The refusal of world governments to introduce a carbon tax on fossil fuel generation has left policy makers struggling with ways to fairly account for the external costs of electricity consumption in overall pricing. Instead of taxing the polluter for carbon produced -- the sensible economic option -- policies are focussed on compensating clean energy technologies for the cost breaks granted to fossil fuels in not including externalities in their pricing. The compensation is either in the form of direct subsidies, or by the creation of protected markets, such as that for green credit trade. The upshot of the compensatory approach has been to focus eyes on the supposed high cost of renewables, rather than on the enormous hidden cost of burning fossil fuels -- past, present and future.
Some countries have introduced partial carbon taxes. Denmark's levy on non-renewables electricity, the Netherlands eco-tax, and now Britain's Climate Change Levy are all functioning variations on the theme. None, however, approach the level of the full "external costs" of burning coal. But the task of introducing a European-wide carbon tax, let alone a worldwide one, has utterly defeated politicians for more than a decade. It is not so much the complexities of carbon tax regulation -- how to apply a tax fairly across the gamut of polluting and less polluting energy sources -- that has stumped them, but the daunting task of tackling the ills of some the most powerful vested interests in the world: the conventional fuel industry.
The medicine, it seems, is just too unpalatable. A carbon tax, so the argument runs, would push up electricity prices to unsustainable levels by making it impossible for industry to compete with counterparts in countries without a tax. It is too much "in your face," to quote a respected British economist, Dieter Helm, who recently appeared before a House of Lords Select Committee in England. So the market sickness prevails.
Governments are not unaware of the external costs dilemma. "To the extent that the electricity industry does not pay these environmental costs and consumers do not pay the full cost of electricity they purchase, energy resources may not be allocated efficiently," admonishes the US Energy Information Administration. In Britain, the Lords committee studying the issue also recommends that, "the government should encourage other Member States [of the EU] to move in the direction of taxation that reflects the environmental impact of energy use." Indeed, plenty of hard evidence is emerging in a broad range of countries that the need to include external costs in electricity pricing is a view now widely shared by government advisory bodies and by electricity regulators.
Economists, for the most part, agree with them. "For true economic efficiency the price should equal the marginal social cost, which includes external effects," according to Shobhana Madhavaen, an economics professor at the London School of Business. The Economist magazine is of the same opinion and favours a carbon tax for including externalities. "An economy-wide carbon tax could be implemented with little of the red tape likely to surround a regulatory approach," it stated last month. In the same article, however, it concedes that "energy taxes do not get far in Congress" and for that reason it is better to pursue a market based support system, such as a cap-and-trade approach to regulating emissions.
If economists have no problems with the use of financial instruments -- such as carbon taxes or market based support systems -- to correct a distorted market, then the cries of "it will ruin us" from opponents start to sound very hollow indeed. Economists clearly see such instruments as market correction, not market manipulation. Dampening demand for fossil fuels, or promoting the renewables, is not necessarily seen as the main aim. Which energy sources step in to make up for the reduced use of coal or oil is irrelevant to economists, just as long as overall economic efficiency is improved. With the price gap between wind and the conventional sources of thermal generation now roughly equal to the external cost of fossil fuels, a carbon tax would inevitably put wind in a strong position.
This is the real world, however, with not a decent carbon tax in sight. Instead there are a plethora of support mechanisms for compensating renewable energy for distorted markets, all with their faults and failings. Different mechanisms have been adopted for different markets, with varying degrees of success in achieving the ultimate aim of realising the full generation potential of wind energy at the least possible cost.
A premium payment for wind output in Germany, fixed by government, has naturally resulted in lots of wind power, but the regulatory simplicity has come at a high cost. Wind in Germany is expensive in comparison with prices paid elsewhere because its support system aims for large amounts of wind power in an area of the world where wind speeds are relatively low. At the other end of the scale, fierce competition for power purchase contracts in Britain under the government's Non Fossil Fuel Obligation (NFFO) revealed to the world how cheap wind power can be when the resource is good. But it also demonstrated that if other vital regulations are not in place, such as streamlined site permitting, a power purchase contract in hand is not the same as wind turbines in the ground. NFFO resulted in dozens of contracts, but relatively few installed wind megawatts.
Between these two extremes of straight subsidy and cut-throat competition lie two other support mechanisms: the "production incentive" approach, as epitomised by Spain's wind support model, which adds a price supplement, and by the Production Tax Credit (PTC) in the United States; and the far more complex "renewables obligation."
Incentives and standards
The production incentive, essentially a price supplement, is paid on top of the "market price" for electricity, whether this is established in a bi-lateral power purchase contract as in North America, or in some form of "power pool" system, as in Spain. By adding the incentive to the price a renewables producer can achieve on the "market," the production incentive model allows wind to be exposed to the price pressures of market forces, an economic benefit for citizens that is prevented under a fixed price model.
But like fixed prices, the production incentive approach breeds political uncertainty, as demonstrated by the roller coaster ups and downs in the industry caused by the on-off PTC in America. Even in Denmark, the recent change in government has shown how a market based on political will does not share the stability of one based on sound economic principles.
A renewables obligation, or Renewables Portfolio Standard (RPS), attempts to do just that. More than a market mechanism, it is an entire market concept based on "legislation which places an obligation on all sellers of power to the retail market to demonstrate through the ownership of tradable renewable energy credits that they have supported the production of a specified amount of electricity from qualifying renewable energy sources."
Like both tendering and production incentive systems, it applies competitive pressure to prices. But the RPS concept also has an overriding advantage compared with all other subsidy systems: it is self-regulating. It requires no authority interference in the contract process. What's more, as long as the RPS is long term, its steady competitive pressure will push down the price of wind power to the point where the RPS sunsets. In other words, the subsidy disappears exactly at the point where it is no longer needed -- preventing any need for governments to step in and create havoc for investors with a sudden red light.
The concept, promoted by the American Wind Energy Association as a long term policy solution for market integration of renewables, has yet to be fully tested anywhere in its pure form, with the possible exceptions of Texas and Australia. It is partially operating in about ten other US states and is about to start-up in Britain, though with complex limitations.
The Achilles heel of the concept lies in its complexity and the need to get all the details right. Particularly crucial is the requirement that governments put their trust in market forces to keep the price to the consumer of meeting the obligation down. Provided there can be enough supply to meet demand created by the obligation, a stiff penalty creates a secure and certain investment climate. A low penalty introduces the risk that power retailers will opt to pay a fine rather than buy green power credits. The higher that risk factor, the higher returns expected by investors and the higher the price of the end product -- the opposite of what politicians are trying to achieve (Windpower Monthly, April 2000). Escape options in the form of low penalties blunt the power of market forces.
from theory to practice
In practice, the effects of these various policies on wind prices supports the theory. Economically, fixed prices are not efficient. Cost will always have a tendency to rise to meet the price on offer, placing an unnecessarily high burden on the consumer. The fixed payment for wind power in Germany, levelised over a theoretical 15 years, is $0.072/kWh. In markets with slightly better winds and which encourage cost reflectivity, the cost of wind generated electricity is just over $0.05/kWh. This is a yardstick figure based on a typical installed price of $1000/kW for a wind installation today on a good, but not exceptional site -- with wind speeds around 7.5 m/s -- an annual charge rate of 10%, and typical operation and maintenance costs (Windpower Monthly, January 2002).
Fixed prices fail to account for falling technology costs over time, changing market conditions, or how hard the wind blows. To be economically efficient, prices should follow these ups and downs. Attempts to achieve price flexibility within fixed price systems -- by using complicated "sliding scale" subsidies to reflect wind speed -- are now in vogue, in Germany, Denmark and France. Indeed, on a good windy site in France the sliding scale brings the price paid down to only a little more than $0.05/kWh. But though sliding scale systems tackle a major problem of fixed prices -- excess profits made on windy sites -- they make no more economic sense than a system which pays a fixed premium price for coal mined from difficult to access reserves compared with coal available elsewhere from easily excavated deposits.
On the cost efficiency stakes, a production incentive system is proving to be superior to a fixed price. Here, the underlying power purchase contract or pool price keeps track of market movements, while the incentive payment reflects the environmental value of wind power. As long as the incentive is no greater than the level of external costs and no less than what is necessary to make a project economically viable, the system in practice is relatively efficient in economic terms. In America wind prices range from $0.032/kWh for large projects on good windy sites to around $0.05/kWh for more expensive projects.
But external costs vary from country to country. The proposed Canadian production incentive is less than half of America's $0.017/kWh (Windpower Monthly, January 2002). It can be argued that this is a fair reflection of the low proportion of fossil fuel generation in Canada, resulting in significantly lower costs of the indigenous generation compared to the US. In Europe an external costs level of around $0.015/kWh has been suggested by the EU's far reaching ExternE study as appropriate in the context of the proportion of fossil fired generation in most European states; the United States has a similar proportion. Since the price of electricity from coal or gas in the US is around $0.03/kWh, America's PTC of $0.017/kWh makes wind competitive at around $0.047/kWh. That and better can certainly be achieved on good wind speed sites.
Evidence of such low prices is being seen in Texas, the only market with detailed experience of a carefully crafted RPS. Exact price levels are a little uncertain, for commercial reasons, but an analysis by the Berkeley National Laboratory concludes that wind projects are being contracted at under $0.03/kWh. Add the PTC and the price of wind is $0.047/kWh, which strongly indicates that the Texas RPS is delivering cost-reflective wind energy with "negligible compliance costs," according to the report. In other words, consumers are having to pay very little more for their electricity and the high penalty for non compliance, $0.05/kWh, is having the desired effect.
The story seems to be similar in Australia, where the first "compliance period" for its Mandatory Renewable Energy Target has just come to a close. The authorities are still totalling up credits to see if all parties have met their obligations and for what price, but with plenty of green power to meet a relatively low target, the indications are that wind energy is coming in at prices between $0.034-0.05/kWh, with the average premium slightly less than the low penalty price of $0.021/kWh. On good sites, its seems, wind is close to being fully competitive, but if there was stronger demand (a tougher obligation target) price might hit the penalty level in the absence of plenty of supply, pushing up the price of wind to more than it costs to produce.
Supply and demand
This is what seems to be happening in Britain and the Netherlands -- a failing which highlights the dangers of getting complex market regulation wrong. Too little supply to meet demand created by regulation appears to be driving up wind prices to high levels in both the Netherlands and Britain, well beyond the level of cost reflectivity. In both countries, deficiencies of the site permitting system are a serious barrier to increasing supply through building more wind plant. Furthermore, fiscal policies -- an option to "buy-out" of the obligation in the UK at a fixed price and an eco-tax in the Netherlands on non renewables generation -- is interfering with the price setting mechanism for green certificates.
The Netherlands does not have an obligation, but a green certificate system driven entirely by consumer demand. That demand is created by an eco-tax on fossil generated power sales to the domestic market, making it possible to sell consumers green power as cheaply as "grey" power. The same eco-tax makes it more profitable for power retailers (utilities) to sell green power to domestic customers than grey. Thus the price of a certificate is dictated by the level of the eco-tax.
The upshot of this is to push up the paper price of green power. Wind producers are only able to sell their electricity with the green certificates attached, so the rising profits from green power retail do not accrue to them. While green power in the Netherlands retails for up to $0.17/kWh, this is twice as much as the producer gets for it, which ranges between $0.07-$0.077/kWh. The system does, however, provide a strong incentive for utilities to build wind by establishing an attractive differential between production price and retail price. An additional incentive is that green power producers are also entitled to a "production subsidy" in the form of a third of the ecotax that would normally be remitted to the tax man.
In Britain, where the Renewables Obligation kicks off next month, a foretaste of the price level was revealed in an auction of "old" NFFO contracts, with wind prices coming in at around $0.09/kWh (admittedly for short term contracts), double that of the last auction and higher than German wind prices (Windpower Monthly, March 2002). Without enough green power to meet the first obligation, UK retailers are anticipating having to pay the price to "buy-out" of the obligation: $0.042/kWh. Since these "fines" are recycled to the industry in proportion to its success in meeting the obligation, retailers seem to be factoring in the monies likely to be returned and this has pushed up prices.
As such Britain's RPS rules contain a fatal flaw that could lead its Renewables Obligation into a Catch 22 where electricity retailers may not make a sincere effort to obtain green credits from potential renewable energy generators and then claim, when no renewables are built, that no credits are available. The lack of a stiff penalty for non compliance is the flaw, as it tempts retailers down the buyout route. Retailers in Britain could end up making a killing on the buy-out circuit at the expense of wind generators, who are no longer the beneficiaries of the RPS price-driver, as intended. This is what is happening in the Netherlands. Meantime, high paper prices, pushed to the level of a temptingly low penalty which puts market forces out of play, could discredit all renewables, consigning them to a permanent ghetto, unless the more competitive technologies are able to flourish on market terms.
So frightening are the prospects of renewables obligations going wrong, that it is tempting to look fondly on the relative simplicity of competitive tenders for delivering lots of wind capacity at low cost. In England NFFO was deemed a "hypothecated" tax and for this reason abandoned in favour of a system which passes cost directly to the consumer without it appearing on the government's tax bill (as a result the consumer, who is the taxpayer, is now likely to end up paying more, but that's another story). Ireland, however, showing less concern about adding to its national tax burden, is pursuing the tender route with its Alternative Energy Requirement (AER). From its start in 1995 the AER avoided some of the pitfalls of NFFO and has been modified over the years in response to criticism.
The AER builds in simple but sensible provisions for market-based "seasonal and time of day" tariffs. These not only make sense to the system operator, but give a small but useful bonus to technologies like wind, which generate more in the winter than in the summer. These days the AER rules also demand that projects have planning permission and set a tight time scale for completion. Under NFFO's low completion rates it appeared that unsuccessful projects had "blocked" others that might have been successful. The Irish government is also looking at infrastructure issues, such as trading penalties and the planning system, with an eye to easing the way for wind.
Under the last AER, 318 MW of large wind power plant was contracted at a maximum price of $0.043/kWh, nearly one cent below the yardstick price for sites with wind speeds of 7.5 m/s. If Ireland delivers 300 MW or so of wind projects with power purchase contracts at that price, the AER tender system will win hands down as the policy which delivers high capacity at low cost.
The ultimate aim of any wind power policy is to achieve high wind capacity at low cost. If the wind industry can and does deliver in Ireland at the accepted bid prices, government controlled tendering would seem to be the answer. But in a world where the aim is to reduce the overall tax burden and encourage free markets -- to the extent of deciding that carbon emissions trading is better than direct regulation for tackling global warming -- the Irish policy looks like a dying breed.
So do fixed price policies, even when made more cost-reflective with the use of sliding scales to reflect wind speed (site productivity). Production incentives in Spain and the US clearly deliver results: lots of capacity and prices that are cost reflective, both in terms of the cost of generation and external costs. They are also transparent and easy to administer. But as a political fix for electricity market failings rather than a permanent cure, they are hard to justify on a long term basis.
In Texas and Australia, where green credit trade has been introduced in carefully crafted Renewables Portfolio Standards (renewables obligations), prices are also low and probably cost-reflective. An advantage of green credit trade is that it should be possible to merge the concept with that of trade in carbon emissions -- marrying two fundamental pillars of a solid market structure in which renewables can grow. It also removes wind power from the necessity of competing head to head with fossil fuels and nuclear in electricity markets, like those of Europe in particular, which have been fundamentally distorted by a century of subsidies to monopoly power industries.
There is a downside, however. Early experience of green credit trading from both Britain and the Netherlands is providing evidence that markets for trading the environmental value of green power will lead to unnecessarily high prices -- and still not produce much in the way of wind power capacity -- if they are structured with inherent flaws.