Is the Government’s approach to the use of biomass to meet our power needs in danger of being subverted? The renewable energy sector is a dense thicket of acronyms, denoting the range of subsidies and contracting mechanisms being used to provide support to the various technologies being used to reduce our reliance on fossil fuels. In the case of biomass, there appears to be a real risk that both investors and the Government may be uncertain about the overall effect of these complex rules, which risk undermining the policy position that has been settled on.
Under Electricity Market Reform (EMR), in line with the Government’s Bioenergy Strategy, the Department for Energy and Climate Change (DECC) has committed to supporting biomass combined heat and power (CHP) projects via the new Feed-in Tariff (FiT) Contracts for Difference (CfDs). At the same time it has committed not to support dedicated ‘electricity-only’ biomass facilities, largely due to the perception that the level of support such plant need to be economically viable is higher per tonne of carbon abated than other renewable energy technologies.
Some infrastructure lenders I recently spoke with suggested that the forthcoming requirements for large biomass CHP generators under the FiT CfDs would be far more stringent than those under the established Renewable Obligation (RO) regime. It was suggested that if heat offtake was to fall away at any time (for example if a major industrial off-taker ceases to operate) the CfD strike price for the electricity element of the station (which usually represents the majority of revenues) would be lost. This would mean that the heat element of the project (usually a small share of total revenues) would represent a disproportionate element of project risk, which, the investors felt, might discourage interest in large scale biomass CHP projects.
Hearing these views compelled me to check things out for myself, and I was surprised that I couldn’t find any grounds for their concerns. Previous drafts of DECC Guidance on CfD terms had suggested that in order to receive the CfD strike price (of £125/MWh), which would be paid alongside the RHI tariff for each MW of qualifying heat produced, stations would need to produce a “Guidance Note 44 Certificate” each year to demonstrate that they meet the Quality Index (QI) of the CHP Quality Assurance (CHPQA) standard. This was consistent with the structure of payments under the RO.
Also consistent with the RO regime, under a CfD, 100% of electrical output from a station that meets the CHP quality index is considered to be qualifying power output (QPO). If the station doesn’t meet the QI in any given year, then payment of the strike price is made only upon its QPO. This is to ensure that support is provided for genuine CHP projects only, in line the requirements of EU Energy Efficiency Directive.
So, apparently no change from the situation under the RO, then? I’m not so sure. After further delving into DECC’s myriad of consultation documents and responses relating to EMR, I found a consultation where DECC proposed to introduce an additional payment safeguard. The version consulted upon would have allowed payments to be made by the CfD Counterparty to the generator for the first five years of operation, regardless of whether it met the CHPQA standard – that is to say the plant could have no heat off-take in place at all, but still get the £125/MWh strike price during these years.
Then in its response to the consultation, DECC gave further flexibility, allowing generators to apply this five year ‘grace’ period at any time of their choosing during the 15-year CfD period, rather than it being limited to a set time period in the CfD. In addition, DECC clarified that the five years of the amnesty need not be applied for in a single block, and may be split non-consecutively.
Whilst the Scottish Government has put parallel arrangements in place for stations in Scotland, the wider RO does not appear to have such generous terms. Consequently, the fears of the aforementioned lenders notwithstanding, risks around investment in large CHP projects are lower than for investments falling under the RO regime. A generator building a new plant could have full five years at the outset to find a replacement heat off-taker, or to replace one that falls by the wayside at any other time during the 15 year CfD period.
One could interpret this as demonstrating DECC’s commitment to delivery of lower carbon energy and delivery upon the targets within its Heat and Bioenergy Strategies, but I fear it could turn out to be a loophole that subverts them. What will happen to facilities that are developed in the absence of a genuine heat off-take agreement, and fail to secure one in subsequent years? Consider MGT’s huge plant at Teesport, which was given planning consent in 2009. This has an electrical generation capacity of 275 MWe, and correspondingly a massive heat output, potentially several times greater. To my knowledge, no manufacturing or refining facility in Teesport (or thereabouts) needs such enormous thermal input, so if it is be a genuine CHP plant, MGT’s station will be relying upon new major manufacturing businesses locating in the area. Despite the Government’s and Local Enterprise Partnerships’ best efforts, this seems hopeful at best.
Nevertheless, DECC somehow appears to be confident that MGT will receive offers for a large proportion of its heat. Following a competitive process, the Department has recently selected the project from a field of 58 for what has been termed the Final Investment Decision (FID) Enabling Program. Together with seven others, the project has therefore been given an early version of a CfD to help it reach financial close.
But will MGT (and similar facilities) ever meet the GQCHP standard? Will much of the station ever be QPO? If a major heat off-taker doesn’t emerge, this is unlikely; but of course they’ll still have the 5 year grace period to work through, Once that has elapsed, I wonder how much appetite DECC will have for pulling the plug on the CfD, especially if baseload capacity is tight.
A cynic might suggest that the financial model, upon which MGT’s investors (a group of Korean companies) are basing their decisions, could be fully pricing in the risk that the plant may only receive the full strike price for 5 years. Then, if the plant goes ahead, and if DECC buckles and allows contract amendments after five years, then any additional grace years MGT is allowed will be a potentially lucrative upside to the investment. It will also mean that the new rules for biomass CHP have turned out just to be a Trojan horse to allow in new, large scale electricity-only facilities of the kind the Government currently believes to be too costly.
The drafting of the consultation response unfortunately does not make clear everything one might wish it to. What power price would apply, for example, if outside its chosen grace periods the station did not generate any useful heat? Or what price would apply to the proportion of the plant which is not QPO? In the absence of a strike price for biomass without CHP under the FiT CfD regime, I assume it would be determined via the specific power purchase agreement (PPA) with the relevant licensed electricity supplier, and is therefore likely to be lower than under the RO. Further consideration of this issue might give a clearer idea of the numbers being pondered by MGT, its investors, and others in the same boat.
To find out, will mean spending several painstaking hours hacking my way through the dense underbrush of detail in another tranche of DECC documentation relating to EMR, and speaking with the unfortunate civil servants who are struggling to understand how the rules on biomass might play out. Fun though that sounds, I think it’s a task for another day.