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Thoughts on the death of DECC

Over the course of 13 and 14 July 2016, UK’s new Prime Minister, Theresa May, appointed the Secretaries of State who will lead the various Departments of Government.  By the end of the process, which was precipitated by the UK’s referendum vote to leave the EU, the Cabinet had gained two new Secretaries of State (for “Exiting the European Union” and “International Trade”).  At the same time, the position of Secretary of State for Energy and Climate Change had been abolished, along with the Department which its holder led (DECC).  To anyone with a professional interest in energy and climate change policy, this will likely have felt like a backward step.  If nothing else, as pointed out by Angus MacNeill, Chair of the House of Commons Energy and Climate Change Committee, it raises some important questions which will need to be answered quickly.

It is, of course, far too early to judge the new Government’s approach to any issue.  After a period of several months in which relatively little in the way of major policy emerged from DECC (no doubt partly because of pre-referendum stasis), there will be a temptation to fall on anything that the Ministers newly appointed to the Department of Business, Energy and Industrial Strategy (BEIS) say in the next few weeks for clues about the future direction of energy and climate change policy – and possibly over-interpret them.  The new regime should be judged on its record rather than its name.

In practical terms, it was probably not feasible for an incoming Prime Minister to create two new Secretary of State posts without losing at least one existing one to compensate – and the former Department for Business, Innovation and Skills has lost a significant chunk of its previous responsibilities (higher education, and, presumably, at least some of international trade), so may have needed some additional bulk.  Historically, the energy portfolio has had its own Department within Government for over 50 of the last 100 years (variously as the Ministry of Power, 1942-1969; the Department of Energy, 1974-1992; and DECC, 2008-2016).  Otherwise (apart from a very brief period in the Ministry of Technology), it has been in the Board of Trade and its successors, the Department of Trade and Industry, the Department of Business, Energy and Regulatory Reform – and now BEIS.  If one looks to international comparisons, practice varies: Germany has a Ministry of Economic Affairs and Energy; Denmark has a Ministry of Energy, Utilities and Climate; in Italy, energy is a matter for the Ministry of Economic Development.  At EU level of course, DG Energy is very much a Directorate-General in its own right: energy has been a key policy area for the EU and its precursors and it will be an important element in both Brexit negotiations and international discussions about post-Brexit trade arrangements with the EU and others.

One thing that distinguishes the new configuration from those other occasions when “energy” has not had its own UK Department, is that on this occasion it does at least feature in the name of the Department that is responsible for it.  It will undoubtedly form a significant part of BEIS’s business.  It is true that “climate change” has lost some profile, but it is also noticeable, if one looks at the DECC organogram, that very few DECC teams could be said to have had an exclusively climate change focus (in any case, when DECC was originally created, only those Defra staff working on climate change mitigation joined the new Department: those working on climate change adaptation remained behind).  Arguably one of the achievements of DECC (and the period of policy formation that immediately preceded it) was to make climate change considerations part of the mainstream of energy policy-making.  The optimistic view would be that with the Climate Change Act 2008 – and its system of carbon budgets, based on work by the independent experts of the Committee on Climate Change (CCC) – well entrenched, there is less need for the symbolism inherent in the name of DECC.  One might also add, more cynically, that there was more than one occasion when having responsibility for climate change policy did not stop DECC Ministers from choosing the “less green” option.

But on a more positive note, there are clearly potential advantages in having “business”, “energy” and “industrial strategy” in the same Department.  As the CCC’s Report on the Fifth Carbon Budget made clear, if we are to achieve the kind of reductions in carbon emissions that we need in order to meet the overall goals of the Climate Change Act, not to mention contributing a fair share to the achievement of the aims of the CoP21 Paris Agreement of December 2015, we will need to go a long way beyond the task of decarbonising the electricity generation sector (admittedly still work-in-progress though that is).  There is a lot to be done in relation to heat and transport, for example, and the challenges are formidable.  Some of this is very much to do with industrial energy use, and having one Department, rather than two, focusing on this area could well make a positive difference (given the inevitable friction that exists between all public sector bodies with shared interests).  Maybe it is even not too much to hope, in this context, that the new Government may revisit the decision to abandon large-scale sponsorship of carbon capture and storage, which is thought by many to have more to offer in a wider industrial context than it necessarily does purely in the electricity generation sector.  At the same time, a Secretary of State for BEIS (Greg Clark) who has come from the Department of Communities and Local Government may be an asset at a time when it is also becoming clear that some aspects of the development of new energy infrastructure are best considered locally, at least within cities.  And “industrial strategy” – unclear as yet though it is what this will involve – could also have a mutually beneficial intra-Departmental relationship with “energy”.  Finally, given that it is only seven years since DECC was partly carved out of one of BEIS’s predecessors, it is to be hoped that this change in the machinery of Government can be accomplished without distracting ex-DECC management too much from the policy agenda (now, of course, supplemented by Brexit).

In the post-Brexit world, nothing is necessarily what it seems.  Any or all of the above speculation may be naïve or misguided.  The new Department should be watched carefully, but today, objectively and at a policy level, it is far too early to say whether (or how much) we should mourn the passing of DECC.

 

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Thoughts on the death of DECC

The New North Sea – Part 1: the revolution begins here

How much of a difference will the recent reforms of UK offshore oil and gas regulation make to the industry and its stakeholders? It may be too early to say whether the creation of the Oil and Gas Authority (OGA), the articulation of the “MER UK Strategy” and the other changes introduced by the Infrastructure Act 2015 and the Energy Act 2016 will facilitate solutions to all the significant problems faced by North Sea operators, but in our view it is already clear that the changes of the last two years will have a profound impact on the industry.

Government intervention in the UK’s offshore oil and gas industry is nothing new. It has taken different forms at different times, and has included, as well as numerous changes in taxation, Government participation (or at least the ability of Government to participate) in decision-making at the individual asset level through rights granted to state-owned entities.

More specifically, for almost 20 years, Government has been aware of, and has been taking action to address, the particular set of problems that the UK Continental Shelf (UKCS) faces as a mature basin.  Between 1999 and 2004, the Department of Trade and Industry and its successors took a series of steps to foster investment and innovation in the industry and improve its efficiency: a joint Government / industry report (A Template for Change) was published in 1999; task forces were appointed; changes were made to the administration of the licensing regime; new types of licence were introduced.

PILOT and small-scale regulatory changes, 1999-2004
1999

 

 

Brent at $9/barrel – a record low – in February, but recovers to $25 by December.

Oil & Gas Industry Task Force report (September) set a vision for the UKCS in 2010, aimed at increasing investment and employment, and prolonging UK self-sufficiency in oil and gas.

2000 PILOT established to take over the work of the Task Force and give effect to its recommendations
2002 PILOT “Progressing Partnership” Work Group launched to address behavioural and supply chain barriers. Initiatives include transferring “fallow” assets to those best placed to exploit them.
2003 “Promote” licences offered for the first time to attract new small players.
2004 22nd offshore licensing round: largest number of blocks since 1965.   “Frontier” licences first offered.
   

However, by the time that Ed Davey, as Secretary of State for Energy and Climate Change, commissioned Sir Ian Wood to carry out a review of the industry in 2013 and the Wood Review’s final report was issued early in 2014, it had become clear that all the good work done after the 1999 report had not resolved or prevented some fundamental problems, and that the “vision for 2010” which it articulated had not been fully realised.   Average production efficiency declined from 81% in 2004 to 60% in 2012.  There had been a downward trend in numbers of exploration wells drilled since 2008 (with about 70% fewer being drilled in 2013 than were drilled five years before).  Perhaps worst of all, costs of production per barrel had risen fivefold in ten years.  And all that was before global oil prices began a period of sharp decline which has seen them fall to levels at which most North Sea fields are said to be uneconomic, with no certainty of a rapid or sustained recovery.

A false sense of security? North Sea licensing events highlighted in Government reports, 2005-2012
2005 24 new companies enter the North Sea as part of a record offering of 151 licences.
2006 UK a net importer of gas in value terms for the first time since the early 1980s.
2007 Legislation to allow storage of natural gas under the seabed / unloading of LNG at sea announced.
2008 Brent crude tops $100 / barrel for the first time, rising to over $140 / barrel in June and July.
2010 Largest number of blocks applied for since the first licensing round in 1964.
2011 Brent crude tops $100 / barrel for the first time since 2008.
2012 Demand for offshore licences again breaks all records (applications covering 418 blocks).
   

Many of the concerns that were articulated in the 1999 report and addressed in the initiatives that followed from are echoed in the Wood Report. Both reports are in favour of such things as “collaboration in place of competition”, “improving relationships between licensees” and encouraging innovation, for example.  But the final results of Wood’s work are very different from those of the earlier report and its follow-up.  Where the 1999 report tends to talk about “deregulation”, the Wood Report has led to the creation of a new, more powerful and better resourced body to regulate the industry.  In the words of the Wood report itself: “In the early days with large fields to be found by major operators, the free market model worked well with a light touch Regulator…However, over time, the number of fields has increased, now to over 300, new discoveries are much smaller, many fields are marginal and very inter dependent, and there is competition for ageing infrastructure. Alongside this, the…Regulator has halved in size in 20 years and…is clearly struggling to perform a more demanding stewardship role.

There has been general agreement with Wood’s conclusion that “a stronger Regulator with broader skills and capabilities able to significantly enhance the level of co-ordination and collaboration” would “largely resolve” the problems that his review identified.  It is rare for an industry to be so apparently united in its desire for stronger regulation – even if it was clear from the first that a regulator based on Wood’s prescription would be different from many sector regulatory bodies in terms of its remit, composition, and its interactions with industry.  It has probably helped that the fall in oil prices has made the problems identified by Wood more acute, increasing the demand for a powerful independent regulator to get to work on solving them.  This, together with the compelling nature of Wood’s analysis and strong political support, has enabled the necessary legislative changes to be put in place rapidly.

The Wood Review and its implementation, 2013-2016
2013 Government commissions the Wood Review of offshore oil and gas recovery (June)

The interim report of the Wood Review is published (November)

2014 Final report of the Wood Review published   (February)

Sharp fall in oil price begins (June)

Government response to the Wood Review published (July)

Clauses on MER UK (to amend the Petroleum Act 1998) inserted into Infrastructure Bill (October)

Appointment of Andy Samuel as CEO of OGA (November)

2015 Andy Samuel asked to lead urgent study of key risks to North Sea oil and gas industry (January)

Infrastructure Act 2015, including revised provisions on MER UK receives Royal Assent (February)

OGA issues “call to action” document in response to DECC’s request to Andy Samuel (February)

OGA launched as an Executive Agency of DECC, carrying out DECC regulatory functions (April)

Energy Bill, dominated by provisions on the OGA, introduced into Parliament (July)

Oil & Gas UK launches efficiency task force (September)

OGA reports: call to action 6 months on (September)

OGA publishes draft corporate plan (November)

DECC launches consultation on MER UK strategy (November)

2016 Brent crude falls below $30 / barrel (January)

Government support package for UK offshore oil and gas (January)

Draft MER UK strategy laid before Parliament (January)

OGA publishes Corporate Plan 2016-2021 (March)

MER UK strategy finalised and comes into force (March)

Energy Bill receives Royal Assent, Energy Act 2016 published (May)

Why do we think that North Sea regulation from now on (or at least from the date on which the relevant provisions of the Energy Act 2016 come into force and the Regulator’s staff complement is up to full strength) will be radically different from what operators have been accustomed to? There are six main reasons.

For the first time, the UK offshore regulatory regime (excluding its environmental and health and safety aspects) has a single governing principle articulated on a statutory basis – the objective of maximising the economic recovery of UK petroleum (MER UK).

Although MER UK is defined in general terms in a strategy promulgated by DECC under the Infrastructure Act 2015, its specific meaning and impact in any given situation will in large measure be determined by the Oil and Gas Authority (OGA).

The obligation to act in accordance with MER UK, as so defined and interpreted, applies – or could be said to apply – to at least one person involved in the taking of almost any commercially important decision in the offshore industry.

Under the new regime, the OGA and DECC will potentially have access to vastly more information about North Sea assets and infrastructure, the commercial intentions of those with interests in them, and the relations between them, than DECC has had to date.

The OGA does genuinely appear to be a new kind of regulator, in terms of its composition, capabilities, culture and combination of functions. It is also likely to take a more proactive approach than its predecessors.

The terms of the MER UK strategy and the robustness of the enforcement tools at the OGA’s disposal suggest that it will enjoy unparalleled leverage over licence holders and others to ensure that collaboration “for the greater good” really does happen.

In future posts in this series, we will explain in more detail how the relevant provisions of the Infrastructure Act 2015, the Energy Act 2016 and the MER UK strategy achieve these results and how we think the application of the new rules by industry parties, DECC and the OGA will affect key moments in the life of North Sea infrastructure and assets.

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The New North Sea – Part 1: the revolution begins here

UK Government initiatives for UK oil and gas : forging links with Mozambique

Last week, the UK Government had a busy week on the oil and gas front – publishing the Draft MER UK Strategy and announcing new measures to encourage investment in the sector and a new City Deal for Aberdeen.

Last Thursday (28 January), the Government laid its new strategy for implementing the plan for maximising economic recovery (the Strategy) before Parliament. The document presented before Parliament is the product of consultation on various drafts since November 2014. Not much has changed from the previous version issued for consultation in October 2015 (see our earlier blog post on the consultation). The Strategy is legally binding upon the Secretary of State, the Oil and Gas Authority (OGA) and players in UKCS upstream operations. The new obligations are intended to help fulfil the aims of MER UK, according to the Strategy without cutting across existing legislation including model clauses…

In case the Strategy wasn’t enough information to absorb in one day, on his visit to Aberdeen on Thursday, David Cameron proudly announced new initiatives intended to demonstrate the UK Government’s ongoing commitment to the UK’s oil and gas industry –

  • 250m investment for Aberdeen as part of a City Deal – the Scottish government has committed a further £254m for infrastructure in Aberdeen and the surrounding region
  • £20 million for funding a second round of new seismic surveys on the UKCS – data from these surveys will be made publicly available
  • £1.5 million available through Innovate UK for innovators outside of the energy sector to develop solutions and disruptive technologies to meet challenges of the energy industry
  • OGA publication of a UKCS Decommissioning plan by early summer (one of the plans to fall out of the Draft MER UK Strategy)
  • Appointment of an Oil and Gas Ambassador to promote the North Sea overseas to boost inward investment, but also to develop links with overseas markets to provide UK oil abd gas companies with best possible access

Of course, an even more powerful display of UK Government support to the industry, might comprise some form of tax relief for faltering producers. We wait to see what happens in the March budget.

Due south to Mozambique

David Cameron’s announcement comes as The Secretary of State for Scotland, David Mundell, prepares to travel to the port town of Pemba in Mozambique, to promote relations with Mozambique’s oil and gas industry. This trip is in conjunction with Aberdeen City Council’s Pemba Initiative which aims to support Pemba’s development as an oil and gas hub.

(A place in the sun - Northern Mozambique) (source: tedchang)

(A place in the sun – Northern Mozambique) (source: tedchang)

The level of oil and gas activity in Mozambique is set to increase dramatically in the next decade. Mozambique has hit the headlines in the last few years, due to huge discoveries of gas in the Rovuma Basin, offshore Northern Mozambique. More than 150tcf of gas discoveries have been made since 2010. Operators, Anadarko and Eni, are both pressing ahead with LNG projects – an initial 12mtpa onshore facility for Anadarko from the Golfinho reservoir in Area 1 and a 2.5mtpa FLNG facility for Eni for the Coral reservoir in Area 4.

A flurry of exploration activity is also expected in the next few years. INP announced the results of the fifth licensing round in October last year, inviting six consortia (including relative veterans Eni, Statoil and Sasol, as well as newcomers ExxonMobil) to enter into negotiations for exploration and concession contracts for six new blocks.

It seems that opportunities abound for Aberdeen and the UK to develop partnerships with and provide support to Mozambique’s relatively young petroleum industry. Although anyone wishing to engage in petroleum operations in Mozambique will need to get to grips with the recently revised petroleum laws, new petroleum regulations and other local laws – including the local content rules.

Mozambique does not have a general local content law, instead provisions for local content are to be found in the 2014 Petroleum Law, and for the Rovuma Basin LNG projects, in the 2014 project-specific Decree-Law. The two laws contain rules about the level of Mozambican nationals participating in the workforce, in addition to, requiring those engaged in petroleum operations to give preference to Mozambican companies and partnerships and joint ventures between foreign and local companies and individuals in the context of procurement of goods and services.

If you would like to discuss any of the issues raised above, please do not hesitate to get in touch with the author or any of your other regular contacts in the Dentons oil and gas team.

Dentons has experience going back over 20 years in advising on energy projects in Mozambique and is heavily involved in the current LNG projects in Mozambique.

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UK Government initiatives for UK oil and gas : forging links with Mozambique

Published at last – a winning strategy for the UK Continental Shelf?

Finally, we have the missing piece of the jigsaw.  The current reforms to the UK’s regulatory regime for the offshore oil and gas industry were recommended by the Wood Review in 2014.  They began to be implemented with the creation of the Oil and Gas Authority (OGA) and the amendments made to the Petroleum Act 1998 (the 1998 Act) by the Infrastructure Act 2015; they are continuing with the current Energy Bill (now half way in its passage through Parliament).  But it is perhaps only with the publication of a draft of the strategy for maximising the economic recovery of UK petroleum on 18 November 2015 that we start to get a full sense of how the new regime may work in practice.

What is the draft strategy, and why does it matter?

The legislation describes the strategy as “enabling” the “principal objective” of “maximising the economic recovery of UK petroleum” (MER UK) to be met.*  The principal objective and the strategy occupy a central position in the revised regulatory scheme.

To begin with the regulators.  In one way or another, the OGA is taking over most of the Secretary of State’s statutory functions under the Petroleum Act 1998 and Chapter 3 of Part 2 of the Energy Act 2011.  The OGA is also to acquire a raft of new functions under Part 2 of the Energy Bill.  In exercising all these functions (including any of its powers under a petroleum licence), the OGA will be obliged to “act in accordance” with the strategy.  The Secretary of State will be similarly obliged to act in accordance with the strategy when exercising her functions under the Part 4 of the 1998 Act “to the extent that they concern reduction of the costs of abandonment”.

At the same time, the strategy will be binding on holders of, and operators under, petroleum licences, when planning and carrying out their activities as such; persons planning or carrying out the commissioning of upstream petroleum infrastructure (broadly defined); and (subject to the Energy Bill) owners (broadly defined) of offshore installations and upstream petroleum infrastructure, when carrying out their activities as owners of such installations or infrastructure, or decommissioning it.  Such persons and (in so far as they can affect the fulfilment of the principal objective) activities are referred to in the draft strategy as “relevant persons” and “relevant functions” respectively.

The Energy Bill provides that if a business which is a relevant person fails to act in accordance with the strategy, the OGA can impose sanctions including financial penalties of up to £1 million (and potentially up to £5 million if the Secretary of State raises the penalty cap by regulations) and revocation of the business’s status as a holder of, or operator under, a petroleum licence.

Although the strategy will become more important as and when the Energy Bill completes its passage through Parliament and becomes an Act, many of the provisions establishing the importance of the principal objective and the strategy are already embodied in the amendments made to the 1998 Act by the Infrastructure Act 2015.  So it is noteworthy that reform of the offshore oil and gas regulatory regime has gone so far without public consultation on a full draft of the strategy.

What the draft strategy says

The Wood Review pointed out, and subsequent OGA papers have elaborated on, the fact that the inter-dependence of different installations and infrastructure in the UK upstream oil and gas industry is such that if each relevant person only seeks to optimise its own financial position, the performance of the industry as a whole is likely to be sub-optimal.  So the key question for the draft strategy to answer is how (and how far) businesses are to be induced to compromise their interests for the greater good.

To look at how the draft strategy answers this question, it is best to start with two of its key definitions.

  • “economically recoverable petroleum” means “those resources which could be recovered at an expected (pre-tax) market value greater than the expected (pre-tax) resource cost of their extraction, where costs include capital and operating costs but exclude sunk costs and costs (like interest charges) which do not reflect current use of resources.  In bringing costs to a common point for comparative purposes a 10% real discount rate will be used“.
  • “satisfactory expected commercial return” means “a reasonable post-tax return having regard to the risk and nature of the investment“.

These two definitions underpin what are perhaps the draft strategy’s two most important provisions:

  • The Central Obligation applies to relevant persons in the exercise of their relevant functions, and obliges them to “take all steps necessary to secure that the maximum value of economically recoverable petroleum is recovered from the strata beneath UK waters“.  (Emphasis added: as a recital to the draft strategy puts it: “all stakeholders should be obliged to maximise the expected net value of petroleum produced from relevant UK waters, not the volume expected to be produced”.  The focus on value (undefined) rather than quantity contrasts with the similar but different words about “securing the maximum ultimate recovery of petroleum” in the petroleum licence model clauses on unitisation, which represent perhaps the greatest degree of intervention by the licensing authority under the existing regulatory regime.)
  • Paragraph 27 provides that if relevant persons “decide not to ensure the recovery of the maximum value of economically recoverable petroleum from their licences or infrastructure (including because that does not achieve a satisfactory commercial return, in accordance with paragraph 3) they must relinquish or divest themselves of such licences or assets“.

The “paragraph 3” referred to here is one of the draft strategy’s Safeguards: “No obligation imposed by or under this Strategy requires any person to make an investment or fund activity where they will not make a satisfactory expected commercial return on that investment or activity.”.

It is hard to quarrel with any of this in the abstract, but applying these principles in any given case will not necessarily be easy.  For example, how do you assess “expected pre-tax market value” in the context of massive uncertainty over future oil and gas prices?  DECC’s own most recent fossil fuel price projections suggest that the average oil price for the next 10 years could be anything from $46.8 to $140.4 a barrel (depending on whether you take the “low” or “high” scenario).

What does this mean in practice?

The consultation document spells out where all this leads.  If you are the owner or operator of an asset or infrastructure and take the view that you cannot make a satisfactory commercial return from its continued operation, you may be obliged to divest it to somebody who takes a different view of what constitutes a satisfactory return or what is economically recoverable.

Paragraph 27 is one of a number of “supporting obligations” and “required actions and behaviours” listed in the draft strategy in respect of exploration, development, asset stewardship, deployment of new technology and decommissioning.  So, for example, owners and operators of infrastructure must plan, commission and construct it in a way that meets the optimum configuration for MER UK, and must allow access to it on fair and reasonable terms.  If the infrastructure is not able to cope with demand for its use, they must prioritise “access which maximises the value of petroleum recovered”.  Meanwhile, the OGA may produce plans addressed to “a single or small group of relevant persons” setting out its view of how the obligations of the strategy may be met in their particular circumstances”.  According to the consultation document: “A plan might target a particular or small range of circumstances, or might be broader and more strategic in nature, for example setting out how the OGA thinks a region should be developed or decommissioned.”.

The new regime

In the words of the consultation document: “How the OGA uses and acts on the Strategy is…of great importance – it will set the tone for the basin and will be a key factor determining its attractiveness to industry and investors.”.

One could perhaps sum up the spirit of the strategy by mangling a famous line from John F. Kennedy: “Ask not what the strategy can do for you, but what you can do to maximise the economic recovery of UK petroleum.”; or perhaps quoting Karl Marx, without modification: “From each according to his ability, to each according to his needs”.

But enough flippancy.  The consultation document goes out of its way to emphasise that the OGA will not be unduly interventionist: “whilst enforcement measures are a necessary backstop, the OGA is expected to act primarily as a convenor and facilitator, working together with industry to deliver increased value from the UKCS for both industry and the UK as a whole”.  If it is “occasionally…the case that the OGA [finds] that a relevant person’s contractual provisions place that person…in breach of the Strategy”, or if the OGA finds that it needs “to assert its right as a regulator to use its sanctions where a relevant person fails to avoid a breach of its MER responsibilities through continued reliance on contractual provisions which conflict with the Strategy…. it will always be for the relevant person to decide for itself how to deal with that in terms of its contracts.”.

Perhaps a useful point of comparison here is the UK power market.  It has become commonplace to note that the UK’s various schemes for subsidising new low carbon electricity production, and the Capacity Market which subsidises old nuclear and fossil fuelled generating stations, have turned the liberalised GB power generation market into something closer to a “planned economy”.  Where the fulfilment of the principal objective is at stake, the Energy Bill requires that the OGA be allowed to participate in meetings between relevant persons, and recommend ways of resolving disputes between them.  Reading such provisions side by side with the draft strategy, it is clear that in the oil and gas industry too, future commercial decision-making may be much more strongly directed by the state than before.

Then again, perhaps one should compare oil and gas production not so much with the power generation market, which is supposed to be characterized by free competition, but with the monopoly markets of transmission and distribution, where it is accepted that it is only economic for one operator to build and operate infrastructure in any given location – just as petroleum licence holders enjoy exclusive rights in their licensed areas and many oil and gas infrastructure owners are de facto monopoly service providers.  In the power sector, to avoid any abuse of monopoly, the returns which network operators can earn on their investment are regulated.  The strategy does not go (quite) that far.

In the end, the strategy highlights the two risks that the OGA will need to guard against particularly carefully in administering the reformed regulatory regime.  The first is highlighted in a letter of 3 December 2015 from the UK Competition and Markets Authority, using for the first time its new powers to make and publish recommendations to Ministers about proposed new legislation: the OGA and those it regulates could collaborate so closely that beneficial competitive pressures, which are important to reduce costs and support the principal objective, could be dampened, so that, for example, the regulatory process ends up facilitating the anti-competitive exchange of information between competitors.  The second and opposite risk is that a less co-operative attitude amongst industry players prompts the OGA to start using its enforcement and other formal powers to an extent that in turn stimulates the kind of “over-zealous commercial and legal behaviour” on the part of the industry that Wood wanted to make a thing of the past.

So perhaps what matters most is not the strategy itself, but the tactics of those who must follow it – both the OGA and industry players.

* Note: The definition given above of the “principal objective” reflects the current text of section 9A of the 1998 Act.  If clause 8 of the Energy Bill (introduced by an Opposition amendment) survives, it will become instead “maximising the economic return of UK petroleum, while retaining oversight of the decommissioning of oil and gas infrastructure, and securing its re-use for transportation and storage of greenhouse gases” – although how much difference some of those additional words will make now the Government has abandoned its CCS commercialisation programme is debatable.

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Published at last – a winning strategy for the UK Continental Shelf?

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”?

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

Oil Price Crash (1): Options for North Sea oil and gas: shut-ins and taxation relief

Companies involved in oil and gas activities globally are tightening their belts. The decline in the price of Brent crude oil (spot sales) from $115 in June 2014 to less than $50 per barrel in just over six months represents a loss in value of over 60%, leading to a reduction in profits (and for some, no profit at all). Regardless of the macroeconomic effects for GDPs, the economics presently look stark.

Some recent headlines demonstrating the devastating effect of the rapid oil price decline:

  • mega mergers and redundancies in the oilfield service sector;
  • the announcements by BP, Talisman and ConocoPhillips of job losses in their North Sea workforces and other operators looking to change the typical “2 weeks on, 3 weeks off” rotation pattern;
  • projects put on hold in Qatar and the Canadian oil sands, (Russia’s Shtokman project and US shale developments are also feeling the pinch);
  • Shell announced last week it will curtail $15bn of investment over the next three years; and
  • across the board rate cuts for North Sea contractors have been implemented since January.

Difficult times for the North Sea

All this comes at what was already a difficult time for the North Sea industry. It is worth noting that some companies were exiting the UK Continental Shelf (UKCS) even before the price crash and that much of the investment, and growth in the UKCS is expected to be in more expensive “frontier” areas. But now, according to a survey of forecasters conducted by The Independent, the oil price is almost at a point that every barrel produced in the North Sea would be unprofitable. There have been calls for a 50% drop in taxes applicable to the North Sea, as 100 (out of around 300) fields were said to be in danger of being shut in.

Weathering a storm

A North Sea platform weathering a storm

Faced with such a drop in the price of their product, operators of producing fields have four choices: (i) sit tight and hope prices bounce back quickly and sharply, (ii) cut costs and/or investment, (iii) shut in production or (iv) lobby the Government to boost their net revenue by changing the fiscal position. We’ve seen some examples of option (ii) already, as noted above. Companies opting for option (i) may wish to consider overlifting or underlifting their share, within the confines of joint venture arrangements, to ease immediate cashflow worries (and see our previous article for issues to consider dealing companies potentially in distress), or gambling on a return to higher prices, respectively. Here we consider options (iii) and (iv) in more detail.

Shutting up shop

Operators of producing fields might consider shutting in production (i.e. stopping production and shutting wells), either for a temporary period until the oil price rises back to a profitable level or permanently with a view to beginning decommissioning. Below, we take a look at some of the practical and legal consequences.

Recommissioning facilities after a temporary shut-in can be a costly and lengthy process. This can be prohibitive, leading to remaining reserves being left in the ground. According to reports it took BP’s Rhum field (temporarily shut in between November 2010 and October 2014) a year to recommence production due to technical delays after receiving approval from DECC.

Those who choose to shut in production with a view to decommissioning must undertake decommissioning activities in accordance with pre-approved programmes. Early field decommissioning can also result in the premature decommissioning of ageing infrastructure which could otherwise be used by newer fields.

Decommissioning in operation

But before an operator can take steps to shut-in production, it must follow a process and obtain certain approvals (which may or may not be forthcoming). Prior to engaging with Government, the operator must obtain approval from its other joint venture parties in accordance with the voting arrangements in the relevant joint operating agreement.  If the green light is given, the operator will need to seek approval in accordance with the law and licence conditions.

Secretary of State blessing

DECC regulates producers operating in the UKCS through the Petroleum Act 1998, as well as the licence conditions in offshore exploration and production licences granted to companies wishing to explore and produce oil or gas in the UKCS. These conditions are drawn from “model clauses” set out in secondary legislation. The model clauses used vary depending on when a licence is granted. But a general principle applying across model clauses for all licences (regardless of when the licence was granted) is that the Secretary of State for  Energy and Climate Change’s (the Secretary of State) consent or approval is required for certain key steps. Under the licence conditions, a licensee cannot abandon any well, nor may it decommission any assets, without the Secretary of State’s consent. Therefore any decision to shut-in a well governed by a UKCS licence requires the Secretary of State’s blessing.

The Secretary of State has the power to revoke a licence (in respect of one or all licensees) on a failure to comply with licence conditions and may direct at the time of revocation that any well drilled is left in good order and fit for further working; thus providing the possibility of future production.

MER UK

The results of prematurely shutting in production seem diametrically opposed to the Government’s aims of maximising economic recovery from the North Sea resource (MER UK) (in line with the proposals set out in the Wood Review). Prior to the coming into force of the Infrastructure Bill, there is no legal requirement for the Government to take MER UK into account when exercising its licensing and decommissioning functions. It is bound to be a factor in decision-making on any request for Secretary of State consent. The Infrastructure Bill, when in force, will also place obligations on producers (see our previous blog) to act in accordance with the Government’s MER UK strategies. 

Death and taxes

There may be nothing more certain than death and taxes, but taxes applying to the UKCS have been far from certain. The surprise increase in the Supplementary Charge from 20% to 32% in 2011 (due to the high oil price) serves as a reminder to the industry of the temptation to shock (but without awe).  Analysts and industry experts believe that what is needed is (i) a quick fix reduction on tax rates to show UK plc supports the North Sea industry (and help those still making a profit) and (ii) a comprehensive review of the tax system in place to reduce complexity.

Head of Oil and Gas UK (OGUK), Malcolm Webb, would like to see “30% as the top tax rate”, whilst “some companies are paying 80% as the highest rate on fields in the North Sea.” How is it that some companies are paying 80% in tax? The Government currently operates three oil and gas tax regimes, which overlap with each other, as follows:

First steps for improving fiscal competitiveness

The Government did respond to the oil price change in December 2014 announcing various reliefs, including cutting the Supplementary Charge from 32% to 30%, extending the ring-fence expenditure supplement for offshore oil and gas activities for four more years as well as plans for new “cluster” allowances. The industry commended these steps, but they were felt not to go far enough. In addition, these reliefs may be more helpful for those engaging in exploration in newer frontier areas than for those producing from the older fields with marginal economics. With the oil price dropping lower (and the potential for sub-$40 Brent crude), in mid-January, Sir Ian Wood, whose Review recommended a wholesale review of the tax structure to encourage investment in the interests of “MER UK”, advocated lowering the Supplementary Charge within the next few weeks by at least 10%, i.e. back to 20%.  Malcolm Webb’s view is that the December “measures can only be seen as the first steps towards improving the overall fiscal competitiveness of the UK North Sea. We will certainly need further reductions in the overall rate of tax to ensure the long-term future of the industry”.

Budget

What else does the 2015 Budget have in store?

Part of the problem is that the UK operates a licensing regime for exploration and development activities, and the Government obtains revenues from the UK’s natural resources through imposing taxes. As a result every response from the Government to market conditions, or attempt to stimulate activity, takes the form of legislation that applies to everyone and tends to hang around. Other jurisdictions, which operate production sharing regimes, have the luxury of adapting production sharing formulas (often set out in contract) to reflect the level of exploration risk for a particular concession or block, with regard to factors such as geographical location and drilling depth, by allowing the parties’ shares to increase or decrease as aggregate production increases. Those operating in such regimes may also benefit from stabilised taxation for a certain period of time (contributing to the attractiveness of a jurisdiction for investment).

OGA to the rescue?

Whilst the UK has tried to import some mechanisms into the tax system to allow for the recognition of risk in exploration, some commentators feel the UK now fields a convoluted and newcomer-unfriendly fiscal system. As the competition hots up between countries to provide home for petrodollar investments, this provides an opportune time to review the tax system for the North Sea. It seems that the new Oil and Gas Authority is getting cracking undertaking a review of measures which could be taken to relieve the existing crisis.

 

 

 

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Oil Price Crash (1): Options for North Sea oil and gas: shut-ins and taxation relief

Large scale solar and the Renewables Obligation: 9 more months of grace

DECC has confirmed that there will be a further year-long grace period for large scale solar PV projects which fail to be accredited under the Renewables Obligation (RO) by 31 March 2015.  In addition to the previously announced grace period for projects which are considered to have made a “significant financial commitment” before 13 May 2014, there will be a further opportunity for those projects which only fail to be accredited by 31 March 2015 for lack of a grid connection.

DECC’s announcement came in a response to a consultation that ran from 2 to 24 October 2014 and followed on the 13 May 2014 consultation on early closure of the RO to large scale solar PV (see our earlier post).   The key difference from what was proposed in the 2 October consultation document in relation to the proposed grid connection grace period is that it will now run for a full year, like the grace period for “significant financial commitment” projects, rather than just three months – giving those projects that meet the relevant criteria until 31 March 2016 to achieve accreditation.

Alongside the response to consultation, DECC has published a draft of the statutory instrument that it proposes to lay before Parliament in the New Year to amend the existing RO Closure Order.  This makes it possible to see exactly how DECC envisages eligibility for both grace periods working. 

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Large scale solar and the Renewables Obligation: 9 more months of grace

The Offshore Safety Directive (5) – Government consultations

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

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

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

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

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

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

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

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The Offshore Safety Directive (5) – Government consultations

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

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

Analogy to a new tax

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

Misalignment of local opposition

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

Reduced justification for compensation

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

Conclusion: proactivity in hindsight

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

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

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