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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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The Offshore Safety Directive (1) – environmental liability


Renewable Energy ZoneHSE and DECC have been busy drafting and amending legislation to transpose the Offshore Safety Directive (“OSD”) into UK law. As the grand reveal of these draft regulations and a formal consultation paper is imminent, it is worth reminding ourselves of the anticipated new and modified regulatory requirements that both Government and industry are, and will be, grappling with.

First, we look at liability for environmental damage.

The OSD extends the meaning of “water damage” under the Environmental Liability Directive (“ELD”) to include damage to “marine waters”, which includes the waters of the renewable energy zone and continental shelf. This change increases the range of remediation actions that companies can be required to carry out in the event of a spill outside national territorial waters.

Article 7 of the OSD requires Member States to ensure that petroleum licence holders are financially liable for the prevention and remediation of environmental damage as defined in the ELD. On the face of it, this appears to reflect the prevailing position under UK law whereby licensees are jointly and severally liable under the petroleum licence and then typically agree in a Joint Operating Agreement (“JOA”) to apportion liability amongst themselves pro-rata to their interest share. However, the liability apportionment in the standard North Sea JOA may not be consistent in every detail with the article 7 requirement.

The UK Government will have to decide whether it needs to take steUK Continental Shelfps to address the standard liability apportionment in North Sea JOAs which it is asked to approve. The Government will also need to consider whether the OPOL regime, under which operators (as distinct from licensees) assume liability for pollution damage, is compliant with article 7.

Finally, the OSD requires Member States to ensure that licences are not granted until satisfactory evidence has been provided that the applicant has or will make adequate financial provision for potential liabilities. This is not a new concept in the UK offshore world, however the Government, oil and gas industry, and insurers will need to tackle the question of how to factor extended ELD damages into financial provision calculations.

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Sam Boileau

About Sam Boileau

Sam focuses on UK and EU environmental and safety law, and has been practicing in these fields for over 15 years. He is one of the few lawyers in the UK to be individually ranked in Chambers & Partners for both environmental and health and safety expertise. His practice area includes waste management, producer responsibility, product liability, pollution liability, environmental permitting, water and drainage, land contamination and health and safety.



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The Offshore Safety Directive (2) – reporting requirements


Oil and gas companies will need to ensure that their existing contractual arrangements relating to information sharing and reporting enable them to comply with the enhanced reporting requirements of the Offshore Safety Directive (“OSD”). We take a quick look below at the new reporting requirements that will be introduced into UK law by the transposition of the OSD.

Reporting accidents outside the EU UK registered companies conducting offshore oil and gas operations outside the EU as licence holders or operators will be required to submit reports, on request, to the UK Government in respect of any major accident in which they have been involved outside the EU. These reports will then be exchanged with competent authorities of other Member States. Wide ranging and onerous information requests may follow. Companies will also need to be mindful of the potential liability implications of disclosing such information.

Corporate major accident prevention policy Operators of EU production installations and owners of EU non-production installations will have to produce corporate major accident prevention policies covering their installations within the EU. This is a new requirement. The policies will need to specify the extent to which equivalent policies are in place for operations outside the EU.

Safety cases Operators and owners will need to prepare major hazard reports for their installations. These will need to be approved by the competent authority before any operations can start or be continued. These reports will be similar to the current UK safety case but will need to consider environmental as well as safety matters.

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Sam Boileau

About Sam Boileau

Sam focuses on UK and EU environmental and safety law, and has been practicing in these fields for over 15 years. He is one of the few lawyers in the UK to be individually ranked in Chambers & Partners for both environmental and health and safety expertise. His practice area includes waste management, producer responsibility, product liability, pollution liability, environmental permitting, water and drainage, land contamination and health and safety.



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The Offshore Safety Directive (3) – competent authority


The Offshore Safety Directive (“OSD”) provides for a single competent authority to deal with both environmental and safety issues. The OSD also requires the joint environmental and safety regulator to be independent of the body dealing with economic development of offshore resources and licensing.

The current UK regulatory structure does not comply with the OSD. Separate entities regulate environmental issues (DECC) and safety issues (HSE); and the same entity (DECC) performs the role of both environmental and economic regulator. Some non-structural changes have already been made as a result of recommendations in the Maitland review, with the HSE and DECC working together to improve effectiveness under a new Memorandum of Understanding. However, further changes will be needed as the OSD contains legal requirements, not just recommendations.

Rather than overhaul the existing machinery of Government to establish a “new” competent authority, the HSE and DECC have made clear in stakeholder meetings that they propose to create an “umbrella” competent authority, consisting of the relevant parts of DECC and HSE. This would be similar to the onshore COMAH regime where the Environment Agency and HSE work together as the competent authority for major hazard sites. The proposed competent authority has been described by one optimistic commentator as a swan gliding gracefully over the waters of offshore environmental and safety regulation, with the HSE and DECC paddling diligently underneath. We will have to wait and see how the swan fares on the choppy waters of the North Sea.

SwanJoking aside, the idea of a joint HSE/DECC competent authority does seem to be a sensible and practical solution to the OSD requirements. To overhaul the machinery of Government to produce a new separate health, safety and environmental regulator for offshore activities would be difficult given the existing regulatory structure. There is a question mark, however, over whether the proposed competent authority will be strictly compliant with the terms of the OSD.

 

 

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Sam Boileau

About Sam Boileau

Sam focuses on UK and EU environmental and safety law, and has been practicing in these fields for over 15 years. He is one of the few lawyers in the UK to be individually ranked in Chambers & Partners for both environmental and health and safety expertise. His practice area includes waste management, producer responsibility, product liability, pollution liability, environmental permitting, water and drainage, land contamination and health and safety.



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The Offshore Safety Directive (4) – the bigger picture


Our previous posts on the Offshore Safety Directive (“OSD”) discussed some of the anticipated new regulatory requirements as well as what companies and the UK Government need to be considering to get ready for the OSD’s implementation. We will be looking further into some of the tricky issues once the HSE and DECC’s hotly anticipated consultation paper and draft statutory instruments have been published, hopefully this month.

The forward thinking amongst you will already be asking “what’s next?”. “Quite a lot” is the answer. With further reforms on the horizon in both the civil and criminal liability spheres, the OSD appears to be only the EU’s first step in reforming our offshore environmental and safety regimes in response to the Macondo disaster.

The offshore oil and gas industry will be subject to common rules governing a range of safety and environmental management issues (the OSD), together with a common liability regime to govern marine remediation in the event of a major spill (the Environmental Liability Directive). There are, however, two other important areas of legal liability that the OSD does not cover and that remain a matter of national law within the EU:

  1. criminal liability (e.g. punitive fines imposed by courts or custodial sentences for senior managers); and
  2. liability to pay damages (e.g. compensation to fishermen for economic losses caused by an oil spillage, or to coastal businesses for losses caused by coastal pollution).

This may change. The European Commission is required to:

  • report to the Parliament and Council by 31 December 2014 on the availability of financial security instruments, and on the handling of compensation claims;
  • examine the appropriateness of bringing certain conduct that leads to a major offshore accident within the scope of Directive 2008/99/EC on the protection of the environment through criminal law and report on its findings by 31 December 2014; and
  • report by 19 July 2015 on its assessment of the effectiveness of liability regimes in the EU in respect of damage caused by offshore oil and gas operations.

The Commission commissioned initial research on these areas whilst the OSD was still being negotiated, with Maastricht University completing its report on civil liability and financial security for offshore oil and gas activities on 28 October 2013.

The reports the Commission is preparing will be accompanied by legislative proposals where appropriate. Offshore oil and gas companies in the EU would be well advised to keep a close eye on these developments. It may be through this route that we see the establishment of a more US-style regime for levying fines and imposing liability following offshore spills.

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Sam Boileau

About Sam Boileau

Sam focuses on UK and EU environmental and safety law, and has been practicing in these fields for over 15 years. He is one of the few lawyers in the UK to be individually ranked in Chambers & Partners for both environmental and health and safety expertise. His practice area includes waste management, producer responsibility, product liability, pollution liability, environmental permitting, water and drainage, land contamination and health and safety.



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Subsidies for green electricity permitted to restrict trade between EU Member States – CJEU


It is normal for Member States to make support for renewable generation available only to generators based in their own territory.  Until recently, it was generally assumed that this was entirely consistent with EU law.  Article 3(3) of the EU Renewables Directive (2009/28/EC) states that Member States “shall have the right to decide…to which extent they support energy from renewable sources which is produced in a different Member State”.

However, a case referred to the Court of Justice of the EU by the Swedish courts called this into question.  Ålands Vindkraft, operator of a wind farm in the Åland Islands, applied to participate in the Swedish “green certificate” scheme.  Although connected to the Swedish grid, the project was in Finnish territory, and its application was refused on that ground, pursuant to the relevant Swedish law.

As well as the question whether that law was in line with the Directive, the resulting appeal to the Swedish courts raised a more fundamental issue.  Are schemes that restrict the availability of subsidy to home-grown renewables, and the provisions of the Directive that ostensibly permit such restrictions, consistent with the EU Treaties’ rules on the free movement of goods?

The Advocate General, who gave his opinion on the case on 28 January 2014, came to the conclusion that in permitting such restrictions, the Directive, as a species of secondary legislation, had gone beyond what was permissible under the primary legislative authority of the Treaties.  Although restrictions on imports can be compatible with the Treaties, they must first be shown to be justified in terms of the protection of one of the public interests that case-law has recognised as capable of overriding the right of free movement, as well as being proportionate.  In this case the overriding interest was supposedly the protection of the environment: the promotion of renewable generation reduces greenhouse gas emissions and helps to avoid harmful climate change.  But the Advocate General could not see how preventing the import of “foreign” green electricity helped the environment.

In so far as the Directive could not be interpreted as doing anything other than permitting the restrictions in the Swedish law, the Advocate General concluded that it should be annulled, but with the Court allowing a two year stay of execution to allow the EU legislature to put its house in order.

It isn’t every day that an Advocate General reaches this kind of conclusion about a Directive, let alone one which is a key instrument of EU policy.  So it is perhaps not surprising that the Court’s judgment, delivered by the full Grand Chamber of 15 judges, declined to follow the Advocate General in those parts of his reasoning which were more disturbing for the status quo in EU renewable support schemes.  But the reasoning behind the decision of the full court is arguably rather less clear than that of the opinion of the Advocate General which it departed from.

The Court agreed that legislation such as the Swedish law is capable of impeding imports of electricity and so is in principle incompatible with the free movement rules.  But it found that this restriction could be objectively justified.  Without confronting head-on the question of how the overriding interest of environmental protection is served by a restriction on imports, it concluded that the Swedish scheme as a whole served an environmentally beneficial purpose and found that Sweden could legitimately consider that the territorial limitation in its law did not go beyond what was necessary to attain the objective of increasing the production and consumption of green electricity in the EU.  Along the way, the Court pointed out that “EU law has not harmonised the national support schemes for green energy”; that it is hard to tell green electricity from other types once they are fed into the transmission and distribution networks; and that the national targets set in the Directive “are formulated in terms of quotas for the production [rather than consumption] of green electricity”.  All of which may be true, but does it inevitably mean that the Swedish law is compatible with the free movement rules?  One might be forgiven for thinking that this was one of those occasions where a majority of the CJEU judges agreed on the result, but not on a single way of reaching it, and some readers may find that the points they could all agree on make for a less than compelling rationale.

The Court’s judgment will no doubt be met with sighs of relief across the EU.  As well as Sweden, Germany, Norway and the Netherlands participated in the case.  The UK did not intervene, perhaps because the ability of a Member State to restrict renewable benefits to generators on its own territory is a point of some sensitivity in domestic politics at present.  The UK Government has been at pains to try to undermine the assumption put forward by the Scottish Government, as part of its case for independence, that consumers in England and Wales will inevitably carry on subsidising renewable generators in an independent Scotland through the Renewables Obligation and Contracts for Difference.  If Scotland does vote “yes” to independence on 18 September, it will be interesting to see whether the Government of what remains of the UK will be minded to try to introduce Swedish-style territorial restrictions into its renewable support schemes – and whether the Ålands Vindkraft judgment will prove a secure precedent on which to found such restrictions.

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Biomethane RHI Consultation – Global Energy Blog


1.            Introduction to the RHI

The Renewable Heat Incentive (RHI) is a long-term financial support programme for renewable heat designed to increase the uptake of renewable heat technologies and reduce carbon emissions.

The scheme provides a subsidy per kWhth  of eligible renewable heat generated from accredited installations and a subsidy payable to producers of biomethane for injection into the grid.

It was launched in November 2011 through the Renewable Heat Incentive Scheme Regulations 2011 (RHI Regulation) with a scheme for the non-domestic sector that provides payments to industry, business and public sector organisations.

The following renewable heat technologies are currently supported:

  • solid biomass;
  • ground and water source heat pumps (GSHP);
  • geothermal;
  • solar collector / solar thermal (at capacities of less than 200 kWth);
  • small scale biogas combustion (at capacities of less than 200 kWth); and
  • biomethane injection.

2.            Biomethane

Biomethane injection involves the production of biogas through anaerobic digestion of waste, crop, slurries or sewage feedstock. The biogas is then ‘upgraded’ to remove the carbon dioxide and other impurities in a process know as scrubbing, and propane is added to ensure the calorific value, or energy content, closely matches that of natural gas in the network. The resulting gas can then be odorised and compressed, and the processed biomethane injected into the gas grid.

RHI Payments for biomethane producers are based on the eligible volume of biomethane produced for injection.

3.            Consultation

When the Government first introduced the ‘one size fits all’ biomethane to grid tariff in November 2011 there were no full scale biomethane to grid plants in operation. The tariff was based on a 1MW waste feedstock plant.

The RHI has kick-started the market for biomethane to grid as there are currently three plants registered to the RHI and it is understood many plants of much higher capacities are planned or in the pipeline.

DECC is now concerned that larger biomethane plants will benefit from economies of scale which may not justify RHI support at current levels, i.e. that at current levels large biomethane would be overcompensated.

As a result of DECC’s concerns, on 30 May 2014, DECC published a consultation seeking views from industry on proposed adjustment to the biomethane to grid tariff. The consultation closed on 27 June 2014 and DECC plan to lay any amended regulations as soon as possible after Parliament returns from Recess in Autumn 2014.

The consultation presents two tariff structures: banding and tiering.

Tiering operates by paying a higher tariff for the first designated amount of kilowatt hours of biomethane injected into the grid (the “tier 1” tariff), and a lower tariff for any subsequent biomethane injected (the “tier 2” tariff), over a period of 12 months. All installations would receive the higher tier 1 tariff payments for a set volume of biomethane injected into the grid, regardless of size of plant. This is a ‘2-tier’ tariff structure – tariff structures with higher numbers of tiers could be developed following the same approach.

Tiering provides for a gradual reduction in the average tariff earned as capacity increases – unlike banding where the average tariff falls in large steps. This reduces the likelihood of operators sizing plant for maximum financial benefit.

Banding works by defining capacity bands for the technology and paying an appropriate tariff for each band. In this case, DECC are proposing higher tariffs for the lower capacity bands and lower tariffs for higher capacity bands.

The biomethane industry cannot be overly surprised at the proposed introduction of banding or tiering as these have been implemented for other developing RHI technologies such as biomass and, indeed, in other renewable schemes such as the Feed in Tariff. As ever with tariff reviews, a fine balance needs to be reached between providing value for money for the tax payer while continuing to promote a relatively immature and growing industry.

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The Offshore Safety Directive (5) – Government consultations


On 28 July 2014, the Government launched two consultations in parallel on the implementation of the Offshore Safety Directive (the OSD). One of the consultations is led by DECC and the HSE (the DECC/HSE Consultation) and the other is led by Defra and the Welsh Government (the Defra Consultation). Both consultations run from 28 July 2014 to 21 September 2014.

The DECC/HSE Consultation concerns the transposition of the OSD and the establishment of an offshore competent authority.  It also seeks comments on HSE’s proposals to update onshore oil and gas health and safety legislation to take account of emerging energy technologies and the review of two Approved Codes of Practice. The DECC/HSE Consultation annexes a suite of draft regulations for comment.

The Defra Consultation is narrower. It concerns the transposition of Article 38 OSD, which extends the scope of environmental liability under the Environmental Liability Directive to Marine Waters. Separate consultation exercises will be taking place later in the year in relation to marine waters off Scotland and Northern Ireland.

The safety and environmental regime which OSD required the UK Government to implement closely resembles the existing offshore regulatory regime in the UK.  Therefore this consultation does not involve proposals to completely dismantle and then reassemble the offshore regime.

However  there are some important issues that this consultation opens up for public comment and debate.  Oil and gas companies would be well advised to give careful consideration to the issues raised.  Key points of interest include:

  • Consolidation of legal duties under one appointed operator.  DECC take the view that as a result of the OSD the same entity must be appointed as both safety duty holder and operator under the Petroleum Act.  This is not consistent with the approach taken by many operators in the North Sea. The OSD requirements on this point need to be considered carefully.
  • Proposed new Competent Authority.  The OSD requires a single authority to be responsible for safety and environmental regulation.  The consultation proposes, as expected, a “competent authority” made up of both HSE and DECC to deliver this – similar to the Competent Authority under the onshore COMAH regime.  However, arguably this complicates rather than simplifies the current regulatory structure.  The new “hybrid” authority will be responsible just for the documentation required under the OSD, whereas operational environmental licences will still be issued by the existing offshore division within DECC.
  • Operator / Licensee Liability for Environmental Damage.  The OSD extends “environmental damage” under the Environmental Liability Directive to include marine waters.  This will have the effect of increasing the potential liability of operators to remediate environmental damage  in the event of a major spill from an offshore installation.  Article 7 of the OSD requires licensees under the Petroleum Act to be “financially liable” for such remediation work.  Defra are consulting on whether any changes need to be made to existing Environmental Damage Regulations to achieve this.

We will be reporting further on these and other points of interest in due course.

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Sam Boileau

About Sam Boileau

Sam focuses on UK and EU environmental and safety law, and has been practicing in these fields for over 15 years. He is one of the few lawyers in the UK to be individually ranked in Chambers & Partners for both environmental and health and safety expertise. His practice area includes waste management, producer responsibility, product liability, pollution liability, environmental permitting, water and drainage, land contamination and health and safety.



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Early closure of RO to >5MW solar PV projects confirmed


Following a consultation that ran from 13 May to 7 July 2014, the UK Government has confirmed its intention that, as a general rule, funding under the Renewables Obligation will not be available to larger scale (>5MW solar) PV projects after 31 March 2015.

There will be a “grace period” of a year for projects which were, in effect, in a position to begin development before 13 May 2014.  Perhaps more usefully for projects which may struggle to meet the requirements for RO accreditation before 31 March 2015, further consultation is taking place on a proposal to protect the position of those projects which only fail to meet the 31 March 2015 cut-off date for commissioning because their electricity network operator has not met a pre-31 March 2015 estimated connection date.

Background

For most technologies, the Renewables Obligation will close on 31 March 2017.  After that date, smaller projects will have to rely on the Feed-in Tariffs regime and larger projects must compete for Contracts for Difference (CfDs) under Electricity Market Reform.  In March 2014, the Government set out its overall approach to the two and a half year  transition period when both the RO and CfD regimes are open to new projects: developers are able to choose between the two schemes (subject to certain qualifications). But subsequently DECC has become increasingly concerned that the rapid growth of the UK solar industry, supported by the “demand-led” RO, will breach the Levy Control Framework (LCF) limits on the overall amount of money that the Treasury will permit to be spent on renewable energy subsidies.  In its May 2014 consultation, DECC estimated that large-scale solar PV deployment under the RO could reach “more than 5GW by 2017”; in the response to that consultation, DECC’s “updated assessment” found that “in the absence of intervention”, up to 10GW of solar PV could deploy within this period, costing some £400m more than was allowed for in the EMR Delivery Plan and exceeding the LCF cap.

Proposals and policy decisions

The table below summarises the Government’s main proposals on RO closure for solar PV in the May consultation and the policy decisions announced in the response to consultation.

table-1

DECC has not been persuaded to change the cut-off date or open up the grace period to a wider group of projects.  Responding to “the main criticism…that any projects that can meet the grace period…requirements are unlikely to need the grace period because they will already be sufficiently advanced to secure connection by 31 March 2015”, DECC states that “the grace period will have fulfilled its purpose if it protects eligible projects that subsequently encounter unexpected events which delay their completion beyond the end of March 2015.  However, DECC very clearly has taken on board the industry’s practical objections around the evidence to be provided by those that are eligible for the grace period and has accommodated its evidential requirements to the realities of the industry.

Further consultation

In response to comments from consultees that early closure of the RO to large-scale solar would create a “cliff-edge” effect for some projects, DECC has put out a further consultation (closing on 24 October 2014) on the proposal that there should be a separate 3 month grace period (until 30 June 2015) for projects which are prevented from meeting the 31 March 2015 deadline only because they are not connected to the grid by that date.

The proposal is that such projects would have to include in their RO application:

  • a grid connection offer and acceptance and a letter from the network operator estimating or setting a date for connection of no later to 31 March 2015 (the estimated connection date);
  • a declaration by the developer that to the best of its knowledge, the project would have been commissioned by 31 March 2015 if the connection had been made by the estimated connection date; and
  • a letter from the network operator confirming that in its opinion, the failure to make the grid connection before the estimated connection date was not due to any failure on the part of the developer.

The first of these proposed requirements is open to the same sorts of objections that were made by the industry against the proposed requirement for a letter from the network operator that formed part of the May 2014 proposals.  However, DECC insists that past experience on banding review grace periods suggests that the difficulties associated with it are “not insurmountable”, and the response to consultation is careful to note that the requirement has been removed from the final policy decision on the May proposals because a letter from the network operator was considered unnecessary in that context, rather than that it would be too difficult to obtain.

What next?

DECC intends to implement the policy decisions described above in relation to RO closure through an amendment to the Renewables Obligation Closure Order 2014, to take effect on 1 April 2015.

DECC is evidently determined to do whatever it has to in order to mitigate the risk that the growth in large-scale solar PV will lead to a breach in the Levy Control Framework limits. It wants the sector to switch to the CfD regime, where the auction-based allocation process will drive down the costs of subsidy, acknowledging that the greater complexity of the CfD regime will favour the larger players in the industry.

The deadline for applications for the first CfD round is now 30 October 2014, and in recent publications both DECC and National Grid (as EMR Delivery Body) have been doing their best to make the regime user-friendly.  The table below suggests which groups of developers may need to consider making a CfD application.  If onshore wind developers (with whom solar projects must compete) are likely to avoid bidding for CfDs in the first auction since they  have until 31 March 2017 to achieve RO accreditation, it may be that solar projects stand a reasonable chance of success of being allocated CfDs later this year.

table-2

At present, for those who miss out on both the RO and a CfD from the first allocation round, the next opportunity would be a CfD allocation round in Autumn 2015.  DECC has given some indications that it is sympathetic to the proposition that the rapid development cycle of solar projects means that there ought to be solar CfD allocations every 6 months rather than every year, as for other technologies, but it also points out that more frequent auctions would not mean any increase in the overall budget.  And since 2015 is a General Election year, no promises of a further allocation round for solar can be made at present.

 

 

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CfDs: not unduly distorting the market, but not best value for money?


The European Commission’s state aid decision clearing the UK’s “enduring regime” of renewables contracts for difference (dated 23 July, published on 2 October 2014) confirms the CfD regime as a model example of the kind of renewables support scheme that the Commission wants to encourage, as described in its April 2014 Guidelines on state aid for environmental protection and energy.

The decision is littered with cross-references to the Guidelines, reflecting the fact that key details of the CfD regime were effectively developed in dialogue with the Commission.  Among the key points in favour of the regime as far as the Commission is concerned are that the strike price mechanism limits the ability of generators to benefit from very high prices; that “the strike price paid will be established via a competitive bidding process”; and that it cannot be higher than the administratively set strike price, which is based on “the levelised costs of eligible technologies and reasonable hurdle rates”.  Other points to note include future measures to ensure that generators do not have an incentive to generate electricity when prices are negative and details of the treatment of biomass conversions and imported renewable electricity.

Given the Commission’s emphasis on the benefits of strike price competition, it is interesting to note the parallel clearance for the award of early “FID-enabling” CfD “investment contracts” – outside the enduring regime, and with no competition on strike prices – to five UK offshore wind farms (Walney, Dudgeon, Hornsea, Burbo Bank and Beatrice).  For the Commission, the award of these contracts was justified because “the Commission was able to verify that the amount of aid for each project is limited to what would be necessary to allow the project to reach a reasonable rate of return” and “the Commission further notes that…the notified projects are all reaching an IRR below the central value of the hurdle rates considered by the UK”.  However, as if DECC needed to be reminded that it cannot please everybody all the time, within a day of the release of the two state aid decisions, the Public Accounts Committee published a report that criticised the investment contracts as poor value for money, repeating a number of points first made in a National Audit Office report in June.

The PAC’s headline criticism is that the investment contracts will consume up to 58% of the total funds available for renewable CfDs to 2020/2021 – without accounting for a correspondingly large proportion of the new renewable generating capacity that is to be funded by CfDs.  They argue that committing so much of the overall CfD budget to the five offshore wind projects and three biomass projects (which have yet to receive state aid clearance) was both unnecessary (because the 2020 targets for renewables deployment could have been met in any event) and represents poor value for consumers, because the enduring regime, with its more competitive allocation processes, can be expected to deliver more MW of renewable power per £ of subsidy.  Ultimately, as both the PAC and NAO acknowledge to some extent, the effect of the investment contract regime may have been to ensure the continuing healthy development of the offshore wind industry in the UK, albeit potentially at the cost of support for some later offshore wind (and possibly other) projects.

Whilst there may be a wider political context to the line taken by each of the Commission and the PAC, their different appraisals of the investment contracts regime also reflect their different functions.  The Commission, in reviewing proposed state aid measures, is properly concerned only with their impact on competition within the EU internal market.  It is not in the business of telling Member States that one renewable technology or project is better or worse value than another for UK consumers, provided that neither is being given more aid than is strictly necessary to remedy the market failure that inhibits its development in the absence of aid.  If gaining state aid approval were simply a matter of comparing the level of subsidy per MW of new generating capacity, the investment contracts for the biomass conversions at Drax and Lynemouth (with an estimated CfD level of support of £2.6m/MW and an assumed load factor of 64.5%) would not still be awaiting clearance when the aid to the five offshore wind farms (with estimated CfD levels of support of between £3.4m/MW and £4.4m/MW and an assumed load factor of 37.7%) has been approved.

 

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