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First flesh on the bones of the new UK government’s energy policy?

The UK Department of Business, Energy & Industrial Strategy (BEIS) chose 9 November 2016 to release a series of long-awaited energy policy documents.  The substance of some of the announcements, which primarily cover subsidies for renewable electricity generation and the closure of the remaining coal-fired generating plants in England and Wales, was first outlined almost a year ago when Amber Rudd, the last Secretary of State for Energy and Climate Change, “re-set” energy policy in outline in a speech of 18 November 2016.  Broadly speaking, the documents indicate that little has changed in the UK government’s thinking on energy policy following the EU referendum and the formation of what is in many respects a new government under Theresa May.

Contracts for Difference

BEIS has confirmed that the next allocation process for contracts for difference (CfDs) for renewable generators will begin in April 2017, aiming to provide support for projects that will be delivered between 2021 and 2023. There will be no allocation of CfD budget for onshore wind or solar, consistent with the Government’s view that these are mature and/or politically undesirable technologies which should no longer receive subsidies.  The only technologies supported will be offshore wind, certain forms of biomass or waste-fuelled plant (advanced conversion technologies, anaerobic digestion, biomass with CHP) wave, tidal stream and geothermal.

The budget allocation is a total of £290 million for projects delivered in each of the delivery years covered: 2021/22 and 2022/23. Details are set out in a draft budget notice and accompanying note.  CfDs are awarded in a competitive auction process, the details of which are set out in an “Allocation Framework” (the one used for the last auction, in 2014/2015, can be found here).  It is likely that most, if not all, of the budget will be taken up by a small number of offshore wind projects, as the size of the projects which could be eligible to bid in the auction is large in comparison with the available budget.

Competition for CfDs will be fierce and Government should be able to show progress towards achieving its target of reducing support to £85/MWh for new offshore wind projects by 2026. For the 2017 auction, “administrative strike prices” have been set at levels designed to ensure that “the cheapest 19% of projects within each technology” can potentially compete successfully.  Behind this terse statement and the methodology it summarises lies an extensive BEIS analysis of Electricity Generation Costs, underpinned or verified by studies or peer reviews by Arup, Imperial College, NERA, Prof Anna Zalewska, Prof Derek Bunn, Leigh Fisher and Jacobs and EPRI.

The heat is on

Alongside the draft budget notice, BEIS has published two documents about CfD support for particular technologies.

One of these is a consultation that returns to the long-unanswered question of what to do about onshore wind on Scottish islands: should it be regarded as just another species of onshore wind (and therefore not to receive subsidy, in line with post-2015 Government policy), or does it face higher costs to a degree that merits a special place in the CfD scheme, as was suggested by the 2010-2015 Government?  It comes as no surprise that the Government favours the former view: another item to add to the list of points on which the UK and Scottish Governments do not see eye to eye.

The second document is a call for evidence on the currently CfD-eligible thermal renewable technologies of biomass or waste-fuelled technologies (including biomass conversions), and geothermal.  These raise a number of issues, on which the call for evidence takes no clear stance.

  • Is continued support for the fuelled technologies in particular consistent with getting “value for money” by focusing subsidies on the cheapest ways of decarbonising the power supply (except onshore wind and solar), given that (with the exception of biomass conversions), they have a relatively high levelised cost of electricity generation?
  • Can they be justified on the grounds that they are “despatchable” (and so do not impose the same burdens on the system as “variable” renewable generation like wind and solar)?  Or on the grounds that (where they incorporate combined heat and power), they contribute to the decarbonisation of heat, as well as of power generation – an area in which more progress needs to be made soon in order to meet our overall target for reducing greenhouse gas emissions under the Climate Change Act 2008 (and the Paris CoP 21 Agreement)?
  • Is the current relationship between the CfD and Renewable Heat Incentive support schemes the right one in this context?  Is a CfD for a CHP plant unbankable because of the risk of losing the heat offtaker?
  • Are all these technologies about to be overtaken as potential ways of decarbonising the heat sector on a large scale by other contenders such as hydrogen or heat pumps (and if so, is that a reason to abandon them as targets for CfD or other subsidy)?
  • Should more existing coal-fired power stations be subsidised to convert to burning huge quantities of wood pellets (is that really “sustainable” – and would such subsidies comply with current EU state aid rules, for as long as they or something like them apply in the UK)?

Against this background, the draft budget notice proposes to limit advanced conversion technologies, anaerobic digestion and biomass with CHP to 150MW of support in the next CfD auction.

Kicking the coal habit

Finally, BEIS is consulting on the best way to “regulate the closure of unabated coal to provide greater market certainty for investors in the generation capacity that is to replace coal stations as they close, such as new gas stations”.  The consultation needs to be read alongside BEIS’s latest Fossil Fuel Price Projections (with supporting analysis by Wood Mackenzie).  These set out low, central and high case estimates of coal, oil and gas prices going forward to 2040.  BEIS has significantly reduced its estimates for all three fuels under all three cases as compared with those in its 2015 Projections.

We are talking here about eight generating stations, which between them can produce 13.9GW. Their share of GB electricity supply tends to fluctuate with the relative prices of coal and gas.  Most are over 40 years old.  All can only survive by taking steps to comply with the limits on SOx, NOx and dust prescribed by the EU Industrial Emissions Directive – at least for as long as the UK is within the EU.

The Government’s difficulty is how to ensure that these plants close (for decarbonisation purposes), but on a timescale and in circumstances that ensure that the contribution that they make to security of electricity supply is replaced without a gap by e.g. new gas-fired plant, of which so little has recently been built. BEIS evidently hopes that by the time this consultation finishes on 1 February 2017, the results of next month’s four-year ahead Capacity Market auction will have seen a significant amount of new large-scale gas fired power projects being awarded capacity agreements at prices that make them viable (when taken together with expectations of lower-for-longer gas prices).

Although BEIS professes confidence in the changes that it has made to the rules and market parameters for the next Capacity Market auctions, one cannot help but wonder how convinced Ministers are that the 2016 auctions will succeed in this respect where those of 2014 and 2015 failed.  Because from one point of view, if the Capacity Market does result in new large gas-fired projects with capacity agreements, and gas prices remain low, the market should simply replace the existing coal-fired plants – which, as the consultation points out, aren’t even as flexible as modern gas-fired plant.  Maybe if a newly inaugurated President Trump pushes ahead with his plans to revive the use of coal in the US, higher coal prices will help accelerate the closure of some of our remaining coal-fired plants: BEIS calculates that with relatively low coal prices and no Government intervention, they could run until 2030 or beyond.

So how will Government make the plants close? Two options are proposed.  One would be to require them to retrofit carbon capture and storage (CCS), the other would be to require them to comply with the emissions performance standard (EPS) that was set in the Energy Act 2013 for new fossil-fuelled plant with a view to ensuring that no new coal plant was commissioned.  Neither path is entirely straightforward.  As it seems unlikely that operators would invest the kinds of sums associated with CCS on such old plant, there must be a risk that in trying to make CCS a genuine alternative to complete closure, regulations could end up allowing operators to run a significant amount of capacity without CCS whilst taking only limited action to develop CCS capacity.  With the EPS approach, there would be some tricky questions to resolve around biomass co-firing, as well as biomass conversion, if that were to remain an eligible CfD technology and budget were to be allocated to it.

When it comes to consider how to ensure that coal closure does not involve a “cliff-edge” effect, the consultation seems to run out of steam a bit: having mentioned the possibility of limiting running hours or emissions, either on a per plant basis or across the whole sector, BEIS says simply that it would “welcome any views on whether a constraint [on coal generation prior to closure] would be beneficial and, if so, any ideas on the possible profile and design”.

What next?

Nothing stands still.  The period of these consultations / calls for evidence, and the next Capacity Market auctions, overlaps with other processes.  Over the next few months, the Government is scheduled to produce over-arching plans or strategies in a number of areas that overlap with some of the questions posed in these documents.  It will also continue to develop its strategy for Brexit negotiations with the EU; and the European Commission will publish more of its proposals on Energy Union (including new rules on renewables, market operation and national climate and energy plans).

The documents state more than once that while the UK is an EU Member State, it will “continue to negotiate, implement and apply” EU legislation. But – at least in relation to coal closure – the Government is trying to make policy here for the 2020s.  By that time, it presumably hopes, it will no longer be constrained by EU law.  It remains to be seen how Brexit will affect the participation of our remaining coal-fired plants in the EU Emissions Trading System, which is at present a significant feature of the economics of such plant.  In the short term, the coal consultation points to an announcement in the Chancellor’s 2016 Autumn Statement (23 November) of the “future trajectory beyond 2021” of the UK’s own “carbon tax”, the carbon price support rate of the climate change levy.

After a period in which we have been relatively starved of substantive energy policy announcements, things are starting to move quite fast, and decisions taken by Government over the next few months could have significant medium-to-long-term consequences for UK energy and climate change policy.

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First flesh on the bones of the new UK government’s energy policy?

DECC’s latest consultation on Feed-in Tariffs – an Era of “FIT Austerity”?

The UK Department of Energy and Climate Change (DECC) has launched a consultation proposing savage cuts in the levels of subsidy under the Feed-in Tariffs (FITs) regime for small-scale renewable electricity generation (the Consultation).  This comes only a few weeks after DECC announced the ending of more or less all subsidies for onshore wind, the removal of the renewables exemption from the Climate Change Levy and other proposals designed to reduce the costs of renewable subsidies significantly.  What does the Consultation say, and what does it mean for the future of renewables in the UK?  We look first at the background of the FITs regime and then at the detail of the proposals.

Some background

The legal foundation for the FITs regime was inserted very late in the Parliamentary passage of the Bill that became the Energy Act 2008.  Although there had been pressure to include provision for FITs from the moment the Bill was introduced in January 2008, the then Labour Government only finally gave in to it on 5 November 2008, by which time the Bill was rubbing shoulders in the Parliamentary timetable with legislation designed to avert financial meltdown as a result of the banking crisis.

Perhaps we should not be surprised that a scheme launched in the far-off days of Gordon Brown’s premiership should now be in the process of being dismantled, after 5 years of apparently too successful operation, as part of the current Conservative Government’s attempts to reduce public spending (whether funded from taxation or levies on consumers).  To see quite how different the world looked in 2008, it is worth recalling that Ministers then looked forward to a time when, by 2020, the Renewables Obligation (RO), newly modified to include different bands of support for different technologies would be “worth about £1 billion a year in support of the renewables industry”.  Current annual support under the RO runs at around three times this level, and it may hit £5 billion by 2020.

During the passage of the 2008 Energy Bill, EU Member States were set the targets for the percentage of final energy consumption from renewable sources that they would have to meet by 2020 under the Renewables Directive of 2009.  Some suggested that the UK would not meet its target of 15% unless FITs were introduced.  There was a widely held view that following the German model of FITs was at least an essential supplement to the RO, and that feed-in tariffs were generally, and could be in the UK, a cheaper way of subsidising renewables.

That was perhaps over-optimistic.  DECC and Ofgem figures show that in 2013-2014, generating stations accredited under the RO produced 49.6 TWh, or 16.3% of electricity supplied in the UK. At the same time, FIT installations produced 2.6 TWh, or 0.84% of the UK’s final consumption of electricity.  But whilst the output of RO-subsidised generation to FIT-subsidised generation stood in a ratio of about 19:1, the comparative costs of RO were no more than 4 times those of FITs.  Another comparison from DECC’s evidence review of FITs is even more interesting, when it calculates that the p/kWh cost of FIT-generated electricity is about 3 times the level of the strike price under the proposed Contract for Difference (CfD) for the Hinkley Point C nuclear power station.

Perhaps this should come as no surprise.  FITs were intended as a way of encouraging “microgeneration”.  One of the ways that renewables resemble other forms of power generation is that they tend to be more cost-effective on a larger than on a smaller scale.  But FITs were not just about meeting targets: they were to make renewable generation accessible to individual households for whom trying to deal with the RO was (in the words of one MP, apparently speaking from personal experience) a “bloody nightmare”.  FITs would be simple, and they would popularise renewables.

That part certainly seems to have worked.  As DECC notes, the scheme has all but reached 750,000 FIT installations already – a level it was not originally expected to reach until 2020.

Headline proposals

DECC says that the deployment of FITs has been significantly exceeding its projections both in terms of numbers of installations and installed capacity. As a result, the FIT scheme has put undue financial pressure on the Levy Control Framework (LCF), which was created to limit the extent to which consumer bills increase to fund the subsidies for low-carbon generation.  The measures proposed in the Consultation are intended to remedy these problems.

Significant decreases in generation tariffs for solar PV, wind and hydro power 

At the larger end of the scale of FIT eligible installations, generation tariff reductions are proposed for:

  • standalone solar PV (Large Solar PV) – from 4.28 p/kWh to 1.03 p/kWh;
  • wind farms with a capacity >1.5 MW (Large Wind) – from 2.49 p/kWh to 0 p/kWh; and
  • hydro installations with a capacity  >2MW (Large Hydro) – from 2.43 p/kWh to 2.18 p/kWh.

Installations with smaller capacity would also see their tariffs reduced, in the case of solar PV, even more steeply, with 4 kW installations having an 87% reduction in generation tariff levels.

In addition, the different capacity-based generation tariff bands for each technology would change (their number being reduced in the case of wind and hydro and the boundaries redrawn for solar).

It can be said that the relative levels of reduction in generation tariffs roughly correspond to the extent to which DECC’s Impact Assessment reckons the different sizes and types of installation have seen reductions in their grid connection and capex costs since 2012.  But only roughly: for example, it appears that Large Solar PV has seen an increase of 3% in costs and will have its tariff reduced by 76%, while the smallest PV installations have seen a decrease in costs of 35% and will have their tariff reduced by 87%. These reductions in generation tariffs are said to be aiming at a target rate of return of 4%, as compared to the 5-8% range of rates of return that was used to calculate the current tariff rates

The changes would mean that for future solar PV installations, the generation tariff (received on all the power they generate) would be a much less significant component of their revenue stream than it has been historically.  For those receiving the export tariff for the electricity which they export (or are deemed to export), the export tariff is likely, at least initially, to be higher in p/kWh terms, but by far the largest benefit for those who consume the renewable electricity that they produce will be in the avoidance of the costs of purchasing electricity generated elsewhere from a third party supplier.

The problem for most solar installations though, especially on domestic premises, is that for much of the year, the bulk of household energy consumption tends to occur at times when there is no sun and no generation.  The solution to that would be to connect your PV panels to a battery and store the electricity generated during daylight hours for the evening.  But – needless to say – the Consultation contains no proposals for any new German-style subsidy for adopting storage technology.


At present, FIT generation tariffs “degress” periodically by a fixed percentage automatically, but can degress further if deployment reaches specified thresholds (contingent degression).

The Consultation proposes:

  • a new fixed quarterly degression mechanism, reducing generation tariffs available for new Large Solar PV to zero by January 2019.  DECC is not proposing to degress the generation tariffs for Large Hydro, which would stand at 2.18p/kWh throughout the three-year period budgeted for under the Consultation;
  • harmonising the frequency of degression to quarterly across all technologies; and
  • a further degression of 5% if deployment of FITs exceeds DECC’s deployment projections, and 10% if the cap (discussed below) on the eligibility of new projects for the FIT scheme is reached.

The Impact Assessment takes as a working assumption the proposition on which DECC consulted in July, that future FIT eligible installations will not be able to protect themselves from the impact of degression by applying for preliminary accreditation when they have planning permission and an accepted offer of a grid connection, thereby “locking in” to the higher tariff band prevailing at the time of preliminary accreditation for a period of between 6 and 30 months (depending on technology and ownership of the installation) provided that they are commissioned and accredited within that period.


Previously, both generation and export tariffs have risen automatically in line with the Retail Price Index (as under the RO).  New installations will see their tariff payments rise according to the movements of the Consumer Price Index link (as under the CfD regime), which is less generous.

Overall cap

So far, the proposed changes, although they slash the amounts of support available to new installations, leave the basic architecture of the regime in place.  But the existence of the proposed new FIT regime is a much more precarious thing than might be suggested by any of the above.

This is because DECC further proposes:

  • a maximum overall budget for the FIT scheme of £75 – 100 million for the period from January 2016 to 2018/2019.  This would apparently be expressed as a series of quarterly limits on FIT-supported deployment at each generation tariff level, so that once the cap is reached no further generating capacity would be eligible for the tariff during the period to which the cap applies;
  • separate caps for each of a number of different capacity-based bands for solar and wind (each of which cover a number of generation tariff bands).  These would limit quarterly FIT solar deployment, for example, to between 42 MW and 54 MW during the period budgeted for by DECC in the Consultation (Q1 2016 – Q1 2019).  This is less than is typically accredited in a single month at present.  The caps on larger solar installations would limit deployment under FIT to one or two per quarter; and
  • unlike the measures relating to generation tariffs and degression, the caps would apply to anaerobic digestion (AD) installations as well as solar, wind and hydro.

With exquisite understatement, DECC observes: “We recognise that implementing deployment caps presents significant logistical challenges.”, although DECC has outlined a number of possible ways in which the caps might be administered (essentially, by Ofgem or by licensed suppliers).  Anticipating the possible objections to a system where eligibility for a particular tariff (or any support at all) would depend on the relative timing of accreditation of different installations, measured in seconds, DECC proposes to suspend the FIT regime pending any better suggestions.  Anticipating the objection that a cap will simply not achieve its purpose of controlling costs, the Consultation proposes the alternative solution of ending generation tariffs altogether, possibly as soon as January 2016.  The industry is, in effect, challenged to accept the capping proposals or face potentially worse consequences.

Almost as an afterthought, DECC adds that its consideration of “further amendments to the existing FITs scheme to ensure that it provides better value for money” includes “consideration of whether future applications within a system of caps could be prioritised through a competitive process“.  It’s a pity the CfD regime, with its competitive allocation process, wasn’t designed to cover microgeneration.

Other points

DECC is concerned that (especially in the wind and AD sectors) the “extension” of an existing FIT installation – or developing what is in truth a single installation in a series of separately accredited stages – can be used as a way to gain the benefits of economies of scale associated with larger installations whilst qualifying for the higher generation tariff rates associated with smaller installations, leading to “overcompensation”.  To put an end to this, it is proposed to “put in place a rule to prevent new extensions claiming support under FITs.”  No detail is given as to how this will work in practice.

When the Energy Bill was being debated back in 2008, three issues were often raised (not necessarily in connection with FITs) on which less progress has been made in the intervening years than could have been wished: smart meters, the impact of small-scale renewable generation on distribution networks, and energy efficiency.  The Consultation has something to say on each.

  • DECC propose to end the practice of estimating how much electricity smaller installations export to the grid (deemed exports) in favour of full metering of exports, and may take further measures to enable remote generation meter reading.  The key question here seems to be whether existing installations of 30kW and below should be compelled to accept smart or “advanced” meters in order to facilitate this more accurate and “remote” measurement of their FIT entitlements.  DECC note that deemed exports were meant to be a temporary measure.  It remains to be seen whether smart meters will be rolled out before the FITs regime closes to new installations.
  • More accurate measurement of exports would facilitate a further reform: moving to “dynamic” export tariff rates that could reflect changes in the wholesale price of electricity, rather than the current, static export tariff rates.  It is a matter of concern to DECC that “the current export tariff is higher than the wholesale electricity price, with resulting overcompensation of generators by suppliers“.  This is because the tariff is meant to represent the wholesale price less the value of the transmission and distribution costs which suppliers do not have to pay in respect of FIT electricity (even though, DECC acknowledges slightly confusingly “in certain circumstances these can be additional rather than avoided costs“).
  • DECC propose an obligation to notify DNOs of new small-scale generators to facilitate grid management.  The problems of DNOs not being made aware of new generation on the grid are not new.  Such an obligation is perhaps a case of “better late than never”, but would no doubt have been more welcome to DNOs when FIT generating capacity was still increasing at a rate unconstrained by the proposed new caps.
  • DECC propose that roof-mounted solar PV installations seeking to accredit at the higher generation tariff rate should satisfy the requirement of being at least in energy efficiency band D before they commission the solar installation, rather than being able to count the installation itself as one of the things entitling them to be certified at band D or above.  Under the current regime, the higher tariff sees to have become effectively a default rate, applying to 99% of installations, rather than setting any kind of incentive to improve the energy efficiency of buildings.  DECC mentions, but is not yet proposing, the further step of raising the higher tariff threshold to band C.

Finally, DECC is “considering implementing”, but is not yet proposing, changes such that AD plants that sought accreditation under the FIT regime would have to comply with the same sustainability requirements that the feedstock of AD plants seeking support under other renewable incentive mechanisms (e.g. the RO and Renewable Heat Incentive) are required to observe.  This would be to avoid FITs becoming a haven for operators with non-compliant feedstocks.

The good news?

In contrast to some of its recent proposals in relation to the RO, DECC has reasserted its commitment to its “grandfathering” policy on FITs, so that existing installations will not be affected by the proposed changes to tariffs and caps.  However, the Consultation does not address explicitly the question whether any tariff reductions will affect projects which have been pre-accredited (whilst this was still possible) but have not achieved full accreditation at the point when the new tariffs come into effect. Such projects are likely to be at risk of being subject to the new, lower tariffs if construction or grid connection delays result in them not being commissioned and applying for full accreditation within their pre-accreditation periods of e.g. 6 months (12 months for community projects) for solar PV.  But it is to be hoped that if they are commissioned and accredited within their pre-accreditation periods, they will still benefit from the earlier, higher tariffs prevailing at the time of their pre-accreditation.

What next?

The proposed measures in the Consultation, if implemented, will bring about a drastic change in the FITs regime.  Is this anything more than the latest manifestation of fiscal austerity, or are the Government’s proposals for the FITs regime part of a coherent renewables / energy policy?

There are a number of points on which the proposals are notably consistent with other statements of the present Government’s policy on renewables.  The gentlest decrease in solar PV generation tariffs (a mere 62%) has been applied to the 250-1000kW band which most obviously represents the commercial rooftop solar sector that DECC has said it wants to see expanding.  The fact that wind generation tariffs have only been abolished for installations above 1.5kW (with proposed tariff reductions of as little as 37% for the smallest wind installations) tends to reinforce the impression that the current Government’s objections to further onshore wind subsidies owe as much to aesthetic as to financial considerations.  There is a general intention that tariffs should be set at a level that encourages “well-sited” installations rather than making viable those that ought not to be viable.

As noted above, the UK nearly didn’t have a FIT regime.  Political pressure ensured that it did.  It may be that calculations of what was and was not politically feasible resulted in the regime being unreformed for too long after its 2012 review.  A number of the ideas in the Consultation feel as if they could have been more usefully deployed if they had been proposed much earlier, but may now come too late, and/or in too Draconian a form, to save the regime as far as any significant quantity of new installations is concerned.

Whether, in retrospect, the proposals will look like a well marked out path to subsidy-free small-scale renewable generation is hard to assess.  However, it is clear that DECC is determined to avoid a situation in which a large bulge of smaller projects that fail to make the relevant cut-off date for accreditation under the RO flood into the FIT regime instead.  The proposed caps should stop that.

If you would like to discuss any issues arising from this post, please feel free to contact the authors or another member of the London Energy team at Dentons.

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DECC’s latest consultation on Feed-in Tariffs – an Era of “FIT Austerity”?

Why won’t UK shale be subject to the renewable energy community stake requirement?

As noted in our recent post on Shared Ownership, the UK Department for Energy and Climate Change (DECC) has published its Community Energy Strategy (Strategy) which anticipates that by 2015, it will be normal for new renewable energy developments to offer project stakes to local communities (and which could be enforced by an enabling power in the draft Infrastructure Bill 2014). At a recent renewable energy industry event, it was asked why shale developers are not similarly targeted by the Strategy to offer stakes to local communities?

Analogy to a new tax

In short, because it would likely be argued to be unfair. Shale developers have already paid and committed to fulfil minimum work obligations onshore under a petroleum, exploration and development licence, in order to have the right to explore for and later extract hydrocarbons from the sub-surface (and off the Crown). Any later requirement to give a royalty or equity interest to a local community, could be regarded as being analogous perhaps to an unexpected new tax. In addition, having to obtain DECC consent or adding say a community interest company (CIC) vehicle to a hydrocarbon licence, could be administratively cumbersome.

Misalignment of local opposition

That said, renewable developers may argue that buying or leasing surface land rights for renewable energy generation, and later having to give a stake to a local community, is little different philosophically. However, the current Strategy proposal is perhaps designed to address the apparent misalignment between national poll results (which are reported to suggest a majority are in favour of renewable energy); and local communities (who often resist wind and solar developments in their own localities). Such opposition is often then said to be reflected in local authority planning application refusals, which in turn reduces renewable energy development and impacts national carbon targets.

Reduced justification for compensation

By comparison, opposition to shale developments, is perhaps expected to be less driven by local planning or land-use opposition, as opposed to broader ideological and environmental concerns, which may not be as effectively addressed with active community participation – few well-heads will have the “wow factor” of a windmill. In addition, once DECC’s current consultation on granting horizontal drilling access rights (to ease shale and geothermal developments) runs its course (see our recent post Compulsory access rights “in the national interest”), then developers will possibly have less need for community alignment on specifically land-use environmental concerns. Indeed, the relative thickness of exploitable UK shale resources means that relatively few well-pad sites on the surface could be used to access large areas of sub-surface resource horizontally, causing little environmental impact (truck movements apart). This may reduce any justification for giving local communities a substantive share of the profits.

Conclusion: proactivity in hindsight

It is also important to note that the nascent shale industry, to the extent represented by the recently invigorated UK Onshore Operator’s Group (UKOOG), has perhaps already drawn some of the sting of potential community engagement regulation, by pro-actively suggesting well-pad and production payments (albeit modest in amount) for local communities. Whilst the renewables industry is more mature, numerous and with diverse interests, it may be noted that a sophisticated regulator is rarely motivated to act, except where market failure is perceived. Therefore, if the shale industry were to fail to implement the recommendations volunteered by the UKOOG, DECC may be tempted to re-assess the absence of unconventional developments from the Strategy and Infrastructure Bill’s proposals for community participation. In hindsight, now that DECC has seen a need to prompt the renewable energy industry into volunteering community participation, it appears less likely that community payments divorced from equity stakes or project profitability alone, will meet the regulator’s perception of community needs.

For further analysis on the potential application of UK and other international examples for tailoring legislation, farm-in and joint operating agreements in developing unconventional basins, please see our Shale Guide, recently presented and discussed over two days in Washington DC at a World Bank and OGEL symposium, aggregating the learning of representatives covering 18 countries.

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Why won’t UK shale be subject to the renewable energy community stake requirement?

Devolution of energy consents proposed for Wales

The Silk Commission, set up to consider possible changes to the powers of the devolved government in Wales, have recommended a new division of responsibilities between UK and Welsh Ministers as regards the consenting of energy projects (click here for their report).  The Commission propose that “responsibility for all energy planning development consents for projects up to 350 MW onshore and in Welsh territorial waters should be devolved to the Welsh Government”.  This would bring Welsh Ministers closer to parity with their Scottish counterparts in energy consenting: they have long complained that there is no good reason why proposed generating stations with a capacity of more than 50 MW should be determined by UK Ministers if they are Wales, but by Scottish Ministers if they are in Scotland.  Although the proposal is not tied to particular technology types, sub-350 MW schemes are always likely to be renewables projects.

As in many parts of the UK, new renewable developments are not always popular in Wales.  In Wales there have been particular problems as a result of the relevant Welsh Government planning policy document, TAN 8, which encouraged developers to focus their proposals for wind farms on a number of designated areas.  So, in Powys, for example, a conjoined public inquiry is currently being held (on behalf of the Secretary of State for Energy and Climate Change) into five proposed wind farms with a combined capacity of several hundred MW.  As well as being unpopular with local residents, this kind of concentration of development in a given area presents major logistical problems for developers: the capacity of the road networks to cope with the large numbers of outsize loads that would need to be transported on them to build the wind farms is severely constrained in the largely rural areas involved.

Under the Commission’s proposals, Welsh Ministers would have to deal with the consequences of TAN 8 as decision-makers on individual applications.  But UK Ministers have so far been very reluctant to give up their decision-making powers over larger Welsh wind projects, even though the objections to them are not confined to Wales itself: the proposed line of pylons that would carry power from mid-Wales wind farms to the Grid in England would pass through Shropshire and has excited plenty of opposition on the English side of the border.   Whilst the Commission’s overall plan is for new primary legislation on Welsh devolution by 2017, they point out that the competence of the Welsh Assembly could be expanded by secondary legislation on a shorter timescale.  However, it seems unlikely that any action will be taken that would result in Welsh Ministers, rather than the Secretary of State, determining the five Powys applications.

The Commission also recommend giving Welsh Ministers the power to approve “associated development” such as roads and substations as part of a development consent order for a “nationally significant” generating station under the Planning Act 2008.  At present, absurdly, this can currently be done for English, but not for Welsh projects, meaning that the supposed “one-stop shop” provided by the 2008 Act for consenting complex projects is nothing of the kind in Wales.

In a politically charged area where there are probably no perfect solution, the Commission’s proposals deserve serious consideration.

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Devolution of energy consents proposed for Wales

Contracts for difference: established technologies must compete for strike prices

Only a few weeks ago, DECC announced the “final” strike prices that were to apply to contracts for difference (CfDs) for the various eligible renewable technologies under Electricity Market Reform (EMR) (see our earlier post on this).  But things move fast in the world of EMR.  On 16 January 2014, DECC announced that for those technologies considered “established”, there would be no guarantee of securing strike prices at the level of the figures fixed in December 2013. 

The group of “established” technologies for these purposes consists of onshore wind (>5MW), solar PV (>5MW), energy from waste with CHP, hydroelectric (>5MW and <50MW), landfill gas and sewage gas.  For these technologies, it is proposed that strike prices will be set by a process of competitive bidding for which the December figures will function as a cap.  For the “less established” technologies (offshore wind, wave, tidal stream, advanced conversion technologies, anaerobic digestion, dedicated biomass with CHP and geothermal) the December strike prices will apply.  A decision has yet to be made about strike prices for biomass conversion and Scottish islands projects.

Moreover, all technologies will have to apply for their CfDs through allocation rounds – i.e. at specified times, rather than whenever it is most convenient for them to do so.  There will be no initial period of “First Come, First Served” allocation of CfDs.  The draft CfD allocation framework, originally scheduled for publication in January 2014, will not now be published until March 2014.

The DECC announcement is cast as a consultation, but the key points look fairly firm.  Although the document lists a number of factors that have been taken into consideration, it is clear that the European Commission’s draft state aid guidelines have played a big part in DECC’s thinking (see our earlier post on the draft guidelines).  The draft guidelines place a heavy emphasis on the desirability of competition for subsidies to renewable generators.  

There can be no doubt that the change of approach on strike prices ought to improve the chances of gaining state aid clearance from the Commission for the CfD regime.  But what will be the practical and wider impacts of more projects having to compete on strike prices sooner? 

How “technology-specific” will each auction be?  How frequently will auctions take place? Some questions will have to wait for an answer until we have seen the allocation framework.  For some time now, it has been clear that the allocation framework will be a hugely important document.  Assuming that DECC sticks to its overall timetable, there will not be very much time to consult on the first allocation framework before the package of EMR secondary legislation that requires Parliamentary approval is laid before Parliament.

In the meantime, it is a fair bet that some projects which might have applied for a CfD will now opt for the more predictable support mechanism provided by the Renewables Obligation (RO) instead (as they will be able to do until 2017).  Many of these projects are not large and the process of competing on strike price can only add to the costs of a CfD application.  But if more opt for the RO from the outset, how will that affect the budget available for CfDs under the Levy Control Framework?  And what will be the implications for any state aid analysis of the RO if projects that fail to win CfDs in the auction process can go on and claim what turns out to be a higher level of support under the RO?

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Contracts for difference: established technologies must compete for strike prices

Winners and losers: Government announces strike prices for new renewables projects

The Department of Energy and Climate Change (“DECC”) today published final strike prices representing the level of income in £/MWh hour that new renewable generating plant will be guaranteed to achieve under Electricity Market Reform (“EMR”) Contracts for Difference (“CfDs”).  We compare the final prices with the draft strike prices consulted on in July for selected technologies below.


Technologies with higher final strike prices included Biomass with CHP (up £5 to £125 for all five years), Anaerobic Digestion and Geothermal.  Landfill Gas, Sewage Gas and Hydro all ended up with lower final strike prices.  The prices proposed for Biomass Conversions, Wave and Tidal Stream projects have not changed, and those for Offshore Wind have only changed for 2018/19 (down £5 to £135).

It is hard to avoid the conclusion that some of the changes are intended to have a political resonance. Reduced subsidies for onshore wind and solar PV should mean fewer locally unpopular wind and solar farms, at least in areas where the weather makes the business case highly sensitive to subsidy levels.

But whether you think you are a winner or a loser, the strike price story is not over yet.  DECC will have a lot of flexibility in terms of writing – and re-writing – the rules for each CfD allocation round, and today’s publication includes strong hints that some or all of these “administratively set” strike prices could be swept away and replaced by a system of competitive bidding sooner rather than later, perhaps as part of the price for persuading the European Commission to approve the state aid aspects of EMR.

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Winners and losers: Government announces strike prices for new renewables projects