'primer', when currents increase more energy is lost to the environment as heat. These losses rise exponentially with current.
As a result of higher peak currents the grid becomes more expensive.
Either:
- users pay for excessive amounts of energy wasted as heat; and the risk of high current tripping (breakers opening) becomes unacceptably high; or
- links need to be duplicated; or
- wires and cables need to be replaced with larger diameter, heavier ones with more substantial supports; and/or
- voltages need to increase; again with more expensive towers and new transformers.
As power-stations become more remote, and interstate sharing increases, voltages are being increased to reduce losses. This involves taller, more costly, towers and a greater risk of insulation failure. There has also been the need for some expensive DC links.
This is necessary partly as a result of higher levels of fluctuation and current peaks due to alternative energy interstate and irregular demand.
Electrical breakers in the grid protect against wires melting (blowing out) due to surges of excessive current. If this happens there is a blackout in the affected area.
This could be something as rare as an induced DC pulse, caused by a strong magnetic pulse emanating from a solar flare or a super nova. This has the potential to bring down or destroy AC components. In 1989 a solar flare caused such a DC pulse and six million people in Canada to lost their electricity. Read More...
I don’t think reasonable measures against these possibilities can be called ‘gold plating’; unless this is code for ‘Union feather bedding’ in the government owned instrumentalities. Maybe this is what the PM meant?
Costs due to Retailers
The role of the retailer is to package up wholesale electricity, from the sometimes wildly fluctuating National Electricity Market (NEM); together with distribution charges; the purchase of LGCs and STCs; and their own marketing and management costs.
They can then ring you up and offer you a deal you can’t refuse. Or perhaps you pay yet another middleman through a newspaper or TV station to get you a notional discount? This is a very competitive area of the business.
There is presently such a deal running; sponsored my two media organisations. Cynics point out that a similar deal is available by going directly to retailers; and that it is aimed at poorer consumers who may not always pay their account on time; in which case there are penalties that could make the arrangement very profitable to the organiser.
The retailers’ profitability rests on them accurately forecasting an average energy price and getting a good price for distribution services from the national grid and the local distributor.
In order to reduce the risk retailers may hedge against forward energy price fluctuations. These uncertainties add an additional cost to their business that gets charged back to customers.
Transparency in these transactions can be further reduced because one of the retailers in a market is usually the local distributor.
When we pay our electricity bill around a tenth pays for administration, retailing, marketing and sending us the bill. Around 4 cents per kWh goes to buying the fossil fuels. Another 2 cents goes to the carbon tax.
But the majority (including 1.2 cents and rising to subsidise the capital cost of renewable energy) goes to servicing capital loans and management, construction, maintenance and depreciation of all the equipment needed at the power-station to convert the fuel to electricity then to transport the electricity via the national and local distribution grids.
Put another way, your bill is due predominantly to the cost of financing, building, maintaining, renewing and managing a lot of capital equipment. A good deal of this cost is due to dividends and interest to the initial investors and lenders.
I have already mentioned the cost to retailers of purchasing renewable energy credits (LGCs and STCs).
As in the transmission grid, each link in the local distribution grid must be able to comfortably supply the typical peak current.
Further complexity has been added at a local level since local feed-in from solar panels (or potentially, private wind turbines) has been accommodated. Additional metering (and billing complexity) adds cost to the local network.
Rooftop solar often feeds back high priced energy or reduces demand when the price from the NEM is low; for example in the middle of the day rather than at the morning and evening peaks.
Except for the summer peak load, solar feed-in lowers local domestic demand when it is already low. This makes the grid more, not less, peaky. It exaggerates the morning and evening peaks relative to average demand.
The net result is a higher cost or less profit to retailers. This is passed on in your bill as higher cost per kilowatt hour.
The increasing peakiness in domestic demand has been blamed as a major factor contributing to distribution costs.
Maximum peak demand now occurs on a few very hot days in summer when air-conditioning is use is at a maximum. In this case roof top solar is beneficial in lowering peek loads. But as already indicated this is the most profitable period for generators.
Although smoothing the peak demand is good for reducing grid costs and losses, it is argued by some that as a result of the MRET transfers to encourage rooftop solar, generators need to increase their bid price at other times to remain profitable; so that it does nothing to lower the averaged retail electricity price. At the same time the STC’s thus created significantly increase that price.
Smoothing the load
If residences were more sensibly designed and insulated, these fluctuations in current would be less extreme and the grid could be lighter and less expensive.
Off-peak water heating was an early attempt to better spread the domestic load. It has been suggested that the advent of electric cars could be another ‘water heater on wheels’. But waiting for midnight or midday to recharge could be a problem if you have run out 20 miles from home in peak-hour traffic.
Batteries, hot salt and pump-storage of water in hydroelectricity schemes have been tried or are used on a small scale in many countries. In every case the scale is modest. The cost of storing say 5 to 10 thousand gigawatt hours (5-10 TWh) across the NEM is mind-boggling.
‘Smart’ meters are already available in trial areas and can be configured to better reflect the actual NEM price to retailers; so that summer peak air-conditioning could be made to cost say ten times the off-peak rate. This would quickly justify a wide range of energy saving changes to buildings including double glazing, wall insulation and rooftop solar, for the summer period alone.
Trials are also currently underway using complementary natural gas powered fuel cells, within local distribution networks, to smooth the unevenness of supply from rooftop solar.
In the commercial sector if the actual NEM price was reflected in the retail price, the higher capital cost of off-peak water chilling or freezing and circulation systems, complemented by better building design and insulation, incorporating heat recovery systems, might quickly be justified.
The net cost to all consumers could then be reduced. But smart meters too cost money and you the consumer will have to pay; one way or another.
The cost of energy sources
The source cost of renewable energy is typically zero. This includes: solar, wind, tides, waves and geothermal energy. But in all of these cases the cost of the conversion equipment is very high; generally many times that of converting fossil fuels.
The price of fossil fuels coal, oil and gas respond to market demand.
Because oil, gas and coal are broadly interchangeable, with a lag due to the conversion investment required, big differences in the energy cost relationship between one fossil fuel and another are usually temporary.
Steaming coal is used almost exclusively in power-stations. Australia has good coal deposits adjacent to its major energy markets. Coal fired power-stations are usually built close to a ‘captive’ mine and have long term contracts. The lower effective fuel cost and greater efficiency possible from a single dedicated fuel source; large boilers tailored to the coal; and optimised turbo-generator sets more than offsets the grid losses involved in transmitting the energy to consumers in nearby cities.
There are additional environmental benefits of generation near mine-sites in the country. Coal burning releases ash; dust; acidic oxides of nitrogen and sulphur; and more radiation than several nuclear stations; in addition to carbon dioxide. Coal burning is best kept away from large conurbations.
Shipping coal by train or road is costly; dusty; consumes energy and lives are lost in road and re-handling accidents. This can be minimised if conveyor belts do most of the materials handling.
Some fossil generation can generally be located even closer to consumers. For example, gas co-generation can supply a cluster of buildings in the middle of a city; with virtually no grid overhead; or losses.
Natural, renewable, resources are cleaner but good wind and solar-thermal sites are frequently remote from the grid, requiring a dedicated transmission line to connect. This transmission line needs to carry the peak currents three to ten times those of a conventional power-station. If the distance is great the cost of the transmission line can easily be the most expensive component in a project.
For example, Capital Wind Farm, the largest in NSW, connects to the grid via a 33kV transmission line just 10 km long. Nevertheless at a cost of about $71m this short transmission line contributed around a third of the total cost of the project. At this was partly funded by the transmission provider some of this cost born by the general consumer; rather than the project owners.
If NSW customers were supplied from wind farms in SA (they are not - although NSW customers pay for it through the LGCs) there would be implicit cost overheads on a similar scale through the entire transmission network.
The impact of the carbon tax on fuel price is not yet apparent. The tax makes the apparent cost of (somewhat randomly selected) fossil fuels higher and in a free market place should depress their price. But the market is not free to move due to contracts, the special relationship between generators and their captive mine and the impact of alternative markets like exports.
The price a generator is prepared to pay for coal is heavily influenced by the price available in National Electricity Market (NEM). This is now higher due to the tax. This suggests that there may be little price movement at least in the short term.
But if electricity demand falls due to the tax, and with it the NEM price, we might expect some fall in the mine-gate price as well, minimising the overall impact on coal demand. This interplay of market forces may well see a return to previous demand levels for coal; or a very marginal dip in the overall upward trend in coal mining; and burning.
In NSW lower industrial demand for electricity has already been contributed to by recent cutbacks in the aluminium industry and manufacturing generally; as a result of the high Australian dollar.
There has also been a long term trend to increased energy efficiency; spurred on by a decade of increases in the electricity price. A number of domestic lighting and consumer electronic products have become significantly more energy efficient and commercial buildings have implemented a wide range of energy saving measures.
These have certainly reduced the amount of fuel required relative to what might have been. But we can expect the longer term growth in demand for energy to rise inexorably; given projected population growth and higher standards of living; in Australia and overseas.
This energy needs to come from somewhere. In the next twenty years this will be predominantly from fossil fuels. The coal is still going to be burnt but at a slower pace domestically where the difference is likely to be taken up by gas; increasingly derived by ‘fracking’ coal seams.
Generation
If you don’t understand where electricity comes from or how it is transmitted there is a short (simplified) primer on this website: Read More…
Generation is not regulated to the same degree as the grid infrastructure as it is deemed highly competitive (unless you are a generator receiving carbon tax compensation). It is intended that eventually investment decisions relating to new power-stations will be market driven and regulation will be minimal.
There are around 260 electricity generators competing to supply electricity to different points in the National Grid.
This competitive position has not yet been achieved as some government owned companies still own much of the generation infrastructure, restricting some investment choices by setting price ceilings and revenue targets.
Governments also interfere in the technology options that generators will be permitted. For example, they continue to apply additional emissions criteria perhaps favouring coal seam gas over coal; rather than relying on rational cost penalties for environmental damage (like carbon trading or fines for methane release) and consequent commercial behaviour; and they impose bans on certain technologies, like the various nuclear options.
As previously mentioned the dispatch price between the National Electricity Market (NEM) and generators is struck every five minutes and averaged to the NEM spot price every half hour for each of five generation regions.
The Australian Energy Market Operator (AEMO) dispatch method is impacted, some say distorted, by the MRET certificates. In meeting a particular demand AEMO calls for offers to supply. It then stacks these from lowest to highest; the final and highest price being the last to complete the stack.
Because wind generators have zero fuel cost, and receive 1 LGC for each MWh provided, they have negative effective energy cost and bid at the lowest price. If wind is available it goes to the bottom of the stack.
The price of coal to a particular station determines the lowest price they can bid without losing money.
At the moment this is around $14 per MWh of thermal energy, on today's coal market. Large generators are around 36% efficient. The price they get for electricity thus determines how much they can pay for fuel. The marginal fuel cost, for coal, on the open market, is presently around $40 per MWh. But the coal price too fluctuates in response to demand. Thus if electricity demand goes up generators make more money; more coal is required and the coal price also rises.
Less efficient thermal stations, and those burning more expensive fossil fuels, will be at the top of the AEMO stack and are most likely to miss out when demand is low. But base load stations need to keep spinning even when there is no load, so they need to bid low to come into the stack and burn coal, even at a price of fuel (and electricity produced) at which they will lose money.
The effect is to suppress the market price and make some thermal stations unprofitable, even though they are essential to meet demand at peak times.
At the same time the consumer is paying more than twice the price of thermal power for wind generated electricity, as a result of the cost to retailers of the LGC’s The base load generators see non of this higher price. It all goes to the renewables - predominantly to Wind.
This may well be a good thing for wind power; but not everyone in the industry is delighted. Some suggest that this is removing the market incentive to invest in new base load capacity.
In other words, at the same time that lower cost base load generators are being squeezed and made increasingly unprofitable, the consumer has to pay an increasingly high price for the electricity generation component of their bill; after taking into account renewable electricity certificates and the carbon tax.
Now, in addition, rooftop photo-voltaic (PV) solar is beginning to add power to local distribution grids in mid-summer, when the market price is at its maximum and thermal stations have previously been assured of a profit. Again the retailer pays for STC’s that subsidise the price of solar.
While again we might applaud the lowering of the peak market price and the reduction of peak grid currents at this time, we will not be so pleased if failure to invest in new generation capacity results in even higher prices; and future brownouts and blackouts.
While at first sight there appears to be a well established competitive generation market, the renewable energy targets and the associated certificates (paid for by our retailer and appearing in our bill) may be having an increasingly adverse effect on future investment decisions; with potentially disastrous outcomes ‘down the track’.
Conclusions
Generators competing to supply the NEM draw energy from many sources. But as a result of the carbon tax the proportions of each fuel are likely to change artificially. Some fossil fuels are presently exempt from the carbon tax (petroleum) or receiving compensation (brown coal). Thus we can expect these to become more dominant in the energy mix than they might have been had the tax not been implemented.
The sad fact is that while imposing economic distortion, not the least by raising electricity prices and then compensating some consumers to minimise the impact on demand, the carbon tax is unlikely to have a significant impact on overall carbon released to the atmosphere.
The present tax serves mainly to distort energy markets; reducing economic efficiency; and hence lowering economic productivity.
As long as we continue to support green energy through the mandatory renewable energy target (MRET) certificates, subsidising relatively expensive wind and solar installations we can expect the price of electricity to continue to rise. At the same time there are real concerns about the level of investment in base load generation required to keep the lights on in future.
These factors begin to make carbon reduction using the nuclear option to progressively replace coal for base-load energy look very attractive in the medium term; but this can't happen in time to assist with meeting the MRET.
This was discussed in some detail above, under the heading 'Meeting the target'.
There is a strong case for replacing both the carbon tax and the mandatory renewable energy targets as soon as possible, well before 2020, and replacing them with a broad based non-discriminatory carbon cap-and-trade scheme designed to meet Australia's Kyoto carbon reduction commitments by reducing carbon intensity across the economy.
By that I mean one in which no industry sector or consumer is exempt or privileged:
- if someone or some business releases a tonne of carbon dioxide, carbon monoxide, or methane - they must buy a credit (no exceptions);
- if they can prove that they have absorbed or sequestered one – they create a credit to sell;
- in order to achieve this any viable, competitive technology is acceptable;
- and if pensioners, or others, are unfairly disadvantaged due to price rises, increase the pension or lower their taxes.
In other respects the scheme would be similar to that proposed by Federal Treasury and Professor Garnaut’s committee in 2010.
Response to comments (see below)
As I have said the falling price of PV solar has effectively put an end to some 100 years of attempts to make thermal solar economic. So let's assume that economies of scale and improved technology will continue to prevail à la Moore's Law, consolidating these gains, and ignore financial cost entirely for a moment.
Let's just look at the limiting technical conditions.
Solar suffers even more than wind from a poor capacity factor. The link referred to: Photovoltaics shows the solar incidence for Paris average 3.34 hrs per day (in spring and autumn). But the difference between summer and winter is over 740%. The difference hour to hour can be even greater; and of course midday to midnight close to infinite.
The problem is that to meet even a tiny fraction of the peak daytime demand in winter you need seven times the number of panels that you do in summer. This means that during minimum daytime demand in summer you will have way more generation than the electricity market can absorb. Germany has already hit this condition several times this year.
Because the spot price of electricity can go negative Germany has had to pay for other countries to take the excess energy away.
If say the present capacity was doubled dumping power would no longer be a viable option. Then for part of the day in summer Germany would need to turn off a proportion of the panels. As I have already said this is presently hard to do and would require additional infrastructure.
As more panels are added to meet periods of high demand, more and more need to be turned off during peak sun and low demand, for longer and longer periods. This reduces the net contribution that a marginal additional panel can make.
These panels consume energy to manufacture, install, maintain and recycle. They also release CO2 in these processes. A British study puts PV solar at about 10 times the CO2 released per kWh of Nuclear (Click Here).
Marginal panels will ultimately fail to recover this 'energy cost of ownership'; so that additional panels never collect the energy expended in deploying them. Well before reaching that point they become more polluting than even fossil fuels.
The same happens with excessive investment in Wind. But Solar is worse than wind because wind has a much better capacity factor. It still blows on rainy days and at night.
So at what point does this decline in effectiveness begin to happen?
As Germany has just demonstrated it begins as the average contribution approaches 6% for solar and as Denmark and South Australia demonstrate, at just over 20% for wind.
Now let's consider cost:
At the point at which production first exceeds demand adding additional panels (or turbines) continues to contribute additional usefull energy at other times but the cost of electricity generated begins to rise rapidly, as panels (ot turbines) are increasingly prevented from delivering all the energy they collect when at their most efficient, on sunny or windy days, if demand is low.
When this happens the other generators, that pay a price for fuel, drop out of the market as the the energy price collapses to zero or less.
But in Australia the renewable energy credits are still paid by the consumer and where feed-in tariffs apply, generators are still paid generously (rather than being fined), increasing the cost to the consumer. Thus unwanted energy is generated at an uneconomic cost to the consumer.
Some of these market distortions may disappear, if as you have said, the price of PV solar falls to the point that it is competitive without any direct or implicit subsidy. But it will still make only a small contribution due to an inherently low capacity factor.
As I have said elsewhere, large scale inexpensive and efficient energy storage and recovery would be a game changer. But present generation batteries have a short re-cycle life (of at best a decade); are still far too expensive; and lose too much energy. Almost everything else is even worse (more costly and/or less efficient). Perhaps super-capacitors can be made to work an integral part of a thin film solar panel.
But when considering the grid and energy demand we are talking in TWh. Not even large scale pump-storage can store enough energy to make up winter demand from summer solar excess.
Sure solar has a place; but probably not more than around 10% of total electricity demand.
For further discussion have a look at Renewable Electricity