The government’s biggest support scheme for renewable energy is known as the Renewables Obligation (RO). The scheme was put in place in 2001. It places an obligation on all retailers of electricity to source a proportion of their electricity from renewable sources. The Obligation will remain in place until 2027 and the renewable proportion grows each year, from around 3 per cent in the first year to reach 20 per cent of supply.
To prove that the retailer has complied with the obligation, a system of electronic ROCs is employed. At the end of each financial year the amount of each retailer’s obligation is determined by Ofgem, which administers the RO. The retailers can then discharge their obligation, either by presenting ROCs to prove that they have used the required proportion of renewable power, or by paying a ‘buyout’ (fine) for each megawatt hour where non-renewable (often called ‘brown’) power was supplied instead. The cash in the buyout fund is repaid, pro rata, to the retailers who presented ROCs.
The upshot is that each ROC has a value equal to at least the buyout fine, and potentially considerably more if there is a shortfall in renewables generation, and many retailers are forced to pay some buyout fees to fulfil their obligation. This has been the case every year, and in fact is designed to be so: the Obligation level is increased each year to ensure that there is a shortfall in the generation achieved, so that renewables project developers can rely on receiving buying cash.
These three components provide the elevated power price required to make a renewables project financially viable. A renewables power project must first be certi- fied by providing information about the plant to Ofgem. Once it is accepted, the plant is awarded one ROC for each megawatt hour of power it produces. The generator can sell the power, the ROC and the likely benefit from the buyout fund.
The Renewables Obligation differs from many support schemes used in other countries because it does not specify which renewables technologies should be employed, nor exactly how much subsidy generators will receive. Many European countries have favoured fixed tariffs (often known as feed-in tariffs), with a different tariff set for each form of renewable energy and paid for each megawatt hour gen- erated for a specified number of years. But the UK favoured ‘market’ instruments, whereby the government’s role was not to distinguish between technologies but to allow the market to bring forward the most competitive.
Finance and local generation 151 This was partly because of a general government preference for market instru- ments, and partly because the avowed intention of the Obligation was to bring renewable energy on to the grid as quickly as possible, at the lowest possible price. In this it has been successful as well-developed technologies, particularly wind power, ramped up installation rates. The British Wind Energy Association, for example, notes that it took 14 years for the UK to install 1 000 MW of wind power, but just 20 months to install the next 1 000 MW.
However, the structure of the subsidy means that it is far less useful in bringing newer technologies forward, something developers of wave- and tidal-power projects have highlighted. It also has very limited usefulness for small and distributed power generators, especially those whose business is not power generation but who have an interest in a local power project for other reasons – to provide on-site power, for example, as a community project, or who have a very small source such as PV panels.
What is the problem? First of all ROCs are cumbersome and costly to administer. Registering as a renewable power source is just the start: although Ofgem has sim- plified the forms required for this process for microgenerators, below 50 kW, they are still 20 or more pages long and necessarily address technical issues that could be difficult for this group – who are generally installing domestic systems – to get to grips with. Systems over 50 kW in size require still more information.
Once they are registered, it is necessary for generators to prove how much power they have generated and to make returns to Ofgem on a regular basis. For micro or domestic users this will probably require new, more sophisticated, meters and the cost could outweigh any benefit from ROCs. It has been proposed that, instead, generators at the domestic level should have a ‘deemed’ figure for the average likely generation of their installation and receive ROC benefits on that basis, but so far this has not been implemented.
Companies are more likely to have half-hourly meters already in place, but will have an additional administrative burden that could mean significant costs.
For this reason, many small generators will rely on an agreement with their elec- tricity retailer to manage their electricity production. This has its own disadvantage, which is mainly that the price offered is likely to be very low and if the installation is very small no price may be on offer.
Companies argue that the contingent nature of the Renewables Obligation is the reason why they offer small generators low prices for the power they have available to export. The base electricity price can vary considerably, as anyone with an electricity bill knows, and the value of the renewables certificate can also vary because, although the buyout price is fixed in advance, the amount of buyout fund likely to be recycled is not known, so nor is the full value of the ROC. Some party has to bear the risk of this unknown price, so power retailers who offer fixed prices to distributed generators will pitch it very low. In practice, retailers have not been obliged to offer export deals to small generators and often declined them, but, at the time of writing, this seemed likely to change, with a new requirement on the horizon that would force retailers also to offer export tariffs.
The cost and complexity of the export process have meant that small generators who may have had power available have sometimes decided not to export, as the costs
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are far greater than the benefits. And, although the RO always included an option of selling ROCs to a consolidator, intended to provide a simpler route to market for small generators, this has never been successful.
An interesting variant of the RO that has been used in Australia for several years calculates an average lifetime generation for a small renewable energy source such as domestic PV and calculates the number of ROCs that would be generated over the life of the scheme. For domestic PV, in the Australian version, the lifetime ROCs are awarded to the PV supplier at the outset, who translates them by an agreed formula into a discount on the purchase price. A similar system has been proposed in the UK. Finally, a major problem with the RO for many local energy projects is that it is entirely focused on electricity production. No benefit or subsidy is available for heat production using this route. This clearly means that heat-only sources are excluded but it also dramatically reduces the amount of subsidy available for mixed sources, which often offer greatly improved efficiency, such as combined heat and power.
CHP has huge potential in all kinds of projects, industrial, commercial and large- scale domestic, where both heat and power are required. CHP projects using fossil fuel would not be eligible for ROCs in any case, but some could use local biomass for fuel and in theory many would be eligible as renewable-energy generators.
But in most projects heat is the most important product – for process heat in industry, heating in commercial premises, etc. – whereas electricity is a by-product. The amount of electricity produced, even in a large product, may be relatively small and production can vary dramatically depending on the heat needs of the site. That puts even large biomass CHP owners in a similar position to small generators: they have a few megawatt hours of power to generate, often unpredictably, so the price they can get for the power, even with ROCs, is low – and often not enough to justify investing in an efficient CHP plant instead of a simple boiler that provides only heat. An Act of Parliament on climate change passed in 2006 required the UK govern- ment to investigate the possibility of a renewable-heat obligation to run in parallel with the RO. There was a precedent for this: the government had already decided to introduce a renewable-transport-fuels obligation that would require transport-fuel suppliers to mix a proportion of biomass-derived fuel with petrol and diesel.
The government had previously resisted the idea of a renewable-heat obligation, saying that, unlike for electricity and transport fuel, where there was a defined group of retailers, it would be extremely difficult to identify a group of heat suppliers to be charged with the obligation.