Day: October 11, 2024

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.

Following the recommendations of the Wood Review of the UK’s offshore oil and gas industry, and an initial debate in the House of Lords, clauses have been inserted into the Infrastructure Bill currently before Parliament to legislate for the key principle in Sir Ian Wood’s report, that of “maximising economic recovery of oil and gas for the UK” (MER UK). So far, though, the legislative provisions that have been put forward leave a number of questions unanswered about the new world of regulation according to the principle of MER UK.

Central to Wood’s vision (discussed in an earlier post on this Blog) was the recommendation that a new regulator with a duty to promote MER UK should replace the Department of Energy and Climate Change (DECC) as the body responsible for administering the licensing of petroleum extraction on the UK Continental Shelf. In its response to Wood, the Government has announced that such a body will be created, and indeed the Oil and Gas Authority (OGA) is already in the process of being established in Aberdeen.

The OGA is to be “an independent arm’s-length body, accountable to the DECC Secretary of State, working within a strategic policy and operating framework set by him…to deliver objectives established by him”. It is to use its powers to require licensed operators to act in accordance with MER UK principles and to “instil a new culture of partnership and challenge that will pervade the delivery of MER UK”.

However, there is no mention of the OGA in the Infrastructure Bill. It is said that there is not time to establish the OGA in its final form in the current Parliament, so it is to begin its life as an Executive Agency of the Department of Energy and Climate Change. Reading the new clauses, therefore,  one needs to be aware that some of the provisions that refer to the Secretary of State (those relating to licensing functions) will in due course presumably be amended to refer to the OGA, whilst others (those that refer to the establishment of the strategies) will not.

The Government’s response to Wood states that the OGA should be “operational” in “shadow” form in autumn 2014 and sets a target date of early 2016 for it to be “vested with the necessary powers, duties and functions”. Delivering this obviously depends on the will of a new Government and Parliament. In the meantime, what do the clauses in the Infrastructure Bill tell us?

The concept of MER UK is referred to in the new legislation as “the principal objective”. It is, however, not defined, on the grounds that the Government thinks that it is “something that itself is likely to change over time”.

The principal objective is stated to involve, in particular, the development, construction, deployment and use of upstream petroleum infrastructure, as well as collaboration among holders of and operators under Petroleum Act licences, the owners of upstream petroleum infrastructure and persons planning and carrying out the commissioning of such infrastructure. The Secretary of State is obliged to produce one or more strategies for enabling that the principal objective is met. (Wood recommended six strategies in all, covering exploration, asset stewardship, regional development, infrastructure, technology and decommissioning.) The strategies are to be produced within a year of the relevant provisions of the Infrastructure Bill coming into force, which fits with the “early 2016” target date for the OGA to be fully established. Strategies are to be consulted on in draft and are subject to Parliamentary control by negative resolution. They must be reviewed every four years.

These strategies are to have significant legal implications. The Secretary of State is to act in accordance with them when exercising licensing, decommissioning and third party access functions. Holders of and operators under Petroleum Act licences must carry out their respective activities and make related commercial arrangements in accordance with the strategies. Similar obligations are imposed on owners of upstream petroleum infrastructure and those planning and carrying out commissioning of such infrastructure. However, it is not immediately clear how such obligations will be enforced.

Whilst the focus of the Wood Review was on the recovery of oil and gas from the UK Continental Shelf, the Government’s response states that it “agrees that the [OGA’s] remit should extend to onshore (as well as to [licensing of offshore] Natural Gas Storage and Unloading and Carbon Dioxide Storage)”. The response also states that the Government “believes that the MER UK philosophy established by Sir Ian’s Review should be applied to all oil and gas recovery whether offshore in the UKCS or onshore”. The new regulatory framework being put in place here, then, is not just for the UKCS oil and gas industry, but DECC’s thinking about its wider application seems to be at a relatively early stage. The Government notes, for example, that the application of MER UK principles “may need to be quite different onshore”, and that further consultation is required on this subject, which “should not detract from the focus that is needed on developing MER UK strategies for the UKCS”. At present, the most recent model clauses for onshore licences further embed the concept of maximising economic recovery from the licensed area, rather than MER UK.

A number of Opposition amendments to the new clauses have been proposed, but have not found favour with the Government. These included requirements for the regulator to attend operating and technical committee meetings (a matter “on which the Government intend to work closely with industry to pursue further before deciding what additional powers might be needed”) and provision for the concept of MER UK explicitly to embrace enhanced oil recovery (“intrinsic” to MER UK and so no reference to it is needed in the legislation) as well as the linked technology of carbon capture and storage (“discussion with industry…is needed before we can say with certainty how the MER UK principle should apply to [this area]”).

One of Wood’s key conclusions was that, as the Petroleum Act regulator, DECC was insufficiently resourced, particularly as compared to its peers in other North Sea countries. The Infrastructure Bill therefore provides for a levy under which licence holders will contribute towards the costs of the Secretary of State / OGA where these are not already recovered through specific fees under other legislation. Initially, levy receipts are likely to fund policy work in developing the MER UK strategies, but the levy provisions effectively expire after three years, “to ensure that an effective and efficient cost recovery mechanism is developed in consultation with industry during this time”.

The Government’s response to consultation is clear on the need for further legislative work. Amongst the points potentially requiring further legislation, it highlights the possible need for the OGA to have dispute resolution powers to deal with “overzealous legal and commercial behaviour between operators”. It notes the need for the OGA to be equipped with a more graduated sanctions and incentives regime for enforcement purposes (at present the main available sanction, that of revocation, is arguably too much of a blunt instrument for most purposes). It notes the Government’s commitment to increasing the transparency of and access to data. It notes the potential need for further powers to encourage e.g. joint development plans, area unitisation and “appropriate access to infrastructure without contravening competition law or weakening market incentives”.

Overall, then, the clauses in the Infrastructure Bill are a good start, but much remains to be done in a relatively short time-frame if the detail of Wood’s ambitious vision is to be fully realised. It also remains to be seen whether the regulatory aspects of MER UK will later be supported by any further measures to increase the attractiveness of the UKCS as against other parts of the North Sea (for example, fiscal incentives beyond those announced in Budget 2014 and discussed in an earlier post on this Blog).

A new stage in the UK Government’s campaign to remove potential obstacles in the way of shale gas developments was reached last week following a debate in the House of Lords.  Clauses on access to “deep-level land” for petroleum extraction and deep geothermal energy projects are now part of the Infrastructure Bill currently before Parliament.

Since English law recognises no lower vertical limit to landowners’ rights, the new clauses should prevent landowners from seeking to obstruct projects on the grounds that e.g. the drilling of lateral wells 1km underneath their property would be a trespass against them, or alternatively demanding an exorbitant price for agreeing to such use of “their” land.

The new clauses begin: “A person has the right to use deep-level land in any way for the purposes of exploiting petroleum or deep geothermal energy”.  Land here means “onshore” land, and “deep-level” means at least 300 metres below the surface.  In Scotland, the right so far only applies to geothermal electricity generation projects.

The right of use would include all phases of a shale gas or geothermal project: exploration, development, production and decommissioning.  The clauses refer explicitly to “drilling, boring, fracturing or otherwise altering deep-level land” and “passing any substance through, or putting any substance into, deep-level land or infrastructure installed in deep-level land”.  They also allow developers – as a matter of private law – “to leave deep-level land in a different condition from the condition it was in before an exercise of the right of use (including by leaving any infrastructure or substance in the land)”.

Although existing legislation provided scope for developers to override landowners’ objections to the use of their land to extract petroleum by statutory means, the Government concluded that the procedures involved were too burdensome.  The new clauses were introduced following a consultation which ran from May to August 2014 and was discussed in an earlier post on this Blog.  The consultation met with an overwhelmingly negative response, but largely from respondents opposed to fracking per se on a range of environmental grounds.

The new statutory right of exploitation removes a potentially time-consuming and expensive obstacle to development.  Those opposed to individual developments that involve the use of “deep-level” land will now have to rely on public law licensing, planning and environmental processes, rather than the exercise or enforcement of their private law rights, if they wish to try to stop projects going ahead.

The Bill does not otherwise change the position in relation to rights and liabilities as between developers and landowners.  If developers cause damage or harm during their operations, they are likely to be liable for remediation costs and to pay civil damages to any third parties adversely affected.  Landowners could also potentially incur liability for environmental damage caused by developers using the new right in certain circumstances such as the insolvency of a developer.  This position is likely to continue to focus commercial and other strategies, including possibly the imposition of some form of security for decommissioning / remediation costs as a condition of planning permission.

For more shale-related posts, including commentary on the 14th Onshore Licensing Round, see Dentons’ UK Planning Law Blog.

In the previous post we looked at the new right to exploit deep-level land for petroleum extraction and deep geothermal projects that is now included in the Infrastructure Bill.  Here we report on the associated financial provisions and some proposals on shale-related matters that have so far not found their way into this part of the Infrastructure Bill.

The Infrastructure Bill provides for secondary legislation about “payment schemes”.  The Government favours the voluntary scheme proposed by industry, under which a one-off payment of £20,000 would be made to communities for each unique horizontal well that extends by more than 200 metres laterally.  So although Ministers will be able to make regulations requiring payments to owners of land over which the new right is exercised (and other persons for the benefit of areas in which such land is situated), the Government currently intends to use these powers only if the voluntary scheme “is not honoured”.

Regulations may also require notice to be given where the new statutory right to use deep-level land for petroleum extraction or deep geothermal projects is to be exercised, including notice of any applicable statutory payment scheme.  The secondary legislation powers are to be reviewed after five years and must be repealed after seven years if they have not been used and the Secretary of State is satisfied that they are no longer required.

The principle behind the clauses on the new right was not seriously opposed in the House of Lords debate.  Amendments were put forward proposing to exclude National Parks and other areas protected for nature conservation or heritage reasons from exercise of the new right, and to require DECC to publish a report on fugitive green-house gas emissions from onshore energy extraction.  Like most of the responses to the Government’s consultation on the new right, these were treated as merely general warnings about potential impacts of shale development that the existing regulatory frameworks are fully capable of addressing.  However, it is always possible that they may re-surface at a later stage in the passage of the Infrastructure Bill, when they can be voted on (by convention there are no votes at the Lords Grand Committee stage which has just concluded).

A separate shale-related amendment was proposed by the Conservative Peer Lord Hodgson of Astley Abbotts.  Drawing on the example of Norway (like the Scottish National Party in the run-up to the Independence Referendum), Lord Hodgson advocated the establishment of a shale sovereign wealth fund.  This would receive “no less than 50% of any revenue received by the United Kingdom Government from any activity connected with the extraction and sale of shale gas”, and its assets would be “deployed to serve long term public objectives other than those connected with monetary and exchange rate policy”.  Lord Hodgson argued that it is imprudent and – from an inter-generational perspective – unfair for all tax revenues from major natural resources such as UK shale gas to be spent when they are received.  So far, the Government response to is that the industry is too immature and the Treasury might need to spend 100% of the revenues from shale gas when it receives them, especially in view of the declining North Sea revenues.

For more shale-related posts, including commentary on the 14th Onshore Licensing Round, see Dentons’ UK Planning Law Blog.

One of the problems faced by the UK in achieving security of electricity supply at an affordable cost is its comparatively low level of interconnection with the electricity networks in other countries.  But recent developments offer some prospect that the UK may become a bit less of a “power island”.

The EU’s goal of a single electricity market has the potential to help national Governments with all three horns of the energy trilemma (how to maintain security and decarbonise whilst keeping energy prices at a reasonable level).  But it cannot be realised without adequate interconnection capacity.  As long ago as 2002, the European Council set EU Member States a target of having electricity interconnections equivalent to at least 10% of their installed production capacity by 2005.  Twelve years on, the UK is only half way to meeting this target.  In May 2014, as part of its work on European energy security, the European Commission proposed an interconnection target of 15% for 2030.  This was adopted by the European Council in its 23 October 2014 conclusions on the EU’s 2030 Climate and Energy Policy Framework.

Meanwhile, as Member States connect increasing amounts of intermittent renewable generating capacity to their networks, leaving them in some cases with total generating capacity that is much greater than the amount of power they can reliably generate at any given moment, the goal of achieving 10% or 15% of total installed generating capacity becomes more challenging (see the statistics and charts below).  While such targets are undoubtedly useful, the optimum proportion of interconnection capacity is not the same for each Member State and is bound to change over time with the evolution of its generating mix and electricity consumption profile.  However, it is not always easy for the market to respond quickly and produce more interconnection capacity where it is most needed given the amounts of capital and the regulatory processes involved.

Achieving an interconnection target of 10% or 15% of installed generating capacity in the UK is particularly challenging.  Even before it began to add significant amounts of renewable generation, the UK had one of the larger generation capacities in the EU, and it is very much more expensive per MW to create connections between the electricity networks of Great Britain and other EU Member States than it is to connect networks between Member States which share a land border.  The costs per km of a subsea cable connection are several times greater than those of an overhead transmission line, and the distances involved in GB interconnectors tend to be larger than those which link the transmission systems of different countries in Continental Europe.

However, if the costs of interconnection are significant, so too are the potential benefits for UK consumers.  In a paper entitled Getting more connected published earlier this year, National Grid estimated that: “each 1GW of new interconnector capacity could reduce Britain’s wholesale power prices up to 1-2%…4-5GW of new links built to mainland Europe could unlock up to £1 billion of benefits to energy consumers per year“.  As the European Commission’s most recent report on energy prices and costs in Europe notes, in some of the countries to which the GB system either is not yet connected or with which it could be much more interconnected, average baseload wholesale electricity prices are up to 40% lower than those in the UK.

So is the potential for new UK interconnection capacity going to be exploited anytime soon?  There are encouraging signs both from a regulatory point of view and in terms of actual projects.

The regulatory treatment of projects is crucial to the development of more interconnection.  In this respect, there have been a number of helpful recent developments for potential UK interconnectors.

• In August 2014 Ofgem confirmed its intention to implement, with only minor modifications, its previously consulted-on proposals for the regime that will apply to the regulation of near term GB interconnector projects (i.e. those expecting to be commissioned by the end of 2020 and likely to be taking significant investment decisions in 2015).  Ofgem recognises that if the development of new UK interconnection capacity is left to proceed without any form of regulated “consumer underwriting”, it is likely that insufficient new capacity will be built.  It therefore proposes a 25 year regulatory regime of a “cap and floor” on revenues, based on its assessment of the need case and efficient level of costs for projects.  The new regime, building on Ofgem’s approach to the Project Nemo interconnector, aims to combine advantages of both the traditional regulated revenue model and more purely market-based approaches.  Ofgem’s 27 October 2014 consultation on the Caithness Moray transmission project shows how far a regulator’s assessment of efficient costs for a project involving subsea cables can vary from a developer’s estimates.

• Also in August 2014 the UK Government published a paper entitled Contract for Difference for non-UK Renewable Electricity Projects.  This raises the prospect of Contracts for Difference (CfDs) under the Energy Act 2013 being competed for by and awarded to renewable electricity generating projects outside the UK by 2018.  This is a significant step, given the continuing importance of subsidies for the renewables sector (and coming as it did shortly after the approval by the Court of Justice of EU Member States’ historic tendency not to extend their national renewables support schemes to generators in other Member States – notwithstanding the potential for such restrictions to impede free movement in the single market for electricity).

• In September 2014, the Government included in a consultation on supplementary design proposals for the Capacity Market established by the Energy Act 2013 an outline of how interconnector owners could participate in future Capacity Market auctions.  This had been promised in the context of obtaining state aid clearance, so as to ensure that the Capacity Market, like similar measures being put in place by other Member States, does not militate against the integration of national markets – clearly a matter of concern to the European Commission.

• Interconnection is most effective when the interconnector capacity is allocated most efficiently and facilitates the flow of electricity from areas of lower to areas of higher prices (see study on this).  These outcomes should be brought closer by the progress there has been in integrating EU national electricity markets through the Target Model.  In February 2014, the markets in GB and 14 other EU Member States became part of the day-ahead price coupling regime for North-West Europe (and in May 2014 they were joined by Spain and Portugal).  In April 2014, a number of Central European Transmission System Operators, National Regulatory Authorities and Power Exchanges signed an MoU to develop flow-based market coupling, which in time will enable better calculation of the network capacities that are allocated through the price coupling process.

• Finally, the 2013 EU Regulation on cross-border infrastructure (“projects of common interest” or “PCIs”, which are to be fast-tracked through national consenting processes) should make it easier to get interconnection projects funded and built.

In terms of actual projects, Ofgem’s October 2014 preliminary decision on eligibility of projects to benefit from the cap and floor regime identifies five projects that aim to commission by 2020 and, having come forward in the first cap and floor application window, have been judged sufficiently mature to proceed to the three to six month initial project assessment stage.

The five projects are: FAB Link between GB and France; Greenlink, between GB and the Republic of Ireland; IFA2, between GB and France; NSN, between GB and Norway (recently granted a licence by the Norwegian Government); and Viking Link, between GB and Denmark.

According to Ofgem, these projects, together with Project Nemo and the Channel Tunnel-based ElecLink, could add up to 7.5GW of interconnection – more than doubling existing GB cross-border apacity.  They have a number of points in common.   A number of these projects feature in the ENTSO-E Ten Year Network Development Plan and the European Commission’s list of PCIs.  Most of them involve the Transmission System Operators of one or both of the countries they would run between or companies affiliated to them.  Establishing links between GB consumers and renewable generation outside GB is an important part of the rationale for many of them (the FAB Link project even involves plans for up to 300MW of electricity generated from the tides around Alderney). Recent publicity for the TuNur project to export large amounts of solar-generated electricity from North Africa to Europe, including the UK, shows the scale of the possibilities in this area.

It now remains to be seen whether the further development of the Government’s proposals on non-UK renewable and interconnected capacity – and perhaps more significantly the outcomes of the first CfD and Capacity Market auctions (which will not be open to interconnected / non-UK capacity) – will enhance or detract from the business case for these projects.

 

Illustrative statistics and charts (drawn from EU Energy in Figures: Statistical Pocketbook for 2014 and other European Commission and ENTSO-E publications)

1. Ratio of available cross-border electricity interconnector capacities compared to domestic installed power generation capacities

2. Electricity generation across EU Member States

3. EU Member States’ power generation supluses and deficits compared to gross inland consumption in Q1 2013 and 2014

4. Electricity consumption across EU Member States in Q1 2013 and 2014

5. EU Member States’ renewable and non-renewable generation

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Two more milestones in the implementation of UK Electricity Market Reform (EMR) have been passed in the last 24 hours (15/16 December 2014): the first EMR Capacity Market auction began, and it became clear that the first auction of EMR Contracts for Difference (CfDs) has been postponed until February 2015.

The Capacity Market aims to secure the availability of 48.6GW of reliably despatchable generating plant from the autumn of 2018.  This is being procured by means of a series of bidding rounds in a “descending clock” auction which must be completed by 19 December 2014.  The auction pits existing coal, nuclear, CCGT and peaking plant against each other and against new build gas and diesel generators, but only new build plant and existing plant spending £125/kW or more on refurbishment can act as “price makers” in the bidding process (see further National Grid’s Auction User Guide).

According to the previously advertised timetable, the first CfD auction should already have taken place in early December, with results being notified to applicants between Christmas and the New Year.  Instead, the revised version of the Low Carbon Contracts Company’s GB Implementation Plan for CfDs, published on 15 December 2014, states that those seeking CfDs will be invited to submit their bids on 17 February 2015 (if, at that point, demand for CfDs exceeds supply under the allocation round budget).

The delay has been driven by appeals against decisions on the eligibility of applications.  The Implementation Plan notes that a longer delay is possible if “Tier 2” appeals are not completed by 6 February 2015.  It is interesting that DECC has chosen to delay the CfD auction rather than make use of the mechanism (provided for in Part 8 of the Allocation Regulations and Rule 21 of the Allocation Framework) that allows an auction to go ahead with disputed applications still “pending”.

While we await the eventual outcome of these two first-of-a-kind auctions, we can start to compare and contrast the CfD and Capacity Market processes.

One striking difference is in terms of transparency.  The Capacity Market prequalification process results in publication and regular updating on the EMR Portal of a full list of applicants (both successful and unsuccessful) and their plants.  By contrast, there is no published list of applications for CfDs or the decisions that have been made as to their eligibility to be allocated a CfD.  In some ways this mirrors the bidding processes themselves: the successive rounds of the Capacity Market auction are rather more interactive and offer bidders some (albeit limited) visibility of each other’s behaviour; in the CfD auction, applicants must effectively put everything into their initial sealed bid.

A second major difference is in the scrutiny to which applicants’ claims to have fulfilled the criteria that make them eligible to bid are subjected.  For example, under the CfD legislation, applicants’ claims to have the necessary planning permission for their generating stations have to be substantiated by submitting copies of the relevant documents, which will then be checked by National Grid (albeit possibly in a fairly mechanical way).  By contrast, compliance with the parallel obligations to have any requisite planning permission before bidding in the Capacity Market auction is simply self-certified.

No doubt there will be further debate about these and other design features during 2015.  Already, Ofgem is consulting on possible changes to the Capacity Market Rules.  It has identified as priority areas for consideration the possible streamlining of the prequalification process, price maker memoranda, and rules about demand side response.  Meanwhile, alleged discrimination against the demand side has prompted Tempus Energy to challenge the European Commission’s decision that the Capacity Market is compatible with EU state aid rules.

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.