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UK onshore wind subsidies: not dead yet

A vote in the House of Lords on 21 October 2015 has, for the moment at least, derailed the Government’s proposals to prevent new onshore wind farms commissioned after 31 March 2016 from being subsidised under the Renewables Obligation (RO).

Readers of our earlier posts on this subject (see here and here) will recall that in June 2015 Government said that its proposals would form part of the current Energy Bill.  In July, “grace period” arrangements were promised for those projects with planning permission, grid connection agreements and land rights by 18 June 2015.  On 8 October, Government amendments to the Bill, setting out the details of grace period relief, were  published.  They covered a somewhat broader range of cases than just the “planning / grid / land rights” one.  After a Committee debate on 14 October 2015 in which Lord Wallace of Tankerness and others identified a range of scenarios where they felt projects would, unfairly, not benefit from the grace period amendments, Lord Bourne, for the Government, withdrew the amendments to consider them further.

Before the debate at Report stage on 21 October, Government re-tabled its amendments, virtually unchanged, and Opposition Peers tabled a number of others, including one that simply removed clause 66 (the early closure provision) from the Bill altogether.  This amendment was passed, by 242 votes to 190.

What is going on, and what (so far as we can tell) happens next?

  • Ministers have suggested that in voting to remove clause 66, Peers were flouting the “Salisbury convention” – i.e. the principle that the unelected House should not thwart measures that have appeared in the election manifesto of an incoming Government.  The Opposition response to this is that the Conservatives’ General Election pledge to “end any new public subsidy” for onshore wind was one thing (which might, for example, equate to removal of onshore wind from the list of technologies eligible to compete for Contracts for Difference (CfDs)); but bringing forward the closure of the RO (an existing subsidy) is another thing altogether.

 

  • The Opposition stress that they are not opposing the phasing out of onshore wind subsidies per se – rather, they object to what they see as the Government’s failure to provide details of the proposed grace period arrangements soon enough for them to be properly scrutinised and amended, and to the fact they do not cover various categories of projects whose exclusion from the RO seems to them to be unfair.  It is also alleged that the average savings to Bill payers (30p per household annually) from early closure are outweighed by the lost investments on the part of the industry (over £300 million).

 

  • Some of the “hard luck cases” cited might not have achieved RO accreditation even under the existing, pre-18 June position on RO closure.  Others that it is said may be unfairly treated by the 8 October amendments include projects where a local authority decided to grant planning permission before 18 June but the mitigation arrangements under a “section 106” (England and Wales) or “section 75” (Scotland) agreement were not yet signed off; cases where the developer gave the local planning authority longer than the statutory minimum before treating its silence as a “deemed refusal” of planning permission and challenging it; and cases where a project essentially had a grid connection agreement for some time prior to 18 June but temporarily lost it before that date.

 

  • Lord Bourne may win a prize for Parliamentary understatement when he said, towards the end of proceedings: “The debate has exhibited a clear difference of position in relation to onshore wind.”

 

  • For the moment, the Bill does not provide for early closure of the RO to new onshore wind projects.

 

  • In order to carry out its policy, the Government will have to muster more support at Third Reading in the Lords, or reintroduce the early closure provision in the Commons, where its MPs are likely to be easier to whip.  In the latter case, the provision would then have to return to the Lords for consideration, and could go through more than one round of “ping pong” between the two Houses – with the wind industry (or at least many projects) in suspense in the meantime.

 

  • Unless the Prime Minister really intends to create enough new Peers to guarantee passage through the Lords of the RO closure provisions in the form the Government wants (as appeared to be suggested in connection with the parallel Lords rebellion on cutting tax credits for working families), it looks as if Government needs to secure agreement on a package of grace period amendments that Opposition Peers are content to accept.

 

  • The Parliament Act 1911 enables the Government effectively to bypass the House of Lords in certain circumstances.  But it is unlikely to be of any use to the Government on this occasion, since its timescales would not allow the Bill to be enacted until well after 31 March 2016 – and possibly not (or only a few weeks) before the general RO closure date of 31 March 2017.

Finally, it is worth noting that the vote on clause 66 was one of two Government defeats during the Report stage debate on the Bill.  Peers also voted in an Opposition amendment that would change the basis on which the UK’s carbon budgets are set under the Climate Change Act 2008 – probably with the effect of making them harder to meet.  This more technical and, on the face of it, less politically exciting change is in part a reaction to the Government’s confirmation that it will not be setting a decarbonisation target for the power sector (whose emissions are said not to be counted in carbon budget setting because they fall within the EU Emissions Trading Scheme).  In the longer term, it may – if it survives – have even more far-reaching effects than those of the removal of clause 66.

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UK onshore wind subsidies: not dead yet

Grace periods for early closure of Renewables Obligation support for onshore wind

On 8 October 2015, the UK Government’s Department of Energy and Climate Change (DECC) set out its detailed proposals for mitigating the impact of the proposed early closure of the Renewables Obligation (RO) to new onshore wind projects from 1 April 2016. The provisions now set out in a series of proposed amendments to the relevant part of the Energy Bill, which are to be debated by the House of Lords on 14 October 2015, go a little beyond what DECC first put forward at the start of its period of “engagement” with the industry at the start of July 2015.

The original grace period proposal was relatively simple, and based on the “significant investment grace period” for >5MW solar PV projects. An onshore project would be able to achieve RO accreditation if it commissioned and applied for accreditation after 31 March 2016 but before 1 April in 2017, provided that, as at 18 June 2015 (the date of DECC’s announcement about the proposed early closure) it had planning permission, an accepted offer of connection to the transmission or distribution network, and sufficient rights over the land where it was to be situated – e.g. in the form of a lease, option, agreement for lease or exclusivity agreement.

The proposals set out in the 8 October amendments are more generous, but also more complex. They consist primarily of the insertion of a new run of sections in the RO provisions of the Electricity Act 1989 and their effect is summarised in the table below.

Section of Act (as it would be amended) Date wind farm / relevant additional capacity  is accredited Applicable grace period conditions to be satisfied in order to obtain accreditation
32LD On or before 31 March 2016 No need for grace period
32LE Between 1 April 2016 and 31 March 2017 Grid and radar delay condition – i.e. that:

In respect of either grid connection or radar mitigation works relating to the wind farm / additional capacity on or before the date when Ofgem decided to accredit it, Ofgem has received from the operator:

(a) evidence of an agreement to carry out the works in respect of the wind farm / additional capacity;

(b) document from the network operator / radar agreement counterparty estimating completion on or before the primary date (see below);

(c) letter from the network operator / radar agreement counterparty confirming that the works were completed later than planned, and that this was not due to any breach by the wind farm developer; and

(d) declaration by the operator that to the best of its knowledge and belief, the wind farm / additional capacity would have been commissioned / formed part of the wind farm before the primary date if the works had been completed by that date.

For the purposes of section 32LE, the primary date is 31 March 2016.

32LF On or before 31 March 2017 Approved development condition – i.e. that the accreditation application is accompanied by the following as regards planning, grid connection and land rights.

Planning

One of the following:

(a) evidence that planning permission (or s. 36 consent / development consent under the Planning Act 2008) was granted on or before 18 June 2015;

(b) evidence that planning permission (or s. 36 consent / development consent under the Planning Act 2008) was refused on or before 18 June 2015 but granted after that date following an appeal or judicial review;

(c) evidence that an application for planning permission was made to the local planning authority on or before 18 June 2015; the authority failed to determine or decline to determine application, or refer it to Ministers, within the statutory period; the application was not referred to Ministers; and the application was granted after 18 June 2015 following an appeal; or

(d) a declaration that to the best of the operator’s knowledge and belief, planning permission is not required for the wind farm / additional capacity,

and that any conditions as to the time for commencement of development in the relevant planning permission have been complied with.

Grid connection

One of the following:

(a) a copy of an offer from a licensed network operator made on or before 18 June 2015 to carry out grid works in relation to the wind farm / additional capacity and evidence that the offer was accepted on or before that date; or

(b) a declaration by the operator that to the best of its knowledge and belief no grid works are required to commission the wind farm / additional capacity.

Land rights

A declaration that to the best of the operator’s knowledge and belief a developer of the wind farm or additional capacity or a person connected with it in within the meaning of s. 1122 Corporation Tax Act 2010:

(a) was an owner or lessee of the land where the wind farm / additional capacity is to be situated;

(b) had entered into an agreement to lease that land;

(c) had an option to purchase or lease that land; or

(d) was a party to an agreement by the owner or lessee of the land not to permit any person other than those identified in the agreement to construct a wind farm there.

32LG Between 1 April 2017 and 31 March 2018

 

Approved development condition

and

Grid and radar delay condition – noting that:

Documentary requirements are as described in relation to section 32LE, but

For the purposes of section 32LG, the primary date is 31 March 2017.

32LH Between 1 April 2017 and 31 December 2017

 

Approved development condition

and

Investment freezing condition – i.e. that the accreditation application is accompanied by the following documents:

(a) a declaration from the operator that, to the best of its knowledge and belief, as at 1 May 2016:

(i) it required funding from a recognised lender (a provider of debt finance with an investment grade credit rating) before the wind farm / additional capacity could be commissioned / added;

(ii) the recognised lender was not prepared to provide such funding until enactment of the Energy Act 2016 because of uncertainty about whether it would be enacted / how it would be worded if enacted; and

(iii) the wind farm / additional capacity would have been commissioned / added on or before 31 March 2017 if the funding had been provided before enactment of that Act; and

(b) a letter or other document dated on or before 1 May 2016 from a recognised lender confirming that it was not prepared to provide funding for the wind farm / additional capacity until enactment of the Energy Act 2016.

32LI Between 1 January 2018 and 31 December 2018 Approved development condition

and

Investment freezing condition

and

Grid and radar delay condition – noting that:

Documentary requirements are as described in relation to section 32LE, but

For the purposes of section 32LI, the primary date is 31 December 2017.

It seems likely that the Government’s proposed amendments will be adopted. It remains to be seen whether subsequent debates as the Energy Bill passes through the remaining stages of its passage through the House of Lords, or through the House of Commons, will result in the addition of any further grace period criteria or the tweaking of those already covered. For now, the following points may be noted:

  • The grace period criteria based around a combination of planning, grid and land rights proposed in July have been broadened as regards planning permission.  In particular, what is now called the “approved development condition” allows grace period status to be claimed not just by projects that had obtained planning permission by 18 June 2015, but also by those who had their planning applications refused on or before that date, but have managed to obtain planning permission through an appeal or judicial review process subsequently.  The value of a further extension, relating to cases which local authorities have failed to handle according to statutory timetables, may be more limited, because as currently drafted it appears only to benefit cases that have not been referred to Ministers for determination.
  • The introduction of provisions acknowledging that some projects may be delayed because lenders are unwilling to commit to finance them before the legislation has received Royal Assent is clearly a welcome addition to the package of mitigation for early closure.  However, note that the “investment freezing condition” in which this is set out does not function as an independent justification for not commissioning by 31 March 2016.  Rather, it allows those projects that can already justify an extension of the period within which they can achieve accreditation under the approved development condition to extend for an additional 9 months.
  • In July 2015 DECC had already indicated that projects which benefited from planning, grid and land rights on 18 June 2015 could bring themselves within the scope of the existing grace period provisions on grid and radar delay – thereby potentially enabling them to apply for accreditation as late as 31 March 2018 where such delay had occurred.  The proposed amendments to the Energy Bill disapply the grace period provisions of the Renewables Obligation Closure Order 2014 from onshore wind projects, but reproduce the effect of its provisions on grid and radar delay as part of their own suite of grace period criteria.
  • The revised impact assessment produced alongside the proposed amendments does not appear to suggest that any more capacity will be accredited as a result of the expansion of the grace period criteria (the numbers in all the key tables are the same as in the version of the impact assessment published in September, apparently on the basis of the original proposals).  However, the accompanying DECC press release states that “around 2.9 GW” of onshore wind capacity could be eligible for the grace periods.

The package of mitigation proposed by the amendments is appreciably more generous than what was suggested by DECC in July, but there are limits to that generosity.  For example, the amendments have not simply followed the model established by the >5MW solar PV RO grace period and allowed the planning criterion within the approved development criterion to be satisfied by any project that had applied for planning permission by 18 July 2015.  However, it is noticeable that the DECC policy paper of 8 October 2015 invites “onshore wind developers to tell us about any of their projects affected by our proposals. In particular, we are interested in hearing from developers with projects that are currently in the planning system, but which have not yet secured planning consent, and to receive information and evidence relating to:

  • the stage that such projects have reached in the planning process, anticipated final planning decision dates, and expenditure incurred on projects as at the date of the Secretary of State’s announcement
  • project timetables and anticipated dates for securing a grid connection offer and acceptance; and
  • the prospects of such projects being in a position to accredit under the RO by 31 March 2017 and expected final investment decision dates.”

It is therefore possible that Government is leaving the door open (or, at least, slightly ajar) to a revised ‘approved development condition’ that more closely resembles the model established by the >5MW solar PV RO grace period (and is more favourable to the industry than that currently tabled in the Energy Bill).

Conversely, it will be interesting to see whether some of the new concepts introduced by the proposed ‘grace period’ conditions for onshore wind, such as the investment freezing condition, will find any place in DECC’s eagerly awaited response to its consultation on the proposed early closure of the RO to ≤5MW solar PV projects.

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Grace periods for early closure of Renewables Obligation support for onshore wind

The UK’s second capacity market auction – likely to deliver more of the same?

The initial results of the pre-qualification stage of the 2015 Capacity Market (CM) auctions, published on 25 September 2015, confirm the trend towards increasingly decentralised power generation.  Less than 3 GW of new projects will be competing for capacity agreements in December, but the total de-rated capacity of the pre-qualified bidders is only just greater than the target capacity identified by DECC in the auction parameters.*

CCGT: familiar disappointments

When the results of the 2014 auction were announced in January 2015, there was disappointment at how few sizeable CCGT projects had been successful.  The low auction clearing price of £19.40 was good for consumers (and a welcome supplement to the revenues of many existing plants), but too low to enable most large new-build projects to be viable.

Subject to the outcome of any pre-qualification appeals,** it appears that by one measure, only one** really new pre-qualified unit of “new” generating capacity with a capacity of more than 100 MW will participate in the “T-4 auction” for delivery in 2019.  This is 370 MW of CCGT capacity at King’s Lynn, but in the 2014 CM register, the same project was said to incorporate some “existing but overhauled and enhanced” elements. Meanwhile, three CCGT projects in the 1GW+ bracket (at Spalding**, Damhead Creek and London Gateway*) were all rejected in the T-4 pre-qualification process, as was a proposed new unit at Thorpe Marsh (640 MW).  The recently consented Hirwaun and Progress open-cycle projects (299 MW each) also failed to pre-qualify.***  Carrington (880 MW) will go forward to the auction, but although it is described as a “New Build” project in the CM Register, this is a project whose construction is already well advanced, so arguably does not represent the CM stimulating new investment.  Meanwhile, the T-4 2015 auction CM Register records about 1 GW of existing CCGT capacity that has opted out on the grounds that it will have decommissioned or otherwise ceased to operate by 1 October 2019.

A number of the rejected projects pre-qualified successfully for the 2014 auction, so their rejection seems puzzling given that the eligibility criteria are unchanged.  On the evidence of the pre-qualification results, it looks as if most, if not all, the new generating capacity will be connected to the distribution, rather than the transmission network, and will have a capacity of no more than 20 MW, often in the form of reciprocating engines that can be fuelled either by gas or diesel.*  Such plants can be developed relatively cheaply, and – being distribution-connected – can boost their revenues with “embedded benefits” such as Triad payments, or ancillary services contracts, in addition to power sales and CM payments.  It is interesting that even the 370 MW King’s Lynn project is described as being distribution-connected.

Coal carries on

The large volume of CCGT schemes consented over recent years were seen by some as the natural successors to the UK’s ageing fleet of coal-fired plants and, with new technology, better able to cope with fluctuations in demand in generating mix increasingly affected by the intermittent characteristics of renewables.  (In a recent interview with World Energy Focus, National Grid’s CEO, Steve Holliday, noted that three of NG’s four future energy scenarios have 20 GW of solar in the UK by 2035.)  But although the CM Register reminds us that by 2019, we will have lost over 5 GW of generating capacity with the closures of coal-fired plants at Eggborough, Longannet and Ferrybridge, it also highlights the point that we are still likely to have at least 13 GW of old coal-fired generation in 2020.

The same point emerges from the recent consultation on the UK’s Transitional National Plan (TNP) for compliance with the Industrial Emissions Directive (IED) as it affects large combustion plants).  It also appears from an Annex to the TNP consultation that some plants have still left themselves the option of either upgrading their SOx and NOx emissions abatement measures so as to meet the IED in a phased manner under the TNP, or taking the “limited life derogation” (LLD) and running for no more than 17,500 hours between 1 January 2016 and 31 December 2023, before closing for good.

So far, most seem to be choosing the TNP route, suggesting that we may have a significant rump of old coal-fired plant beyond 2020.  Those hedging their bets have until the end of the year to make their final choice as between TNP and LLD (or earlier closure).  Among the factors they will have to weigh up is how far low coal prices will offset the tax burden of the carbon price support rate of the Climate Change Levy; the reliability and maintenance costs of their ageing equipment; and whether there is a realistic prospect of new subsidy for biomass conversion or co-firing following e.g. the recent response to consultation on changes to the Renewables Obligation rules for those technologies.  Other generators may have to calculate how far the CM subsidies to coal may depress wholesale power prices, making the economics of CCGT more challenging and Contracts for Difference for low carbon plant more expensive per MWh.

New elements

Ofgem has now taken over the main responsibility for the complex rules that govern the CM.  Following the 2014 auction, a very large number of rule changes were suggested, and a significant number were made.  However, perhaps the two biggest changes in the 2015 process originated in DECC and European Commission policy decisions.

When the auctions take place later this year, the T-4 auction will be the second time that a CM auction has invited bids to provide reliable generating capacity four years ahead but the “Transitional Auction” will be the first specifically in support of Demand Side Response projects.  In fact, a number of DSR projects have been successful in both the T-4 auction and Transitional auction pre-qualifications.  These projects are a mixture of “behind the meter” generation and what is sometimes called “genuine” DSR in the form of load reduction.  Some are based around a single large industrial or commercial user, and others would aggregate the demand of multiple customers.  Both specialist aggregators such as Kiwi Power and “mainstream” electricity suppliers such as EDF and Smartest feature among the pre-qualified projects.  Given that the Transitional Auction is for first delivery in 2016/2017, it is interesting to note that a number of bidders have yet to specify exactly what their capacity market units will consist of.

The European Commission required the UK Government to include interconnectors in the CM, but accepted that this was not possible for the 2014 auction.  Following a consultation, a lot of work on how to approach the de-rating of interconnector capacity in the CM context, and some steps forward in Ofgem’s broader policy-making on various interconnector projects, a number of interconnectors were eligible, or required, to engage in the pre-qualification process for the 2015 T-4 auction.  The two Irish interconnectors (Moyle and East-West) opted out, BritNed’s application was rejected, and  among the proposed new interconnectors, only Nemo appears to have applied, and was rejected.****  The IFA has pre-qualified, but by definition it will be four years until its performance in the CM can inform further policy debate or the strategies of other interconnectors.  The case that national capacity markets will be easily compatible with the workings of the EU internal electricity market is perhaps not fully made out yet.

*Update note: since this blog post was first published, a number of new projects that were initially rejected for prequalification have been prequalified or conditionally prequalified – see the notes below.

**Update note: since this blog post was first published, National Grid has issued revised results reflecting Tier 1 Dispute Outcomes.  Amongst the changes from the 25 September 2015 results, the large-scale CCGT projects at Spalding, Damhead Creek and London Gateway are now listed as prequalified, or conditionally prequalified, for the T-4 2015 Auction, as has Thorpe Marsh CCGT Unit A.  This opens the prospect of there being 5 really new large-scale CCGT projects in the auction, rather than one as appeared from the 25 September results. 

***Update note: further to the appeals process, both these projects have now conditionally prequalified.

****Update note: Britned has now prequalified, and Nemo has conditionally prequalified.

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The UK’s second capacity market auction – likely to deliver more of the same?

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.

Degression

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.

Indexation

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”?

Levellling the playing field? UK Government reduces effective of price of renewable power by £5/MWh

On 8 July 2015, George Osborne’s Summer 2015 Budget had little new to say about UK energy policy: extension of some North Sea tax reliefs, a review of energy efficiency taxation, repetition of existing commitments to seeking a UN climate change deal at Paris later this year.  However, one measure stood out as an unwelcome surprise for generators of renewable electricity.  From 31 July 2015, suppliers who sell “green” power to business users will have to pay the same “climate change levy” (CCL) of £5.54/MWh as they do when supplying “brown” power from coal, gas or nuclear plant.

The CCL is a tax on business and public sector energy use.  The general rule is that supplies of electricity to non-domestic customers are subject to a levy of £5.54/MWh.  (There are separate or additional rates for supplies of other “taxable commodities” such as coal and gas.)  But electricity generated from renewable sources is exempt.  Generators of such electricity receive “levy exemption certificates” (LECs) from Ofgem which entitle suppliers to claim relief on the tax when they supply the associated power.  As a result, when renewable generators sell their power to suppliers under power purchase agreements (PPAs), part of the payment which they receive from the supplier for each MWh of power that they sell is made up of a proportion of the value of the associated LEC to the supplier.

Brief details of the change announced in the Budget are set out in a policy paper from HMRC.  The removal of the exemption is justified on the grounds that it will contribute to “fiscal consolidation” and “maintain the price signal necessary to incentivise energy efficiency”, and that a third of the value of the exemption (£3.9 billion over the life of the current Parliament) goes to supporting “renewable electricity generated overseas” (possible sub-text: “and those pesky EU single market rules might make it hard for us to stop overseas projects receiving LECs without also removing the entitlement from domestic ones”?).  HMRC also suggest that the value of LECs will be “negligible by the early 2020s, when the supply of renewable electricity will exceed CCL eligible business demand for it”, but even if that is so, it is not clear why it justifies scrapping LECs now, while they are still worth having.

The Budget indicates that there will be some transitional provision: “There will be a transitional period for suppliers, from 1 August 2015, to claim the CCL exemption on any renewable electricity that was generated before that date. The government will discuss the details of this transitional period with stakeholders over the summer and autumn, to determine an appropriate length for it.“.  The relevant legislation will be included in the Summer Finance Bill 2015 and the Finance Bill 2016.

However, the key point is that within a few months, all existing and future renewables projects will be deprived of a small but significant element of their anticipated revenue, and the suppliers who buy their power will have one less reason to purchase renewable power.  Some projects may find that the reduction in the rate of corporation tax, also announced in the Budget, offsets, or helps to offset, the reduction in revenue.  But for projects in the early stage of their operating lives that are on relatively low rates of Renewables Obligation or Feed-in Tariff support, there is likely to be an appreciable impact.  Moreover, the removal of LECs is one of a number of recent changes that may make renewable PPAs less attractive.  These include the shift from the Renewables Obligation to CfDs – admittedly partly counterbalanced by the backstop PPA or “offtaker of last resort” regime – and Ofgem’s decision to increase significantly the imbalance prices that suppliers can be exposed to as a result of contracting with intermittent generators.

The good news is that removing renewable generators’ entitlement to LECs will help to reduce the deficit.  The Government’s estimates of the impact of the measure show a positive impact on annual tax revenues of £450 million in 2015/2016 rising steadily to £910 million in 2020/2021.

Behind these fairly large increases in Exchequer revenues lie some significant negative effects on individual projects.  Shares in Drax fell substantially on the announcement and the company indicated that the change could reduce its 2016 earnings by £60m.  It is also possible that projects whose bids set, or were close to, the clearing prices in the first auction of Contracts for Difference (CfDs) may feel the loss of LECs if they included LEC revenues in the financial modelling assumptions for their bids.

The LEC change comes on top of the Government’s announcement of early termination of the Renewables Obligation for onshore wind and suggestions by the Competition and Markets Authority in the summary of its provisional findings on competition in GB energy supply markets that even the competitive allocation process that was used by DECC to allocate CfDs earlier this year may be too generous (in reserving particular “pots” of funding to specified technologies).  While they wait to see what allocation of funding will be made available for new projects in the next CfD round, and when it will take place, renewable generators are likely to want to spend some time reviewing the Change in Law provisions in their existing PPAs (or even CfDs) to see how the loss of LECs affects them.

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Levellling the playing field? UK Government reduces effective of price of renewable power by £5/MWh

The Politics of Onshore Wind

The new Conservative Government has made curbing the growth of onshore wind one of its short-term priorities.  On 18 June 2015, the Department of Energy and Climate Change (DECC) confirmed the Government’s intention to implement the Conservatives’ 2015 General Election manifesto promise to “end new public subsidies for onshore wind” by “legislating to close the Renewables Obligation across Great Britain to new onshore wind generating stations from 1 April 2016”.  The Secretary of State for Energy and Climate Change, Amber Rudd, made a further, oral statement to Parliament on 22 June 2015, giving further details of her thinking and the potential impacts of the change.

DECC has stated that “up to 5.2GW of onshore wind capacity could be eligible for grace periods which the Government is minded to offer to projects that already have planning consent, a grid connection offer and acceptance, as well as evidence of land rights”.  But it has also calculated that some 7GW of new onshore wind capacity (250 projects, 2,500 turbines) are likely not to be commissioned as a result of the early closure.  The future treatment of onshore wind under the separate Contracts for Difference and Feed-in Tariffs regimes remains to be clarified.

Industry has not been slow in condemning the chilling effect which the Government’s announcement will have on many projects.  But what can they actually do about it?

The Renewables Obligation (RO) is scheduled to be closed to new projects on 31 March 2017 in any event (subject to some grace period arrangements) as part of the transition to the Contracts for Difference regime being the primary subsidy vehicle for large-scale renewables projects.  The early closure for onshore wind echoes the treatment of >5MW solar projects, to which the RO was closed on 31 March 2015, subject to one-year grace periods both for projects already holding planning consent, grid connection offer and acceptance and evidence of land rights, and for projects which only failed to commission in time to be accredited by 31 March 2015 because of grid delays.

The early closure of the RO to >5MW solar was effected by an “RO closure order”: a piece of secondary legislation which Ministers were given powers to make (subject to Parliamentary approval) under the Energy Act 2013.  Ministers could, of course, use the same method in the case of onshore wind, but the DECC announcement states that the closure of the RO for onshore wind will be achieved by primary legislation – i.e. a Parliamentary Bill.  This means that there will be no statutory obligation to consult on the proposals before they are put to Parliament.  It also means that they will receive vastly more Parliamentary scrutiny: when a draft order is put before Parliament, it is presented on a take-it-or-leave-it basis and it is seldom debated for more than an hour by a handful of MPs or Peers.  In the vast majority of cases, the draft is approved.  By contrast, any provision that is put before Parliament as part of a Bill is capable of being amended or made the subject of counter-proposals.  So the industry can fight back by lobbying MPs and Peers, and the Government’s Commons majority may or may not be strong enough to make it impossible for those seeking a less harsh outcome for onshore wind projects to make some headway.

Before the 18 June announcement, there was much talk of possible legal challenges to the expected ending of onshore wind subsidies.  However, DECC’s decision to use primary legislation makes judicial review a less promising avenue for the industry.  A recent judgment in a case relating to changes to solar subsidies has made it clear that in certain circumstances a Government decision to consult on proposed subsidy cuts can be challenged in itself (even if there is no subsequent decision to implement the proposal).  The same case has clarified the range of circumstances in which projects which have not yet achieved accreditation under a subsidy scheme can nevertheless still make a claim for damages as a result of a change in subsidies.  However, if the next thing that Government does is to introduce provisions to implement the closure of the RO to onshore wind in its forthcoming Energy Bill, it is doubtful whether that action could be judicially reviewed.  Unlike a decision to make a piece of secondary legislation, or to consult on doing so, which are executive acts, a Minister’s decision to put forward a Bill is something that he or she does in his or her capacity as a Member of Parliament.  As such, it may well be considered by the Courts to fall within the category of “proceedings in Parliament” which are not judicially reviewable.  One possible trump card for the industry might be to find a way of characterising the proposed legislation as contrary to EU law: no doubt some opponents of onshore wind (inside and outside Parliament) would relish that.

The industry – using the language of judicial review – has attacked the early closure as “irrational”.   Amber Rudd told Parliament: “We could end up with more onshore wind projects than we can afford – which would lead to either higher bills for consumers, or other renewable technologies, such as offshore wind, losing out on support.  We need to continue investing in less mature technologies so that they realise their promise, just as onshore wind has done.”  The references to issues of affordability and the impact that the amount of subsidy budget (the “Levy Control Framework”) that wind would consume might have on support for other types of renewable generation echo the arguments for closing the RO early to >5MW solar, where a claim for judicial review was firmly dismissed.  But it is hard to avoid the feeling that political, as well as economic considerations are in play.  And although DECC has stated that “we now have enough subsidised projects in the pipeline to meet our renewable energy commitments”, it is interesting to note that a few days earlier, the European Commission published a status update on EU Member States’ prospects of meeting their 2020 renewables deployment targets that showed the UK as being one of a number of Member States that need to “assess whether their policies and tools are sufficient and effective in meeting their renewable energy objectives“.

The subsidy change is explicitly linked to the parallel commitment to “give local communities the final say over any new wind farms”, fleshed out in a statement from the Secretary of State for Communities and Local Government on the same day.  But whilst the subsidy changes would apply throughout Great Britain (the content of the RO being for DECC Ministers to determine), the planning regime is more of a patchwork.  Hitherto, broadly speaking, onshore wind projects up to 50MW were consented by local planning authorities (everywhere), while applications to develop projects of 50MW or above fell to be determined by DECC Ministers in England and Wales and Scottish Ministers in Scotland.  It is now proposed that all wind farm applications in England will be decided locally, and that planning permission should only be granted if “the development site is in an area identified for wind energy development in a Local or Neighbourhood Plan”.  This gives English local authorities who do not wish to see wind farms in their area much greater ability to refuse them planning permission.  In Wales, under the St David’s Day Agreement, there are moves to devolve consents for projects up to 350MW to Welsh Ministers.  But before that happens, a number of old consent applications for >50MW onshore wind projects in Wales that have attracted considerable opposition and been the subject of a public inquiry are likely to be decided by DECC Ministers.  In Scotland, where >50MW consents are already devolved, no changes made by Ministers in Whitehall in relation to consenting will have an effect, but the subsidy changes will probably have a much greater negative impact on future projects throughout Great Britain than any decisions taken by planning authorities or Ministers on consents.

It could be said that all this is simply democracy at work.  There is a broad strand of Conservative opinion that is anti-onshore wind.  The Conservative Party sent a clear signal of its intentions in regard to onshore wind in its manifesto.  It won the election.  Of course, it didn’t do very well in Scotland, but while most of the big onshore wind farms are in Scotland, the money to support them under the RO mostly comes from England, where the largest number of consumers (who pay for subsidies in their electricity bills) live.  No doubt there will be lively debates on the provisions of the current Scotland Bill that proposes (very limited) further devolution of energy matters to the Scottish Government, as well as on the provisions of the forthcoming Energy Bill on closure of the RO to onshore wind.  But it hardly needs saying that however politically exciting the process may be, it does not provide a stable background for investment in what is apparently still the cheapest form of renewable generation – and one which new research suggests could also be made a lot quieter and more efficient, thus removing some of the stronger potential non-aesthetic objections to it.

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The Politics of Onshore Wind

Global perspectives on the energy sector

What is the future for traditional power utilities?  What can Europe learn from the US experience of capacity markets?  What is holding back the development of the power sector in Africa?  What are the key political and economic considerations for those investing in Middle East energy projects?  How should energy companies deal with cyber security risks?  How can they gain business advantage by engaging proactively with Human Rights law and international investment treaties?  Where is the oil price going and what does that mean for industry consolidation?  Will the Paris 2015 UN Climate Change talks succeed where others are perceived to have failed?  How can projects to prevent deforestation be made to pay their way?

For perspectives on these and other hot topics in the energy sector worldwide, see our Global Energy Summit London 2015: Key Themes report, based on presentations given on 21 and 22 April 2015 in Dentons’ London Office by a range of expert contributors.  Individual presenters’ slides are also available on our website.

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Global perspectives on the energy sector

Failure of competition in retail energy markets: “disengaged customers” (still) the root cause?

Emerging analysis from the investigation into GB gas and electricity supply by the UK’s Competition and Markets Authority (CMA) suggests that consumers are paying more than they need to because of their failure to “engage in” the market and because of shortcomings in the regulation of the sector.

Some seven months into an investigation instigated by Ofgem and six months after producing its initial issues statement setting out the areas on which it would be focusing, the CMA has published an updated version of the issues statement and a summary of smaller suppliers’ views on barriers to entry and expansion in the market (one of a series of “working papers” that provide more detail of the CMA’s analysis and the evidence on which it is based).

The problem

The CMA is fairly clear that both domestic and “microbusiness” consumers of gas and electricity are paying more than they need to – noting, for example, that “95% of the dual fuel customers” of the Big 6 could have saved an average of between £158 and £234 by switching tariff and/or supplier.  They also note, as others have done before them, that customers on “Standard Variable Tariffs” (SVT) tend to see their bills rising faster and falling slower than increases and decreases in the underlying costs of supply would suggest (the so-called “rocket and feather” effect – see graph below).

CMA fig 1

The search for causes

However, the CMA has so far rejected a number of the “usual suspects” when it comes to explaining why consumers appear to be paying more than they need to, without there being any obvious reason for their loyalty to their existing suppliers.  The initial issues statement was based on four hypothetical “theories of harm” that could account for failures of competition:

  • “market power in electricity generation leads to higher prices;
  • opaque prices and/or low levels of liquidity in wholesale electricity markets create barriers to entry in retail and generation, perverse incentives for generators and/or other inefficiencies in market functioning;
  • vertically integrated electricity companies harm the competitive position of non-integrated firms to the detriment of the customer, either by increasing the costs of non-integrated energy suppliers or reducing the sales of non-integrated generating companies;
  • energy suppliers face weak incentives to compete on price and non-price factors in retail markets, due in particular to inactive customers, supplier behaviour and/or regulatory interventions.”.

Taking each of these in turn, the CMA’s current (but explicitly provisional) analysis is as follows:

  • The Big 6 are not making excessive profits from generation and do not have the ability or incentive – individually or collectively – to increase profits by withdrawing capacity.
  • There are not significant problems as regards the transparency of the wholesale markets.  Those smaller suppliers who complain about a lack of liquidity, at least for certain products, have yet to persuade the CMA that this is a major concern, although they note that Ofgem’s Secure and Promote licence condition has not addressed all the problems in this area.
  • The CMA also does not think that the Big 6’s vertical integration enables them to cause independent generators to restrict their output or allows them to take action in the wholesale markets that disadvantages independent retailers.  One independent supplier saw vertical integration as a competitive disadvantage (potentially tying a supplier to generating plant whose efficiency reduces over time, especially if measured against the best in the market).
  • The only one of the original “theories of harm” which seems to offer an explanation of the failure of competition is the fourth one above, notably “inactive consumers”.  Although the domestic market share of independent suppliers grew from 1% to 7% (electricity) or 8% (gas) between July 2011 and July 2014, the fact remains that almost half of domestic consumers have not switched supplier for at least 10 years.  Many do not even believe switching is possible.  As one of the independent suppliers points out, having a large base of relatively price-insensitive customers on SVT may enable an incumbent to compete more aggressively against new entrants for the business of those who do take active steps to get a good deal.  Another suggests that it is almost as if there are two markets: one composed of potential switchers and another of those who are terminally loyal to their incumbent supplier.

Regulation may be stifling competition

One of the things that stands out in the CMA’s analysis is the emphasis on the potentially adverse effects that various aspects of sectoral regulation may be having on competition.  This is most conspicuous in the addition of two new hypothetical “theories or harm”:

  • “the market rules and regulatory framework distort competition and lead to inefficiencies in wholesale electricity markets;
  • the broader regulatory framework, including the current system of code governance, acts as a barrier to pro-competitive innovation and change.”.

But it is also seen elsewhere.  Examples of potentially problematic regulation identified include:

  • Elements in Ofgem’s recent reform of cashout prices (the Electricity Balancing Significant Code Review) “may lead to an overcompensation of generators”.
  • It may be inefficient not to have a system of locational prices for constraints and losses on the transmission network.  It may be that consumers in Scotland and the North of England should be paying more, and those in the South of England paying less, for their electricity.
  • The Capacity Market element of Electricity Market Reform (EMR) “appears broadly competitive”, but the CMA plan to look at if further.  They note that the Contracts for Difference regime may not secure the lowest prices for renewable generation subsidies by having separate “pots” for different technologies, rather than requiring them to compete all-against-all, or by allowing the award of contracts on a non-competitive basis, before observing, equally obviously, that “there are potentially competing objectives that need to be taken into account in the design of the CfD allocation mechanism”.  One independent supplier also characterises the system by which CfD costs are recovered from suppliers as “madness”.
  • But any problems caused by EMR are for the future.  Looking back, the CMA have clearly listened both to those who have criticised Ofgem’s 2009 decision to prohibit regional price discrimination (while providing exemptions for promotional tariffs), which may have led to a consumer-confusing increase in the number of tariffs, and to those who question Ofgem’s 2013 decision to force suppliers to “simplify” their tariff portfolios drastically, which resulted in the loss of tariff discount options that may or may not have been valued by consumers.  However, the CMA have yet to form a final view on the merits of either decision.
  • It has often been observed that the 250,000 account threshold, above which suppliers become subject to the Energy Company Obligation (ECO), may act as a barrier to growth for independent suppliers.  More interestingly, the CMA note that the costs of the social and environmental policies delivered by suppliers “fall disproportionately on electricity rather than gas”, meaning that “domestic consumption of electricity attracts a much higher implicit carbon price than domestic consumption of gas” – which may have implications for the take-up of electrical heating systems (normally thought of as part of decarbonising energy usage).  This is another area where the CMA will be investigating further.
  • Finally, the CMA identify aspects of the Balancing and Settlement Code (BSC) and other industry agreements that could be standing in the way of more effective competition.  They ask, for example, why, once smart meters have been rolled out, there are no plans to move away from the system whereby domestic customers’ consumption is “profiled”, rather than being based on half-hourly meter readings.  Failure to take advantage of the new technology in this way could “distort incentives to innovate”.  The CMA will also be considering further whether there are just too many codes in the electricity industry (constituting a barrier to entry) and whether the mechanisms for changing industry rules may be stacked too heavily in favour of incumbents and the status quo.  On the first point, Elexon itself, administrator of the BSC, apparently thinks that “rationalising” the codes will remove potential barriers to competition.

Next steps

Interested parties have until 18 March 2015 to comment on the updated issues statement.  The next major step will be the publication of “provisional findings”, currently scheduled for May 2015.  Overall, the investigation is not due to conclude before November / December 2015, and it could be extended into 2016.  It is of course far too early to speculate on possible remedies, but for now the more obviously Draconian options in the CMA’s armoury, such as the breaking up of vertically integrated groups, appear unlikely outcomes.  Something eye-catching to cause “inactive” consumers to “engage”, and a lot of “boring but important” changes in the regulatory undergrowth around industry codes and agreements seem reasonable bets for now, but there is a long way to go yet.

 

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Failure of competition in retail energy markets: “disengaged customers” (still) the root cause?

UK fracking: the pursuit of safety

Further changes to the Infrastructure Bill have now addressed the potential problems for the UK unconventionals industry introduced by a Labour amendment two weeks ago, but the approach of Scottish and possibly Welsh Ministers is less encouraging for would-be shale developers.

Infrastructure Bill

At the last substantive debate on the Infrastructure Bill in the Commons, an amendment was inserted providing that “any hydraulic fracturing can not take place” unless 13 conditions are fulfilled.  As we pointed out in an earlier post, the drafting of this “safeguarding” provision (which can be seen here at amendment no.21) left considerable scope for doubt as to when some of these conditions would be satisfied.  Such uncertainty inevitably assists those who want to delay or obstruct fracking operations.

The House of Lords has now replaced the Commons’ amendment with some much better drafted provisions (see amendment 21B here) that provide a clear and practicable route to satisfying each of the safeguarding requirements proposed by the Commons.  Although the Labour spokesman, Lord Tunnicliffe, raised a number of points of detail which he suggested had been lost in translation from the Commons’ amendment to the Government’s version (see column 1079 of the Hansard report), it seems possible that there will be no further changes when the Bill returns to the Commons for the next stage of the so-called ping-pong process.

In the meantime, here are ten points to note about the new clauses:

1      The new clauses insert two new sections (4A and 4B) into the Petroleum Act 1998, under which oil and gas exploration, production and development licences are granted.

2      The standard conditions of licences for onshore development (the model clauses) provide that the licensee may not commence drilling of any well or borehole without the Secretary of State’s consent.  In future, any such “well consent” must contain a condition prohibiting fracking at a depth of less than 1000 metres and a condition requiring the licensee to have the Secretary of State’s consent for any fracking at a depth of 1000 metres or more.

3      Under new section 4A, the Secretary of State may only issue a “hydraulic fracturing consent” if he is satisfied that 12 conditions are met.  These conditions reflect the Commons’ 13 pre-conditions for permitting fracking, but they are expressed more clearly and 11 of them are accompanied by a description of the documents whose existence will be sufficient for the Secretary of State to be satisfied that the relevant condition is met – although the legislation explicitly states that he may also consider them to be satisfied without reference to such documents.

4      The 12th condition is “that a scheme is in place to provide financial or other benefit for the local area” – slightly wider than the equivalent Commons drafting.  The Commons’ 13th condition was about not fracking at less than 1000 metres: this is subsumed into the well consent itself, rather than being a condition for issuing the hydraulic fracturing consent.

5      The new conditions avoid imposing the Commons’ requirement to notify “residents in the area on an individual basis”, substituting a requirement for the local planning authority to confirm that the applicant has self-certified its compliance with publicity requirements under the planning regime.  Baroness Verma, speaking for the Government, pointed out that it would be difficult for the Secretary of State to be satisfied that all residents had been individually notified.

6      The picture is not yet quite complete.  Draft regulations are to be laid before Parliament, by 31 July 2015, to clarify the burning issue of exactly which “protected groundwater source areas” and “other protected areas” will be off-limits to fracking.  Unless the current Government (or its successor) means to beat that deadline by a wide margin, it may be Autumn before these important details have been clarified and we know whether Greenpeace’s analysis of the extent of the protected areas is unduly optimistic from an anti-fracking point of view.

7      Government has made a lot of statements and published guidance about the inter-relationship of the various different consenting regimes that apply to fracking, but new section 4A for the first time “joins the dots” between the different regimes in legislation.  So, for example, the condition on environmental impact assessment is linked to a notice from the local authority; the requirements about methane monitoring are linked to conditions in the environmental permit; and the requirement on well integrity is linked to an HSE certificate.

8      The decision to permit fracking in each case rests with the Secretary of State, but if everything is working as it should, he will issue the consent on the basis of work that is already required to be done under the existing planning and other regulatory regimes. Presumably for that reason, applications for hydraulic fracturing consents are not required to be published or consulted on.

9      A hydraulic fracturing consent may be issued subject to conditions.  Failure to comply with the conditions of a hydraulic fracturing consent, or with the prohibition on fracking at less than 1000m, could lead to revocation of the underlying licence.

10    Once the new sections are in force, the requirement to apply for and obtain a hydraulic fracturing consent before beginning to frack will apply whenever a licensee seeks a new well consent, regardless of when the licence under which the consent is sought was granted.

The provisions about hydraulic fracturing consents link to another change made to the text of the Bill as it left the Commons.  This relates to reporting by the Committee on Climate Change on the impact that greenhouse gas emissions from the use and extraction of gas from onshore sources may have on the UK’s ability to meet its Climate Change Act emissions reduction targets.  When such reports are produced (on 1 April 2016 and every 5 years thereafter), the Secretary of State will be obliged either to legislate to terminate the right of use of deep level land for petroleum and deep geothermal exploitation or to produce a report explaining why he has not done so.  But if the right of use is terminated, it will only be removed in respect of projects that have not already made use of that right.

Scotland and Wales

While for the Coalition Government in Westminster, a safety-first approach to fracking may be achievable simply by means of some deft legislative drafting, the politics in Edinburgh and Cardiff are different.  Both Scottish and Welsh Ministers have recently taken a less positive stance on fracking.

The negative noises from Ministers in the devolved governments come in the context of debates about further devolution of energy-related powers and against the background of the awkward split between the oil and gas licensing regime (currently administered by the Secretary of State for all of Great Britain, but a potential candidate for further devolution, particularly in Scotland)  and the planning regime (where Welsh and Scottish Ministers are, or can be, the ultimate decision-makers).  Any unconventional development will need both a Petroleum Act licence and planning permission.

On 28 January 2015, Fergus Ewing, the Scottish Energy Minister, announced that the Scottish Government’s “cautious, evidence-based approach” to fracking and its desire to hear “the voices of the communities…likely to be most affected…in a formal and structured way” meant that “it would be inappropriate to allow any planning consents in the meantime” and he announced ” a moratorium on the granting of planning consents to unconventional oil and gas developments…until such time as the work I have referred to has been completed”.  Scottish Ministers have also directed the Scottish Environment Protection Agency not to issue any “controlled activity regulation licences” during the moratorium (see page 17 of the report here for the full debate).

On 4 February 2015, there was a vote in the National Assembly for Wales in favour of both the devolution of energy consents and a fracking moratorium.  Discussion of fracking, ranging as far afield as New York and New South Wales, dominated the debate: the party lines on the subject in Cardiff are not the same as those in Westminster.

It seems that Welsh and Scottish Governments have made the political calculation that it is best to let England lead the way in building the UK evidence base on fracking.

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UK fracking: the pursuit of safety

UK Parliament votes against moratorium on fracking – but there may be a catch

Perhaps unsurprisingly, yesterday afternoon’s House of Commons debate on the Infrastructure Bill did not result in the introduction of the explicit moratorium on further attempts to develop a UK shale gas industry that had been proposed by a number of MPs opposed to fracking.  However, two significant changes have been made to the Bill’s provisions on shale gas exploitation in the UK.

Pre-match build-up

The debate was at the Bill’s “Report” stage in the Commons: this is the first opportunity that the full House, rather than the Committee which has done most of the line-by-line scrutiny work, has to vote on changes to a Bill.  (It is also the last such opportunity, unless the House of Lords subsequently disagrees with changes made by the Commons.)  A large number of amendments had been tabled, mostly seeking either to restrict fracking in some way or requiring further investigation of and reporting on its impacts on climate change, for example as a result of fugitive emissions of methane from fracking sites.  Whilst both the Government and the official Labour Party lines are that fracking should be allowed subject to proper safeguards, there are differences of view as to how far existing legislation and institutions provide sufficient protection for the environment.  And there are a number of MPs of all parties who disapprove of fracking in any circumstances.

This strain of opposition to fracking in principle was demonstrated when the House of Commons Environmental Audit Committee (EAC), which has been considering fracking, chose to publish its report on the morning of the debate.  The report puts the case against developing a UK shale industry on the grounds that it would inevitably be inconsistent with the UK’s climate change emissions reductions targets to do so.  The EAC argue that the Government is wrong if it argues that shale gas is good because it will displace coal as a fuel for electricity generation and so reduce emissions.  They believe that a flourishing shale industry would be bound to breach the UK’s carbon budgets, set under the Climate Change Act 2008.  Essentially, they see the UK’s apparent shale reserves as a prime example of “unburnable carbon“.  The Committee also express concern about the uncertainty surrounding some other impacts of fracking, e.g. on water, and cite “a lack of public acceptance” for the technology.  They conclude that “a moratorium on the extraction of unconventional gas through fracking” is required to “allow the uncertainty surrounding environmental risks to be resolved”.

By a further happy coincidence, The Guardian simultaneously published a leaked letter from George Osborne to Cabinet colleagues on fracking.  The letter demonstrates in some detail the extent of the efforts being made by central Government to ensure that it does everything that it can properly do to facilitate consent for fracking through processes that it does not entirely control (because planning and other consents are administered by local government or the Environment Agency).

Finally, in the days between the end of the Committee sessions and the debate, there was a slow drip-feed of anti-fracking amendments being published and trailed in the media – and Vivienne Westwood and others turned up to protest outside Parliament on the day.

The main event

In the end, as often happens, the debate itself was something of an anti-climax.  The Government used its control of the House to confine the debate to less than two hours, which was followed by votes on a more or less representative sample of the amendments.  Some of the debate generated (in participants’ own words) more heat than light.  Attention was paid to the fate of a report by Defra on the impact of shale gas on the rural economy, which has so far been published only in redacted form.  Some suspect that the Government is suppressing unwelcome analysis.  Ministers have done little to dispel this by saying that the report should not have been produced, is not analytically robust and would not help the debate.  A fair amount of time was also devoted to the question of whether or not MPs had received a copy of a letter from a Minister following up on an earlier debate.

But there was also a considerable amount of substantive discussion.  For example, the arguments from the EAC report were rehearsed, and rebutted by a number of speakers, who pointed out the continuing importance of gas to our heating, as well as electricity generation needs, and that the life-cycle carbon emissions of LNG (on which we are likely to depend in the long-term if we do not find new sources of indigenous gas) have been found to be higher than those associated with shale gas.

The question of further devolution of powers to Scotland was also raised: if legislative competence for the licensing of onshore oil and gas exploration and extraction is to be devolved to the Scottish Parliament, as the Government has proposed following the recommendations of the Smith Commission, should the Government not wait before awarding further licences in Scotland?  Unsurprisingly, Ministers were not persuaded by this view.  After all, they are not proposing to devolve the actual granting of licences to the Scottish Government.

If you don’t want to know the result, look away now…

In the end, only two substantive amendments have been introduced into the Bill in relation to shale gas as a result of yesterday’s debate.

  • A Government amendment requiring the Secretary of State to request the Committee on Climate Change (CCC) to provide advice on the impact which “combustion of, and fugitive emissions from, petroleum got through onshore activity” is likely to have on the Secretary of State’s ability to meet the Climate Change Act duties to reduce greenhouse gas emissions by 80% by 2050 and to meet each of the carbon budgets set under the Act in the meantime.  Future Governments will be obliged to report on the conclusions they have reached after considering the advice of the CCC – a sort of “comply or explain” mechanism.
  • As was expected, the Government allowed a Labour front bench amendment to pass.  The intention of the new clause it introduced is said to be: “to ensure that shale gas exploration and extraction can only proceed with appropriate regulation and comprehensive monitoring and to ensure that any activity is consistent with climate change obligations and local environmental considerations”.  Politically, accepting the new clause was clearly the expedient course.  From a legal point of view, it may cause more problems than it solves.

The new clause lists 13 things that must happen before “any hydraulic fracturing activity” can take place in Great Britain.  The list is a mixture.  Some of the pre-conditions it sets reflect existing legislation – for example requirements to carry out an environmental impact assessment; for planning authorities to consider the cumulative impact of fracking proposals in a given area; and to seek Environment Agency approval of fracking fluids.  Others include monitoring of the site for 12 months before fracking begins; “site-by-site measurement, monitoring and public disclosure of existing and future fugitive emissions”; independent inspection of well integrity; avoidance of groundwater source protection zones; a statutory requirement for the kind of community benefit schemes the industry has already promised; bans on fracking in “protected areas” (undefined), or at depths of less than 1,000 metres; and notification of residents in the area “on an individual basis”.

The House of Lords will now have an opportunity to consider the amendments made by the Commons.  Unless some changes are made to clarify the less tidy parts of the new clause’s drafting, uncertainties over what it requires may lead to a moratorium on GB fracking by the back door if and when the new clause comes into effect.

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UK Parliament votes against moratorium on fracking – but there may be a catch