Oxford Energy Associates

House of Commons Environmental Audit Committee

Energy subsidies in the UK

Written evidence

Only those submissions written specifically for the Committee for the inquiry into Energy subsidies in the UK and accepted as written evidence are included

List of written evidence

Page 1 Oxford Energy 1 2 Bryan Norris 57 3 Calor Gas Ltd 59 4 Energy Fair 77 5 Dr David Toke 83 6 Renewable Energy Association 93 7 Association for the Conservation of Energy 98 8 Wood Panel Industries Federation 108 9 Friends of the Earth 110 10 Nuclear Industries Association 119 11 Platform 121 12 BSW Timber 128 13 Alan Simpson 130 14 Renewable UK 135 15 EDF Energy 140 16 Oil & Gas UK 147 17 Vestas Wind Systems 156 18 Fuel Poverty Advisory Group 157 19 Malcolm Grimston 166 20 Department of Energy and Climate Change and HM Treasury 179 1

Written evidence commissioned by the Committee from Dr William Blyth, Oxford Energy Associates

Acknowledgements

This report has benefited from inputs and suggestions from a number of colleagues, and the author would like to thank in particular Antony Froggatt, Doug Koplow, Richard Tol, Morgan Bazilian, and Ulrik Stridbaek. Any outstanding errors and omissions remain the author’s.

CONTENTS

1 Background ...... 1

1.1 Subsidies from first principles ...... 1

1.1.1 Perfect markets as a benchmark for assessing subsidies ...... 2

1.1.2 Critique of perfect market assumptions ...... 3

1.1.3 Consequences for policy decision-making on subsidies ...... 4

1.1.4 Source of economic inefficiencies of subsidies ...... 6

1.1.5 Types of subsidy ...... 8

1.2 Methodologies used in major international studies of subsidies ...... 11

1.2.1 Price-Gap Approach ...... 11

1.2.2 OECD ‘Effective Rate of Assistance’ Approach ...... 12

1.2.3 World Bank ...... 14

1.2.4 IMF ...... 15

1.2.5 Global Subsidies Initiative ...... 17

2 Extent of energy subsidies in the UK ...... 19

2.1 Energy Mix in the UK –Historical and Future Trends ...... 19

2.2 Fossil Fuel Subsidies ...... 20

2.3 Nuclear Subsidies ...... 22

2.3.1 Historical liabilities ...... 23

2.3.2 Waste and decommissioning for future plant ...... 24

2.3.3 General operating conditions for new nuclear ...... 25

2.4 Renewables ...... 27

2.4.1 Current subsidy arrangements ...... 27

2.4.2 Future Investments – implications of electricity market reform ...... 30

2.5 Electricity ...... 31 3

2.6 General ...... 32

2.6.1 Government funded energy R&D ...... 32

2.6.2 Climate Change Levy Exemptions and Discounts ...... 33

2.6.3 Enhanced Capital Allowances ...... 34

2.7 Summary of UK Subsidies ...... 34

3 International comparison ...... 35

3.1 Fossil Fuels ...... 35

3.2 Renewables ...... 39

3.3 Nuclear ...... 42

3.4 European-level Support for Energy ...... 44

3.5 Energy R&D ...... 50

References ...... 50 4

Energy Subsidies in the UK 1 Background This report provides an overview of energy subsidies in the UK, starting with an overview of the basic economics, then identifying the scale of subsidies in the UK, and finally comparing the UK position with other countries.

The scope of the report is limited to a review of published sources, and it is not possible to say that such an approach captures all subsidies. Although a considerable amount of information has been published, such efforts nevertheless feel somewhat piecemeal. Some subsidies are hidden and hard to quantify, so the figures identified here probably represent a lower limit. For example, cross-subsidies relating to payments for electricity system balancing and maintaining security of supply in the face of risks of unexpected outages for different plant would ideally be included, but they are notoriously difficult to quantify and allocate, and are beyond the scope of this report. In other cases, the definition of subsidies is very dependent on the particulars of a country’s tax base, making international comparisons difficult.

Ideally, a thorough study on energy subsidies would track, for each branch of the energy system, total income arising through energy taxes, and net off all public payments made for infrastructure, services (including regulatory functions, system balancing etc.) as well as the direct subsidies provided through price support mechanisms.

At an economy-wide level, simple generic comparisons can be made on this basis. Tax revenues from energy in the UK amount to around £28bn annually, the vast majority (97%) of which comes from road fuel taxes. Tax income for transport of around £27bn considerably outweighs the total government transport budget of around £20bn1. Road transport fuel has long been used to provide net revenues to treasury.

Outside of the transport sector, the other energy sectors on the other hand are much more lightly taxed (as shown in Figure 5). The consumer tax base for energy products in the UK generates revenues (excluding VAT and carbon taxes) of around £1bn (Figure 5). This compares with subsidies identified in this report totalling around £10bn, which is around 0.8% of the market value of energy (~£120bn excluding road transport fuel). Even considering that this is a lower bound estimate, in aggregate, energy subsidies and taxes are therefore rather low compared to market value. Nevertheless, they form an important part of the revenue stream for many different types of energy investment, and for this reason, subsidies have an important strategic influence on the development and choice of energy technology used in the UK.

1.1 Subsidies from first principles Subsidies have become synonymous with bad economic practice because of the distortionary effects they have on producer and consumer behaviour. This leads to a

1 http://www.ukpublicspending.co.uk

working assumption in policy-making that subsidies generally reduce economic efficiency, and that removal of subsidies should therefore lead to an overall welfare gain, albeit with winners and losers along the way. The creation of winners and losers means that there are often strong interests on all sides about the appropriateness and scale of different types of subsidy.

This section attempts to take out some of the heat and inject some light into the debate by exploring the underpinnings of these basic assumptions in more detail in order to clarify the theoretical basis from which different points of view are argued. It will be shown that there are indeed unresolved theoretical issues over which reasonable people might reasonably disagree. Energy subsidies are part of a country’s adaptation to uncertain and dynamic futures, and decisions will need to be based as much on political judgment as on ‘hard’ economic evidence.

1.1.1 Perfect markets as a benchmark for assessing subsidies Subsidies are usually measured in terms of the deviation they create in terms of the prices and quantities of goods exchanged from the ‘ideal’ equilibrium market price. In order to understand why, it is worth revisiting some basic economic principles.

Arguments in favour of free markets usually proceeds along two different routes (Sander 2009). The first is the libertarian defence of the principle of free markets which argues that letting people engage in voluntary exchanges respects their freedom. As Amartya Sen compellingly points out in his review of the role of markets in economic development, “To be generically against markets would be almost as odd as being generically against conversations between people…”(Sen 2001). Sen’s argument is that free exchange between people is part of the natural order of the human experience, and therefore in general is a desirable mechanism to promote, although he recognises that there are many instances where the power balance between people is such that exchange is not truly free, and protections need to be put in place.

The second main defence of free markets is made in terms of economic efficiency. In 1906, Vilfredo Pareto showed that social welfare is maximised by an allocation of resources that meets with unanimous approval. A Pareto efficient allocation means that it is impossible to reassign resources so as to make any individual better off without making at least one other individual worse off. (Arrow and Debreu 1954) then showed that a competitive market economy would lead to an equilibrium position which would satisfy this condition of optimal social welfare (the so-called first fundamental theorem of welfare economics). The Arrow- Debreu proof requires perfect and complete markets in all transactions in order for the optimal equilibrium position to be reached.

Pareto efficiency does not however guarantee political desirability. There are many different possible equilibrium positions in which individuals are allocated a different level of initial wealth, but which could still be considered overall welfare maximising. This leads to the second fundamental theorem of welfare economics, which states that any of these efficient equilibrium solutions can be achieved by a perfect market as long as it is accompanied by a (politically decided) lump-sum redistribution of resources.

This is the basis of the rather convenient general claim of economics to be able to separate issues of efficiency (i.e. maximising overall social welfare, the typical domain of economists) from issues of equity (i.e. the distribution of wealth, the typical domain of politicians).

Based on the idea that perfect markets achieve maximum social welfare, it then follows simply that any distortion of these markets (including taxes, subsidies etc.) must therefore reduce social welfare, incurring an overall cost to society. This viewpoint reaches its peak in the Chicago school and the economic outlook of Milton Friedman. The rationale for these beliefs rests on the assertion that the real world comes sufficiently close to the idealised world enshrined in the first fundamental theorem that its tenets can be applied to real- world policy making. Whilst most economists would recognise that although the markets may not be optimally efficient, government interventions are not either, and politicised interventions will often have unintended consequences, making unambiguous social welfare improvements difficult to achieve. However, as we will see in the next section, there are opponents of this school who question the applicability of the two fundamental theorems to the real world.

1.1.2 Critique of perfect market assumptions The history of the two fundamental theorems of welfare economics is not as solid as one might suppose (Blaug 2007). The assumption of perfect market conditions is a severe constraint on the applicability of the first theorem. Meanwhile the applicability of the second theorem is severely limited by the fact that it is practically impossible to achieve perfect lump-sum transfers that do not influence marginal behaviour of producers and consumers (calling into question the ability to separate issues of efficiency and equity).

In quantitative terms, the most significant challenge to the perfect market view is given by the general theory of second best (Lipsey and Lancaster 1956). This shows that although social welfare is maximised under perfect market conditions, if there are some market imperfections already in the system that cannot be addressed, there is no guarantee that ‘correcting’ other market imperfections will necessarily improve efficiency or welfare. Lipsey demonstrates with a simple example of a market with three commodities. It is assumed that one commodity has a tax imposed that cannot be removed, and a second commodity has no tax imposed. The socially optimal tax on the third commodity ranges from positive (tax), zero, or negative (subsidy) depending on the degree to which the commodities act as substitutes or complements2 for each other.

The general theory of second best does not contradict the first fundamental theorem of welfare economics, but it does potentially limit the latter’s applicability to real-world policy decisions, depending on one’s view of the degree to which market imperfections in the real world prevail. Many economic theorists and practitioners still work on the assumption that the perfect market assumption is good enough that the first fundamental theorem still applies to real-world situations.

However, there are also many reasons to suppose that market imperfections are ubiquitous in the real world, and that assumptions of general equilibrium may be a poor guide to policy

2 Substitutes can be used in place of each other, whereas complements require the other commodity to be in place before it can be consumed.

decisions. As Lipsey noted in a later paper (Lipsey 2007), many real-world sources of economic imperfection prevail which are not created by policy:

1. Markets are rarely competitive enough to make prices equal to marginal costs. Pricing is often influenced by other factors such as economies of scale, barriers to entry of new firms, and product differentiation (e.g. brand value).

2. When products are differentiated, fixed costs such as establishing distribution networks, product development costs and marketing costs create non-convexities that break the requirement of general equilibrium.

3. There are many cases of missing markets, where commodity exchanges required to achieve general equilibrium are not available, and many markets (e.g. labour markets) often deviate from perfect market assumptions due to incomplete and asymmetric information.

4. Externalities (both positive and negative) are associated with many economic activities, and it is often hard to create compensating market mechanisms to internalise these costs or benefits.

In addition to these ‘static’ market imperfections, there is also the question of how economies should respond to dynamically changing and uncertain future conditions. Equilibrium economics assumes that conditions can be optimised in terms of economic efficiency given knowledge of all current and future states of the input variables. In practice, the future is uncertain, and firms undertake innovation activities in order to adapt to these uncertain changes.

It has been argued (Blaug 2007) that even if one were to take the first fundamental theorem as a valid guideline for achieving static efficiency, there is no theoretical basis to suppose that achieving static efficiency will guarantee achievement of dynamic efficiency. Whilst competitive pressures can no-doubt help to channel such innovation in socially useful ways, the conditions for innovation to respond to dynamic and uncertain futures are generally far from those usually considered under static equilibrium. Indeed, Schumpeter’s conception of ‘creative destruction’ (Schumpeter 1942) is a determinedly non-equilibrium view of how competition leads to dynamic progress. Indeed, a branch of operations research (Abernathy 1979, Adler, Benner et al. 2009) has grown up around a micro-economics view of how this might play out at the firm level. This suggests that firms may experience a tension between aiming for static efficiency (optimising processes based on historical learning about what has worked in the past), vs. a focus on learning and innovation to respond to new challenges in the future.

1.1.3 Consequences for policy decision-making on subsidies The upshot of the theoretical literature is not that markets are an inappropriate model. On the contrary, in Lipsey’s (2007) words there is a “long line of appreciative theorising running from Adam Smith to Milton Friedman and Thomas Schelling and many others…” behind the key propositions that:

“1) the market system coordinates economic activity better than any known alternative – not optimally, just better, and 2) markets do this relatively efficiently by

producing prices that are influenced (but not solely determined) by relative scarcities”

In other words, the market model still provides a very important benchmark, but this should not be used as the basis for a dogmatic rejection of interventions that seek either to redress some of the more obvious failings, or to help build in robustness to dynamic pressures. Lipsey recommends basing “advice on a combination of formal models, appreciative theorising, empirical knowledge, and a large dose of judgement”.

In the case of energy subsidies, arguments in favour of some intervention include:

1. Infant industries. In cases where new technologies are being introduced which are not yet competitive with mainstream technologies, but could be expected to be so in the future, there is a dynamic efficiency argument for creating protected niche markets to allow these to develop appropriate economies of scale and learning by doing cost reductions in the supply chains for these industries. These arguments are typically used in connection with subsidies for renewable energy, and to some extent are again being invoked in the case of third generation nuclear energy. In practice, infant industry arguments are often used inappropriately as a lobbying tool by industry players who wish to carve out a specific subsidy that will benefit them. In general, the infant industry argument can only be justified for a certain length of time before those industries should be expected to stand on their own feet. In the long run, subsidy-dependence is likely to breed inefficiency and lack of competitiveness.

2. Pro-poor policies. Some sections of society may simply be too poor to access the supposedly ‘free’ market, or they may not be able to afford sufficient fuel to maintain a basic level of energy services. In these circumstances, subsidies are often introduced to reduce prices for reasons of equity and to promote overall economic development or standards of living across the whole population. Such subsidies are perhaps the most prevalent stated reason for subsidies on fossil fuels at the global level. On the other hand, there is evidence that many of these subsidies are not well targeted towards poorer consumers, but actually create proportionally higher benefits for richer sections of society.

3. Protection from foreign competition. Subsidies to protect domestic industry from foreign competition have been rife throughout the history of economic development, but are coming increasingly under control as a result of free trade agreements such as WTO and the EU single market. Nevertheless, protection of jobs is still an important political driver for subsidies in contexts where there is a perception that foreign competitors in some way have an unfair advantage. This is particularly relevant in dynamic contexts (such as emerging economies are experiencing) or where such subsidies are taken as a precaution against explicit anti-competitive behaviour by external trade partners. However, in a long-run equilibrium context, such domestic subsidies will tend to lead to higher domestic prices for the protected goods, leading to inefficiencies that leave the country worse of in terms of jobs and the economy.

The common factor behind all these arguments for subsidies is that they are very context- specific, and they usually relate to a situation that is temporary or dynamic by nature. Whilst the general theory of second best suggests that it is difficult, or perhaps even

impossible to judge what exact conditions are required to achieve a social optimum in terms of static efficiency across the whole economy, there are grounds for considering positive interventions based on more parochial considerations of costs and benefits in relation to potential ‘corrections’ of dynamic effects in the particular sector being considered.

In general, subsidies introduced to address these temporary conditions should therefore be designed with a sunset clause. This allows them to be phased out in line with the timescale over which the dynamic effects are expected to be addressed in order to avoid fostering inefficient subsidy-dependence. though there are many examples of provisions with sunsets being continually extended, and legacy subsidies that do not get debated. Super-majorities for overturning sunset clauses is one way around this. If the factors that the subsidies are intended to correct for are not expected to be temporary by nature, then subsidies are unlikely to be a suitable response. For example, if a foreign supply of cheap energy becomes available (and is expected to remain available over a long period of time), then it is likely to be more efficient for a country to adapt to this new situation rather than trying to protect domestic sources for long periods of time. Clearly however, adaptation also raises its own set of costs that need to be factored into this consideration.

1.1.4 Source of economic inefficiencies of subsidies Putting aside for the moment concerns raised by the general theory of second best, it is useful to review the theoretical basis for how subsidies introduce economic inefficiency and loss compared to a perfect market context, because this often provides the basis for most major studies of energy subsidies.

In order to calculate the total economic cost of a subsidy, the cost to government of paying the subsidy needs to be weighed against the economic benefits that accrue to producers and consumers. This is illustrated in Figure 1. The effect of a subsidy is not only to change prices, but also the quantity of goods exchanged. This is because of the elasticity of demand, whereby consumers will tend to increase demand if prices reduce. Subsidies paid to a producer will in general alter market prices leading to benefits to both consumers and producers, although the total costs of the subsidy outweigh these total economic benefits. Based on the area of the triangle DWL in the final diagram, the total economic loss (or deadweight loss DWL) is approximately ½ΔQS where S is the size of the per unit subsidy. The size of the overall economic loss is therefore strongly dependent on the slope (elasticity) of the demand curve.

It should be noted that very similar considerations apply to taxes (since subsidies are effectively just a negative tax). Taxes also result in a deadweight loss to the economy (although an exception is where fees termed as “taxes” are really user fees to recover the government cost of goods or services linked to a specific fuel: the absence of such fees would actually constitute a subsidy). In principle, subsidies are no more inefficient than taxes, except insofar as they need to be funded, and may therefore have budget implications for overall tax burden.

This simple graphical representation needs to be treated with care, as it assumes that the initial equilibrium point is somehow optimal. In practice, there may be various externalities that are not included in such a representation. For example, in considering the quantity of fuel purchased in the context of fuel poverty, the free market equilibrium point may well

represent a sub-optimal consumption level, leading for example to health problems for elderly consumers not able to heat their houses sufficiently in winter. In such cases, the optimal level of consumption may indeed be higher than the simple crossing point of supply and demand curves would indicate. This is not to say that subsidising energy (especially for all consumers) is necessarily the most appropriate measure to take, only to point out that simple analyses of equilibrium points in the market need to be considered carefully to see what may be missing.

Figure 1 Subsidies alter both prices and quantities leading to deadweight loss

1. In a ‘free’ market, supply and demand balance at an equilibrium price Pe and quantity Qe the crossing point of the supply and demand curves. 2. If a subsidy is given to suppliers, they are willing to supply any given quantity at a lower price, since they will recoup the production costs via the subsidy. This leads to a downward shift in the supply curve indicated by the dashed line. 3. Supply and demand now reach a new equilibrium at a lower price to the consumer Pc who as a result will tend to consume a greater amount of the good increasing the quantity by ΔQ. Price Demand Supply Size of subsidy (per unit) 4. The supplier receives price Ps which is the price the Ps consumer pays (Pc) plus the size of the subsidy. Size of subsidy Pe 5. Both consumers and suppliers therefore benefit (per unit) from the subsidy, since the consumers pay a lower Pc price, whilst the suppliers receive an increased price. ΔQ

Quantity Qe

6. The total benefit (£) to consumers of the lower price is the change in price (£/unit) multiplied by the quantity (number of units). This is the consumer surplus shaded in red. Likewise, the benefit to producers is the producer surplus shaded in blue. 7. In theory, the benefit of the subsidy is always shared between producers and consumers, irrespective of who the subsidy is paid to.

8. The total cost of the subsidy to government is the size of the subsidy multiplied by the total quantity of the good supplied (yellow rectangle). 9. The yellow rectangle is larger than the producer and consumer surpluses. This means that the cost to government is higher than the overall economic benefits. The difference is the triangle marked DWL known as deadweight loss. This measures the overall efficiency losses arising from subsidies in comparison with the ‘free’ market equilibrium.

1.1.5 Types of subsidy Subsidies can come in many different forms. Direct subsidies are the easiest to measure as they usually provide some form of direct payment either to the producer or consumer of a particular good in order to influence the price and / or quantity of goods exchanged.

Examples of direct energy subsidies include feed-in tariffs for renewable energy, where additional payments are made to suppliers over-and-above the payments they receive from consumers for the electricity provided. Another example is where governments set energy prices for consumers below the cost of supply, usually implying the need to compensate producers for associated losses through some other budgetary mechanism. This is the source of the majority of energy subsidies measured in non-OECD countries.

However, the net can be cast much more widely than these direct subsidies. What constitutes an economic approach to defining a subsidy is itself the subject of much debate among economists and those responsible for measuring subsidies. As noted by (Donohue 2008),

“Broadly speaking, subsidies can be seen in one of two ways: subsidies are given by governments or subsidies are given by society. Almost all subsidy definitions available in the literature could be seen as generally conforming to one of these perspectives on subsidies. … An economic approach might be to define subsidies as transfers that distort the allocation of economic resources which would be a society-wide approach to defining subsidies. A more government-oriented approach might be to define subsidies simply as financial payments from governments to firms or consumers. … The distinction between subsidies derived from government action, versus social subsidies, is profound, and includes many possibilities for refinement.”

Because of its remit, the definition of subsidies used in the WTO is fairly focused on the more direct government-oriented approach. Article 1 of the WTO‘s Agreement on Subsidies and Countervailing Measures defines a subsidy as involving a financial contribution by a government or any public body within the territory of a Member … or price support in the sense of Article XVI of GATT 1994‖ that confers a benefit. Among the financial contributions covered by the definition are:

i. direct transfers of funds (e.g. grants, loans, and equity infusion), potential direct transfers of funds or liabilities (e.g. loan guarantees); ii. the foregoing or non-collection of government revenue that would otherwise be due (e.g. fiscal incentives such as tax credits); and iii. goods or services (other than general infrastructure) provided by a government in kind, or goods purchased from companies in a way that confers a benefit to that company (e.g., by paying a price that is higher than the market price).

The definition also covers situations in which a government makes payments to a funding mechanism, or entrusts or directs a private body to carry out one or more of the type of functions illustrated in (i) to (iii) above which would normally be vested in the government and the practice, in no real sense, differs from practices normally followed by governments.‖

However, energy economists concerned about the wider set of economic distortions in the energy sector often cast the net wider than this and would also include other types of regulation that influence market prices and quantities. For example, the OECD’s definition used in its ‘producer support estimate’ (PSE) indicator also includes all forms of market price support involving transfers between consumers and producers created as a result of policy such as government interventions on tariffs. The OECD’s ‘consumer support estimate’ (CSE)

includes any additional policy-induced transfers that affect consumption. The OECD’s framework is discussed in more detail in the following section.

Another issue to consider is the treatment of externalities (i.e. costs which are incurred in other parts of the economy that are not directly party to the transaction between producers and consumers). In the energy sector, the most obvious example includes environmental impacts of energy use. Most local pollutants are coming under a regime of increasingly stringent controls, so that it is reasonable to say that these external costs have largely been internalised.

One of the problems of internalising the climate change externality is the difficulty of estimating the scale of the damage, and therefore identifying a suitable level for the carbon price. Carbon emissions in principle are internalised through the EU-ETS for the sectors covered, although there are concerns that the carbon price is inadequate. The UK government has taken the position that carbon prices ought to follow a trajectory in line with the costs of meeting a long-term carbon reduction trajectory appropriate to staying within a 2 degree warming limit. This has led to a long-term carbon price forecast which was used to inform its carbon price floor which applies to UK emitters covered by the EU-ETS. This guarantees that carbon prices for UK power generators will not fall below a level that the UK deems is a reasonable approximation of the external costs of carbon emissions.

The imposition of carbon prices acts to correct a market failure, so carbon prices should be considered as a correction to suboptimal prevailing market price signal. In that sense, the absence of a carbon price in energy markets constitutes a subsidy since in a market without carbon prices, polluters are not paying their full production costs. Whilst this is the most intellectually robust way to consider externalities, it is clearly politically sensitive, as the attempt by the EU to impose EU-ETS carbon prices on external airlines has shown (despite the rock-bottom carbon prices). Political constraints are largest for commodity producers competing with parties outside of the jurisdiction of the policy. However, potential solutions (e.g., pooling airline carbon fees to finance upgrades within the industry rather than disbursing to national treasuries) may be one way around the conflicts. Multi-lateral agreements would also work in principle, but are struggling to make progress in practice.

A class of subsidy which is alluded to in the WTO definition, but which are difficult to measure is the provision of various forms of guarantee by government on behalf of private companies making investments in the energy sector. These guarantees can take a number of forms, loan guarantees for upfront capital investment, or guarantees associated with long-term liabilities such as nuclear waste or long-term CO2 storage. In cases where there is partial or full government ownership of the energy companies, such guarantees are implicit, and even harder to measure. Rates of return on capital may be much lower than commercial rates, and difficult to identify in financial reports. Such guarantees transfer risk from private companies to public tax-payers. These risks may or may not materialise as real costs to the economy, but nevertheless, the transfer of risk to the public domain allows companies to borrow at lower costs of capital than would be the case if the risks were fully costed within the boundaries of the loan decision, and should therefore strictly be counted as a subsidy. Methods for quantifying the financial magnitude of such risk transfers are discussed in (Lucas 2010)).

1.2 Methodologies used in major international studies of subsidies This section reviews some of the different methodologies used to measure subsidies in major international studies.

1.2.1 Price-Gap Approach The most widely used method to measure subsidies is the ‘price-gap’ approach, developed in detail by the (IEA 1999) in their landmark publication on energy subsidies. This approach follows the same logic as that portrayed in Figure 1. The first step is to measure the price gap based on the difference between end-use prices to consumers, and a reference price that is taken to be the ‘efficient’ price that would prevail in the absence of subsidies. The second step is to calculate the impact of the price gap on consumption, based on estimates of the elasticity of demand. This quantity effect is then used (as described previously) to estimate the scale of welfare losses associated with the subsidy.

Conceptually, the price gap approach is straight-forward, but a number of complexities arise in calculating both the consumer and reference prices. As noted in (IEA 1999), methodological issues arising in the calculation of consumer prices include:

 Appropriate currency units (local, international at market rates, international at purchasing power parity)

 Inclusion of energy-specific taxes, fees, levies and surcharges, as well as all rebates and reductions requires detailed data

 Appropriate treatment of general taxes such as VAT

 Accounting for situations where there is a physical constraint to the supply of energy, so that consumption levels are only partially influenced by price

The reference price indicates the opportunity cost of consumption of one unit of energy, its true economic value. It corresponds either to the border price for internationally traded energy products or to the costs of production for non-traded ones, both adjusted for transport and distribution costs. For some energy goods, especially those that are internationally traded, the reference price is fairly easy to identify. Even where these markets vary regionally, there are relatively well-established traded prices in most parts of the world for oil, gas and coal, and the border prices (for both energy exporters and importers) is the relevant reference point against which the prices of domestic energy consumption can be compared. Nevertheless, care is required to take account of all internal transportation costs and to ensure that adjustments are made to account for differences for example in fuel quality between domestic sources and international markets.

Treatment of VAT needs careful handling, since it is often a general part of a country’s tax structure, so could be considered a ‘normal’ cost which should be included in the reference price. This would allow tax exemptions to show up as subsidies in the price gap calculation. On the other hand, the electricity sector often bears no general taxation, since it is an intermediate energy transformation process rather than a final consumer, so the IEA methodology treats zero VAT rates as the normal reference point.

To date, the IEA methodology has also excluded environmental externalities from their calculations of subsidies on the basis that carbon pricing is not (yet) ‘normal’ practice within its member countries, although they recognise that in principle carbon prices etc. should at least theoretically be part of the reference price.

The limitations of the price gap approach are summed up by the IEA as follows:

“The price-gap approach captures the effects of subsidies on economic efficiency to the extent that they lower the end-use price of the good in question. Other forms of subsidies, especially those, like import tariffs, which are designed to support domestic production, would raise final consumption prices.

When more than one subsidy applies to the same good, a frequent occurrence, the price gap measures only the net price effect of all the different subsidies together. In reality, however, the effects on economic efficiency of coincident subsidies are not netted out, but add up. For instance, the combined application of a subsidy to capital costs and an import tariff might well leave end-use prices close to the reference price. In this case, the price-gap approach would yield little or no insight, but double efficiency losses do occur. So work based on price differentials cannot measure all efficiency losses associated with government policies.

Trade effects, the reduction of imports or the additional availability of exportable fuels, are particularly affected by this analytical limitation. Depending on the specific forms of the subsidies, their removal might have much greater impacts than simply closing or narrowing the price-gap. Removing a capital subsidy and an import tariff might change prices little, but it would have very strong trade implications.

Depending on the form in which the subsidies are administered, taxes can also offset their impact on prices, at least to some degree. For example, if subsidies lead to lower capital costs for power generation, a tax on electricity would offset the increased consumption due to lower prices. Energy taxes, however, would not offset the efficiency losses induced by an inefficient factor mix, such as a bias towards capital-intensive forms of energy production bolstered by a capital cost subsidy.”

1.2.2 OECD ‘Effective Rate of Assistance’ Approach One of the key limitations of the price gap approach is that it does not adequately address support to energy producers (Koplow 2009). The OECD calculates subsidies using a more bottom-up assessment of the scale of government budget transfers involved to energy consumers and producers arising from the major subsidies identified. This requires in-depth analysis of the policy framework for each individual energy sector. Table 1.1 shows the potential range of different types of subsidy that need to be considered under such an approach, using the coal industry as an example (IEA, OPEC et al. 2010).

Table 1.1 OECD categorisation of subsidies with examples (OECD 2012)

To whom transfer is first given

Consumer Support Producer Support

Unit cost of Household or Output Enterprise Cost of Costs of consumption enterprise returns income intermediate production income inputs factors

Direct Unit Government Output bounty Operating Input-price Capital grant transfer of subsidy subsidized or deficiency grant subsidy linked to lifeline payment acquisition funds electricity of land rate Transfer of Price- Means-tested Government Third-party Provision of Assumption risk to triggered cold-weather buffer stock liability security (e.g. of subsidy grant limit for military occupational government producers protection health and of supply lines) accident liabilities Tax revenue VAT or excise Tax deduction Production Reduced rate Reduction in Investment foregone tax related to tax credit of income tax excise tax tax credit concession energy on input on fuel purchases that exceed given share of income Other Under-pricing Under-pricing Under-pricing government of of of access to a a government access to Transfer Mechanism revenue natural good or service government foregone resource land harvested by or natural final consumer resources Induced Regulated Mandated Import tariff or Monopoly Monopsony Land-use transfers price; lifeline export subsidy concession concession; control cross subsidy electricity export rate restriction

The OECD method involves making a producer support estimate (PSE), a consumer support estimate (CSE), and general services support estimate (GSSE) that support both consumers and producers.

Producer support estimate (PSE). Support provided to producers by governments may be delivered through a wide range of mechanisms: increasing the output price (Market Price Support); providing cash directly (a cheque from the government); reducing the riskiness of investing in fixed capital (e.g., loan guarantee; investment insurance); foregoing a payment that would otherwise be due to the government (e.g., a tax concession) or reimbursing a tax or charge (e.g., as for fuel taxes in some countries); reducing the price of an input (e.g., electricity for mining) or of a value-adding factor (e.g., a wage subsidy); providing a service in kind (e.g., police protection of a pipeline) for free or at a price less than the producer would pay on the open market; investing in knowledge-creating activities (e.g., research and development; education and training of specialists).

Consumer support estimate (CSE) includes price transfers to or from consumers. The normal case, especially in countries that are net exporters of fossil fuels, is that transfers are made to consumers through administered pricing. These transfers may exist alongside other subsidies in cash or in kind (including vouchers) linked to the consumption of a particular energy product. When consumers pay more than the reference price for a fuel, such as because of an import tariff, market transfers can be considered the inverse of transfers associated with market price support for the production of commodities that are consumed domestically; these are called price transfers from consumers. Sometimes, when domestic prices are above international prices, budgetary transfers may be provided to first

consumers of energy products where these are provided specifically to offset the higher prices resulting from market price support.

General services support estimate (GSSE). Unlike the PSE and CSE, GSSE transfers do not directly affect producer revenue or expenditure by consumers, although they may affect production or consumption of energy products in the longer term. This includes for example, research and development, inspection services, infrastructure specific to the energy sector being considered, and marketing & promotion.

The OECD method then involves quantifying the budget transfers associated with each source of subsidy in each of these three categories, and then summing them up together. Care is needed to avoid double counting, so that any transfers made from producers to consumers as a result of producer support measures passed through to consumers is netted off the calculation. See (OECD 2010) for a detailed review of the methodology.

1.2.3 World Bank The World Bank recently undertook a review of energy subsidies globally (WorldBank 2010), with a focus on consumer subsidies for fossil fuels in developing countries. The study is not aimed so much at quantifying subsidies as understanding their role in different country contexts, and identifying conditions under which subsidy reform might be possible and effective. The Bank notes that such subsidies are often regressive, with the benefits flowing mostly to richer sections of society. Key findings of the review are:

 Gasoline, diesel, and LPG subsidies are weakly targeted to the poor, particularly in low‐income countries.  Kerosene subsidies may be targeted to the poor through their direct effects, but the leakage to better‐off households, commercial establishments, and the transport sector arising from the ease of adulterating diesel fuel with kerosene means that the subsidies’ pro‐poor benefits may be limited.  Electricity subsidies resulting from excessive losses or failure to collect bills do not have economic justification and should be actively reduced.  Electricity subsidies through generalized under-pricing are likely to be regressive, and much better targeting may be achieved through a careful design of the tariff structure. Volume differentiated tariffs appear to perform much better in this respect than increasing block tariffs.  Subsidies to connection charges for electricity can be designed to be strongly progressive, but their substantial cost per household requires an investigation into the lowest cost method of supply as well as comparative assessment of other options to help the poor.  Cross‐subsidies for tariffs and for connection charges between different classes of users can be an important instrument, but are of limited use where overall connection rates are very low.  Social safety nets can provide a more effective way of reaching the poor while controlling public expenditure. However, they require a strong administration.  Because energy subsidies can result in a large fiscal burden, all subsidy schemes should consider the inclusion of natural phase-out provisions. This can help to

reduce the expectation of a permanent subsidy that can be very difficult to combat at the time a government feels the need to reduce the fiscal burden. However, some subsidy schemes may be designed to be permanent, such as cross‐subsidies between different groups of consumers (such as urban households cross-subsidizing rural households for whom costs of electricity supply can be markedly higher).  Transparency is important. Proper accounting and public awareness of which groups benefit from subsidies, by how much, and the cost is essential to evaluate government policies.  Subsidies to support a switch from fossil fuels to renewable energy need to be carefully planned and to consider the inclusion of natural phase‐out provisions.

1.2.4 IMF The IMF has also recently completed a major study of energy subsidies (IMF 2013) across both advanced economies and developing countries. Whilst the study recognises the importance of both consumer and producer subsidies, the evaluation of subsidies focusses mainly on consumer subsidies for fossil fuels. However, unlike the World Bank study, the IMF study considers post-tax subsidies – e.g. tax breaks such as reduced VAT – consistent with the definitions used by the OECD. Whilst pre-tax subsidies are mostly focussed in developing countries (especially oil-producing states in the Middle-East and North Africa), post-tax subsidies are more widespread in advanced economies.

Remarkably, the IMF also introduces another strand to their analysis by including in their definition of subsidies the lack of taxes to address the externalities. They include environmental damages, as well as estimates of transport externalities, but probably the most significant element is the inclusion of a $25/tCO2 benchmark for CO2 emissions from fossil fuels to cover climate change damages.

Using this basis of accounting transforms the focus of the energy subsidy debate. Since most countries do not tax carbon at this level (if at all), the combination of counting tax breaks as well as under-pricing of externalities swings the total level of energy subsidies from being dominated by developing country producers (as suggested by IEA price-gap approach) to being dominated by the major energy users.

On the IMF’s accounting basis, of the global total, pre-tax subsidies account for about one- quarter, and tax subsidies account for about three-quarters (see Figure 2). The advanced economies account for about 40 percent of the global total. The top three subsidizers across the world, in absolute terms, are the United States ($502 billion), China ($279 billion), and Russia ($116 billion).

The study also undertook 22 case studies to assess experiences of energy subsidy reform (IMF 2013). The case studies show that subsidy reform requires careful handling. The case studies show examples of both successful and unsuccessful episodes of subsidy reform over the past two decades in a wide range of country contexts, but focussing mainly on developing and emerging economies.

Figure 2 IMF estimates of global energy subsidies including tax adjustments and under- pricing of externalities

The IMF study also gives a country-level breakdown of these subsidies, and the countries classified as ‘advanced’ in the IMF analysis is shown in Figure 3. According to the IMF definition, the UK falls into the lower half of the distribution, with energy subsidies totalling around 0.45% of GDP.

Figure 3 Subsidy levels in ‘advanced’ economies as defined in IMF study

4 3.5 3

2.5 2 Coal

% of GDP % 1.5 gas 1 electricity 0.5 Petroleum 0

Italy Israel Spain Japan Korea Malta France Cyprus Ireland Austria Greece Taiwan Iceland Finland Estonia Canada Norway Sweden Belgium Slovenia Portugal Australia Denmark Germany Singapore Switzerland Netherlands Luxembourg New Zealand New United States United Czech Republic Czech Hong KongSAR Hong Slovak Republic Slovak United Kingdom United However, it should be noted that these figures focus mainly on consumer subsidies, and underestimate producer subsidies. In particular, subsidies for nuclear energy and renewable energy are not included explicitly in these figures. These are addressed further in Sections 2 and 3.

1.2.5 Global Subsidies Initiative The Global Subsidies Initiative of the International Institute for Sustainable Development has been working for a number of years towards increasing the level of transparency over the definition and measurement of subsidies, and has produced a manual aimed at promoting best practice in this regard (GSI 2010). The study goes beyond energy subsidies, looking at the environmental impact of all subsidies including the natural resources, minerals and agricultural sectors.

One issue the GSI has focussed on quite strongly is the underestimates that occur when only consumer support measures and price-gap approaches are used. As noted above, these approaches tends to suggest that subsidies are a developing country issue, whereas including producer support measures tends to show a much greater spread globally, but they require considerably more in-depth analysis in order to evaluate the extent of subsidies. To date, the GSI has produced the following quantitative studies in the area of producer subsides focussing particularly on upstream oil and gas sectors:

 Government support for upstream oil and gas in Norway (GSI 2012). The study identified nine subsidies that are offered to the oil and gas sector, totalling around $4bn per year in 2009, although these are expected to be declining over time. By far the largest component of subsidy is provided via a faster rate of capital depreciation for tax purposes compared to other industries in Norway.  Tax and Royalty-related subsidies to oil extraction in high cost fields: Brazil, Canada, Mexico, UK and US (GSI 2010). Given the importance of high-cost fields in setting global oil prices, the role of subsidies here has considerable international importance. The report indicates that all five countries considered provide some

preferential treatment to smaller marginal fields, though quantification of these was not possible.  Government support for upstream oil in three Canadian provinces (GSI 2010). This report identifies annual subsidies in the region of $2.8bn, approximately $2bn of which were allocated to Alberta, and evenly split between Federal and State sources. Most of the subsidies identified seek to increase exploration and development activity, (59 per cent of total subsidies $1.68 billion). These subsidies typically reduce capital expenditures through accelerated write-offs, tax credits, royalty reductions or allowances. Subsidies to support exploration, drilling, operations and research and technology comprised the remaining share of subsidies in about equal proportion.  Government support for upstream oil and gas in Indonesia (GSI 2010). For the areas that could be quantified, subsidies totalled around $1.8bn annually, the largest component (86%) of which arises from the Domestic Market Obligation which obliges producers to sell a certain share of their production to the government- owned oil company Pertamina at below market rates. Given the involvement of the state at various levels in the industry, the total level of subsidies is likely to be significantly higher. The report identifies several areas where subsidies potentially exist, but could not be quantified without further research.

2 Extent of energy subsidies in the UK

2.1 Energy Mix in the UK –Historical and Future Trends The energy mix in the UK and beyond is in a state of transition due to multiple drivers including technological developments in oil & gas sector, environmental constraints on carbon and other emissions, energy security concerns including international reactions to the Fukushima disaster.

The UK mix has shifted dramatically since the early 1970s from being dominated by coal and oil, to having a much larger share of gas. There are many different projections of the fuel mix going forward, but all of them show that further change in the UK is inevitable. Figure 4 shows DECC’s projections with a continued decline in coal use, and expanded contribution from renewable sources. The share of a fuel in the energy mix is an important element in determining the overall size of subsidies paid to each energy source.

Figure 4 Primary Energy Mix in the UK

In terms of downstream energy consumption, analysis of the tax base shows that like many countries, the UK raises the great majority of its energy taxes from transport fuels (OECD 2013) as shown in Error! Reference source not found.. The shaded bars in the figure orrespond to total tax revenue, excluding ad valorum taxes such as VAT. The most intellectually robust way to assess whether or not such taxes represent net revenues or net subsidies would be to take gross revenues, and subtract the degree of government expenditure for example on infrastructure or other services required to support that energy service. Such detailed assessments are beyond the scope of this study, and tend also to be excluded from assessments such as those carried out by the OECD, which takes each country’s tax code as a ‘norm’ from which to assess subsidies.

Figure 5 The consumer tax base for energy products in the UK (excludes VAT)

2.2 Fossil Fuel Subsidies The UK has progressively reduced subsidies to fossil fuels over the past 30 years in line with EU and OECD guidelines. There are no end-user price controls, with all prices being set by the market. The following analysis is based on the recent OECD calculations of energy subsidies for its member countries (OECD 2012).

Producer support

The main type of producer subsidy remaining in the UK is in the oil and gas sector and relates to tax allowances to partially offset the petroleum revenue tax (PRT). The PRT is the main tax levied at 50% of gross profits on oil and gas production in the UK. All oil and gas producing countries levy some kind of tax or royalties on production which is how they gain value from the resources being extracted. There is no common international standard for the rate of such taxes and levies, the level is set by each country. The standard PRT therefore defines the ‘normal’ baseline tax rate for oil production in the UK.

Various allowances which partially offset the PRT are available to companies which act as subsidies. These include a new-field allowance that was introduced in 2009 for small, ultrahigh-pressure and high-temperature oil fields, and ultra-heavy oil fields. As noted in Section 1.2.5, such subsidies for high-cost fields are not uncommon (GSI 2010). This allowance was subsequently extended by the government to cover remote deep-water gas fields (March 2010), very deep fields with sizeable reserves (March 2012), and certain large shallow-water gas fields (July 2012). Other measures to support certain types of production include Promote licences, which allow small and start-up companies to obtain a production license first and secure the necessary operating capacity and financial resources later through reduced rent for the first two years. These PRT allowances added up to £159m in 2011 for oil, and £121m for gas.

The OECD considers that in the context of the UK tax system design, the ability of oil and gas companies to write off exploration and production expenditures immediately does not constitute a subsidy.

Producer support for coal-mining sector has been removed since 2006, with only inherited liabilities relating to previous public ownership estimated by the OECD at a level of £4m in 2011. This includes management of abandoned mines and treatment of mine-water discharges.

Looking ahead, shale gas is a potentially important new area of energy resource development in the UK. HM Treasury is currently consulting with industry on a fair tax regime for this new development (DECC 2012). The definition of a ‘fair’ tax in this context will have to take into account whether special tax treatment is required for the sector given its different pattern of capital investment and other differences compared to conventional oil and gas fields. Given the normative nature of subsidies in the energy sector, a decision on whether or not any special treatment given to shale gas vis-à-vis conventional sources would have to take into account similar considerations. In the US which has the greatest experience of shale gas development, emerging subsidy issues include the adequacy of bonds used by oil and gas producing states to assure funding for reclamation of drilling sites, cover regulatory costs and offset public infrastructure costs. Road damage from use of heavy trucks on secondary roads, and payments for cleanup of fracking water are also emerging as costs which will need to be accounted for.

Consumer support

By far the largest subsidy for fossil fuels in the UK relates to the lower VAT rate of 5% for domestic energy supplies (compared to 20% for the economy as a whole). Since VAT is a general economy-wide tax, any reduction from the general national rate is considered by the OECD to be a subsidy. Domestic energy supplies have always been taxed at a lower rate in the UK, since being raised from zero to 5% in 1994, but this practice is unusual, as most countries tax energy at the prevailing rate of VAT (see Section 3.1).

In 2011, this tax was worth £81m for coal, £380m for oil and £3,510m for gas.

There are very few measures other than tax exemptions or reductions that support energy consumption in the United Kingdom. Schemes such as winter fuel payments for the elderly or cold-weather payments do not depend on the price of fuels and are provided in-cash to eligible households. Most of the remaining measures target consumption technologies such as low-carbon vehicles and hydrogen refuelling equipment rather than energy use per se.

Discounts to the climate change levy CCL (an end-user energy tax) are offered for eligible energy intensive users in return for committing to a climate change agreement to reduce energy consumption (see Section 2.6.2).

Missing Data

The OECD study points to a number of areas where data was not available to calculate subsidy levels for fossil fuels. These include:

Ring-Fence The Ring-Fence Expenditure Supplement (RFES) was introduced in January 2006 to replace Expenditure the former Exploration Expenditure Supplement (EES). In its current version, it provides oil Supplement and natural-gas companies with a yearly 10% increase in the value of unclaimed deductions for expenses related to exploration and appraisal for a period of up to six years. Field This new allowance was first introduced in 2009 and later extended to encourage the Allowance development of small or technically-challenging fields. Before 2012, qualifying fields had to be small in size, feature ultra-high pressure or temperature, possess ultra-heavy oil reserves, or be remote deep-water gas fields. In 2012, it was then announced that new field allowances would also be extended to very deep fields with sizeable reserves, and large shallow-water gas fields. This extension is expected to generate revenue losses of about GBP 20 million per year (HM Treasury, 2012). The field allowance provides companies with a partial exemption from the Supplementary Charge. Relief is calculated at the level of the field but is provided at the company-level. Unclaimed allowances can be carried forward. Mineral The Mineral Extraction Allowance (MEA) was introduced in 1986 to provide mining Extraction companies (including coal, oil, and natural-gas producers) with faster rates of depreciation Allowance for qualifying capitalised expenditures. The latter include the acquisition of mineral rights or deposits and expenditures connected to access to the reserves. Prescribed rates vary with the type of expenditure to which the provision applies. Analysis of this provision is, however, complicated by the interaction of the MEA with the general tax regime that applies to oil and gas extraction. These caveats do not apply to coal though. Although this provision applies to the mining sector as a whole, data from the OECD’s STAN database indicate that mining of fossil fuels accounts for nearly 90% of total gross output for the mining and quarrying sector (as defined in the standard ISIC Rev.3 sector classification). Abandonment This provision allows capital expenditures connected to the abandonment of fields and Costs mines to be deducted in full in the year in which they are incurred. Deductions are coupled with a carry-back provision which makes it possible for companies to use losses arising from decommissioning costs against profits earned in earlier years. This may therefore result in tax refunds. Although this provision applies to the mining sector as a whole, data from the OECD’s STAN database indicate that mining of fossil fuels accounts for nearly 90% of total gross output for the mining and quarrying sector (as defined in the standard ISIC Rev.3 sector classification).

2.3 Nuclear Subsidies Nuclear plants provided 62.7 TWh or 17.8% of the UK’s electricity in 2011 (down from a maximum of 26.9% in 1997), coming from ten nuclear power stations with a combined capacity of 11 gigawatts (GW). The largest nuclear operator is EDF Energy, a wholly owned subsidiary of Electricité de France (EDF), which purchased British Energy Group plc in January 2009. It runs eight nuclear power stations, seven of which are advanced gas-cooled reactors (AGRs) and the remaining one is a pressurised water reactor (PWR) at Sizewell B. Two plants operated by Magnox Ltd. run Magnox gas-cooled reactors. The Nuclear Decommissioning Authority (NDA) owns several closed Magnox stations.

The UK reactor fleet is comparatively old. Up to 7.4 GW of existing nuclear capacity were scheduled for closure by 2019. However, the AGR reactors are being awarded life extensions, which is likely to delay closure, currently for around 7 years. The other reactor is the 1200 MW PWR at Sizewell B whose scheduled lifetime is to 2035 (IEA 2012).

2.3.1 Historical liabilities The NDA has responsibility for radioactive waste management and decommissioning, and for nuclear legacy sites. It is a non-departmental public body created in 2005 that employs about 200 people. NDA owns former nuclear sites and the associated civil nuclear liabilities and assets of the public sector, including all the former sites and reactors of British Nuclear Fuels Limited (BNFL) and the UK Atomic Energy Authority (UKAEA). Its responsibilities include decommissioning and clean-up of these installations and sites, as well as the implementation of the UK nuclear waste policy. It is currently working on an annual budget of around £3 billion, of which £2.3 bn comes from the UK government, and the remainder from commercial operations. Total public liabilities for NDA’s sites on a total discounted lifetime cost basis are around £50bn. As shown in the breakdown in Table 2.1, by far the largest of these is £32bn for Sellafield (net of remaining operating revenues).

However, as pointed out by the National Audit Office (NAO 2012), these cost estimates, although improving, are still quite uncertain. They note

“The [NDA’s] undiscounted provision for the lifetime cost of the clean-up of Sellafield up to 2120 increased from £46.6 billion as at March 2009 (in 2011-12 prices) to £67.5 billion as at March 2012. The [NDA] expects that the lifetime cost will continue to rise, as uncertainties in the lifetime plan are addressed, then plateau, and finally decline as Sellafield Limited manages the decommissioning process better.”

Some of the financing of the NDA comes from the Nuclear Liabilities Investment Portfolio (NLIP), a fund of about £4bn that was separately identified in BNFL’s accounts before privatisation, but which stayed in public hands. Arguably therefore, some of NDA’s budget comes from the industry rather than from government, but in the bigger scheme of things, this is only sufficient to pay for two years or less of NDA’s expenditure, so for the large part NDA can be considered to be publicly funded (Thomas 2004).

Table 2.1 Public liabilities for retired nuclear plant3

2011/12 Estimated Discounted Lifetime Plan (£m) Decomm & Total Commercial Net Government Clean-up Operations Revenue Running Funding Costs* Costs** Cost Site Licence Site A Running C D = (B-C) E = (A+D) Company Cost B Magnox Magnox Support 690 0 690 Limited Berkeley 659 0 659 Bradwell 506 0 506 Chapelcross 749 0 749 Dungeness A 647 0 647 Hinkley Point A 699 0 699 Hunterston A 667 0 667

3 Source: NDA available at http://www.nda.gov.uk/sites/financials/index.cfm accessed March 2013

Oldbury 1,008 0 1,008 Sizewell A 778 0 778 Trawsfynydd 611 0 611 Wylfa 1,045 80 80 1,125 Research Harwell and 1,122 0 1,122 Sites Winfrith Restoration Limited Dounreay Site Dounreay 1,904 0 1,904 Restoration Limited Sellafield Sellafield 36,601 3,571 8,040 -4,469 32,132 Limited (including Calder Hall and Windscale) Capenhurst 647 0 647 LLWR Limited LLWR 253 533 598 -65 188 Springfields Springfields 384 0 384 Fuels Limited Sub-Total 48,970 4,184 8,638 -4,454 44,516 Electricity Sales 90 246 -156 -156 Geological 3,840 3,840 Disposal Facility NDA Central 83 1,447 1,550 -103 -20 Liabilities & Group Total 59,893 5,721 10,434 -4,713 48,180

2.3.2 Waste and decommissioning for future plant Waste liabilities for future plant are even more uncertain than historical liabilities. The government’s position is that any new nuclear plant must cover the costs of future waste and decommissioning out of their current operating costs without any public subsidy. This requires companies to put aside funds each year which can accumulate over the operating lifetime of the plant to pay for these back-end costs. However, long term disposal options will not start to become operational until after 2050, and until then, costs remain speculative.

The problem with costs being so uncertain is that it creates a barrier to investment because of the potential for liabilities to be higher than originally expected. In order to help companies manage this risk, the government therefore has proposed to introduce a fixed payment mechanism, the so-called ‘waste transfer price’ (DECC 2011):

“In order to provide Operators with certainty over the maximum amount they will be expected to pay for waste disposal the Government will, at the outset, set a Cap on the level of the Waste Transfer Price. The Cap will be set at a level where the Government has a very high level of confidence that the actual cost will not exceed the Cap. However the Government accepts that, in setting a Cap, the residual risk that the actual cost might exceed the Cap is being borne by the Government. Therefore the Government will charge an appropriate Risk Fee for this risk transfer. Hence for clarity, the Waste Transfer Price will include two separate risk allowances:

• The Risk Premium is the premium over and above expected costs that will be included in the Waste Transfer Price to reflect the risk being assumed by the Government, when the Waste Transfer Price is set at the end of the Deferral Period, that actual costs might be higher than the Waste Transfer Price.

• The Risk Fee is an additional element included in the Waste Transfer Price to reflect the small residual risk being assumed by the Government, when the Cap is set at the outset, that actual costs might be higher than the Cap.”

The offer by government of a cap on liabilities could be considered a subsidy because it acts like an insurance policy. On the other hand, the government is aiming to charge for this transfer of risk via the risk fee, which in principle cancels out the subsidy. It is very hard to determine an appropriate ‘market price’ for this risk, since it would be almost impossible to obtain an insurance against such open-ended risks.

As an illustration of the potential scale of subsidy, DECC have published an indicative waste disposal liability based on cost estimates for the disposal of intermediate level waste of £14.5k/m3. Based on this estimate, the illustrative cap would be £48.4k/m3. However, estimates of the NDA’s true marginal cost for waste disposal is put at £67/m3 which suggests a significant risk that future liabilities may end up being transferred to the public purse. Estimates of the potential total value (undiscounted) of this subsidy have been estimated at between £400m to £1500m depending on the lifetime of the nuclear plant between 40-60 years (Greenpeace 2011). The Birmingham Policy Commission (Birmingham 2012) puts the waste transfer fee price cap into context, estimating that it is worth at most 1.5-2% of the revenue from sales of electricity, and quotes DECC estimates that the likelihood of the cap being exceeded is less than 1%.

The true scale of these risks come down to an assessment of how realistic these estimates of these liabilities are. In principle, the government could try to sell a portion of the ultimate liability on the secondary market to reality test pricing assumptions against market value, although the liquidity of such markets is likely to be questionable.

2.3.3 General operating conditions for new nuclear Despite Ministerial announcements as recently as October 2010 that there would be no public subsidies for new nuclear plant, it is apparent that several subsidies will in fact be in place, some explicit, some implicit, driven in large part by the rapid escalation in the estimates of capital costs for building new nuclear plant (for estimates of how costs have changed over the past 10 years, see (Schneider, Froggatt et al. 2012 ).

The most transparent will be the price support for producers under the feed-in tariff to be introduced as part of recent electricity market reforms. The tariff is still being negotiated between the government and EdF, for planned new build at Hinkley Point in Somerset. The price that the company receives for its electricity will be fixed by a contract for difference, which requires consumers to top up payments over and above the market price up to the agreed level. Once the strike price has been announced for Hinkley Point, the extent of the subsidy will become more apparent.

These arrangements constitute a subsidy not only because of the raised price compared to market levels, but also because long-term fixed price contracts with reliable counterparties allow companies to borrow money at lower interest rates – a particularly important factor for capital intensive projects like nuclear plant. The duration of the contracts is therefore

very important element of the subsidy, and is also still under negotiation, but there has been some speculation that contract periods of up to 40 years are being discussed4.

It is likely that in the early years of operation, this market price support will constitute a substantial subsidy compared to the cost of the cheapest alternative (i.e. gas-fired plant), but in the long run, the subsidy element is not so clear. Given a 40 year time horizon, gas prices are extremely uncertain, and nuclear may turn out to be cheaper, especially taking into account the costs of removing CO2 from gas-fired generation. On the other hand, nuclear will be competing with renewable energy sources, for which costs have been coming down rapidly over recent years. From a strategic energy security perspective, governments may consider that these macro-economic uncertainties are beyond the scope of private companies to cope with via normal market mechanisms.

Other types of subsidy are less transparent. The nuclear industry operates in a somewhat protected commercial environment because of the fact that each plant is too big to fail. This means that it is necessary for national governments to underwrite most of the commercial risks of nuclear power, as evidenced by the way the UK government had to bail out British Energy in 2005 at a cost of about £5 billion. This demonstrates the general point that, ultimately, national governments have no choice but to underwrite the commercial risks of nuclear power. The state aid for the rescue and restructuring of British Energy and BNFL were allowed by the EC in 2004 and 2006 respectively5. In November 2009, British Energy was sold to EDF Energy for £12bn, the proceeds of which were put into the nuclear liabilities fund. An issue for the government to manage is how to accrue sufficient interest on these funds to cover future liabilities given the current low return on secure investments such as treasury bonds. A related issue is how government funds should be accounted for when considering the cost of capital for infrastructure projects such as waste disposal. One line of argument suggests that government cost of capital is an inappropriate measure of the real costs, since it tends to mask the effects of risk (Lucas 2012).

The same goes for limits to company liabilities associated with major incidents such as nuclear accidents, terrorist threats and so on. Despite the low probabilities of such events occurring (at least on a plant-by-plant basis), the excessively high level of the maximum liability incurred means that companies are unable to obtain private insurance against such risks6. The value of such implicit subsidies are very difficult to assess. Estimates depend crucially on assessments of the likelihood of such events occurring. This tends to be a very subjective issue, and difficult to obtain impartial analysis. Despite the difficulty of quantifying these implicit subsidies, it is clear that without them, private investment in new nuclear power plant would not go ahead.

The UK government intends to increase the cap on liabilities to €1.2 billion from its present level of £140 million as part of its implementation of an international treaty on nuclear third

4 http://www.guardian.co.uk/environment/2013/feb/18/nuclear-power-ministers-reactor

5 The case reference documents are in the state aid register: http://ec.europa.eu/competition/state_aid/register/

6 See discussion in Der Spiegel http://www.spiegel.de/wirtschaft/soziales/0,1518,761826,00.html#ref=nldt or here for an English translation: http://tinyurl.com/d7yz48k

party liability - the Paris and Brussels Conventions, to which the UK and most of the other EU countries are signatories (DECC 2012). This increases substantially the range of low-level incidents that companies will have to cover themselves. It is clearly substantially short of a full-scale disaster of the order of magnitude of Fukushima, for which the clean-up costs alone have been estimated at €175bn, not including the wider economic damages incurred (EnergyFair 2012). Significantly higher liabilities in the private sector are not unprecedented (e.g. BP has allocated $41bn to settle claims resulting from the Gulf of Mexico disaster). Such large sums are probably beyond the ability of relatively smaller utility companies to handle, but the fact remains that there is an incentive for companies to understate their ability to secure private insurance for such risks in order to gain government protection, and ways should be sought for these risks to be internalised as far as possible within the general costs of production.

2.4 Renewables

2.4.1 Current subsidy arrangements Renewables Obligation

The main subsidy to large-scale renewable energy sources in the UK is currently the Renewable Obligation (RO) scheme which requires suppliers to provide a certain proportion of their electricity from approved renewable sources. Generators of renewable energy are issued with a renewable obligation certificate (ROC) for each MWh of power generated. Some sources of renewable energy are credited with more than one ROC per MWh, and some less in order to balance out investment incentives with respect to technology costs7. For example, onshore wind receives 0.9 ROCs per MWh, whilst offshore wind receives 2 ROCs per MWh (falling to 1.5 from 2014/15 onwards). These certificates are tradable. Suppliers buy sufficient ROCs to be compliant with their obligations. This creates a market for ROCs, so that their price is a transparent observable value.

Any suppliers who do not hold enough ROCs pay a ‘buy-out’ price. These penalty fees are paid into a central fund, out of which is taken the administration costs of the scheme, and the remainder is redistributed back to suppliers in proportion to their degrees of compliance with the RO. This recycling of the buy-out fund effectively increases the value of holding ROCs, and adds to their market price.

The value of holding excess ROCs is zero, since they cannot be banked for use in future periods, so to stop the market price of ROCs falling to zero, the government sets the RO at a level above what is expected to be delivered, so as to achieve ‘headroom’, ensuring a positive payment into the buy-out fund.

The current obligation level for suppliers for April 2012 to 31 March 2013 is 0.158 ROCs for each MWh they supply to customers in England and Wales. The obligation level for April 2013 to 31 March 2014 is 0.206 ROCs for each MWh supplied. This figure is calculated by DECC8 based on the list of potential new build expected to generate in 2013/14 sourced

7 https://www.gov.uk/calculating-renewable-obligation-certificates-rocs

8 https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/65530/6527-calculating- renewables-obligation-2013-14.pdf

from the Renewable Energy Planning Database (REPD), the National Grid’s Transmission Entry Capacity (TEC) Report, Ofgem’s preliminary ROC Register, and, the UK Wind Energy Database.

ROCs (millions) Potential ROCs from existing stations 39.7 Potential ROCs for new build 16.2 Total expected ROCs 55.9 Total (with 10% headroom) 61.5

Suppliers can pass on the costs of purchasing ROCs to their customers. The market price is currently around £42 per ROC (and has traded in a fairly narrow band between £40-50 over the duration of the market as shown in Figure 5). This puts the total value of the RO subsidy at (55.9m x £42) at around £2.4bn for 2013/14. In addition to receiving the ROC price, renewable generators also receive payments for generating levy exemption certificates (LECs). The value of a LEC is tied to the charge made on energy users under the climate change levy (CCL). Electricity is currently subject to the CCL at a rate of £5.09/MWh, which effectively sets the traded price of LECs. For the last full year for which data is available (2010/11), the number of LECs issued was 29.8m. This puts the value of this subsidy at £152m.

Figure 5 Market (auction) price for ROCs have been quite stable over the past 3 years

NFFO

Prior to the introduction of the renewable obligation, market support for renewables was via the non-fossil fuel obligation (NFFO). These were long term contracts priced by auction giving a fixed price per kWh for different bands of renewable technology. Based on the volumes and prevailing auction prices of the NFFO, the value of these remaining contracts are shown in Table 2.2, totalling around £400m. However, unlike ROCs, these payments are not additional to the value of the electricity, but instead they include the value of electricity generated. For NFFO 4 and NFFO 5 rounds, the fixed payments made under the long-term

contracts is actually less than the wholesale price of electricity. Therefore, these contracts no longer act as a subsidy for the NFFO generators. NFFO generators are not eligible for producing LECs.

Table 2.2 Value of contracts remaining under NFFO arrangements

period Total Average Total value Approx. Approx. contracted price 06/07 of NFFO market value of capacity (p/kWh) payments value of subsidy (MW) (£m) electricity (£m) (£m) NFFO 3 01 Apr 1995 - 627 6.15 128 99 29 28 Aug 2013 NFFO 4 01 May 1997 843 4.51 132 138 -6 - 30 Dec 2016 NFFO 5 01 Dec 1998 - 1177 3.40 137 195 -58 29 Nov 2018 TOTAL 2647 396 432 -36

Feed-in Tariffs

For small-scale renewables, the RO system has been deemed too complex, so to provide a simpler and more certain revenue stream, a feed-in tariff (FiT) was introduced for plant installed up to 5MW. This provides a fixed additional revenue stream over and above the value of electricity generated for each kWh of electricity generated. By far the largest beneficiary of the scheme since it was first introduced in 2010 has been rooftop solar PV, accounting for about 90% of installed capacity under the scheme (Ofgem 2012). The tariff for April 2010 – March 2011 was set to 41.3 p/kWh for systems up to 4kW retrofitted to rooftops. Tariffs are fixed in real terms for 25 years, adjusted for inflation annually at RPI. In addition, householders receive an additional tariff for any exported electricity, acting as an incentive to run the household efficiently.

The tariff was due to remain unchanged for the first two years, and then drop by 8% to 37.8p/kWh in the third year (UK 2010). In fact, demand for the tariff was so strong, that government decided to drop the tariff rate much more quickly to 21p/kWh for schemes after March 2012. The latest arrangements for setting solar PV tariffs require Ofgem to set quarterly tariff rates which can be adjusted to take account of the volume of uptake of the subsidy (UK 2012). The tariffs for other renewable technologies are set annually by Ofgem. The latest rates for small scale rooftop solar are as follows9:

Table 2.3 Change in tariff rates for rooftop solar PV <4kW10

9 From http://www.ofgem.gov.uk/Sustainability/Environment/fits/tariff-tables/Pages/index.aspx

10 Properties with an energy performance rated D or below receive a lower tariff. Developers installing solar PV on more than 25 properties also receive a lower tariff.

FIT Year 1 Mar 2012 – Aug 2012 – Nov 2012 - Feb 2013 – May 2013 2010/11 Aug 2012 Nov 2012 Feb 2013 May 2013 – Jul 2013 (for projects up to Mar 2012) FiT p/kWh 45.40 21.00 16.00 15.44 15.44 15.44 Export tariff 3.2 3.2 4.5 4.5 4.64 4.64 p/kWh

Total subsidy payments made under the FiT scheme are summarised in Figure 6. The amount of installed capacity dropped significantly in 2012 Q2 compared to previous periods after the tariff was reduced, but have picked up again since then. The total payments made under the scheme are cumulative, since any new projects add to the payments made against capacity that has already been installed in previous periods. Total annual payments in 2012 will therefore amount to more than £500m for the FiT scheme.

Figure 6 Payments made under the FiT to date11

2.4.2 Future Investments – implications of electricity market reform As a result of the recent energy market reforms, all support for renewables will now be moved to a feed-in tariff support mechanism. The arrangement for small (<5MW) systems remains as before. Large-scale renewable projects that would previously have been supported under the RO will instead receive a fixed price based on a contract-for-difference (CfD) payment mechanism which tops up payments to generators over and above the amount they receive for selling electricity at market rates. The tariff rates will vary according to the type of technology.

The tariffs to be received for renewables have not been yet been finalised, but it seems likely that they will be broadly comparable with the support levels received under the previous RO scheme. An indication of the total value of the subsidy is provided by the levy

11 Data from http://www.ofgem.gov.uk/Sustainability/Environment/fits/Newsletter/Pages/Newsletter.aspx

control framework, which sets a total limit on the value of payments that can be made via ‘levy-funded’ spending (i.e. increases to consumer energy bills to pay for low carbon energy sources). This is currently £2.35bn, rising to £3.56bn by FY 2014/15 (DECC 2011), and in the pre-budget report in November 2012, it was agreed to set the figure for 2020 at £7.6bn per year12. Figure 7 indicates that the limit on levy spending specified in the levy control framework provides some headroom compared to spending to date and projected spending over the next year on FiTs and ROCs, the two main sources of levy spending. The projected rise to 2020 appears sufficient to allow for a continuation of the expansion of renewable energy at its current rate.

Figure 7. Value of current subsidies to renewables and the spending constraint under the levy control framework out to 2020

2.5 Electricity VAT rates for electricity for domestic use is charged at a reduced rate of 5%. This acts as a subsidy compared with the general rate of VAT of 20%, leading to a higher than optimal rate of electricity usage. Because this applies to final use, it does not distort the choice of fuel used in the generation of electricity, since generators receive the ex-VAT value.

The ex-VAT value of electricity sold to the domestic sector is approximately £14.8bn per year. The value of a 15% discount on VAT is therefore of the order of £2.2bn per year.

Some of the distortions created by this subsidy are offset by a reduction in the VAT rate for energy saving equipment as listed below13.

Table 2.4 Reduced VAT rates on energy saving goods

The installed goods VAT rate Air source heat pumps 5% Boilers - wood fuelled 5%

12 Press release: https://www.gov.uk/government/news/government-agreement-on-energy-policy-sends- clear-durable-signal-to-investors

13 http://www.hmrc.gov.uk/vat/forms-rates/rates/goods-services.htm

Central heating and hot water controls 5% Draught stripping 5% Ground source heat pumps 5% Insulation 5% Micro combined heat and power units 5% Solar panels 5% Water and wind turbines 5% Nevertheless, the lower rate of VAT for electricity and gas are a significant distortion to the tax code. Removing such subsidies is however difficult. As noted in a set of case studies on environmentally harmful subsidies in the EU (Valsecchi, ten Brink et al. 2009):

“The traditional argument to tax ‘necessities’ at a reduced VAT rate (or not to tax them at all) is that low-income households tend to spend a relatively large part of their income on these goods and services, so that taxing them at the standard rate would have a regressive distributional impact. In reality however, only a small part of the subsidy reaches the intended recipients (low-income households). High-income households receive most of the benefits, as the income elasticity of demand for energy is positive. The original social motive for the subsidy has largely disappeared, as the share of energy in household expenditure has decreased dramatically, also among low-income households. A more cost effective alternative would be to provide direct income support or tax relief for low-income households.

There have been previous attempts to remove this subsidy including an attempt in 1995 which failed because of the expected distributional impact. In particular the fact that it would hit elderly people the hardest, led to the abandonment of the proposed increase of VAT to the standard level. A possible compensation measure that could be used to palliate the impact of removal would be to reinforce existing schemes to assist low-income households with investments in energy saving.”

2.6 General

2.6.1 Government funded energy R&D The UK spends about £7.5 per capita per year on energy-related R&D (IEA 2012), which is approximately equal to the median amount for IEA countries. R&D expenditure has increased rapidly in recent years following a period of decline over the previous decade. Total expenditure in the UK including R&D and demonstration projects in 2010 was over £500m, representing a very significant increase (76%) increase since 2009. The figure for 2011 dropped back to around £300m, but the trend over the past 5 years is still significantly higher than over the previous decade. The breakdown of expenditure between different energy sources is shown in Figure 8.

Figure 8. UK Government energy R&D expenditures

Research on energy efficiency and renewables in particular have increased rapidly, with nuclear energy and carbon capture and storage for fossil fuels also having experienced a resurgence over recent years.

2.6.2 Climate Change Levy Exemptions and Discounts The climate change levy is a tax applied to business energy users (including industrial, public, commercial and agricultural users). It applies to electricity, gas and solid fuels for heating, lighting and process use. The purpose of the tax is to work towards the principle that the polluter pays for the climate change externalities of the energy use, and because the tax is applied rather generically across the economy, exemptions from the CCL should therefore be considered a subsidy.

Exemptions from the climate change levy are available for:

 Small businesses (e.g. <1000 kWh per month)  Supply from good-quality CHP schemes  Supply of electricity from renewables  Inputs for own-use electricity generation  Non-fuel use (e.g. chemical feed-stocks) In addition, a discount of 65% is available to energy-intensive users who sign up to a climate change agreement (CCA) to meet an energy reduction target. Based on the author’s estimate, and assuming that CCAs cover a large proportion of industrial energy consumption, the discount is worth around £500m in avoided tax.

In some sense, this could be seen as a subsidy, since these companies face a lower tax rate than the norm for business in the UK. On the other hand, DECC estimates that the energy savings achieved under the CCAs are at least as great if not greater than the energy savings that would have occurred if the companies involved were subject to the full energy costs associated with the CCL. Therefore, tying the CCL discounts to CCAs actually reduces energy demand rather than increasing energy demand as would normally be the case for a straight subsidy. If a definition of subsidies is used which only counts situations where there is a resulting increase in energy consumption, then CCL discounts tied to CCA energy reductions would not be considered a source of subsidy.

2.6.3 Enhanced Capital Allowances The Enhanced Capital Allowance (ECA) scheme enables businesses to claim a 100% first year capital allowance on investments in certain energy saving equipment, against the taxable profits of the period of investment. Capital allowances enable businesses to write off the capital cost of purchasing new plant or machinery (e.g. boilers, motors), against their taxable profits. The general rate of capital allowances is 18% a year on a reducing balance basis, so 100% capital allowance in one year represents a considerable benefit in terms of 1st year cash flow, and also reduces overall tax payments. It is estimated that the cost to treasury of the ECA tax breaks is round about £100m per year14.

2.7 Summary of UK Subsidies The values assigned to different forms of subsidy are, as described in the introduction section, dependent on a definition of what constitutes ‘normal’ taxation practice, which is not necessarily comparable across fuel types. Table 2.5 pulls together the various estimates made in the text should therefore be used with caution. Nevertheless, it is useful to see where the estimates of significant levels of subsidy lie, and where there are still significant gaps in the data that is readily available.

Table 2.5 Summary of UK Energy Subsidies

Energy type Primary Annual Source of subsidy Comments Energy Value of Demand15 Subsidy (GWh) £m Oil 975,792 159  PRT  Producer support 380  VAT  Consumer support Gas 906,489 121  PRT  Producer support 3510  VAT  Consumer support Oil & Gas ?  Additional  Producer support exemptions from charges and accelerated tax allowances Coal 385,174 4  Mining liabilities  Producer support 81  VAT 5%  Consumer support Nuclear (incl 68,980 ~2300  Gov’t input to NDA  Producer support historical annual budget liabilities) ?  Possible increases in budget required to

14 Personal communication with Carbon Trust.

15 Figures for fossil fuels relate to total primary energy demand in the UK in 2011. For nuclear, renewables and electricity, the figures relate to total production in 2011.

deal with legacy waste Current 34,409 2400  ROCs  Producer support Renewables 152  LECs  500  FiTs  Electricity 364,897 2200  VAT reduction  Consumer support Energy R&D 300  All sectors  General services CCL 500  For energy intensive  Consumer support discounts industry (but offset by CCAs) ECAs 100  For en. efficiency  Consumer support 3 International comparison

3.1 Fossil Fuels The most thorough assessment of fossil fuel subsidies in comparable countries to the UK is provided in the OECD report “Inventory of Estimated Budgetary Support and Tax Expenditures for Fossil Fuels” (OECD 2012). The data is provided in local currency units, and has been converted here to US$ for comparison. However, a health warning is required when making these comparisons between countries. As noted in the introduction to this report, subsidies are defined in comparison to the particular tax regime, measuring deviations from whatever is deemed ‘normal’ in that country. Since the tax regimes vary considerably, there is no single consistent measure for subsidies in this case that ensures that they are being compared on a like-for-like basis. The OECD caveat to these figures reads:

“Tax expenditures for any given country are measured with reference to a benchmark tax treatment that is generally specific to that country. Consequently, the estimates … are not necessarily comparable with estimates for other countries. In addition, because of the potential interaction between them, the summation of individual measures for a specific country may be problematic.”

With that caveat in mind, the figures are presented here in two ways. Firstly, in total expenditure terms as presented in the OECD report but converted to a common currency unit. Secondly, the total subsidy levels are divided through by the total primary energy supply of each fuel type in that country in order to adjust for the size of the country when making the comparison. Subsidies are distinguished between Producer Support measures, Consumer Support measures and General Services.

Data is not shown here for all the countries covered in the OECD report, but the focus is on larger countries, and those that are more comparable with the UK.

Figure 9 Total Subsidy levels for fossil fuels (US$m)

Producer Consumer General 12000 Coal 10000

8000

6000

4000

2000

Producer Consumer General 12000 Oil 10000

8000

6000

4000

2000

Producer Consumer General 12000 Gas 10000

8000

6000

4000

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AUS AU BE CAN CZ DE FR GER IT JP NL NO PO SP UK US In common with many other OECD countries, UK subsidies for coal are small by international standards. Coal subsidies mostly take the form of producer support measures in countries that still have significant levels of production (Germany, Poland, Spain, US), although not all producer countries have such subsidies (e.g. Australia). In general, there is a declining profile over time for these subsidies as they are gradually phased out, and as a result of a declining share for coal in most countries.

In the oil sector, producer support measures are a smaller fraction of total subsidies, and concentrated mostly in Australia, Canada and US. In most countries, oil subsidies are provided to consumers, and take the form of various tax credits, exemptions, refunds and discounts for specific end-use of oil products. These are too diverse to list in detail here, but a full explanation of the subsidies defined for each country is provided in the OECD report.

For gas, producer support is limited mainly to Canada and the US, and relatively little subsidies of any sort in most OECD countries. The UK has a relatively high level of subsidy for gas which is mostly the VAT tax break for domestic consumers. The UK is unusual in Europe in this respect in providing a sales-tax break for natural gas, although In the US, state-level exemptions of energy from sales taxes levied on other goods and services are common.

In order to adjust these subsidy comparisons for the size of the country, the figures are compared with the total primary energy consumption of each fuel in the relevant year. The charts are shown in Figure 10 in units of US$/MWh. It should be noted that under this measure, the subsidy expenditure is divided by the total fuel use for the country concerned. This will tend to underestimate the value of the producer subsidies to individual companies for the particular applications for which they apply.

Figure 10 Subsidy per unit of primary energy supply in each country

25 Producer Consumer General Coal 20

10 Subsidy (US$/MWh) Subsidy

Producer Consumer General 25 Oil

10 Subsidy (US$/MWh) Subsidy

Producer Consumer General 25 Gas

10 Subsidy (US$/MWh) Subsidy

2005 2007 2009 2011 2006 2008 2010 2005 2007 2009 2011 2006 2008 2010 2005 2007 2009 2011 2006 2008 2010 2005 2007 2009 2011 2006 2008 2010 2005 2007 2009 2011 2006 2008 2010 2005 2007 2009 2011 2006 2008 2010 2005 2007 2009 2011 2006 2008 2010 2005 2007 2009 2011 2006 2008 2010 AUS AU BE CAN CZ DE FR GER IT JP NL NO PO SP UK US Relative to its overall consumption levels for each fuel, the UK appears to have low subsidies by international standards for coal and oil. For gas, UK subsidies are relatively high by international standards, but other countries such as Austria (tax break for energy intensive users), Czech Republic (energy tax exemptions) and Canada and Norway (producer support) also have a relatively higher degree of subsidy under this measure. Nevertheless, in general, subsidies across most OECD countries are lower for gas than they are for coal and oil.

3.2 Renewables In principle, renewable energy subsidies focus on explicit price support mechanisms which should be more transparent to trace than subsidies for other fuel sources. In practice, there is quite a complex pattern of different support rates for different sizes and vintages of plant, and the legislation in each country tends to change frequently. As a result, there seems to be little literature available providing a like-for-like comparison of subsidies between countries. Two data sources have been used to construct a comparison, the EU energy portal (Portal) and a study for the European Renewable Energies Federation (Fouquet 2012).

Some countries’ schemes are based on a feed-in tariff that represents the total payment to renewable generators per MWh produced. Other schemes are based on a ‘premium’ over and above the wholesale electricity price. In these cases, an estimate has to be made of the market price for electricity in order to reach the total payment to make a like-for-like comparison. The UK situation is similar to the premium tariff in the sense that renewable generators receive income from electricity plus an additional amount for the renewable energy certificates (ROCs + LECs). Error! Reference source not found. shows values that are inclusive of electricity prices, and therefore do not represent the subsidy, but rather the subsidy + market value. Because of the difficulty of comparing across countries, a relatively smaller sample is presented here.

In some cases, there appears to be a discrepancy between the different data sources, leading to a range of estimates – these cases are noted with an asterisk. In other cases, the range relates to different tariffs applying to different sizes of plant, or for different vintages (i.e. year of installation). For example, in the UK case the ranges apply to different tariff rates applied to different dates of installation as described in the notes below the charts.

700 Solar PV 600

500

400 /MWh

€ 300

200

100

350 Biomass 300

250

200 /MWh

€ 150

100

NOTES: * Range due to differences between sources + Support based on a premium: these figures include an estimate of wholesale market price received ^ Tariff suspended (1) Lower limit is the reduced banding rate for offshore wind of 1.5 ROC per MWh. Upper limit is current rate of 2 ROC per MWh (2) Lower limit is the current PV tariff, upper limit is the rate that existed for projects up to Mar 2012 (3) Lower limit is for biomass co-firing, upper limit is for dedicated energy crops or biomass with CHP

Onshore wind tariffs lie within a relatively narrow band (with the exception of Italy), reflecting the mature state of the technology. The UK lies at the upper end of this range, but is broadly comparable with other European countries. By comparison, offshore wind tariffs vary

considerably. The lowest figures appear to be for Denmark, based on data from the EREF report which constitutes the lower bound of the range. On the other hand, the tariff rate arrived at by auction for the recent Anholt offshore wind farm was around €140/MWh, which is comparable with the lower end of the UK range (€134/MWh) which applies to the lower banding rate for projects built after 2014. In general, it therefore appears that under current RO banding arrangements, the price for offshore wind including subsidies and market prices is either comparable or relatively low compared to other major European countries.

Solar tariffs also vary considerably between countries, and generally have a wide range even for individual countries. This largely represents the fact that tariffs are under frequent review, and are generally coming down quite quickly. Many countries have a degression rate for subsidy levels, and these are often tied to the rate of uptake (notably in Germany). This means that different plant will receive very different rates depending on when it was installed. The range for the UK represents the difference between the current (lower) rates and the higher rates that pertained prior to March 2012. Broadly speaking, the new lower rates in the UK lie at the lower end of the range of European tariff levels, whereas the rates prior to March 2012 were at the upper end.

Support levels for Biomass in the UK are broadly comparable to those in the rest of Europe, although direct comparison is more complex than this chart would suggest because the wide range of applications of biomass and different sources of biomass tend to attract different rates, and there is no harmonisation of these categories across different countries.

3.3 Nuclear International comparisons of national-level nuclear subsidies for new plant are difficult to obtain, partly because nuclear subsidies are more obscure, and partly because of the scarcity of new build operations. The new plant at Flamanville in France is being undertaken by EdF, a majority state-owned company, so cost overruns presumably are picked up ultimately by the state, and therefore constitute a subsidy, but independent figures are difficult to obtain. The Olkiluoto 3 plant in Finland is being built under market conditions, but it is not yet clear who will ultimately pick up the tab for cost overruns.

Estimates of funding arrangements for decommissioning and waste are available through EU comparisons of state aid, although it is not clear that such comparisons are truly on a like- for-like basis. The EU is involved in nuclear support at the national level in a number of ways, some direct, some indirect. In terms of direct support, during the accession negotiations, the Lithuanian, Slovakian and Bulgarian Governments committed themselves as part of their Accession Treaties to close their Soviet-design reactors. This was a central issue in the negotiations with all three countries, and an important part of the whole package of rights and responsibilities. To help them meet this commitment, substantial Community assistance in addition to that provided under the former PHARE programme were agreed. The overall financial support for the three programmes totals some € 2.5 bn. This covered the support for Bulgaria until 2009 and covers Lithuania and Slovakia until 2013. The EU is also involved more indirectly through its influence on state aid decisions made by Member States.

The significant liabilities for decommissioning and waste disposal built up during the lifetime of a nuclear reactor are supposed to be covered by the EU’s Polluter Pays Principle. To comply with this principle, plant operators should build up a supply of finance to cover these

liabilities over the productive life of the plant. This principle is only partially complied with across the EU.

The European Commission has recently (March 2013) released a staff working paper which sets out the level of support provided by Member States to fund nuclear decommissioning activities (EU 2013), from which data is summarised in Table 3.1. Member State governments are involved in these decommissioning funds in a number of different ways. Most directly, where nuclear power plants are under public ownership, the government will be directly responsible for the decommissioning and waste costs. Often these liabilities will be met out of current budgets rather than building up ring-fenced reserves. In other cases, governments have made commitments to meet some of the liabilities on behalf of the companies that own the plant. In Germany, the financial provisions for decommissioning are provided by the owners of the plant, conforming to the polluter pays principle. Nevertheless, the tax treatment of these funds does constitute a subsidy, although not a state aid, a decision arising from a test in the European courts. With €30bn of decommissioning funds set aside, the German government is forgoing income tax revenues on the order of €4.5bn16. This estimate is confirmed by a DIW study (Diekmann and Horn 2007) which valued this subsidy at €5.6bn.

Table 3.1 Comparison of nuclear decommissioning cost estimates across the EU

Total estimated Provisions % of required % of operational decommissioning accumulated by funds lifetime expired costs end 2009 accumulated

[€ million] [€ million] Belgium 3,453 2,002 64% 63% Bulgaria Special case Czech Republic 1,280 251 20% 46% Germany 11,672 2,529 22% 100% Denmark 98 98 100% 100% Finland 519 506 97% 62% France 77,048 36,781 48% various Hungary 4,030 116 3% 51% Lithuania 2,400 153 0% 100% Netherlands Confidential Romania 598 13 2% 28% Sweden 8,548 4,459 52% 63% Slovenia 1,155 145 13% 68% Slovakia 1,955 931 48% 62% UK 42,405 83%

16 Based on an assumed application of Germany’s flat rate corporate tax level of 15%.

For a review of energy subsidies to the nuclear industry (past and present) in the US, see (UCS 2011). This quantifies subsidies for investor-owned utilities (IOUs) and publicly-owned utilities (POUs), suggesting that for existing plant, legacy subsidies amount to around 140% of market prices, whilst ongoing cost subsidies amount to between 13-100% of market prices. For new plant the study concludes that subsidies amount to between 70-200% of market price (Figure 11).

Figure 11 Estimates of subsidy levels for nuclear plant in the US ¢/kWh (Source: (UCS 2011) A) Existing B) New plant plant

3.4 European-level Support for Energy The EU’s influence on energy issues has increased in recent years and culminated with the adoption of the Treaty of Lisbon and within that the inclusion of energy as an area of joint competence between the EU and Member States.

The total value of energy consumption in the EU is around €1.2 trillion per year. The EU has both a direct and indirect impact on this price through its legislation. However, the financial implications of these impacts are relatively small, compared to total energy expenditure. Of the two, the direct impacts of EU legislation is around 1% of the total expenditure, whereas the indirect affect is around 5%.

Direct Impact: The EU institutions can make available finance, either in the form of loans or grants, for the development and piloting of new energy technologies or for energy infrastructure, in particular for the gas and electricity grids, transport infrastructure and the energy efficiency of infrastructure in general. The types of projects being funded by the EU are dependent on a number of factors, for example the sector specific support mechanisms

for nuclear and to a lesser extent coal exist as a direct result of the establishment of the EURATOM and Coal and Steel Treaties, over fifty years ago. However, a larger share of the finance is determined by current policies, in particular as the EU strives to meet the 20:20:20 targets.

Indirect Impact: The EU, through it legislation or rulings, also has an indirect impact on the subsidies and support schemes in Member States. This is most financially significant in the area of State Aid rulings, which determine the extent to which Member States can assist their industries, and in setting the framework for the use of market mechanisms such as feed in tariffs for renewable energy. Feed in tariffs do not require direct public financial support, but will often lead to additional financial assistance for a technology or technologies from within the market.

Figure 12 shows the degree to which the EU institutions have control and/or influence on energy subsidies and ultimately energy pricing within the borders of the European Union.

Figure 12: Influence of EU Institutions on Energy Subsidies in Europe

Member State Support (Indirect EU influence) coal

nuclear

environmental Indirect subsidies renewables Key Total EU Grant market value Loan Consumption (€) of EU-ETS allowances R&D Market State aid

Direct subsidies EIB Loans

coal road

Framework Programmes gas rail oil sea Trans European Networks nuclear renewables air all non-nuclear energy nuclear transport Structural Funds Recovery Plan Energy Intelligent Europe road EU Treaty networks networks Total rail ECSC Coal offshore wind renewables urban transport Euratom Safeguards Nuclear coal CCS energy efficiency ports, inland waterways multimode transport Euratom loans Nuclear other other airports

There are a number of mechanisms in which the EU directly funds, either through loans or grants, the development of the energy sector within and outside the EU. However, there is no single process which decides the engagement of the EU institutions. This creates both a complexity and potentially a lack of consistency in the projects and infrastructure funded.

The main loans are granted through the European Investment Bank which, in terms of the volumes of finance that it disperses, is the largest International Financial Institution in the world (see Figure 13)

Figure 13: European Investment Bank Energy Lending 2006-2009 (€ million)

Source: EIB 201017

More recently, EIB has consolidated lending around renewable energy, and gas and electricity infrastructure projects. In 2012, there were no loans to coal plant, and one loan for the expansion of uranium enrichment facilities in Almelo, Netherlands (Figure 14).

Figure 14 EIB lending in 201318 (€m)

Electricity 1885 1860 infrastructure Gas

Nuclear

434 R&D / strategy 75 1928

17 EIB (2010): Projects financed data-base, accessed June 2010 http://www.eib.org/projects/loans/index.htm

18 EIB (2013): Projects financed data-base, accessed Mar 2013 http://www.eib.org/projects/loans/index.htm

The other major direct area of influence is the EU’s structural funds, which through the European Fund for Regional Development (EFRD), the European Social Fund (ESF) and the Cohesion Fund can make available over €300 billion to promote growth and jobs leading to the convergence for the least-developed Member States and regions. In the energy sector this includes financial assistance to meet EU objectives, such as energy efficiency targets, but also the greater integration of the energy networks, though the trans European energy and transport networks programmes. The EU also seeks to directly influence the development and deployment of new technologies, through its long established research programme or through demonstration funding, such as in the European Recovery or the Energy Intelligent Europe Plans.

Figure 15: Expenditure on Energy Infrastructure 2000-6 in the European Regional Development Fund (€ million)

900 772.64 800 700 580.93 600 500 354.52 400 300 190 200 100 0 Energy-Unallocated Electricity, gas, oil Renewables Energy Efficiency, and solid fuels co-generation

Source: European Commission 200219

The Structural and Cohesion Funds are used widely in the EU to harmonise the economic and social conditions in different regions. Europe's poorer regions receive most of the support, but all European regions are eligible for funding under the policy's various funds and programmes. The Structural Funds are made up of the European Regional Development Fund (ERDF) and the European Social Fund (ESF). Together with the Common Agricultural Policy, the Structural Funds and the Cohesion Fund make up the great bulk of EU funding, and the majority of total EU spending. New objectives have been defined for the current programmes, which run from 1 January 2007 to 31 December 2013. The overall budget for this period is €347bn: €201bn for the European Regional Development Fund, €76bn for the European Social Fund, and €70bn for the Cohesion Fund.

In July 2004 the European Commission adopted its legislative proposals on the reform of the cohesion policy for the budgetary period, 2007-13. Within this and through the Cohesion Fund, a specific budget for investment in both energy efficiency and renewable energy was

19 European Commission (2002): Staff Working Paper Inventory Of Public Aid Granted To Different Energy Sources. , December 2002, page 121. It must be noted that the figure used for renewables is less than that quoted in the same report on page 50, which estimates the renewables expenditure during this period to be €487 million.

established.20 The anticipated budgets are seen below and show how much the shift has taken place to support the development of renewable energy and energy efficiency.

Table 3.2 summarises the major direct expenditure by the EU for energy, including transport issues. As can be seen transport expenditure dominates the major EU sources of funding, the structural funds and the loans from the EIB. The transport sector receives eight times more funding from structural funds than energy and three times more from the EIB. The transport sector in fact receives nearly one quarter of all structural funds.

Table 3.2 Summary of Direct EU Influence on Energy Expenditure and Pricing (Source: European Commission21)

Technology Type of Programme Dates Total Annual support (€million) (€million) Grants Energy Networks Grant Structural and Cohesion funds 2007-2013 675 112 Renewables Grant Structural and Cohesion funds 2007-2013 4761 793 Energy Grant Structural and Cohesion funds 2007-2013 4272 712 Efficiency Other Grant Structural and Cohesion funds 2007-2013 1101 183 Transport Road Grant Structural and Cohesion funds 2007-2013 41000 5850 Rail Grant Structural and Cohesion funds 2007-2013 23600 3370 Urban Grant Structural and Cohesion funds 2007-2013 8100 1160 transport Ports and Grant Structural and Cohesion funds 2007-2013 4100 590 inland waterways Multi-mode Grant Structural and Cohesion funds 2007-2013 3300 470 transport Airports Grant Structural and Cohesion funds 2007-2013 1900 270

Networks Grant Recovery Plan 2009-2011 2365 1182 Offshore Wind Grant Recovery Plan 2009-2011 565 282 Coal – CCS Grant Recovery Plan 2009-2011 1050 525

Coal Grant ECSC 1952 – 2002 13,000 260 2003-2006 60 15 Energy Grant Energy Intelligent Europe 2008 10 10 Efficiency Renewables Grant EIE 2008 11 11 Transport Grant EIE 2008 13 13

Nuclear R&D Framework Programmes 1994-2013 8701 457 4-7 All non-nuclear R&D Framework Programmes 1994-2013 5959 313 energy 4-7 Transport R&D Framework Programme 7 2007-14 4100 585

Loans ENERGY

20 European Commission (2007): Cohesion policy: the 2007 watershed: Inforegio, Fact Sheet 2004: European Union Regional Policy.

21 European Commission (2007): Cohesion Policy 2007-13: Energy, DG Employment, Social Affairs and Equal Opportunity, DG Regional Policy. http://ec.europa.eu/regional_policy/themes/statistics/2007_energy.pdf

Technology Type of Programme Dates Total Annual support (€million) (€million) Gas Loan EIB 2006-2009 6981 1745 Oil Loan EIB 2006-2009 626 156 Renewables Loan EIB 2006-2009 6837 1709 Nuclear Loan EIB 2006-2009 886 221 Coal Loan EIB 2006-2009 1060 265 Nuclear Loan Euratom loans 1977-2009 3,420 N/A TRANSPORT Road Loan EIB 2006-2009 21416 5354 Rail Loan EIB 2006-2009 11576 2894 Sea Loan EIB 2006-2009 4509 1127 Air Loan EIB 2006-2009 5782 1145

3.5 Energy R&D

A comparison of government R&D expenditure on energy is provided by (IEA 2012). As noted in Section 2.6.1, funding for energy research in the UK increased dramatically between the mid-2000’s and 2010. Figure 16 indicates a similar trend (though not so extreme) in many IEA countries as interest in energy issues and concerns over energy security and the rise in energy prices rose over this period. R&D expenditure in the UK shifted from being amongst the lowest of IEA countries (measure relative to GDP), to being the median level of expenditure.

Figure 16 Government R&D budgets across IEA countries

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Adler, P. S., M. Benner, D. Brunner, J. MacDuffie, E. Osono, B. Staats, H. Takeuchi, M. Tushman and S. Winter (2009). "Perspectives on the Productivity Dilemma." Journal of Operations Management 27(2): 99-113. Arrow, K. J. and G. Debreu (1954). "Existence of an Equilibrium for a Competitive Economy." Econometrica 22: 265-290. Birmingham (2012). THE FUTURE OF NUCLEAR ENERGY IN THE UK Birmingham Policy Commission, University of Birmingham. Blaug, M. (2007). "The Fundamental Theorems of Modern Welfare Economics, Historically Contemplated." History of Political Economy 39(2): 185-207. DECC (2011). Control Framework for DECC Levy-Funded Spending: Questions and Answers. https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/48244/32 90-control-fwork-decc-levyfunded-spending.pdf. DECC (2011). Waste Transfer Pricing Methodology for the disposal of higher activity waste from new nuclear power stations, Department of Energy and Climate Change. DECC (2012). Gas Generation Strategy, UK Department of Energy and Climate Change. DECC (2012). Nuclear third party liabilities to be increased sevenfold. Diekmann, J. and M. Horn (2007). Fachgespräch zur Bestandsaufnahme und methodischen Bewertung vorliegender Ansätze zur Quantifizierung der Förderung erneuerbarer Energien im Vergleich zur Förderung der Atomenergie in Deutschland Available online at: http://www.erneuerbare-energien.de/inhalt/39617 Available online at: http://www.erneuerbare-energien.de/inhalt/39617, Auftrag des BMU. Donohue, M. (2008). Environmentally Harmful Subsidies in the Transport Sector. Paris, OECD. OECD Document No. ENV/EPOC/WPNEP/T. EnergyFair (2012). Nuclear Subsidies. www.energyfair.org.uk. EU (2013). Commission Staff Working Document: EU Decommissioning Funding Data. Brussels. SWD(2013) 59 final. Fouquet, D. (2012). Prices for Renewable Energies in Europe: Report 2011-2012 European Renewable Energies Federation. Greenpeace (2011). Subsidy Assessment of Waste Transfer Pricing for Disposal of Spent Fuel from New Nuclear Power Stations GSI (2010). Fossil Fuels – At What Cost? Government Support for Upstream Oil Activities in Three Canadian Provinces: Alberta, Saskatchewan, and Newfoundland and Labrador. Geneva, Switzerland, International Institute of Sustainable Development. GSI (2010). Fossil Fuels – At What Cost? Government Support for Upstream Oil and Gas Activities in Indonesia. Geneva, Switzerland, International Institute for Sustainable Development. GSI (2010). Subsidy Estimation: A survey of current practice Geneva Switzerland, International Institute for Sustainable Development.

GSI (2010). Tax and Royalty-Related Subsidies to Oil Extraction from High-Cost Fields: A Study of Brazil, Canada, Mexico, United Kingdom and the United States. Geneva, Switzerland, International Institute for Sustainable Development. GSI (2012). Fossil Fuels - At What Cost? Government Support for Upstream Oil and Gas Activities in Norway. Geneva, Switzerland, International Institute of Sustainable Development. IEA (1999). World Energy Outlook: Looking at Energy Subsidies, getting the prices right. Paris, International Energy Agency. IEA (2012). Energy Policies of IEA Countries: The United Kingdom 2012 Review. Paris, International Energy Agency. IEA, OPEC, OECD and W. BANK (2010). ANALYSIS OF THE SCOPE OF ENERGY SUBSIDIES AND SUGGESTIONS FOR THE G-20 INITIATIVE Joint Report Prepared for submission to the G-20 Summit Meeting Toronto (Canada) IMF (2013). Case studies on energy subsidy reform: Lessons and implications. http://www.imf.org/external/np/pp/eng/2013/012813a.pdf, International Monetary Fund. IMF (2013). Energy Subsidy Reform: Lessons and Implications. http://www.imf.org/external/np/pp/eng/2013/012813.pdf, International Monetary Fund. Koplow, D. (2009). Measuring energy subsidies using the price-gap approach: what does it leave out?, International Institute for Sustainable Development. Lipsey, R. G. (2007). "Reflections on the general theory of second best at its golden jubilee." International Tax and Public Finance 14(4): 349-349. Lipsey, R. G. and K. Lancaster (1956). "The General Theory of Second Best." The Review of Economic Studies 24(1): 11-32. Lucas, D. (2010). Measuring and Managing Federal Financial Risk, University of Chicago Press. Lucas, D. (2012). "Valuation of Government Policies and Projects." Annual Review of Financial Economics 4: 39-58. NAO (2012). Managing risk reduction at Sellafield: REPORT BY THE COMPTROLLER AND AUDITOR GENERAL, National Audit Office. OECD (2010). Measuring Support to Energy. OECD (2012). Inventory of Estimated Budgetary Support and Tax Expenditures for Fossil Fuels 2013. Paris, OECD Publishing OECD (2013). Taxing Energy Use: A Graphical Analysis. Ofgem (2012). Feed-in Tariff Quarterly Report. Issue 10. Portal, E. "Europe's Energy Portal." Retrieved 27 March 2013, 2013. Sander, M., J. (2009). Justice. London, Penquin Books. Schneider, M., A. Froggatt and J. Hazemann (2012 ). World Nuclear Status Report. Paris, London. Schumpeter, J. (1942). Capitalism, Socialism and Democracy. New York, Harper & Row.

Sen, A. (2001). Development as Freedom. Oxford, Oxford University Press. Thomas, S. (2004). The UK Nuclear Decommissioning Authority, Public Services International Research Unit UCS (2011). NUCLEAR POWER: Still Not Viable without Subsidies Union of Concerned Scientists. UK (2010). The Feed-in Tariffs (Specified Maximum Capacity and Functions) Order 2010 No. 678. UK (2012). The Feed-in Tariffs (Specified Maximum Capacity and Functions) (Amendment No. 2) Order 2012 No. 1393. http://www.legislation.gov.uk/uksi/2012/1393/pdfs/uksi_20121393_en.pdf, UK Government Statutory Instruments. Valsecchi, C., P. ten Brink, S. Bassi, S. Withana, M. Lewis, A. Best, F. Oosterhuis, C. Dias Soares, H. Rogers-Ganter and T. Kaphengst (2009). Environmentally Harmful Subsidies: Identification and Assessment Final report for the European Commission’s DG Environment, November 2009 WorldBank (2010). Subsidies in the Energy Sector: An Overview Background Paper for the World Bank Group Energy Sector Strategy. Washington, World Bank.

17 April 2013

Letter received by Bryan Norris from DECC, 11 June 2012

Dear Mr Norris Freedom of Information Request Thank you for your email dated 11 May 2012 in which you requested information regarding decommissioning tax relief. We have now completed our search for the information you requested. The information which can be disclosed is given below. The remainder of the information is exempt under section 35(1) of the Freedom of Information Act and is therefore withheld. 1. How many oil and gas rigs will be decommissioned with taxpayers money? There are currently 291 oil and gas platforms in the UKCS. The total cost of decommissioning these plus pipelines, wells and other subsea infrastructure is currently estimated to be around £30 billion in today's money, spread over the next 40 years or more. 2. How many oil rigs are involved. Please refer to the answer for question 1. 3. What is the total budget for this subsidy? The Government is not offering a subsidy to the Oil and Gas industry for decommissioning expenditure. Budget 2012 announced a consultation on new contracts to provide long term certainty on decommissioning tax relief; this consultation will be published this year. The Exchequer impact of this policy is beneficial to the taxpayer in receipts, driven by an increase in investment and production. Companies are legally required to decommission their assets at the end of a field’s life. The total cost of decommissioning upstream petroleum infrastructure is currently estimated to be about £30 billion in today's money. Tax relief at a rate of 50% (75% for older fields) is available on these costs of business, but uncertainty around the future availability of such relief has been deterring investment in older fields and making it difficult for new players to enter the market. At Budget 2011, the Government said that it would work with industry with the aim of announcing further, longer-term certainty on tax relief for decommissioning costs. The Government has already committed to provide relief; greater certainty will generate additional investment and production. The Government will legislate in 2013 giving it the power to sign contracts with oil and gas companies guaranteeing that they will receive a certain level of relief on the cost of decommissioning their assets. We will consult on the detail and form of the contracts in the coming months. Costings The Office for Budget Responsibility (“OBR”) scrutinised the assessment of the Exchequer impact. This can be found at: http://cdn.hm-treasury.gov.uk/budget2012_policy_costings.pdf The measure is expected to increase investment and production, and thus Exchequer revenues, by encouraging increased incremental activity and improving market efficiency in the UKCS, leading to asset trades, stimulated by certainty over the tax treatment of decommissioning costs. The size of this change in investment and production is estimated using HMRC modelling and the relevant determinants from the OBR’s economic forecast. These estimates are consistent with consultation work to date. 58

Exchequer impact (£m) The Exchequer impact has been projected as follows. 2012/12 2013/14 2014/15 2015/16 2016/17 Exchequer impact (£m) -115 +245 +385 +340 +290 (Positive figures denote Exchequer yield) Appropriate oversight and analysis will continue with the NAO and OBR, following consultation. 4. Has the National Audit Office been made aware of such new extended subsidy? If so what is their judgement? Please refer to the answer for question 3. 5. What is the independent auditors advice on value for money for UK taxpayers and Total exposure? Please refer to the answer for question 3. 6. What checks have been enacted to prevent corruption? The decommissioning process is open and transparent, operators are required to submit decommissioning programmes which are subject to wide ranging scrutiny by DECC, other government departments and statutory consultation with public bodies before approval to decommission is granted. On completion of a decommissioning programme operators submit a ‘close out report’ summarising the outcome of the decommissioning activity – these close out reports are also subject to scrutiny. Copies of draft and approved decommissioning programmes are published on DECC’s website and can be found at: http://og.decc.gov.uk/en/olgs/cms/explorationpro/decommissionin/ decommissionin.aspx 7. With the oil industry receiving extra large tax breaks for oil exploration, please identify total positive tax receipts minus subsidies and losses and ‘contractual arrangements’. Please refer to the answer for question 3. 8. Please supply details of ALL contracts concerning taxpayer decommissioning of North sea oil rigs. Please refer to the answer for question 3. 59

Written evidence submitted by Calor Gas Ltd

“The fact is, thousands and thousands of our customers have already taken advantage of this amazingly generous subsidy and are enjoying the many benefits.”

Solar Fusion Ltd leaflet, distributed to homes, 2013.

EXECUTIVE SUMMARY

1. Subsidy to wind has been on a rising trend since 1991: the annual subsidy will reach £5bn in 2020 – this subsidy burden is ultimately borne by households. Subsidising an industry for 30 years leads to a dependent and vulnerable industry rather than a commercially viable industry. Denmark has found that subsidy to wind creates no net jobs, has depressed its GDP and has distorted its economy away from more profitable sectors.

2. Wind is an intermittent technology with an unfortunate tendency not to deliver during the coldest weather. It has to be backed up 80% by fossil fuel power, and thus embeds a significant need for fossil fuel generation for decades to come. The Government has made no calculation of the cost of installing this back‐up power.

3. Wind‐power from offshore is double the cost of cheaper, alternative means. Its subsidy costs the economy far more than the value of the carbon it saves. The Government recognises significant negative environmental negatives from wind, and these need to be added to the debit side of the balance sheet.

4. Subsidy to biomass is likely to surge as biomass capacity is likely to at least double from 2012 levels. 92% of RHI accredited installations are biomass boilers, and RHI installations with their accompanying subsidies are rapidly rising, too.

5. Biomass increases carbon emissions in the short to medium term – conditions are unlikely to be met for it ever to repay its own carbon debt, even after 90 years.

6. The demand for wood in UK biomass is met mainly by imports, increasing our reliance on third parties, worsening the trade balance, and causing enormous loss of habitat abroad. 60

7. RSPB, Friends of the Earth and Greenpeace calculate that Drax biomass power station alone will be getting a subsidy of £550m a year by 2016 from the taxpayer. At that rate, it costs £225 to save one tonne of CO2 – three times the computed social cost of the carbon.

8. Government made the assumption that there are no net emissions from biomass production. In fact, the drying process alone causes high energy consumption with a high environmental impact. DECC has acknowledged, however, negative environmental effects, including on climate change and air quality, of increased transportation throughout the lifetime of a biomass facility. Government does not know how much black carbon – a potent global warming factor – is emitted by biomass combustion.

9. Particulates emitted to air cost an associated loss of total population life of 340,000 life‐years, a greater burden than the mortality impacts of environmental tobacco smoke or road traffic accidents; under the previous Government’s targets for biomass this loss of life would have been doubled. The social costs of early death and disease to be caused annually by biomass are now calculated at £1399m. Householders are paying subsidy to have their lives significantly shortened. Other poisons are emitted to air, including tonnes of arsenic and hexavalent chromium (of Erin Brokovich fame). This will add to the external costs of biomass.

10. Subsidy to heat pumps is set to rise significantly when RHI payments for the technology begin in 2014 for domestic households.

11. Tests to date on installed heat pumps show most failing the test of sustainability. Failures would not count towards our renewables target and could either completely waste or forfeit subsidy. Most heat pumps when installed do not do what it says on the tin.

12. Heat pumps are highly consumptive of electricity. Large scale installation of pumps would mean having to reinforce the grid at great cost. For instance, by 2030, each heat pump in a rural area could cause extra reinforcement costs of up to £1,130 – another cost to be heaped upon the shoulders of electricity consumers, and this for a technology that so far does not work in most cases.

13. DECC does not know the total of subsidy devoted to renewables so neither the Department nor the Public Accounts Committee can do a study to ascertain whether the subsidy is good value for money.

14. Total subsidy to renewables over the period to 2030 has been calculated by a third party at £130bn – this cost will be paid through fuel bills. Is this supportable in an age of austerity, where some 4.5 million families are already in fuel poverty?

15. The total cost of renewable energy policies (subsidy plus extra network costs) is about £175bn by 2030. Will the value of carbon saved by 2030 be worth over £175bn because if not the policy is fatally flawed?

1. The subsidy to wind is rising to insupportable levels

1.1. The original intent was that subsidy would be degressive as wind approached commercial viability. The opposite has been the case ‐ subsidy has been on a rapidly rising trajectory. In 1990/2000 total subsidy to wind was £7.3m (WA, 28.2.11, col. 244W). £2.2bn was spent in subsidy to wind between April 2002 and March 2010 (WA, 11.2.2011, col. 457W). Subsidy to wind will rise to £5bn in 2020 (WA, 4.7.2011, col. 1072W). If after thirty years of rising subsidy the industry remains commercially unviable it is never likely to be commercially viable.

1.2. The day‐ahead wholesale electricity price averaged approximately £50/MWh in June 2011, according to the London Energy Brokers Association. The level of renewables obligation support available to onshore wind farms is one renewables obligation certificate (ROC) per MWh of electricity generated, and that available to offshore wind farms is two ROCs per MWh. The expected value of a ROC is constant over time at around £43 in 2011‐12 prices (WA. 4.7.2011, col. 1073W). Thus, for offshore wind the total level of subsidy is 172% of what it costs to generate electricity on a commercial basis.

1.3. The cost of wind power from the consumer’s perspective is not simply the basic cost of generation, plus the subsidy (paid by the consumer) but also the cost of integrating wind into the grid (also ultimately paid by the consumer). The cost of integrating wind comprises three elements – system operation costs of £16/MWh caused by errors in wind forecasting; transmission upgrade costs of £20‐23/MWh to move the energy from wind farms to load centres; and, a planning reserve costing some £24‐28/MWh to keep conventional plant running at a reduced load factor ready to pick up on wind’s incapacity to deliver on windless days (Source: Colin Gibson, “A Probabilistic Approach to 62

Levelised Cost Calculations” 2011). So, the system cost from the consumer’s perspective totals £190/MWh for onshore wind and £270/MWh for offshore wind. In contrast, a combined cycle gas plant generates at £66/MWh.

1.4. Households pay approximately 40% of the Renewable Obligation costs. The remaining 60% of the RO cost imposed on industry, commerce and the public sector is ultimately paid for by households in terms of increased costs of goods, services and taxes.

2. The cost of subsidising wind is far more than the cost of the carbon it saves

2.1. What is the cost‐benefit analysis of subsidising wind? Its supporters say that it reduces carbon emissions. In 2002, the UK Government Economic Service recommended an estimate for the social cost of carbon at £70/tonne of carbon for use in policy appraisal across Government. The Renewable Energy Foundation (REF) has found that onshore wind costs £93/MWh to remove a tonne of carbon from emissions and offshore wind £185 per tonne. On this basis, wind costs more to society than the carbon it displaces – and in economic terms, offshore wind costs our economy far more than double the carbon it is meant to displace.

3 .DECC knows full well about the “severe negative” environmental effects of wind

3.1. DECC itself has enumerated the environmental negatives of wind. Paras. 3.24ff of the “Appraisal of Sustainability for the revised draft NPS for Renewable Energy Infrastructure: Non‐Technical Summary” (DECC, October 2010) can be summarised ‐the construction of wind farms has a negative environmental effect; this impact could be severely negative when wind farms are close together; offshore wind farms could have a severely negative impact on international navigation routes; noise disturbance can be a hazard for humans and fauna and the disturbance lasts for 25 years; the visual effects could be significant and would last 25 years; where wind farms are clustered the impact will be cumulative; and, clustered wind farms offshore may result in increased flooding of the coast.

4. Wind, far from creating jobs, may have a negative effect on GDP

4.1. UK Government support is posited on the kit lasting 25 years. But, “Wind Energy – the Case of Denmark” CEPOS, September, 2009 found that, “Many ten to fifteen year‐old turbines are past their useful life”. This puts into question the strategic, economic and environmental benefits of a power plant that may have to be scrapped, replaced and resubsidized every ten to fifteen 63

years. On the plus side, then, the negative environmental effects listed by DECC may last 10 to 15 years less than expected, but conversely subsidised plant which lasts half as long as expected will produce a lot less electricity, a lot more expensively over its lifespan.

4.2. The Danes have subsidised wind power since 1988, and in 2007 generated 19% of their demand by wind turbines. They are further along the curve than we are. CEPOS concluded:

“The Danish Wind industry counts 28,400 employees. This does not, however, constitute the net employment effect of the wind mill subsidy. In the long run, creating additional employment in one sector through subsidies will detract labor from other sectors, resulting in no increase in net employment but only in a shift from the non‐ subsidized sectors to the subsidized sector… The subsidy per job created is 600,000‐ 900,000 DKK per year ($90,000‐140,000). This subsidy constitutes around 175‐250% of the average pay per worker in the Danish manufacturing industry.

In terms of value added per employee, the energy technology sector over the period 1999‐2006 underperformed by as much as 13% compared with the industrial average. This implies that the effect of the government subsidy has been to shift employment from more productive employment in other sectors to less productive employment in the wind industry. As a consequence, Danish GDP is approximately 1.8 billion DKK ($270 million) lower than it would have been if the wind sector work force was employed elsewhere.”

4.3. Evidence from the UK so far strengthens these concerns. In the period 2002‐2010 the UK spent £5 billion subsidising dedicated renewable electricity generators, at a cost of £230,000 per wind industry worker over that period. Subsidy per wind industry worker in the year 2009/10 amounted to £54,000 ‐ greatly in excess of the median earnings in either the public (£29,000) or the private sectors (£25,000) (Source: “The Green Mirage” by John Constable, August 2011). While it is not yet possible to estimate the net employment impacts of such costs, they are unlikely to be positive.

5. Wind is intermittent and inherently unreliable especially in the depth of Winter

5.1. The UK Renewables Strategy 2008 was frank about wind:

“3.9.4 Analysis of wind patterns suggests that, at high penetration levels in the UK, wind generation offers a capacity credit of about 10‐ 20%. This is an indicator as to how much of the capacity can be statistically relied on to be available to meet peak demand and compares to about 86% for conventional generation. This means that controllable capacity (for example fossil fuel and other thermal or hydro power) still has to be available for back‐up at times of high demand and low wind output, if security of supply is to be maintained. New conventional capacity will, therefore, still be needed to replace the conventional and nuclear plant which is expected to close over the next decade or so, even if large amounts of renewable capacity are deployed…

3.9.6 In the British market electricity generating capacity does not earn money simply for being available; it earns money only when it actually generates. This is consistent with striking the optimal balance between costs and benefits of spare capacity on the system. It also means that wholesale electricity prices are likely to rise to very high levels at times when high demand and low wind speeds coincide. This is necessary in order to cover the costs of plant which does not get to generate very often, and so ensure that generators are incentivised to provide back‐ up capacity.

3.9.7 It is nevertheless possible that uncertainty over returns on investment, because of the difficulty of knowing how often plant will get the opportunity to run, will discourage or delay investment in new conventional capacity – or speed up the closure of existing capacity – and hence increase the risk of occasional capacity shortfalls.”

5.2. The Revised Draft NPS on Energy accepts this argument: “An increase in renewables will therefore require additional back‐up capacity and mean that we will need more total electricity capacity than we have now” (Para.3.3.11).

5.3. Put more plainly, every 10 new units worth of wind power installation has to be backed up by what are likely to be 8 new units worth of fossil fuel generation, because fossil fuel can and will have to power up suddenly to meet the deficiencies of wind. Wind does not provide an escape route from fossil fuel but embeds the need for it. Nuclear runs at base load and cannot power up to cover the absence of wind. If fossil fuel plant has to be constructed and stand by waiting for wind to default then its power will have to be more expensive in order for the plant to “wash its face”. So, the effect of having a large investment in wind is to drive up the price of power generally. Surprisingly, Government has not worked out the costs: “The Department has 65

not provided estimates of the cost of constructing fossil fuel power stations to compensate for intermittency in the period out to 2030” (WA 9.2.2011, col. 356W).

5.4. The Daily Telegraph reported on 11th January 2010 that out of a UK capacity of 5% wind was delivering 0.2% during the January cold spell. The wind was not blowing when most needed. Andrew Horstead, a risk analyst for energy consultant Utilyx, commented: “This weekʹs surge in demand for energy in response to the cold weather raises serious concerns about the UKʹs increased reliance on wind power…Failure to address these concerns could mean further rationing of energy in future years and could even lead to black‐ outs, so it is vital that the UK Government takes action now to avoid the lights going off,ʺ (ibid.) The poor performance of wind in January 2010 was echoed in the cold snap of December 2010: The Times of 3rd January 2011 reported that since the beginning of December turbines had been operating at only 20% of their capacity – on 2nd January wind was contributing but 0.5% of the country’s power. At the coldest times of year then, wind power has an unfortunate tendency to make itself unavailable.

5.5. Low wind conditions can prevail at times of peak load over very large areas and that low wind load factors in other European countries can coincide at exactly the same time – a European Supergrid may not be able to solve such problems. Wind power can be highly variable year on and back‐up conventional generators will not only have uncertain income over shorter timescales, but will face significant year on year variations – all this forces up energy costs for the hard‐pressed consumer.

SUBSIDY AND BIOMASS

6. Subsidies to biomass are rising fast

6.1. The value of subsidy given to biomass generation in 2010‐11 was £370 million (WA, 29.6.11, col. 850). This subsidy is on a rising trend as well. 92% of Renewable Heat Incentive payments are for solid biomass boilers. RHI applications and installations are rising rapidly. For large scale electricity generation by biomass dedicated regular biomass generation receives 1.5 ROCs/MWh, while ʺadvanced conversion technologiesʺ (gasification, pyrolysis and anaerobic digestion), dedicated biomass burning energy crops, and dedicated regular (non‐energy crop) biomass with CHP all receive 2 ROCs/MWh. Installed capacity of plant biomass and co‐firing in 2012 was 1,399MW but this figure – and the pertinent subsidy – is due to rise significantly (3,812MW of biomass capacity have been approved in the planning system). 66

7. Biomass emits more GHGs than fossil fuels; its carbon debt is unlikely to be repaid

7.1. The purported benefit from subsidising biomass is reducing carbon emissions. The UK regards biomass as “zero carbon” yet defines it as sustainable if it makes GHG savings of 60% over fossil fuels: “These sustainability criteria include a minimum greenhouse gas emissions saving of 60% compared to fossil fuel” (WA, 20.1.11). It does not need an advanced arithmetical or logical mind to recognise that a 60% reduction in emissions from fossil fuel levels is not and cannot be regarded as “zero‐carbon”. This is a logical somersault too far, conveniently ‐ for the sake of cherry picking this technology ‐ equating 40% to 0%! However, doubts about the true sustainability of biomass go much further.

7.2. In 2010, a Manomet report for the Commonwealth of Massachusetts (Biomass Sustainability and Carbon Policy”, June 2010) acknowledged, “Growing concerns about greenhouse gas impacts of forest biomass policies” and quoted the IEA report “Bioenergy (2009): “Conversion of land with large carbon stocks in soils and vegetation can completely negate the climate benefit of the sink/bioenergy establishment”. The UK Environment Agency is alert to this danger: using biomass for generating electricity and heat could help meet the UK’s renewable targets but “only if good practice is followed…worst practice can result in more greenhouse gas emissions overall than using gas (“Biomass – carbon sink or carbon sinner?” April 2009).”

7.3. Manomet discussses the varying rates by which regrowing forests repay the carbon debt incurred by their removal and combustion: burning biomass emits more greenhouse gases than fossil fuels: “Forest biomass generally emits more greenhouse gases than fossil fuels per unit of energy produced. We define these excess emissions as the biomass carbon debt. Over time, however, re‐growth of the harvested forest removes this carbon from the atmosphere, reducing the carbon debt…Over a long period of time, biomass harvests have an opportunity to recover a large portion of the carbon volume removed during the harvest. However, this assumes no future harvests in the stand as well as an absence of any significant disturbance event. Both are unlikely.” Recovering the carbon debt is a gamble, and it seems strange to be cracking open these cheap and natural stores of carbon while at the same time investing billions of pounds in trying to create as yet unproven carbon capture and storage technologies.

7.4. A report supported by the DG Development and DG Environment of the European Commission (ʺFlows of biomass to and from the EUʺ, July 2011) concluded: “Analysis of the data and trade statistics looked at in this report shows that the quantity of wood required to satisfy the 2020 targets is likely to 67

be too large to be met by increased production within the EU…Most of the increase in imports will therefore most likely come from Canada, the USA, and perhaps also Russia (if the risks associated with imports from Russia do not become prohibitive when the EU’s Illegal Timber Regulation is fully implemented in 2013). This risks not only damaging ecosystems in other parts of the world, but will also increase the EU’s own carbon footprint”.

7.5. DECC admits that, “The UK is expected to be increasingly reliant on biomass imports in the future” – this for a commodity that was once vaunted as decreasing our reliance on third parties. Unfortunately, HMG does not know how much wood is being imported for biomass combustion (WA, 1.12.2010, col.801W). We do know, however, that imports are increasing very fast: imports of wood pellets into the EU rose by 50% in 2010 alone (The Economist 6th April, 2013) and that DECC itself expects that approximately 80% of feedstock to come from imports. The RSPB, Friends of the Earth and Greenpeace conclude: “Demand for wood, for electricity generation, will therefore add to the existing trade imbalance” (“Dirtier than Coal?” by RSPB, Friends of the Earth and Greenpeace 12th November 2012).

7.6. The EEA Scientific Committee on Greenhouse Gas Accounting states that the assumption that burning biomass is carbon neutral is incorrect: “Using land to produce plants for energy typically means that this land is not producing plants for other purposes, including carbon otherwise sequestered.” If biomass production replaces forests, reduces forest stocks or forest growth, which would otherwise sequester more carbon, it can increase carbon concentrations net. If biomass displaces food crops – as biofuels did – this leads to hunger if crops are not replaced, and to emissions from land use change if they are. To reduce carbon in the air, the Committee concludes, bioenergy production must increase the net total of plant growth, or it must be derived from biomass wastes that would otherwise decompose. The Committee warns that the danger of this error is “immense”. It states, “Current harvests…have already caused enormous loss of habitat by affecting perhaps 75% of the world’s ice and desert free land, depleting water supplies and releasing large amounts of carbon into the air” (“Opinion of the EEA Scientific Committee on Greenhouse Gas accounting in Relation to Bioenergy, 15th September, 2011).

8. As with wind, biomass subsidy costs more than the carbon it purports to displace

8.1. The RSPB, Friends of the Earth and Greenpeace comment that DECC’s flawed emission accounting on biomass has led to a situation where, “Burning whole trees in power stations would make global warming worse, undermining goals of reducing our greenhouse gases by 2050”. On that basis 68

they call for the withdrawal of public subsidies for generating electricity from feedstocks derived from tree trunks and to refocus support for bioenergy on the use of wastes and other feedstocks that are harvested sustainably. We agree. At a subsidy of £45 per MWh, it has been calculated that Drax, just one power station in the UK will be getting a subsidy of £550m a year by 2016 from the taxpayer. At that rate, it costs £225 to save one tonne of CO2 (“Dirtier than Coal”, op.cit.). Even DECC has admitted: “Compared to offshore wind dedicated biomass electricity is a costly way of saving carbon,” (“Renewables Obligation: Consultation on a notification process for new build dedicated biomass projects”, May 2013). This is saying something because as already pointed out in para. 2.1. offshore wind costs our economy far more than double the carbon it is meant to displace.

9. Biomass emissions during production are underestimated

9.1. The “UK Biomass Strategy” (2007, p.41) made a blasé and dangerous ‐ assumption: “For all biomass resources no net emissions during production assumed”. All the emissions produced during planting, harvesting, sawing up, drying and delivery of these bulky and heavy items are ignored. E4Tech’s study on biomass prices for DECC (“Prices in the heat and electricity sectors in the UK”, January 2010) makes the assumption that for the wood pellet imports there would be 50km of road transport necessary for production purposes, 200km of road transport necessary in the country of origin, sea transport of 1500km and 50km of road transport necessary in the UK. This cannot be written off as equating to “no net emissions”. The Environment Agency pointed out (“Biomass – carbon sink or carbon sinner?” op.cit.): “How a fuel is produced has a major impact on emissions: transporting fuels over long distances and excessive use of nitrogen fertilisers can reduce the emissions savings made by the same fuel by between 15 and 50% compared to best practice”.

9.2. Besides, and probably more importantly, biomass has to be dried before combustion can take place. Environmental emissions result from both the drying process and combustion in the boiler. These emissions typically include particulates, VOCs, and NOx to the extent that a common problem around biomass drying plant is so called noxious “blue haze”. “Biomass and Bioenergy” confirms that, “Forest residues require a drying stage, which involves high energy consumption and high environmental impact” (Volume 34, Issue 10, October 2010, pp. 1457‐1465). The pollution caused by these emissions should be calculated and factored into policy.

10. DECC knows full well about negative environmental effects of biomass “in the short, medium and long term” 69

10.1. The revised Draft NPS for Renewable Energy documents (December 2011) also revealed the damage to the environment likely from “considerable” transport movements: “Depending on the location of the facilities, air emissions and dust, which could impact sensitive flora, may also be increased through the high number of heavy goods vehicles transporting fuel and combustion residues” (p25). “There are potential negative environmental effects, including on climate change and air quality, of increased transportation throughout the lifetime of the facility…The overall effect of implementation on traffic and transport of biomass/waste combustion through the implementation of EN‐3 is considered to be negative in the short, medium and long term. These effects are primarily from the movement of fuel and residue during the operational phase of the facility, although some significant, short term, local negative effects may result from the movement of component parts to the facility during construction” (p.39/40). The Revised Draft National Policy Statement for Renewable Energy Infrastructure (EN‐3) admits some of this environmental damage: “Biomass or EfW plants are likely to generate considerable transport movements. For example, a biomass or EfW plant that uses 500,000 tonnes of fuel per annum might require a minimum of 200 heavy goods vehicles (HGVs) movements per day to import the fuel. There will also be residues which will need to be regularly transported off site” (para.2.5.22).

11. We should measure and control emissions of black carbon and isoprene from biomass before we deem it sustainable

11.1. We need to adopt a precautionary principle in relation to the emissions of black carbon (BC) from biomass. BC is part of the particulate emissions caused by combustion. BC is the second largest contributor to global warming after CO2. The UN’s Economic Commission for Europe found that, “Urgent action to decrease (black carbon) concentrations in the atmosphere would provide opportunities, not only for significant air pollution benefits (e.g. health and crop‐yield benefits), but also for rapid climate benefits, by helping to slow global warming and avoid crossing critical temperature and environmental thresholds” (UNECE’s Executive Body for the Convention on long‐range transboundary air pollution, meeting in Geneva, 15‐18 December 2008: Item 13 of provisional agenda). The possibility that biomass could potentially contribute significantly to global warming by emissions of BC would be perverse indeed.

11.2. The Government does not know how much black carbon is emitted, or potentially emitted specifically by burning biomass in the UK, nor has it assessed how international control measures in the pipeline on black carbon might undermine the principle of subsidizing biomass combustion (WA, 4.5.2011: Col. 782W) . It should remedy these black holes of knowledge.

12. Biomass combustion leads to early death and illness on a significant scale

12.1. Biomass combustion can kill people. The particulates it emits damage human health by attacking lungs, hearts and brains. The latest Public Health Observatory data puts the percentage of total mortality attributable to particulates in England at 5.6%. What part of that can be attributed to biomass? We can work out the damage in terms of lives shortened and lost from an Impact Assessment published by DECC on new standards designed to cut down on the current level of mortality from biomass combustion. The quantum of mortality caused by biomass boilers currently being sold can be calculated from the assessment at £4343m. The new limits will, if implemented, cut this reduction in life years to an equivalent of £1399m. However, the new limits apply only to the larger particulates, and evidence is growing that the smaller particulates are more harmful than the large. No sum of the mortality caused by smaller particulates from biomass has been given. One must assume nonetheless that the impact from these smaller particulates in reducing human life‐spans will be considerable.

12.2. The Committee on the Medical Effects of Air Pollution estimated that the 2008 burden level of particulates cost an “associated loss of total population life of 340,000 life‐years…a greater burden than the mortality impacts of environmental tobacco smoke or road traffic accidents” (“The Mortality Effects of Long‐Term Exposure to Particulate Air Pollution in the United Kingdom” December 21st 2010). Remarkably, this figure is exactly the level of extra burden of mortality to have been inflicted on the UK atmosphere by 2020 under the previous Government’s policy on biomass, with its target of 38TWh by that date. No wonder Government has resiled from a specific target. The last Labour Government was aware biomass boilers deteriorate as they age so proposed an annual MOT test on domestic biomass boilers – all mention of such an annual MOT test on boilers has since been dropped.

12.3. A rising output of particulates from biomass will add to our problem in complying with the EU air quality limits. Current UK emissions of particulates are acknowledged by the Government to be “relatively high” and could cause rack up fines for the UK’s infringements. The Government calculates that over 3,500t of larger particulates will be emitted to air in 2020 from biomass – a self‐inflicted injury subsidised by the taxpayer, because without deliberate policy cherry picking of this technology and without significant subsidy mass generation of electricity from biomass would not be viable.

12.4. Biomass combustion also releases a wide variety of other pollutants into the air that we breathe. Non domestic burning of biomass emitted in 2010 71

160t of chromium, 130t of arsenic, and 16t of hexavalent chromium (WA, 23.5.2012.). Arsenic is poison: chromium and hexavalent chromium are carcinogenic (the latter being of Erin Brockovich fame). These figures will rise as more biomass capacity comes on stream, and the related morbidity and mortality toll will rise. We suspect that a location near a biomass plant will reduce the value of the housing concerned.

SUBSIDY AND HEAT PUMPS

13. Subsidy to heat pumps is set to rise

13.1. Subsidy is currently provided to householders who install an air source heat pump (ASHP) at the rate of £850 per installation; and at a rate of £1,250 for householders who install a ground source heat pump (GSHP). Renewable Heat Incentive payments for operating these systems are scheduled for introduction in domestic premises from next year at an indicative rate of 6.9‐ 11.5p/KWh for ASHPs and of 12.5‐17.3p/KWh for GSHPs.

14. Too often, heat pumps when installed fail to deliver value for money

14.1. The key to whether heat pumps deliver value for money or not is the Coefficient of Performance (CoP) of the heat pumps in the field. Heat pumps extract heat from the ground or air and redirect the heat for space heating and hot water. CoPs represent the ratio of heat produced per unit of electricity consumed in generating that heat. A CoP of 3 means that 3kWh of heat are output for 1kWh of electricity used to run the pump. Higher CoP values represent relatively more efficient heat delivery. Heat pumps must achieve a CoP of 2.9 before their energy can contribute to the renewable energy target. Note that even with CoPs of 2.9 the carbon footprint of heat pumps will be higher than the fossil fuel, natural gas, so the UK taxpayer will be paying to incentivise the expensive and disruptive installation of a technology that is more polluting than a widely used fossil fuel.

14.2. A study of installed heat pump performance published by the Energy Saving Trust on the 8th September 2010 – “Getting Warmer: a field trial of heat pumps” revealed that the actual performance of heat pumps installed in the UK was surprisingly poor. The study was financed by the heat pump industry and based on a sample of sites where pumps had been installed pre‐ selected by the industry. The pumps were installed and accredited through the Microgeneration Certification Scheme’s immediate predecessor, the Clear Skies programme. The study showed that only 1 of the 22 properties with Ground Source Heat Pumps (GSHPs) achieved the implicit minimum EU Directive CoP, and only 9 of the 47 sites with ASHPs achieved the standard. REF commented on this report: “The risk of premature adoption and 72

consumer disenchantment is clearly real, thus raising the spectre of a UK heat pump tragedy… On the basis of this study, there seems a distinct risk that some heat pumps will be subsidised even though they fail to meet the minimum standard for being considered a renewable energy source. If, on the other hand, government withdraws subsidies from such installations, well‐ meaning householders may discover after investing heavily in a heat pump that their installations fail to come up to the required EU standard, and thus forfeit entitlement to RHI payments” (“Renewable Heat Initiative”, September 2010).

14.3. Something similar occurred during the Joseph Rowntree Foundation study in Elm Tree Mews in York where a communal ground source heat pump was installed with a nominal design CoP efficiency of 3.2‐3.5. Despite a number of interventions, throughout the year of monitoring the delivered CoP efficiency was 2.15 – that is, it failed the renewable test of reaching a CoP of 2.9, and would not be good value for the householder, nor contribute towards national renewable targets. Potentially, expensive technology will have been installed under a false premise.

14.4. A report by the Association for the Conservation of Energy, “Improving the energy efficiency of off‐grid properties – the role of different heating technologies”, (March, 2011) made assumptions about the CoPs of heat pumps based on international data: “For GSHPs we assume a lower end CoP of 2.3 and a higher end CoP of 3.5. For ASHPs we assume a CoPs of 2.15 and 2.7 respectively”. On this basis all ASHPs would fail the test of being renewable since the qualifying bar for this is set by DECC at 2.9, and would not deliver savings towards the EU targets; some GSHPs would also fail.

14.5. The Building Services Research and Information Association (BSRIA) is the leading independent UK laboratory for testing, certification and performance verification of a wide range of building services products. Its website discusses the pros and cons of heat pumps: “Test conditions (and hence manufacturersʹ quoted CoP data) can therefore differ significantly from actual design and operating conditions”. This confirms the essential point that it is not enough to accept pre‐installation manufacturers’ quoted CoP data. BSRIA avert to manufacturers claiming impressive CoPs but say BSRIA, “This data should be treated with caution”.

14.6. The BSRIA website proceeds to make the point that heat pumps can struggle at the coldest times of year, and their CoPs can fall below the acceptable: “The relevant test standard for most packaged heat pumps is BS EN 14511. For an air‐to‐water heat pump the standard specifies test conditions of 7oC outdoor air temperature (source temperature). At external 73

air temperatures lower than this, the COP will fall, as will the heating output of the heat pump. Depending on the application this reduction may be significant, such as during a cold winter morning when building pre‐heat is needed”.

14.7. In England the average daily temperature is below 7°C in January and February; in Scotland, the average daily temperature is below 7°C in December, January, February and March. The risk is, then, that for substantial parts of the year, varying by location heat pumps will struggle to deliver heat when it is cold outside. Recent experience of cold Winters emphasises this point. Met Office statistics for December 2010 show mean temperatures for the UK of ‐1°C, ‐0.5°C for England, ‐ 0.4°C for Wales and ‐1.9°C for Scotland. Indeed, in 2010, Met Office statistics show the mean temperature for the year to be 8°C in England and 6.5°C in Scotland – note below the 7°C reference point on average for the whole year. Perhaps it should come as no surprise that ASHPs should not prove so efficient when installed in the UK as their comparative systems in warmer continental countries.

14.8. DECC is well aware of the problem: “We are aware that systems installed in the past have not always worked as well as they should” (Para. 199, DECC Consultation on the RHI, 20th September 2012) and again: “It is a common feature in field trials and assessments that there is a significant gap between expected and actual performance” (para. 1.23, Microgeneration Strategy Consultation, DECC, 22nd Dec, 2010).

14.9. DECC is currently monitoring 150 heat pumps and preliminary results show that most heat pumps operating on a mild Spring day were achieving below the required performance levels ‐ some significantly below. Far from backing a winning horse, DECC is backing a flop but it has been coy in admitting it, confining itself so far to admit: “We think it is likely that on average the results will still be a long way off the high‐performing systems that are consistently being measured in Germany”. Time after time heat pumps simply do not do what is says on the tin.

15. Wide deployment of heat pumps would put a very expensive strain on the grid network

15.1. The Revised NPS (Oct. 2010) revealed the full implications of a pure electricity play including the electrification of heat: “Generation capacity will need at least to double to meet this demand and, if a significant proportion of our electricity is supplied from intermittent sources, such as wind, solar, or tidal, then the total installed capacity might need to triple” (para.1.66). This is a major driving factor behind the rising cost of energy to householders. 74

15.2. A key culprit technology pushing up prices so astronomically is fingered by DECC itself: “In the case of heat pumps the challenge to be managed is in the form of significant new electricity demand. Relative to a conventional household, installation of a heat pump could mean a doubling of annual electricity demand. Given heat demand coincides with peak electricity demand, this is likely to put additional load on the network when it is most strained. Clearly, roll out of heat pumps at scale will have significant impacts on our electricity network, (Microgeneration Strategy Consultation Briefing, 23rd December 2010)”.

15.3. “Network costs of a high heat pump deployment scenario are estimated to be £290 per heat pump on a GB‐wide basis in 2030 (£390 in 2050). This compares to £1,130 per heat pump in rural areas in 2030 (£1,490 by 2050) (“Assessing the Impact of Large‐Scale Deployment of Heat Pumps on Electricity Distribution Network Costs”, by Ernst and Young, 2013). These large extra costs will fall on the already hard‐pressed consumer.

SUBSIDY IN AN AGE OF AUSTERITY

16. Subsidy to renewables is projected to rise to staggering levels

16.1. The Public Accounts Committee has not undertaken a specific study of the value for money from subsidy to renewables since the Coalition came to power – DECC does not have the key information: “We found that the Department did not know the total level of direct government funding that had been allocated to developing renewable energy technologies by the various organisations involved. The absence of a coherent approach to delivering direct government funding for renewable energy technologies or framework for evaluating its impact meant the Department could not therefore demonstrate that funding had delivered value for money” (Funding the development of renewable energy technologies, PAC, October 2010).

16.2. Levy‐funded spending (ie increases to consumer energy bills to pay for low carbon energy sources) is currently at £2.35bn for this year. Forward projections by REF show total subsidy rising to £8bn a year by 2020. The total of subsidy would be some £130bn over the period 2002‐2030. If system integration costs are added in the total cost of the renewables policy will be £13bn a year by 2020, and the total cost over the period 2002‐2030 would be £175bn. Are these costs affordable and sustainable on any reasonable projection of our economic future?

17. Fuel poverty is problematic, and could worsen

17.1. The latest figures (issued 2013) show 4.5 million households living in fuel poverty in the UK (cf. 1.2 million in 1994). The going is likely to get tougher. OFGEM predicted a rise of up to 60% domestic fuel bills (Evidence to Energy and Climate Change Committee 2.12.09). The Renewable Energy Strategy admitted: “Poorer households are likely to spend a higher proportion of their income on energy and so increases in bills will impact more on them”.

17.2 Professor Hills in his recent Fuel Poverty Review has proposed a new definition of fuel poverty to reduce this embarrassing figure, but redefining it will not lessen the eventual quantum of misery inflicted by a Government beggaring sections of its electorate. As Hills states, “In our central projections, the key fuel poverty gap indicator will rise by more than 50% between 2009 and 2016”. Such policies risk social unrest, and run against the Prime Minister’s pledge that green energy “must be affordable” (25th April, 2012). Redefinitions may ease political pain, but not the practical experience of people struggling with their energy bills.

17.3. DECC’s own estimates for the impact on electricity prices in 2010 arising from its energy and climate change policies is +27%. The sticking plaster on this otherwise crippling blow to family finances was the claim by Mr Huhne in 2011 that by 2020 on average households would be paying on average 7% less to heat and power their homes because of policies taken in the round. Unfortunately, this average hides a big variation between households, and using DECC’s own questionably optimistic figures REF calculated that 65% of households would be net losers from the policies ie the few will be gainers at the expense of the many (”Shortfall, Rebound, Backfire”, op.cit.).

17.4. In its January 2012 Research Note, Policy Exchange came to the same conclusions – two thirds of households will be worse off because of DECC policies. Policy Exchange estimated the full impact of renewable energy subsidies on an average household by 2020 (through bills, tax and costs of products and services) to be £400 per year – equivalent to 2.5p on VAT. This implies that by 2020 the total net cost (not just through energy bills) to the average household of carbon and renewable policies will be equivalent to around 15% of the (without policies) energy bill.

17.5. Calor has urged OFGEM to undertake a study of how far Government subsidies are anti‐competitive and drive up fuel prices; and, a parallel study to assess how far Government cherry picking certain technologies and in effect excluding otherwise viable technologies from the market are having an 76

inflationary effect on fuel pricing. Indeed, if the policy cost is £175bn to 2030 does the policy cost more than the problem it is purporting to address?

Written evidence submitted by Energy Fair

Submission from the Coordinator of Energy Fair, a think-tank and campaigning group set up in February 2009, with a main focus on subsidies for nuclear power. We have produced three detailed reports and submitted a formal complaint to the European Commission, as described below.1 Executive summary For many years, nuclear power in the UK has been benefitting from seven main kinds of subsidy, several of which are substantial. Withdrawal of just one of those subsidies would raise the price of nuclear power to at least £200 per MWh, much more than the unsubsidised cost of offshore wind power (about £140 per MWh). The Finance Act 2011 introduced a subsidy for nuclear power by exempting uranium from a tax on fuels used for the generation of electricity. Three other subsidies have been proposed in the Energy Bill, most notably the “contracts for difference”, as applied to nuclear power. There are five major types of risk for any investor considering putting money into new nuclear plants. It appears from news reports about ongoing negotiations between EDF and the Government about the proposed new nuclear plant at Hinkley Point that the Government may be prepared to allow most of the financial risks to be transferred from EDF to consumers or taxpayers. That would be a large subsidy for EDF. Energy Fair, with several other environmental groups and environmentalists, has submitted a formal complaint to the European Commission (DG Competition) about state aid for nuclear power in the UK. There is no valid justification for subsidising nuclear power. It is a mature technology that should be commercially viable without support. Renewables have clear advantages in cost, speed of construction, security of energy supplies, and effectiveness in cutting emissions of CO2. There are more than enough to meet our needs now and for the foreseeable future, they provide diversity in energy supplies, and they have none of the headaches of nuclear power. Subsidies for nuclear power have the effect of diverting resources away from techniques and technologies which are cheaper than nuclear power and altogether more effective as a means of meeting our energy needs. Existing subsidies should be withdrawn and no new ones should be introduced. 1 Introduction This memorandum presents evidence that relates to the issues listed in the Environmental Audit Committee’s notice. 2 Existing subsidies for nuclear power Our report, Nuclear Subsidies (PDF, bit.ly/wPVERU), describes seven existing subsidies for nuclear power:

1 The reports may be downloaded via links from www.energyfair.org.uk. Our (second) formal complaint to the European Commission is described on www.energyfair.org.uk/actions. 78

• Limitations on liabilities: The operators of nuclear plants pay much less than the full cost of insuring against a Chernobyl-style accident or worse. • Underwriting of commercial risks: The Government necessarily underwrites the commercial risks of nuclear power because, for political reasons, the operators of nuclear plants cannot be allowed to fail. • Subsidies in protection against terrorist attacks: Because protection against terrorist attacks can only ever be partial, the Government and the public are exposed to risk and corresponding costs. • Subsidies for the short-to-medium-term cost of disposing of nuclear waste: In UK government proposals, the Government is likely to bear much of the risk of cost overruns in the disposal of nuclear waste. • Subsidies in the long-term cost of disposing of nuclear waste: With categories of nuclear waste that will remain dangerous for thousands of years, there will be costs arising from the dangers of the waste and the need to manage it. These costs will be borne by future generations, but they will receive no compensating benefit. • Underwriting the cost of decommissioning nuclear plants: In UK government proposals, the Government is likely to bear much the risk of cost overruns in decommissioning nuclear plants. • Institutional support for nuclear power: the UK government is providing various forms of institutional support for the nuclear industry. Sizes of the subsidies Of those seven subsidies, the largest is probably the cost of managing nuclear waste for thousands of years, although it is difficult to quantify. The next largest are probably the considerable risk of cost overruns in both the decommissioning of nuclear plants and the disposal of nuclear waste on short-to-medium timescales—but again these subsidies are difficult to quantify. With regard to the cap on liabilities for nuclear disasters, Versicherungsforen Leipzig GmbH, a company that specialises in actuarial calculations, has shown that full insurance against nuclear disasters would increase the price of nuclear electricity by a range of values—€ 0.14 per kWh up to € 2.36 per kWh—depending on assumptions made. If those insurance costs were to be paid, even at the lowest level (€ 0.14 per kWh), the cost of nuclear power would rise to at least £200 per MWh, substantially more than the unsubsidised cost of offshore wind power (about £140 per MWh). Details of the calculations may be found on www.energyfair.org.uk/oppcost. 3 Other existing or proposed subsidies for nuclear power Our report, Subsidies for nuclear power in the UK government’s proposals for electricity market reform (PDF, bit.ly/wZqBDH), describes four other subsidies for nuclear power, the first one, below, in the Finance Act 2011 and the other three proposed in the current Energy Bill: • Exemption from tax. The “carbon price floor”, introduce in the Finance Act 2011, is, in effect, a subsidy for nuclear power because it is a de facto tax on fuels used for the generation of electricity, and uranium is exempted from that tax. • Contracts for difference. Although it is a mature technology that should not need subsidies, nuclear power would be eligible for the same system of subsidies as is proposed for renewable sources of power.

• Capacity mechanism. The UK government’s proposals for a ‘capacity mechanism’ as a backstop for the power supply system are not yet finalised. However, there is potential for the proposed mechanism to be used to provide unjustified support for nuclear power. • Emissions Performance Standard. Although peer-reviewed research shows that nuclear power emits substantially more fossil carbon than wind power, it appears that the effect of the proposed new standard would, for the foreseeable future, be to lump them together as if they were equivalent in their carbon emissions. The ‘contracts for difference’ could be very substantial. For example, it has been reported that, for the proposed new nuclear plant at Hinkley Point, EDF has been holding out for a 40-year deal with a guaranteed price for nuclear electricity at around £95-£100 for each megawatt hour generated, close to twice the current market price for electricity.2 4 The financial risks of investing in new nuclear plants and what that can mean in terms of subsidies Our report, The financial risks of investing in new nuclear power plants (PDF, bit.ly/JhdNtL) describes five major types of risk for any investor considering putting money into new nuclear plants: • Market risk. By the time any new nuclear plant could be built in the UK (2020 or later), the market for its electricity will be disappearing, regardless of any possible increase in the overall demand for electricity. The rapidly-declining cost of photovoltaics (PV) with the falling costs of other renewables, and the likely completion of the European internal market for electricity with the strengthening of the European transmission grid, will be transforming the market for electricity in the UK, and throughout the rest of Europe and beyond. Consumers, large and small, will be empowered to generate much of their own electricity (on their own sites or elsewhere) or to buy it from anywhere in Europe, and this without the need for subsidies. Explosive growth of PV is likely to take much of the profitable peak-time market for electricity. And there will be stiff competition to fill in the gaps left by PV, from a range of renewable sources, many of which are better suited to the gap-filling roll than is nuclear power. • Cost risk. There is good evidence that, contrary to the often-repeated claims that nuclear power is cheap, it is one of the most expensive ways of generating electricity. The inflation-adjusted cost of building new nuclear power stations has been on a rising trend for many years. The introduction of new safety measures after the Fukushima disaster will push up prices further. Meanwhile, the cost of most renewable sources of power is falling. • Subsidy risk. Although nuclear power is a long-established industry which should be commercially viable without support, it depends heavily on subsidies. This is a clear breach of the principle of fair competition. At any stage, some or all of the subsidies may be withdrawn, either via formal complaints to the European Commission, or via the European Court of Justice, or via decisions made by politicians. All state aid which is deemed to be illegal must be repaid. Consumers may refuse to pay surcharges on electricity bills. There is additional subsidy-related risk arising from the great complexity of government proposals in this area, with its potential for unexpected and unintended consequences.

2 “EDF staff cuts raise fresh fears over Hinkley Point C”, The Telegraph, 2013-04-23, bit.ly/XUwVWJ.

• Political risk. Apart from the risk that politicians may decide to withdraw some or all of the subsidies for nuclear power, it is vulnerable to political action arising from events like the nuclear meltdowns in Fukushima. That disaster led to a sharp global shift in public opinion against nuclear power and it led to decisions by politicians in several countries to close down nuclear power stations and to accelerate the roll-out of alternative sources of power. The next nuclear disaster—and the world has been averaging one such disaster every 11 years—is likely to lead to even more decisive actions by politicians, perhaps including the closing down of nuclear plants that are still under construction or are relatively new. • Construction risk. The delays and cost overruns in the Olkiluoto and Flamanville nuclear projects are just recent examples of nuclear projects where actual build times and actual costs greatly exceed what was estimated at the outset. But the extraordinary complexity of nuclear power stations—which is likely to increase, after Fukushima, with the added complexity of new safety systems—means that construction risk will remain a major hazard for investors for the foreseeable future. The connection between these risks and possible subsidies for the nuclear industry is that risk equates with cost, so if some or all of the risk is transferred from a nuclear operator to consumers or taxpayers, that is a subsidy for the nuclear operator. As we have seen (Section 3), EDF is seeking a guaranteed price for electricity from the proposed Hinkley Point nuclear plant of £95-£100 for each megawatt hour generated (close to twice the current market price for electricity) for a period of 40 years. Any such contract would mean that most of the financial risks outlined above would be transferred from EDF to consumers or taxpayers. This subsidy would be worth many billions of pounds. Any such contract would be extremely wasteful and very unfair, as described in A subsidy for nuclear power and its unintended consequences (bit.ly/16sbLEm). 5 There is no valid justification for subsidising nuclear power The Government has suggested repeatedly that nuclear power is needed because it is cheap, because it is a low-carbon source of power, and because it provides security in energy supplies. But: • Cost: o As we have seen (Section 3), EDF is seeking a guaranteed price for electricity from the proposed Hinkley Point nuclear plant that is nearly double the current market price. o As noted in Section 1.1, removing just one of the several existing subsidies for nuclear power would raise the price to at least £200 per MWh, substantially more than the unsubsidised cost of offshore wind power (about £140 per MWh). o The cost of nuclear power has been on a rising trend for many years, while the cost of renewables is falling. • Emissions. Peer-reviewed research shows that the nuclear cycle emits between 9 and 25 times more CO2 than wind power (Jacobson, M.Z., "Review of solutions to global warming, air pollution, and energy security". Energy and Environmental Science 2,148– 173, 2009. doi:10.1039/b809990c.). • Security:

o Nuclear power is a hindrance, not a help, in ensuring security of energy supplies: Like all kinds of equipment, nuclear power stations can and do fail. Failure of a nuclear power station is very disruptive on the grid because a relatively large amount of electricity is lost, often quite suddenly and with little warning. For that reason, special provision is need, the Large Loss Response, to cope with the failure of a nuclear plant.3 By contrast, variations in the output of renewables are much easier to manage because they are gradual and predictable. o There is a range of techniques for ensuring reliability of electricity supplies with 100% renewable sources of power (see www.desertec- uk.org.uk/elec_eng/supply_demand.html). o There are now many reports showing how to decarbonise the world’s economies without nuclear power. Details, with download links, may be found via www.mng.org.uk/gh/scenarios.htm. o Nuclear power is not a home grown source of power in the UK. All uranium is imported. In addition, there is abundant evidence from reputable sources that, in general, renewables, with conservation of energy: • Can be built much faster than nuclear power stations. • Can easily meet all our needs for energy, now and for the foreseeable future. • Provide more flexibility than nuclear power. • Provide diversity in energy supplies. • Are largely free of the several problems with nuclear power. Detailed evidence may be found on www.energyfair.org.uk/oppcost and via links from there. Nuclear power is a mature technology that has been established for many years. It should be commercially viable without subsidies. Subsidies for nuclear power have the effect of diverting resources away from techniques and technologies which are cheaper than nuclear power and altogether more effective as a means of meeting our energy needs. 6 Formal complaint to the European Commission In December 2011, Energy Fair, with several other environmental groups and environmentalists, submitted a formal complaint to the European Commission (DG Competition) about state aid for nuclear power in the UK. Our press release about this submission may be seen in Legal bid to halt nuclear construction (bit.ly/Mp9Bfy). We understand that the Commission has passed the complaint to the UK government for its response but we have not yet heard a ruling on the submission. In summary, the ‘grounds for complaint’ in our submission is:

3 See “Exclusive: Will wind farms pick up the tab for new nuclear? “ (Business Green, 2010-08-24, bit.ly/czZCRx) and “Renewable energy providers to help bear cost of new UK nuclear reactors” (The Guardian, 2013-03-27, bit.ly/15Uz44N).

• That the so-called “carbon price floor”, introduced in the Finance Act 2011, is a de facto tax on fuels used for the generation of electricity and that the exemption of uranium from that tax is incompatible with EU state aid rules, Articles 107 and 108 of the Treaty on the Functioning of the European Union (TFEU). • That the cap on liabilities for nuclear accidents of the Paris/Brussels Conventions constitutes state aid in the sense of Article 107 of the TFEU. Since Article 351 of the TFEU requires EU Member States to adapt and align their pre-existing Treaty obligations to be compliant with EU law, since relevant UK laws have not been amended in the light of that requirement, and since the cap on liabilities has not been notified to the European Commission, it is, technically, illegal under EU law. • That the proposed cap on liabilities of nuclear operators for the disposal of nuclear waste falls under the definition of state aid in Article 107(1) of the TFEU; that, unless or until it is notified to the Commission, it is illegal under EU law; and that, since the measure cannot be justified (Article 107(3) of the TFEU), it should not be approved by the Commission and should not enter into force. • That the proposed “feed-in tariff with contracts for difference”, as applied to nuclear power, is, under Article 34 of the TFEU, a measure having an effect that is equivalent to “quantitative restrictions on imports” and is thus contrary to EU law. 7 Conclusion and recommendation For many years, nuclear power has been enjoying seven main types of subsidy, several of which are substantial. Another subsidy was introduced in the Finance Act 2011, and three more are proposed in the Energy Bill. In connection with the current negotiations between EDG and the Government about the proposed new nuclear plant at Hinkley Point, it appears from news reports that EDF would like UK consumers and taxpayers to take on most of the financial risks of the project. Since the risks are large, the transfer of those risks would be a correspondingly large subsidy for EDF. 1.1 Recommendation There is no valid justification for subsidising nuclear power. Renewable sources of power, with conservation of energy: Are cheaper than nuclear power (taking account of all subsidies); Can provide greater security in energy supplies than nuclear power; Are substantially more effective than nuclear power in cutting emissions of CO2; Can be built much faster than nuclear power stations; Can easily meet all our needs for energy, now and for the foreseeable future; Provide more flexibility than nuclear power; Provide diversity in energy supplies; and Are largely free of the several problems with nuclear power. Subsidies for nuclear power have the effect of diverting resources away from techniques and technologies which are cheaper than nuclear power and altogether more effective as a means of meeting our energy needs. Existing subsidies, as described in this memorandum, should be withdrawn and no new ones should be introduced.

Written evidence submitted by Dr David Toke

Dr David Toke is Reader in Energy Politics at the Department of Politics and International Relations, University of Aberdeen.

Summary

1. The Government’s claims that similar support is being made available to all electricity generators under Electricity Market Reform is false since better terms are likely to be offered to nuclear developers compared to developers of renewable energy. In particular the Government is likely to award contracts giving nuclear power developers premium price support (subsidies) for much longer periods compared to contracts to be offered to renewable energy developers. Indeed if the demands posed by EDF are met not only will nuclear power developers be given premium price (subsidy) support for more than twice as long as renewable energy developers, but they will also be paid considerably more in ‘headline’ strike prices than onshore wind and they will also be offered loan guarantees which will not be available to renewable energy developers. A Government offer of loan guarantees, whether initially agreed as ‘partial’ or complete, as suggested by the DECC Select Committee, will lead to a blank cheque for nuclear which will crowd out funds for renewables which are much more cost-competitive in practice.

2. The Government appears to be gearing up to justify giving preferential treatment to nuclear power compared to renewable by pointing to a distinction between ‘baseload’ and ‘intermittent’ low carbon generators. This distinction is irrelevant and arbitrary for the purposes of giving subsidies, and moreover represents an about turn in the policy compared to that given when EMR was introduced at the end of 2010. Then it was argued that novel technologies like offshore wind could receive higher support, not nuclear power which is not a novel technology. This policy change seems to have no other plausible explanation other than nuclear power turning out to be more expensive in reality than was expected according to hopeful projects by nuclear advocates.

3. Any policy of giving preferential support to nuclear power compared to renewable sources such as wind power is contrary not only to the principles underlying competitive energy markets but is in flagrant breach of EU state aid rules. The EAC should warn against this and urge that the best disposition of low carbon support to achieve good value for the consumer is towards renewable energy rather than nuclear power.

Introduction

4. The aim of this submission is to discuss the balance of support (or subsidies) between renewable and nuclear power proposed by the Government’s in its 84

‘Electricity Market Reform’ (EMR). Will this policy fulfil its stated central purpose of offering a pathway for ‘decarbonisation’ that is competitive and cost-effective?

5. The issue of whether support (whether called subsidies or not) which the government is offering to generators from these technologies are indeed being made available on equally competitive terms to these technologies is of central importance to the debate being held by the EAC. Indeed the Government has repeated claimed that the support for low carbon energy sources, that is the proposed contracts for difference (CfD) mechanisms, are equally available to all generators. For example Ed Davey told the House of Commons on February 7th this year that:

6. ‘Under EMR, as set out to Parliament in October 2010, new nuclear will receive no levy, direct payment or market support for electricity supplied or capacity provided, unless similar support is also made available more widely to other types of generation’ (Gov UK 2013)

7. There are two key aspects of the question considered here. First, does the Government’s approach actually meet up to this specification, and second, can this specification be achieved if EDF’s demands for support for the Hinkley C development are approved by the Government? The answers to these questions will help us understand the extent to which Government policies are genuinely competitive, the extent to which they favour particular interests over others, the extent to which the policies are consistent and, in a practical sense, the extent to which they may pass the ‘state aid’ test that will be set by the European Commission. The discussion is put into five sections: first the intentions set out in the EMR proposals set out in 2010 and the extent to which the current government discussions are consistent with that. Second the issue of the lengths of the contracts for difference (CfD) that are likely to be offered. Third is the issue of the ‘strike prices’ that are to be offered. Fourth is the issue of ‘construction risk’. Finally there is the issue of EU ‘state aid’ rules.

Change since 2010?

8. There can be no doubt that there have been some highly significant changes in the framing of the debate about Government support for low carbon sources since the Government published their proposals at the end of 2010. Some key paragraphs are reproduced in the annex to this submission to illustrate this. Summarised here, it can be said that the original proposals give an impression that there would be a competitive auction of contracts to supply low carbon electricity, with the cheapest sources winning the contracts. The only major caveat to this seemed to be that some allowance could be made for ‘early stage, high cost technologies such as renewables’ 85

(DECC 2010, 117). In other words the clear impression that was left was that it was anticipated that nuclear power would be the cheapest.

9. Many of us were sceptical of this. Speaking for myself I found it very challengeable to expect that, for example, onshore wind, would be more expensive than nuclear power. I was unconvinced by the widely agreed assumption that the latest models of nuclear power plant (eg the EPR) was going to be cheaper than previous incarnations of nuclear sets, such as Sizewell B. It could not even be assumed that, in practice, the new nuclear plant could be financed to be at a lower cost than offshore wind plant.

10. My assumption was a somewhat cynical one in that the Government policy would not be implemented as it appeared, and that some policy ‘fix’ would be applied to ensure that nuclear power was given much superior terms compared to renewable energy. In the past, hopeful over-optimistic projections about the cheapness of nuclear power have always been proved wrong by reality. The recent period has followed this trend, with studies of nuclear power costs prepared by the pro-nuclear engineering establishment proving to be gross underestimates compared to the realities of building EPRs as evidenced by the reactors being built in Finland and France. However, in the past nuclear power was given an effective blank cheque by the state. Perhaps nuclear advocates had been hoping that the Government’s claims to support competition in provision of low carbon energy would be abandoned in fact and that there would be a return to the nuclear ‘blank cheque’ practices of the past.

11. Indeed, proposals now appear to be emerging that will offer nuclear power a superior set of terms compared to renewable energy. The only point of debate is whether the terms offered by the Government will be sufficiently weighted in favour of nuclear power to give them the very wide advantage that they need over renewables in order to be deployed.

12. What is clear is that the reality of relative support given under EMR to nuclear compared to renewable is somewhat different to that which was presented in the original EMR proposals. It is nuclear power, not renewables, that will be given special treatment of much more generous and amounts of support (subsidy).

Contract Length

13. The Government’s own proposals, and my own informal feedback on the contract negotiations, indicate that renewable energy generators such as onshore and offshore wind developers will be offered contracts of 15 year length, and no longer. On the other hand it appears that the Government is prepared to offer nuclear power developers contract lengths of at least 25 years. Certainly the implication from Ed Davey’s statements is that nuclear 86

developers will be offered longer contracts than those offered to renewable energy developers (Davey 2013). This gives a clear competitive advantage to nuclear developers. If, for example, nuclear developers are given 25 years and are given the same ‘strike price’ as renewable operators then the nuclear developers will receive premium price support that is two thirds more in total compared to renewable energy developers.

14. This appears to be justified by assertions that renewable energy plant lasts for a shorter period compared to nuclear plant (Davey 2013). This will indeed usually be the case, but such an assertion ignores the fact that, in the case of wind plant, the existing infrastructure can be re-used following refurbishments, perhaps with new blades. This is especially significant in the case of offshore wind where a successor scheme could financed much more cheaply than the initial project given that the foundations and electricity distribution infrastructure has already been installed. Perhaps this second project, consisting perhaps of no more than new blades, may require a guaranteed contract price of no more than the wholesale electricity price. A further factor is that wind power plant costs could well have declined after the first fifteen years. By comparison consumers become ‘locked in’ to paying much higher premium price levels of support to nuclear power plant. Locking in consumers to paying premium prices for longer than is necessary does not represent good value to consumers, but it does represent a policy bias in favour of nuclear power and against their main low carbon competitors such as wind power and solar power whose prices have tended to fall in the past.

15. In fact EDF has been lobbying for a contract length of 40 years (Utility Week 2013), sometimes described in the press as a demand for a 35 year contract. This contract length would therefore commit the energy consumer, for a given strike price and given amount of energy production, to paying more than twice the amount of total support to nuclear power compared to wind power. If, as discussed below, nuclear power were given higher than onshore wind’s expected strike price of £80 per MWh, this disparity would increase to even higher multiples.

Strike Price

16. Under EMR the strike price is the payment, per MWh, for low carbon electricity production, that developers will be assured of being paid over periods specified in a long term contract. Such long term contracts are referred to as ‘feed-in tariffs’. However, not all low carbon technologies will be paid the same. For example. it seems likely that onshore wind power developers will be offered around £80 per MWh (2013 prices) as a strike price. This is less than the income theoretically available under the Renewables Obligation (RO). However under a feed-in tariff system there should be more certainty about future income levels compared to the RO, 87

and making the cost of investment capital cheaper and thus requiring the required power purchase price per unity generated lower.

17. It seems that nuclear power developers will be offered at least £80 per MWh, and certainly it is the case that EDF have lobbied for a lot more – just under £100 per MWh according to the press. Indeed DECC itself appeared to suggest that nuclear ‘First of a Kind’ would cost £98 per MWh (DECC 2010, 28), although the ascription ‘First of a Kind’ is a curious formulation since nuclear power plant have been operating for 60 years.

18. Coincidentally or not, the ‘strike price’ suggested by EDF is also around this level, - £98 per MWh – although as mentioned earlier, involving a much longer contract compared to wind power. As commented previously this level of support would mean that the consumer would be committed to giving several multiples of higher support for a unit of nuclear energy compared to onshore wind power, and much higher quantities of subsidy compared to offshore wind power schemes.

19. The Government have outlined a vision to bring down the cost of offshore wind to £100 per MWh (Renewable Energy Roadmap 2011). Yet it seems that this is in a policy context of offering 15 year contracts to offshore wind and offering at least 25 year contracts to nuclear power (with EDF wanting 35-40 years). This means, in effect, that if the Government did acceded to EDF’s demands for a £98 per MWh strike price it would be giving much more support to nuclear power than it would prefer to give to offshore wind. This contrasts with an originally dominant discourse has often been that offshore wind is a less mature technology. Is the logic about to be turned around and nuclear power now to be regarded as an immature technology and offshore wind to be regarded as a being an ‘old’ technology relatively less deserving of support compared to nuclear power?

20. However, the contrast between the initial impression given by Government policy and the possible out-turn of policy is made even sharper by the fact that EDF’s demands for a high strike price and very long contract do not end there. They also want (at least some) underwriting of construction risk.

Construction Risk

21. Underwriting of construction risk means that whatever happens, then some agent (in this case HM Government) will agree to pay the cost of construction of the plant, or an agreed portion of that grant. Currently EDF is requesting only (to my knowledge) an unspecified part of the construction risk, although some nuclear advocates, including the Select Committee on Energy and Climate Change itself (DECC Select Committee 2013a), appear to be recommending that the entire nuclear construction risk be underwritten by government. This would help nuclear projects because banks may be more 88

likely to lend that amount of money at relatively low interest rates compared to the much higher rate of return required by equity investors. However, three issues are raised by this.

22. The first issue is that analysis of the history of nuclear power construction might question the assumption that this was a ‘risk-free’ action by the Government. Nuclear power plant have been subject to cost overruns and often take longer to complete than planned meaning that the loan guarantees would have to be called in if this experience repeated itself. A nuclear constructor could spend some or all of the money that was underwritten and, having suffered unplanned reverses, announce that they would ask the government to repay the loans the pay for ‘part’ of the project. However they would quite probably also say that they would be unable to complete construction unless the state guaranteed the rest of the power station costs. ‘Partial’ underwriting would thus collapse into full underwriting. The nuclear constructor would suffer no financial penalty, but the state would be faced with the dilemma of having a part completed nuclear power station.

23. This scenario effectively happened in the case of Sizewell B when the electricity industry was privatised part way through its construction. The Government agreed to guarantee the costs of completing the project. The electricity consumer ended up picking up all of the costs guaranteed under a mechanism called the ‘fossil fuel levy’. History could quite easily repeat itself if the state agreed to any form ‘underwriting’ of construction costs. Despite this the DECC Select Committee has actually recommended such a strategy (DECC Select Committee 2013a). By offering what may be initially sold as ‘partial’ underwriting of construction risk, the Government will be signing a blank cheque for nuclear power in all but name. For nuclear power there is no such thing as ‘partial underwriting’, any more than there is such a thing as being ‘partially pregnant’.

24. The Government’s reply to the DECC Select Committee has been interpreted as a response which did not completely rule out this possibility of nuclear underwriting. Indeed the letter from DECC actually suggested that ‘baseload’ and ‘intermittent’ plant could be treated differently. This may be referring to offering longer contracts to nuclear constructors compared to renewable developers, but this is unclear.

25. A second issue is how the claims for ‘competitiveness’ can survive if one party (nuclear power) is given preferential terms through ‘underwriting’ risk. I have already discussed how it seems that nuclear is going to be given preferential terms through a longer contracts, and also, perhaps (if EDF’s demands are met), through a higher strike price compared to onshore wind. Now there is also a possibility of nuclear power being afforded a third type of preferential term through having their construction costs underwritten. 89

26. A third issue is whether such ‘underwriting construction risk’ support could possibly be reconciled with the EU’s state aid rules (see below). The Government would have, at the very least, to offer comparable support for construction risk to offshore wind, as well as offer equivalent terms to renewable on other matters. Given that a MW of nuclear power generates a much larger amount of electricity than a MW of offshore wind this means that if the Government underwrites Hinkley C at 3.6 GW worth of capacity it would have to offer similar underwriting to something around 10 GW of offshore wind. Underwriting would be of significant benefit to offshore wind and would lead to major cost reductions because of the reductions in interest charges on debt portions of the investment. Certainly, if any technologies should be offered underwriting, the newest, most innovative technologies, such as tidal lagoons, tidal stream and wave power technologies should be given priority. It is difficult to see how, some 60 years after their genesis, nuclear power might claim to require a market preference policy.

27. Nevertheless, as mentioned earlier, the Government through its distinction between baseload and intermittent plant seems to be preparing the ground for giving preferential terms to nuclear power compared to renewable. Yet it is difficult to see the basis for this. Contrary to frequently made assumptions, wind power and other renewable developers have to pay for the balancing of their output through their own income stream from sales of electricity. When their electricity is traded on the wholesale markets the value of this electricity is discounted to pay for the balancing services consequential upon the ‘intermittent’ (or variable) source of electricity. Indeed the very choice of language (intermittent as opposed to variable) implies a bias in the Government approach towards seeing variable renewable output as being less valuable than ‘baseload’ nuclear production. It is the case that if large proportions of electricity are sourced from renewable then more transmission interconnector capacity will have to be built. But not only is this facility open to other electricity trading uses but also such costs will be offset (in the comparison with nuclear subsidies) by in-kind or actual subsidies to nuclear power. These include the sharing of costs for extra back-up capacity required to guard against sudden breakdowns by nuclear power stations (Carrington 2013), and other subsidies discussed by other submissions to the EAC.

EU state Aid rules

28. EU state aid rules exist for a very good purpose – to ensure that the Government does not give state aid that would distort the efficient allocation of resources through market mechanisms (Europa 2013a). The Government insists that its low carbon support policies do not discriminate between different technologies. However, as covered in the arguments above, the proposals to support nuclear power clearly do discriminate in favour of nuclear power. This will be at the very least through offering nuclear 90

developers longer contracts than will be awarded to wind power developers, and, if EDF’s terms are accepted, a lot more than this.

29. In fact, as can be seen by reference to the state aid rules renewable energy has an exemption on the grounds that it is an environmental measure. In contrast, nuclear power has no such exemption (Europa 2013b). Yet the Government proposes to do the exact opposite of the these rules, that is offer better terms to nuclear investments compared to renewable energy. It is extremely difficult to see how this can be reconciled with the state aid rules.

Conclusion and recommendations

30. It can be seen through this argument that the Government has shifted from an ostensible policy of saying (initially) that it would allow some concessions to be made for some newer renewable generation in its low carbon support towards now building a case to justify why better terms should be given to nuclear power. It has been the contention of many that the process of presenting nuclear power as somehow cheaper than renewable has been flawed from the start. It does seem that public policy has been dragged along on the basis of a process of what Tom Burke has called ‘salami slicing’ – that is presenting nuclear costs as being smaller than they are, but bit by bit gaining policy acceptance of an ever increasing set of subsidies. The strategy has been of gaining policy commitment for a steady incremental rise in the level of subsidies offered to nuclear power. It would have been politically unacceptable for the policy process to have become by an open declaration that nuclear power would receive better terms than renewable energy sources. However now we see these better terms emerging through this process of ‘salami slicing’. The Government have already it seems, committed to offering nuclear developers longer contracts to received low carbon premium support compared to renewable energy developers. The exact scale of the preferential treatment is yet to be seen. However if the Government does accede to the demands set by EDF the difference between the terms will be very large indeed. Given that renewable and nuclear are competing for a limited set of resources under the ‘levy controlled framework’ it is difficult to avoid the conclusion that Government’s policy will achieve poor value for consumers in that the cheaper resources of renewable energy will be sidelined by Government policies to give better terms to more expensive resources associated with new nuclear power stations.

Recommendations

32. It is therefore recommended that:

a) the EAC should warn against the possibility that the Government may give better terms to nuclear power compared to renewable energy technologies, 91

that is by giving longer contracts, a higher strike price (compared to onshore wind) and/or loan guarantees to nuclear power.

b) the EAC should reconsider the basic policy premise that nuclear power should be offered low carbon support. It is clear that the Government’s own strategy implies that there are limits on funds (subsidies) available to support low-carbon energy and that if these are to be most cost-effectively disposed they need to be reserved for low carbon technologies other than nuclear power. Maintaining a belief that nuclear power is economically competitive with renewable energy leaves Government policy in a state of unreality leading to a failure to plan a consistent, workable, energy strategy for the future.

Annex

Excerpts from Government’s Introductory Paper on Electricity Market reform issued in December 2010 (DECC 2010), pages 116-117

9. The Government is attracted to a greater use of auctioning as a mechanism to set the level of feed-in tariff support, regardless of the specific model for FIT chosen in the White Paper next year. The price discovery characteristics of an auction should enable financial support to be set at a level just high enough to lead to deployment but not high enough to lead to excessive profits, with bids driven down by competition.

10. However, adopting an auction-based approach would require Government to determine what share of the electricity mix should be low-carbon and may require Government to have a view on the breakdown of technologies within the low-carbon mix. Leaving decisions on technology choice to individual investors – who are directly exposed to the risk of making poor decisions, could lead to a lower-cost and lower-risk technology mix. (page 115 DECC 2010)

14. Having one auction for all low-carbon technologies would maximise competition between technologies, allowing investors (who are driven by maximising the return on their investments) to determine the most costeffective low-carbon technologies. However, this could on the other hand lead to a “winner takes all” outcome where the current lowest cost technology would win all the bids and dominate the technology mix. This would not be good for encouraging early stage, high cost technologies such as renewables.

15. Having technology-specific auctions would enable different tariffs to be set for different technologies but could lead to insufficient competition (not enough bidders) and would probably entail the Government having to specify how much capacity from each technology was wanted (i.e. how many GW of onshore wind, offshore wind, nuclear etc).

16. One way to provide differentiation in support for individual low-carbon technologies within an auction approach, and replicate the benefits of allowing investors to choose the technology mix, could be to have a technology neutral 92

auction for a single tariff level for all low-carbon generation and then to offer technology specific premiums on top to early stage technologies with higher costs such as offshore wind. This would give additional revenue certainty to the lower cost and more mature low-carbon technologies but would allow Government to recognise that innovation in earlier stage, higher-cost technologies is a legitimate objective in its own right. (p116-117)

References

Carrington, D., (2013) Renewable energy providers to help bear cost of new UK nuclear reactors, Guardian March 27th http://www.guardian.co.uk/environment/2013/mar/27/renewable-energy-cost-nuclear- reactors

Davey, E, (2013) ‘Edward Davey speech to the Commons on new nuclear power on February 7th’, Gov UK, https://www.gov.uk/government/speeches/edward-davey- speech-to-the-commons-on-new-nuclear-power

DECC (2010), Electricity Market Reform Consultation Document, http://www.decc.gov.uk/assets/decc/Consultations/emr/1041-electricity-market- reform-condoc.pdf

DECC (2011) Renewable Energy Roadmap, https://www.gov.uk/...data/.../2167-uk- renewable-energy-roadmap.pdf

DECC Select Committee (2013a) Building New Nuclear: the challenges ahead, www.publications.parliament.uk/pa/cm201213/cmselect/.../117/117.pdf

DECC Select Committee (2013b) Government Response to Committee's Report on Building New Nuclear http://www.publications.parliament.uk/pa/cm201314/cmselect/cmenergy/106/10604.h tm

Europa 2013 (2013a) http://europa.eu/legislation_summaries/competition/state_aid/index_en.htm

Europa (2013b) http://europa.eu/legislation_summaries/competition/state_aid/ev0003_en.htm

Utility Week (2013), unsigned, EDF aims to strike CfD deal in next three months http://www.utilityweek.co.uk/news/news_story.asp?id=198148&title=EDF+aims+to+st rike+CfD+deal+in+next+three+months

11 June 2013 93

Written evidence submitted by the Renewable Energy Association

The Renewable Energy Association (REA) is pleased to submit this response to the Environmental Audit Committee’s Inquiry on Energy Subsidies. The REA represents a wide variety of organisations involved in renewable energy in the UK, across the power, heat and transport sectors, with members ranging in size from major multinationals to sole traders. With over 1,100 corporate members, the REA is the largest renewable energy trade body in the UK. The REA’s main objective is to secure the best legislative and regulatory framework for expanding renewable energy in the UK.

Executive Summary • There is nothing new about energy subsidies – they are a reflection of the pivotal role that energy plays in the economy. It is reasonable for governments to apply subsidies in line with clearly stated policy objectives, such as encouraging promising new and emerging technologies into the marketplace, reducing reliance on imported fuels, controlling greenhouse gas emissions and stimulating economic growth. However there is an issue in that subsidies often lack transparency, though this is not generally the case for renewable energy.

• Government’s aim should be to create a competitive energy marketplace based on a transparently level playing field. It is crucial that external costs of energy sources be fully taken into account; when that is done the costs of many renewable energy technologies compare very favourably. Until external costs are fully internalised, support for renewables may be required to compensate, however the costs of many renewable technologies are falling whilst the costs of conventional energy sources are rising. Support for renewables is therefore fully justified as a stopgap measure, especially as they fulfil all of the previously identified objectives.

• The Government must therefore do more to ensure transparency and a level playing field. Subsidies should be tied to clearly defined objectives. More work is needed to quantify and account for the externalities of conventional sources. The UK Government must heed the conclusions from the most recent European Council meeting on 22 May 2013, reiterating the “priority that should be attached to ensuring a level energy playing field” and “phasing out environmentally or economically harmful subsidies, including for fossil fuels”.

Introduction There is no clear definition of energy subsidies and the subject is inherently political. Subsidies are any form of support that reduces the price paid by the final consumer, and therefore encourages consumption of that particular energy form. For more expensive energy forms like renewable energy or nuclear, that might be to help them compete with the fossil fuel benchmark. For fossil fuels the support might be to encourage indigenous production in the face of cheaper international competition or, as is the case in the less developed countries, to make energy more accessible to consumers.

Subsidies for renewable energies are more transparent than those to fossil fuels and nuclear. The REA therefore welcomes this inquiry and the Oxford Energy Associates (OEA) work. It is extremely important to set out a framework enabling comparison across the 94 different energies and therefore work on this topic should be continued and updated on a regular basis.

Responses to Inquiry Questions

1. Has the Government identified and measured energy subsidies? 1.1. In 2004 the European Environment Agency (EEA) produced a report, ‘Energy subsidies in the European Union, a brief overview’1, for the International Renewables Conference in Bonn. The executive summary’s opening paragraph is worth repeating here: “There is no agreed definition of energy subsidies among European Union (EU) Member States. The term may include cash transfers paid directly to producers, consumers and related bodies, as well as less transparent support mechanisms, such as tax exemptions and rebates, price controls, trade restrictions, planning consent and limits on market access. It may also cover government failure to correct market imperfections, such as external costs arising from energy production or consumption. This results in a wide range of economic estimates and confusing policy arguments.” 1.2. The OEA report documents how subsidies are often hidden and are therefore hard to quantify. This is exacerbated by the lack of clarity over the precise meaning of ‘subsidy’. The majority of studies focus on consumer subsidies with less attention paid to producer subsidies. These are detailed in paragraph 2.3. 1.3. The annual subsidy for renewables in the OEA report totals £3,052m. This is far lower than the total for oil (£539m), gas (£3,631m), coal (£85m), and nuclear (£2,300m), which total £6,555 (Figure 1). Furthermore, some of the costs, e.g. ‘Additional exemptions from charges and accelerated tax allowances’ for oil and gas and the costs of dealing with the legacy nuclear waste, are not quantified meaning their totals are underestimated. 2. The Government’s treatment of subsidies compared to best practice. 2.1. As described by Oxford Energy Associates, there are different ways to define and scope energy subsidies and there appears no formal clarification by the Government as to which is the correct methodology. 2.2. Section 1 of the OEA report details and explains the background to subsidies and how they work. Having explained the economics involved, the report identifies a number of types of subsidies and how they are calculated in the different reports. Despite noting such differences and limitations, the report does not specifically specify which method is best practice. 2.3. In a recent report by the International Monetary Fund (IMF)2, subsidies are defined under two headings: consumer and producer. Consumer prices are those which arise when the prices paid by consumers are below a benchmark price, generally calculated as the cost minus the recovery price for the domestic producer. On the other hand, producer subsidies are those which arise when prices received by suppliers are above this benchmark. The report notes that one key difference between the two is that, unlike consumer subsidies, producer subsidies do not lead to excessive consumption of energy. Whilst distinguishing between the two types of subsidies, the report chooses to focus on consumer subsidies and the producer subsidies remain rather unclear.

1 http://www.eea.europa.eu/publications/technical_report_2004_1 2 http://www.imf.org/external/np/pp/eng/2013/012813.pdf

Figure 1. Summary of UK Energy Subsidies (Written evidence commissioned by the Committee from Dr William Blyth, Oxford Energy Associates, page 34). [not reproduced here]

2.4. A recent report by the Overseas Development Institute3 presented a number of subsidy categories, types and definitions. Based on their identification of subsidies they estimated that globally developing country governments spent more than $396bn subsidising fossil fuels in 2011, whilst only $5bn was spent on combating the effects of climate change. 2.5. Rarely mentioned are the hidden subsidies associated with providing the British Armed Forces to protect offshore oil and gas companies: http://www.amsslimited.com/?page_id=111, and http://platformlondon.org/wp- content/uploads/2012/10/A-Secret-Subsidy-piracy.pdf

3. The scale of subsidies in the UK and comparison with other countries. 3.1. As noted in the OEA report, the most comprehensive assessment and comparison of international subsidies is the OECD report ‘Inventory of estimated budgetary support and tax expenditures for fossil fuels’4. This report notes that it is extremely hard to directly compare countries as ‘[t]ax-expenditure accounting was not designed with international comparability in mind’. A fundamental limitation being the differences in the definition of the benchmark tax system. Therefore national tax expenditure estimates can only be considered in the context of the specific tax system for that country. For this reason the report focuses on accounts of individual countries rather than making direct comparisons. 3.2. The OECD is working on expanding its work to include such country-specific backgrounds when estimating tax expenditures. However it also notes the need for countries to be open and transparent in their reporting of tax-system features which support the production or consumption of fossil fuels. 3.3. In line with paragraph 2.5, the EEA report compared energy subsidies in the EU-15. The report, however, has not been repeated since this 2004 edition. At the time of the report however, it was found that whilst on-budget support for the coal industry continued in the UK, Germany and Spain, it had more or less ceased in other countries like Belgium and France. It was further noted that the UK, along with Italy and the Netherlands provide the highest level of support to the oil and gas sector through reduced VAT rates. 3.4. Additional conclusions drawn from the EEA report were that, across the EU-15, support for fossil fuels was high whilst support for renewable energy ‘represents a much less mature industry with arguably greater need for technological and market support to enable full commercial development.’ Furthermore, in historical terms, renewable energy subsidies in the EU-15 have been ‘relatively low in comparison with other forms of energy during periods of fuel transition and technology development’. 3.5. Whilst both the OECD and the EU reports aim to assess the scales of subsidies in the UK and internationally, there appears to be a lack of national reports which assess the size of energy subsidies solely in the UK. Furthermore, as noted in paragraph 1.2,

3 http://www.odi.org.uk/sites/odi.org.uk/files/odi-assets/publications-opinion-files/8335.pdf 4 http://www.oecd.org/site/tadffss/48805150.pdf

all reports which have attempted to do so tend to focus on one type of subsidy or note a number of limitations to the study. 3.6. Based on the information in paragraphs 3.1 - 3.5, the scale of subsidies in the UK and in comparison with other countries have not yet been reliably reported. The future work of the OECD appears promising but it remains essential that countries are transparent in their reporting. 4. Whether the Government has any plans or targets to reduce or eliminate ‘harmful’ subsidies. 4.1. In 2009 the G20 committed to ‘rationalize and phase out over the medium term inefficient fossil fuel subsidies that encourage wasteful consumption.’ This statement is however rather flexible, for example, there is no specific deadline, only a pledge to do it in the ‘medium term’. 4.2. A progress update5 published in June 2012, noted the limitations of the text. The ‘vague definition [of] fossil fuel subsidies in the G20 commitment has allowed many countries to “opt-out” even reporting on their fossil fuel supports’. It is suggested that there has been divergence over the terms: ‘subsidy’, ‘inefficient subsidy’ and a subsidy which ‘encourage[s] wasteful consumption’. This led to six countries opting out of reporting in 2011 and the number is expected to have risen since. 4.3. As further noted in the progress report discussed in paragraph 4.2, for any further analysis or reform, transparency on support policies to fossil fuels is essential. Allowing policies to be visible to others will mean that assumptions made by national governments can be seen and in turn potentially challenged. 4.4. Most recently David Cameron attended a European Council meeting on 23 May 2013 whose conclusions6 included the following: “Priority will be given to: … (c) the revision by the Commission of state aid rules to allow for targeted interventions to facilitate energy and environmental investment, ensuring a level playing-field and respecting the integrity of the single market; (d) phasing out environmentally or economically harmful subsidies, including for fossil fuels.” 5. Progress in reducing such harmful subsidies, and how current energy policies and DECC’s ‘Energy Pathways’ for the mix of energy sources will influence the magnitude of any subsidies. 5.1. Despite the agreement discussed in paragraph 4.1, it was reported7 that worldwide fossil fuel subsidies rose to at least $470bn in 2010, about $100bn on 2009 figures. It was further reported that whilst fossil fuels receive subsidies of this scale (admittedly the total was reported at $409bn in this report), renewable energy technologies obtained a smaller $66bn in the same year8. 5.2. Furthermore, the G20 progress report (paragraphs 4.2 and 4.3) found that nations are just changing their definitions of subsidies. The report concluded that no subsidies have (at the time of the report) been eliminated as a result of the G20 commitment. It is suggested that there has been a lack of growth in identified policy interventions since the first progress report which was submitted by members in June 2010.

5 http://priceofoil.org/content/uploads/2012/06/FIN.OCI_Phasing_out_fossil-fuel_g20.pdf 6 http://www.consilium.europa.eu/uedocs/cms_Data/docs/pressdata/en/ec/137197.pdf 7 http://www.guardian.co.uk/environment/2011/oct/11/g20-curb-fossil-fuel-subsidies 8 http://www.guardian.co.uk/environment/2012/jan/19/fossil-fuel-subsidies-carbon-target

5.3. It is widely reported, for example in the IMF report9, that the removal of subsidies would encourage reductions in consumption and waste and therefore lead to reduced CO2 emissions. This positive effect would be furthered still by strengthening incentives for ‘research and development in energy-saving and alternative technologies’. I.e. energy efficiency and renewable energy sectors would benefit from the removal of these harmful subsidies and in turn so would the environment. 5.4. Current policies are working well to incentivise renewables and energy efficiency measures, however to truly make a fair playing field, there needs to be greater transparency across all energy sources. The Government therefore needs to make a concerted effort to fulfil the G20 commitment made in 2009. 6. REA recommendations 6.1. In forming this response we recognise that the available data are limited and the topic of defining and quantifying subsidies is complex. We therefore suggest that an alternative approach may prove most useful. 6.2. In 2011 the Committee on Climate Change produced ‘The Renewable Energy Review’10. The document partly focused on estimating the cost of low-carbon technologies up to 2040. These were presented as shown in Figure 2, though we hasten to add that we do not agree with many of the costs shown (for example the costs of solar PV have fallen dramatically since this report was written).

Figure 2. Estimated cost of low-carbon technologies (2011, 2020, 2030, and 2040). [From ‘The Renewable Energy Review’, CCC, Figure 1.10 [not reproduced here]]

6.2 Presenting the costs in this manner, i.e. basing estimations entirely on the costs and free of subsidies allows a simple comparison across technologies and internationally. 6.3 As an addition to a graph such as this, it would be useful to indicate the impact that subsidies and taxes could have on these costs, for example by adding vertical arrows. By changing the lengths of these it would allow the user to see what options are available in order to bring all technologies to the same benchmark level. This could be done in a similar way as the DECC 2050 calculator whereby you change the scenarios used. 6.4 Having a framework such as this will help consumers to see how the costs have changed and are changing over time, therefore adding to the transparency in the market 6.5 It is a perennial frustration for the REA that while the costs of renewable energy are routinely quantified, the benefits are not subject to systematic quantification. Aside from the environmental benefits, additional advantages include balance of trade benefits, employment, exports, security (including defence), price stability and HMT tax revenues. We believe that the wider advantages need to be taken into account and make for a compelling case in favour of renewable energy.

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9 http://www.imf.org/external/np/pp/eng/2013/012813.pdf 10 http://archive.theccc.org.uk/aws/Renewables%20Review/The%20renewable%20energy%20review_ Printout.pdfhttp://archive.theccc.org.uk/aws/Renewables%20Review/The%20renewable%20energy %20review_Printout.pdf

Written evidence submitted by the Association for the Conservation of Energy

Introduction

1. The Association for the Conservation of Energy was formed in 1981 by major companies active within the energy conservation industry, in order to encourage a positive national awareness of the needs for and benefits of energy conservation; to help establish a sensible and consistent national policy and programme and to increase investment in all appropriate energy-saving measures. We welcome this opportunity to respond to the Environmental Audit Committee’s inquiry into energy subsidies.

The nature of this submission

2. This submission mainly concerns paragraph (v) of this inquiry by the Committee – ‘how current energy policies and DECC’s ‘Energy Pathways’ for the mix of energy sources will influence the magnitude of any subsidies.’

3. We will be arguing that ‘current energy policies’ as specified in The Carbon Plan and explained in detail in ‘DECC’s Energy Pathways’ ‘will most certainly ‘influence the magnitude of any subsidies’ to the extent that they will require an unnecessary spending of the between £19 and £396 per year for 40 years by every single person in the UK. That amounts to a total of between £1.19 billion and £24.97 billion per year and between £47.6 billion and £998.8 billion over the 40 year period.

4. That unnecessary spending that will be dictated by ‘current energy policy’, while not necessarily taxation is never-the-less is the public’s money. And so constitutes a subsidy.

What is a subsidy?

5. This definition of a subsidy as including ‘the public’s money’ and so being far wider than simply ‘public money’ (i.e. taxation) definition is not new. For instance:

(i) The government itself defines the feed in tariff, which is paid by the public as consumers and not as taxpayers (and so is ‘the public’s money’), as a subsidy . (ii) The amount of money available for, and paid out as, ROCs is also collected from the public as consumers rather than taxpayers yet it is listed in the Blue Book as a tax (table 11.1).

6. In his Report for the Committee Dr William Blyth of Oxford Energy Associates explains (on page 9) that a subsidy can include ‘transfers between consumers and producers as a result of policy...’ .

‘Current energy policies’ in the DECC Pathways involve

(i) Massive extra (i.e. more than other alternatives that deliver the same – or better- results) use of ‘the public’s money’ that will result from those pathways; and (ii) Massive transfers of money as a result of policy

in a wholly unjustifiable way because all the benefits of those ‘current energy policies’ can be achieved by cheaper policies. Indeed, we go further – a major benefit of current energy policies, energy security (‘keeping the lights on’) can be more reliably achieved by cheaper policies.

6. So as we said above the public is being required by current energy policies in the pathways to subsidise polices that are both more expensive and less reliable than the alternatives that are available and known to government and based on evidence and ‘robust’ analysis by DECC and included in DECC’s own pathways – but ignored by DECC.

Subsidies for new nuclear power

8. The subsidy we will now explain is to the ‘current energy policy’, as detailed in the ‘DECC pathways’, that is dependent on new nuclear power stations to keep the lights on and achieve our legally binding 80% CO2 reduction target by 2050.

It is a hidden subsidy – but never-the-less it is still a subsidy in the sense we described above: it involves requiring the public’s money to be spent on a policy that is both more expensive than an alternative policy that achieves exactly the same objectives far more cheaply and also more reliably. How does this work?

9. On the Pathways calculator DECC’s 4 main pathways specified in the Carbon Plan called

 Analogous to MARKAL

 Higher Renewables more energy efficiency

 Higher nuclear less energy efficiency and

 Higher CCS more biofuels are explained in full. These are the main ways forward for government policy. In the DECC Review of April 2013 DECC’s Head of Strategy Ravi Gurumurthy, wrote that the Analogous to MARKAL pathway was considered to be the most cost effective pathway.

10. So let us explain how the subsidy occurs. First we list the cost of the 4 main government pathways, from the DECC pathways calculator. Table 1 DECCs estimated cost of current policy.

Table 1

COSTS £ per person per year 2010-2050 Fossil Bioenergy Electricity Buildings Transport Industry Finance Other Total

Higher renewables more 537 225 314 762 2292 146 835 7 5118 energy efficiency

Higher nuclear less energy 544 393 244 806 2469 15 856 2 5329 efficiency

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Higher CCS, more bioenergy 608 319 190 1028 2157 146 801 16 5265

Analogous to MARKAL 3.26 550 305 231 733 2011 146 747 13 4736

11. The calculator explains that this is not an energy bill it is ‘the absolute cost to society of the whole energy system (mean undiscounted real pounds per person per year 2010 – 2050) and ‘includes only the physical costs of constructing, operating and fuelling equipment.’

All of these government pathways achieve 80% CO2 reduction and keep the lights on by passing the stress test and by importing energy.

12. Secondly we investigated whether this was the most cost effective way of achieving those two objectives; and we did this by removing the new nuclear power element from the government pathways and substituting other levels of activity for the various policy measures listed in the pathways (exactly what changes we made for each comparison pathway is contained in Appendix 1).

We emphasize that we did not change the government’s robust evidence and analysis: all we changed was the activity level (listed as 1-4 or A-D) on the pathways calculator for various possible demand side and supply side measures. And here is the result in Table 2

Table 2

COSTS (£) Fossil Bioenergy Electricity Building Transport Industry Finance Other TOTAL

Higher renewables more 537 225 314 762 2292 146 835 7 5118

energy efficiency Comparison v 1 547 287 295 762 2118 146 801 8 4964

Higher nuclear less energy efficiency 544 393 244 806 2469 15 856 2 5329

Higher CCS, more bio energy 608 319 190 1028 2157 146 801 16 5265 Comparison v.1 627 319 180 1007 2157 146 785 16 5237 Comparison v 2 629 319 187 1007 2157 146 785 16 5246 Comparison v.3 615 319 182 1007 2165 146 785 20 5239 Comparison v 4 597 283 172 1028 2213 106 817 16 5232

Analogous to MARKAL 550 305 231 733 2011 146 747 13 4736 Comparison example 1 579 283 167 638 2039 146 601 20 4473 Comparison example 2 596 289 200 723 1861 146 675 23 4513 Comparison example 3 585 289 206 723 1861 146 695 24 4529 Comparison example 4 620 289 178 723 1861 146 658 23 4498 Comparison example 5 617 289 202 723 1861 146 659 23 4520

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Comparison example 6 611 289 236 723 1861 146 668 23 4557 Comparison example 7 585 304 235 439 2039 146 576 16 4340 Comparison example 8 601 283 232 721 1980 146 723 24 4710 Comparison example 9 590 283 238 721 1980 146 720 16 4694 Comparison example10 580 319 232 721 1869 146 683 16 4566

13. What this shows is that ALL the comparison pathways involving no more nuclear power stations cost less than the equivalent government pathways – i.e. less of the public’s money will be required as a result of them. Table 3 summarises this information.

Table 3

Cost of Cost of our Annual subsidy of Total annual Total subsidy of government comparison(s) government subsidy of government pathway per per person per pathway per government pathway over 40 person per year calculated person as pathway (Based on year period (£) year 2010- by the DECC compared to our population figure 2050 stated on calculator (£) pathways (£) of 63,075,914 from the DECC ONS) (£) calculator (£)

Higher 5118 4964 154 9.71billion 388.4 billion renewables more energy efficiency

Higher CCS more 5265 5232-5246 19 - 33 1.19 billion – 2.08 47.6 billion – bio billion 83.2 billion

Analogous to 4736 4340-4694 42 - 396 2.64 billion – 24.97 98.4 billion – MARKAL billion 998.8 billion

13. Of course it may be argued that the government pathways are necessary to achieve our joint objectives of 80% CO2 reduction and keeping the lights on, and so these policies that involve spending of the public’s money are not subsidies but are needed to achieve vital policy objectives.

14. This argument is factually incorrect. As Appendix 2 shows ALL of our alterative pathways achieve the 80% and keep the lights on. Indeed the evidence regarding the latter point is that the alternative pathways are more reliable than the equivalent government pathways because, as Appendix 3 shows, not only do they require either the same or less security back up than the government pathways, but they all rely on less imported energy than the government pathways.

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And in an uncertain world who knows what conflicts, wars and upheaval and political allegiances there will be in 2025 let alone 2035 or 2045? The more we rely on imported energy the less will be the certainty of keeping the lights on.

15. So the government is pursuing a course requiring massive extra spending of the public’s money ‘as a result of policy’ (to use Dr Blyth’s words) because it is blindly adhering to a policy decided some years ago (the building of new nuclear power stations) – despite evidence that it holds that this policy is neither the cheapest nor the most reliable way of achieving energy policy objectives.

The public’s money and the government’s promises

16. All of this is totally contrary to repeated ministerial promises, as well as the Conservative Election Manifesto and Coalition Agreement. The latter says (at page 17) new nuclear power stations will be allowed ‘provided that they receive no public subsidy’.

The Conservative Election Manifesto of April 2010 used almost identical words and saying that new nuclear power stations would be ‘encouraged’ – ‘providing they receive no public subsidy.’

And Ministers have repeatedly given similar assurances repeatedly. For instance:

Charles Hendry: Government's position on new nuclear power is clear. It is for the private sector energy companies to construct, operate and decommission new nuclear power plants, as long as they are subject to the normal planning process for major projects and that they receive no public subsidy.’ -Hansard, 24 June 2010: Columns 465-6

There are numerous similar pronouncements by, for instance, Mr Hendry1, Chris Huhne MP2, Baroness Wilcox3, and Lord Marland4.

17. Indeed, quite apart from the case argued herein, Dr Blyth in his written report for the Committee stated unequivocally (at page 25): ‘despite ministerial announcements ... that there would be no public subsidies for new nuclear plant, it is apparent that several subsidies will in fact be in place’ and he goes on to explain them.

1 Hansard 24.6.10 cols 465-6; www.decc.gov.uk/en/content/cms/news/NIF10/NIF10.aspx 2 The Times 15.5.10; Independent on Sunday 13.6.10 3 Hansard 2.6.10 col 271 4 Hansard 3.6.10

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18. And the nuclear industry itself accepts that it will now be receiving subsidies. Writing in Energy World May 2013 Peter Haslam, the Public Policy Advisor with the Nuclear Industry Association said that ‘new nuclear will be delivered without any direct public subsidy.’ But not without any public subsidy!

Appendix 1

Entries on the DECC Pathways Calculator for our comparison pathways.

POLICY HR1 CCS1 CCS2 CCS3 CCS4 DEMAND SIDE Domestic transport behaviour 4 3 3 3 3 Shift to zero emission transport 3 2 2 2 3 Choice of fuel cells or batteries 2 2 2 2 1 Domestic freight 3 3 3 3 3 International aviation 2 2 2 3 2 International shipping 2 2 2 2 2 Average temperature of homes 4 4 4 4 3 Home insulation 4 3 3 3 3 Home heating electrification D C C C C Home heating that isn't electric D B B B B Home lighting and appliances 4 4 3 3 3 Electrification of home cooking B A A A A Growth in industry B B B B C Energy intensity of industry 3 3 3 3 3 Commercial demand for heating and cooling 4 3 3 3 3 Commercial heating electrification D D C C C Commercial heating that isn't electric D C C C C Commercial lighting and appliances 4 3 3 3 3 Electrification of commercial cooking B A A A A SUPPLY SIDE Nuclear power stations 1 1 1 1 1 CCS power stations 1.3 2 2 2 2 CCS power station fuel mix B C C B C Offshore wind 1.9 1.3 1.3 1.3 1.3 Onshore wind 2.7 1.5 1.5 1.5 1.4 Wave 1.6 1 1.3 1.3 1.3 Tidal Stream 2 1 1 1 1 Tidal Range 2 1 1 1 1 Biomass power stations 1 1 1 1 1 Solar panels for electricity 1.2 1 1 1 1 Solar panels for hot water 1.8 1 1 1 1

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Geothermal electricity 1 1 1 1 1 Hydroelectric power stations 2 1 1 1 1 Small-scale wind 1 1 1 1 1 Electricity imports 1 1.5 1.5 1.5 1.5 Land dedicated to bioenergy 3 3 3 3 3 Livestock and their management 2 2 2 2 2 Volume of waste and recycling B B B B B Marine algae 1 1 1 1 1 Types of fuels from biomass A B B B B POLICY HR1 CCS1 CCS2 CCS3 CCS4 SUPPLY SIDE Bioenergy imports 2 3 3 3 2 Geosequestration 1 2 2 2 2 Storage, demand shifting and interconnection 4 2 2 2 2

POLICY MP1 MP2 MP3 MP4 MP5 MP6 MP7 MP8 MP9 MP10 DEMAND SIDE Domestic transport behaviour 4 4 4 4 4 4 4 4 4 4 Shift to zero emission transport 3 1 1 1 1 1 3 2 2 1 Choice of fuel cells or batteries 1 1 1 1 1 1 1 1 1 1 Domestic freight 3 3 3 3 3 3 3 2 2 3 International aviation 3 2 2 2 2 2 3 3 3 3 International shipping 3 3 3 3 3 3 3 3 3 3 Average temperature of homes 4 4 4 4 4 4 3 4 4 4 Home insulation 1 3 3 3 3 3 1 3 3 3 Home heating electrification C A A A A A A A A A Home heating that isn't electric A A A A A A A A A A Home lighting and appliances 4 4 4 4 4 4 3 3 3 3 Electrification of home cooking B B B B B B A A A A Growth in industry B B B B B B B B B B Energy instensity of industry 3 3 3 3 3 3 3 3 3 3 Commercial demand for heating and cooling 4 3 3 3 3 3 3 3 3 3 Commercial heating electrification C C C C C C C C C C Commercial heating that isn't electric C C C C C C B B B B Commercial lighting and appliances 4 4 4 4 4 4 3 3 3 3 Electrification of commercial cooking A B B A A A A B B B SUPPLY Nuclear power stations 1 1 1 1 1 1 1 1 1 1 CCS power stations 2 2 2.1 2 2 2 2 2.5 1.9 1.9 CCS power station fuel mix B A A A A A C B B B Offshore wind 2 2 2.7 1.5 1.5 1.5 2.5 2.5 2.5 2.5 Onshore wind 1 1 1.3 1 1 1 1 1 1 1 Wave 1 1 1 1 2 3 1 2 2 2 Tidal Stream 1 1 1 1 2 3 1 1 1 1 Tidal Range 1 1 1 1 2 3 1 1 1 1 Biomass power stations 1 1 1 1 1 1 1 1 1 1 Solar panels for electricity 1 1 1 1 1 1 1 1 1 1

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Solar panels for hot water 3 3 3 3 3 3 3 3 3 3 Geothermal electricity 1 1 1 1 1 1 1 1 1 1 Hydroelectric power stations 1 1 1 1 1 1 1 1 1 1 Small-scale wind 1 1 1 1 1 1 1 1 1 1 Electricity imports 1 2 2 2 2 2 1 1 2.1 1.8 Land dedicated to bioenergy 3 3 3 3 3 3 3 3 3 3 Livestock and their management 2 1 1 1 1 1 2 2 2 2 POLICY MP1 MP2 MP3 MP4 MP5 MP6 MP7 MP8 MP9 MP10 SUPPLY SIDE Volume of waste and recycling B B B B B B B B B B Marine algae 1 1 1 1 1 1 1 1 1 1 Types of fuels from biomass B B B B B B B B B B Bioenergy imports 2 2 2 2 2 2 3 2 2 3 Geosequestration 2 2 2 2 2 2 1 1 1 1 Storage, demand shifting and interconnection 3 3 3 3 3 3 3 1 2 2

Key:

HR1 - Government higher renewables, more energy efficiency pathway (our comparable)

CCS1/4 – Government higher carbon capture and storage, more bio-energy pathway (our comparables)

MP1/10 – Government analogous to Markal pathway (our comparables)

Appendix 2

Calculations done by the DECC Pathways Calculator showing that our comparison pathways ALL achieve energy security with the same or less ‘back-up’ than the government equivalent pathway

Security C02 back up Nuclear Onshore Wind Level 4

Higher renewables more 80% 24 1.4 (5-6) 2.7 (11500) 12 energy efficiency Our comparison with above 80% 24 1 2.7 (11500) 11

Higher nuclear less energy 80% 11 2.7 (25) 1.4 (5840) 1 efficiency

Higher CCS, more bioenergy 81% 0 1.5 (6-7) 1.5 (6200) 1 Comp to Higher CCS, more bio v. 1 80% 0 1 1.5 (6200) 3 Comp to Higher CCS, more bio v. 2 80% 0 1 1.5 (6200) 1 Comp to Higher CCS, more bio v. 3 80% 0 1 1.5 (6200) 1 Comp to Higher CCS, more bio v. 4 81% 0 1 1.4 (5840) 0

Low cost pathway 80% 0 2.6 (23/4) 1 (4,400) 10

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Compare to above v 2 82% 0 1 (0) 1 (4,400) 10

Analogous to MARKAL 3.26 82% 7 1.8 (10/11) 1.3 (5480) 6 Comparison to MARKAL example 1 83% 0 1 (0) 1 (4,400) 5 * Comparison to MARKAL example 2 82% 5 1 (0) 1 (4,400) 4 * Comparison to MARKAL example 3 82% 1 1 (0) 1.3 (5480) 4 * Comparison to MARKAL example 4 82% 2 1(0) 1 (4,400) 4 * Comparison to MARKAL example 5 82% 4 1 (0) 1 (4,400) 4 * Comparison to MARKAL example 6 82% 0 1 (0) 1 (4,400) 4 * Comparison to MARKAL example 7 82% 7 1 (0) 1 (4,400) 1 * Comparison to MARKAL example 8 80% 7 1 (0) 2 (8000) 2 * Comparison to MARKAL example 9 81% 7 1 (0) 1 (4,400) 2 * Comparison to MARKAL example 10 83% 7 1 (0) 1 (4,400) 2 *

Appendix 3

Calculations done by the DECC Pathways Calculator showing that our comparison pathways ALL rely less on imported energy than the government equivalent pathway.

IMPORTS TWh/year Coal Oil Gas Bioenergy Uranium Electricity Total

Higher renewables more 0 290 18 70 336 0 714 energy efficiency Our comparison with above 0 278 135 70 0 0 483

Higher nuclear less energy 0 118 107 201 1605 0 2031 efficiency

Higher CCS, more bioenergy 23 368 214 140 420 15 1180 Compare to Higher, more bio v.1 0 368 320 140 0 15 843 Compare to Higher, more bio v.2 0 368 324 140 0 15 847 Compare to Higher, more bio v.3 177 351 182 140 0 15 865 Compare to Higher, more bio v.4 45 345 204 70 0 15 679

Low cost pathway 0 233 55 77 1496 0 1861 Compare to above v 2 540 110 170 70 0 0 890

Analogous to MARKAL 3.26 96 296 0 105 672 24 1193 Comparison to MARKAL example 1 37 310 331 70 0 0 748 Comparison to MARKAL example 2 228 419 41 70 0 30 788 Comparison to MARKAL example 3 253 419 40 70 0 30 812 Comparison to MARKAL example 4 228 419 48 70 0 30 795

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Comparison to MARKAL example 5 228 419 47 70 0 30 794 Comparison to MARKAL example 6 228 419 46 70 0 30 793 Comparison to MARKAL example 7 0 275 471 105 0 0 851 Comparison to MARKAL example 8 194 383 239 70 0 0 886 Comparison to MARKAL example 9 74 383 193 70 0 0 720 Comparison to MARKAL example10 39 367 192 140 0 24 762

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Written evidence submitted by the Wood Panel Industries Federation (WPIF)

About WPIF The Wood Panel Industries Federation (WPIF) represents all UK manufacturers of wood based panels, including OSB, particleboard and MDF. The industry annually consumes around 4.1 million green tonnes of wood (around 0.9 million of which is post‐consumer wood waste). WPIF’s members supply 60% of the UK demand for wood panels.

There are six wood panel plants in the UK – 3 in Scotland, 2 in England and 1 in Wales. These are in areas of high rural unemployment, and provide valuable employment opportunities, as well as contributing to the local and national economies.

The Impact of Energy Subsidies The wood panel industry relies on domestic wood to produce its products. As well as post‐consumer waste wood, over two thirds of the industries wood requirements comes from the sawmilling and forestry industries. This includes small roundwood and sawmill products (sawdust and chips), the very types of wood which are now being targeted by biomass burning power companies. Historically such wood was considered to be a waste, but the introduction of the wood panel industry and other product manufacturers has resulted in a strong market demand for all of these sources.

WPIF is extremely concerned about the unintended consequences of the Government’s subsidy regime which supports energy companies in burning wood which has an alternative use, and could be processed into furniture or construction materials. The unintended consequence of this policy is that the wood market is being distorted, prices are rising, and if left uncontrolled, existing users of the wood will be priced out of the market and displaced.

Biomass is unique amongst renewables, as the only technology which requires a fuel for which there are existing and competing users. This means that part of the subsidy paid to energy companies goes towards their purchase of the fuel (in this case wood), and consequently has an impact on the wider market for that material. WPIF does not believe that the uniqueness of biomass in this regard has been adequately considered in the design of the subsidy regime. The Renewables Obligation, and the proposed Contracts for Difference, are too blunt an instrument, and urgently need to be reassessed.

The scale of biomass required to meet the UK’s forecasts for deployment of this technology is around six to ten times the domestic wood harvest (a harvest which is already consumed in full by existing wood processors). As a result, it is inevitable that many tens of millions of tonnes of biomass will have to be imported to satisfy demand. The Government has long been aware of this, and has set the subsidy level at a rate which supports those importing wood. There is currently only one level of subsidy support (per technology band). No differentiation is made between domestic and imported wood, despite the fact that importing wood costs twice as much as using domestic wood. As a result, energy companies can buy domestic wood at higher than the normal market rate, and pass the additional subsidy benefit on to their shareholders. This will distort the wood market, and price traditional users, who operate in low margin businesses, out of the market completely. WPIF has, on very many occasions, proposed to DECC that support should be differentiated for 109

imported and domestic wood, and that only imported wood should receive a subsidy. WPIF has received a Legal Opinion from a top QC which states there would be no trade barriers to such a move, and we are happy to share this with the Committee if it would be helpful for your inquiry.

Given their commitment to ensure best returns for their shareholders, and the vast difference in price between domestic and imported wood, energy generators will use the subsidy to buy domestic wood. Despite most biomass installations still being in the planning process, Ofgem’s Annual Sustainability Report Dataset 2011‐2012 reports that around 1,621,393 tonnes of UK wood biomass was burnt during 2011‐2012, around 16% of the UK’s annual wood harvest. This includes reporting that ‘virgin wood’, ‘small round wood’, ‘wood chip’, ‘forestry residues’, ‘pellets’ and ‘waste wood’ were all burnt. The wood panel industry’s wood take is around one third roundwood, one third sawmill co‐products, and one third waste wood. These feedstocks are particularly attractive to generators as they are traditionally of lower value than sawlogs. This leaves the wood panel industry particularly vulnerable to the growth in biomass burning.

Industry reports show that since 2008 the wood price paid by our sector has increased by 57%. However, the sales prices of our panels has only increased by 31%. In real terms sale prices are now at 52% of the 1995 price (when records began). This rate of divergence has increased since 2010 and, although we understand that in any market prices can fluctuate, it is this divergence between feedstock and product sales price that is particularly concerning for our industry.

As well as an economic impact, and a potential loss of jobs, the risk of displacement also has environmental consequences. Wood panel production produces only 378kg (with CHP) or 458kg (without CHP) per tonne of wood used, whereas burning wood for electricity generation produces 1,950kg of CO2. An independently produced report by Carbon River report states that over the lifecycle of a tree 1,370kg CO2 is sequestered per tonne of timber processed in the wood panel industry. Over the lifecycle of a tree the net emission is 157kg CO2 per tonne of timber processed in the biomass industry. Carbon River’s report also states that displacement of the wood panel industry would increase net emissions by 6 million tonnes per annum (more than 1% of the UK’s reported emissions in 2008).

We believe that the Government needs to act urgently to address the unintended, but very real, consequence of current subsidies to biomass power stations. The Scottish Government has accepted the risk, to existing wood users, of large new entrants into the market for this finite resource, and has capped at 15MW the size of dedicated biomass plant which is eligible for subsidy support. WPIF supports this measure, however this does not address the impact of the largest entrants into the field (converted coal plants, and co‐firing coal plants). WPIF urges the UK Government to look at means of reducing the impact of these plants, and ensuring that wood processors have a future in the UK.

12 June 2013

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Written evidence submitted by Friends of the Earth England, Wales and Northern Ireland

1. Friends of the Earth is pleased to submit evidence to this extremely important inquiry, and would like to thank the Committee for initiating it.

2. The Government is increasing, not decreasing, financial support for fossil fuels. The Committee is interested in whether the Government appears to have plans to phase out environmentally harmful energy subsidies, and what progress they are making. The Government is in a headlong rush to issue tax discounts for new fossil fuel exploration (from the North Sea and, looking forward, shale gas). Rather than winding down fossil fuel subsidies the Treasury is in active behind-the-scenes discussions with the shale gas industry about which new ones to introduce, and it has delivered a package of North Sea tax support which has been heartily welcomed by Oil and Gas UK.

3. Some things need subsidy, like renewable energy. As stated by the very helpful scoping study produced by Oxford Energy Associates (OEA)1 for the Committee, discussions about energy subsidies are characterised by more heat than light. It is right to subsidise critically needed new industries like solar and wind power; even if domestic decarbonisation was not urgently required (which it is) we must seize the opportunity for the UK to build supply chain capacity and manufacturing prowess in the technologies that are being fast adopted across the developed and developing world. There is a market failure. Incumbent dirty energy has benefitted – and still does - from generations of financial and institutional support. As Rob Gross at Imperial College argues, targeted support for new technologies “have what economists call dynamic effects: they foster innovation, yield increasing returns to adoption and help low carbon technologies move along their learning curve. Thus, targeted subsidies bring down the cost of low carbon technologies, creating options which can be deployed cost-effectively in the future”2.

4. Fossil fuel subsidies cannot be justified economically or environmentally. The corollary, as the EU, G20 and International Energy Agency stress, is that we must end implicit and explicit support for the extremely well establish and infrastructurally embedded use of fossil fuels. The Chief Economist of the IEA has called dirty energy subsidies the “appendicitis” of the global energy system, which must “be removed for a healthy energy economy”3. We agree. We also welcome that the OEA study draws attention to the biggest energy subsidy of all: the failure to require fossil fuel producers to pay the full social, environmental and long- term economic impact of climate change. The IMF points out that this is the single largest global energy subsidy once properly accounted for4.

1 Oxford Energy Associates, Written evidence commissioned by the Environmental Audit Committee, May 2013, http://data.parliament.uk/writtenevidence/WrittenEvidence.svc/EvidencePdf/700 2 Imperial College London, On Picking Winners: the need for targeted support for renewable energy, 2012, https://workspace.imperial.ac.uk/icept/Public/On%20Picking%20Winners%20low%20res.pdf 3 Guardian, ‘Phasing out fossil fuels could provide half of global carbon target’, 2012, http://www.guardian.co.uk/environment/2012/jan/19/fossil‐fuel‐subsidies‐carbon‐target 4 IMF, ‘Reforming Energy Subsidies’, March 2013, retrieved from http://www.imf.org/external/np/fad/subsidies/index.htm

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5. There can be no room for dogma or artificially narrowly and politically expedient definitions of subsidy. What matters is that the balance of support in all its forms must be rapidly tilted towards the clean industries of the 21st century.

6. This submission focuses on dirty energy subsidies in the UK. We believe the balance of attention and controversy has unjustly settled upon the relatively minor balance of subsidy to immature renewable energy technologies, rather than the outrage of explicit and implicit subsidies for fossil fuels. We start by reiterating the case made by the IMF, OECD and International Energy Agency for a broad definition of a subsidy – into which the Government’s recent tax breaks for oil and gas exploration would fall. We then examine

• the rapid expansion over the last financial year of ‘field allowances’ to encourage the production of oil and gas from the UK Continental Shelf

• the prospects for a similar future favourable tax regime for unconventional fossil fuels, including shale gas, and its implications

• The flawed Capacity Mechanism, which looks likely to create an unnecessary and avoidable subsidy for fossil fuels.

Definition of a subsidy

7. The International Monetary Fund (IMF) defines an energy subsidy as anything that affects what the price for energy would otherwise have been in a perfectly competitive market – the ‘price gap’ approach. The IMF bypasses semantics to point out that in practice “although energy subsidies do not always appear on the budget, they must ultimately be paid by someone.” 5 The IMF includes within this definition the implicit subsidy given to fossil fuel energy by not incorporating within its price the full cost of the social and environmental damage caused by climate change. It is not possible to accurately price this subsidy, and indeed many of the attempts to do so miss entire categories of impact – but it is indeed likely to be very large.

8. The OECD define a subsidy similarly broadly: “Governments support energy production in a number of ways, including by: intervening in markets in a way that affects costs or prices; transferring funds to recipients directly; assuming part of their risk; selectively reducing, rebating or removing the taxes they would otherwise have to pay; and undercharging for the use of government-supplied goods or assets… the scope of ‘support’ is deliberately … broader than some conceptions of subsidy”6. The International Energy Agency provides the most straightforward definition: “an energy subsidy is defined as any government action that lowers the cost of energy production, raises the revenues of energy producers or lowers the price paid by energy consumers.”7

5 IMF, Energy Subsidy Reform: Lessons and Implications, January 2013, http://www.imf.org/external/np/pp/eng/2013/012813.pdf 6 OECD, An OECD‐wide inventory of support to fossil‐fuel production or use, 2012, http://www.oecd.org/site/tadffss/PolicyBrief2013.pdf 7 IEA, OECD, World Bank, ‘The Scope of Fossil Fuel Subsidies in 2009 and a roadmap for phasing out fossil‐fuel subsidies’, 2010, http://www.worldenergyoutlook.org/media/weowebsite/energysubsidies/second_joint_report.pdf

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9. Under any of the definitions of energy subsidies listed above - a far more nuanced and sensible discussion of subsides in practice than is often allowed for in public debate - it is clear that the UK fossil fuel industry is heavily subsidised. Subsidies come directly through field allowances and other supportive tax measures, and indirectly via the failure of the Government to reflect the real social and environmental cost of the damage caused by climate change.

10. For Europe, the EU's State Aid rules are clear there are two main conditions for subsidies: environmental protection and helping infant technologies8. Two main actions follow from this: First, helping infant technologies is a good justification for providing subsidy. There is a follow-up - clearly, technologies are not infant for long. Mature technologies should not receive subsidy, and infant technologies' subsidies should fall as their costs fall and incumbent's unfair advantages diminish. Second, don't subsidise environmentally damaging industries, whether they're infant or not. Indeed, environmentally damaging, mature technologies should be the absolute priority for having subsidies removed.

UK fossil fuel tax breaks: 'field allowances' and tax certainty

11. This central section of our response focuses on ‘field allowances’ – Government reductions on the headline rate of tax payable from profits from certain designated oil and gas fields. We focus on this area for two reasons. First, because it represents a significant increase in subsidy to the fossil fuel industry consciously driven forward by this Government, in particular over the last financial year. Second, we note the OEA scoping study lacks the latest data in this area, which our research is able to provide.

12. Field allowances are a relatively new phenomena and their expansion over the last twelve months has been significant.

• Field allowances were first introduced by Alistair Darling in Budget 2009 and have been rapidly expanded by George Osborne, in particular over the last financial year (see below).

• Of the 34 licences awarded in 2012/13, 28 qualified for one of the Chancellor’s expanded suite of field allowances.

• Oil and gas fields that qualify for a field allowance pay less tax on the profits from production from those fields than they otherwise would; in addition to the 30% corporation tax rate levied on profits from oil and gas production, an extra ‘supplementary charge’ of 32% is generally levied, taking the headline tax rate to 62%9.

• However field allowances waive this additional supplementary charge for up to five years. As an example of how field allowances work, consider the £3 billion 'large

8 Directive 2009/72/EC of the European Parliament and of the Council, http://eur‐lex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:32009L0072:EN:NOT 9 Some older fields (pre‐1993) also pay the Petroleum Revenue Tax of an additional 50 per cent, which can be deducted from their corporation tax rate, meaning profits from about 30 such fields are taxed at a marginal rate of 81 per cent.

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deep water oil field' allowance created in Budget 2012, designed specifically to encourage investment off the coast of Shetland. Over five years the allowance allows £3 billion in profits from that field to not be subject to the 32% supplementary charge, reducing total tax payment over that period by £960 million (£3 billion x 0.32).

13. The oil and gas industry should pay high taxes. It is worth reflecting here that the high tax rate supposedly levied on oil and gas is entirely appropriate. Fossil fuel production remains highly profitable even after tax, and it is right that the Exchequer benefits from the exploitation of a national resource. Of most relevance to the terms of this inquiry, even after these high rates of tax the fossil fuel industry evades having to pay the full social and environmental cost of its activity; the Stern report estimated that climate change caused by fossil fuels could reduce global GDP by 20 per cent, to say nothing of the impact of oil spills and air pollution.

14. New research by Friends of the Earth10 shows that the total value to the industry over five years of the 28 field allowances awarded in 2012/13 is £1.952 billion:

• 17 ‘Small Field Allowances’, each worth up to £48 million over five years = £816 million

• 9 ‘Brown Field Allowances’, each worth up to £160 million over five years = £720 million

• 1 ‘Shallow-Water Gas Field Allowance’, worth up to £160 million over five years

• 1 ‘Ultra-Heavy Oil Field Allowance’, worth up to £256 million over five years.

15. Field allowances are clearly subsidies. They are a reduction in the headline rate of tax payable on non-qualifying oil and gas fields. HMRC notes that the field allowances are explicitly designed to “increase investment and production in fields that are economic but – for tax reasons – are considered to be commercially marginal”11: they lower the cost of energy production by reducing the overall tax rate payable on those fields. Under any of the sufficiently broad definitions of a subsidy outlined above, it is not credible for Oil and Gas UK CEO Malcolm Webb to claim that “the oil and gas industry enjoys no subsidy from Government… field allowances are not subsidies”12.

16. Either the allowances stimulate new dirty energy, or they are a tax give away in a time of public spending restraint. What is not clear to the external observer is the extent to which the economics of the 28 fields licensed with qualifying allowances since Budget 2012 were sufficiently marginal that the allowances 'tipped the balance' to allow new investment to take place. As the field allowances apply uniformly to qualifying fields regardless of need, it is possible that by expanding the availability of allowances the Treasury is merely foregoing tax

10 Friends of the Earth, UK fossil fuel tax breaks 2012/13, May 2013, http://www.foe.co.uk/resource/briefings/uk_fossil_fuel_tax_breaks.pdf 11 HMRC, Tax Information and Impact Note: Field Allowances, 2012, http://www.hmrc.gov.uk/tiin/field‐allowances.pdf 12 Platform London, ‘The Battle of Definitions: no subsidies for the oil industry’, May 2013, retrieved from http://platformlondon.org/2013/05/13/the‐battle‐of‐definitions‐no‐subsidies‐for‐the‐oil‐industry/

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revenue it would otherwise have received for activity that would have happened anyway. Illustratively, even if only a quarter of the new licenses did not economically depend on the allowances, it amounts to half a billion pounds of tax revenue foregone over five years. At the individual field level therefore field allowances are doing one of two things: either improving otherwise marginal economics to the point that an investment now becomes viable, meaning oil and gas that would otherwise have stayed in the ground now gets extracted; or merely foregoing tax revenue at a time of immense pressure on the public purse. Friends of the Earth believes either is unjustifiable.

17. Government expects that the allowances will stimulate oil and gas production. The Treasury states that it is indeed encouraging oil and gas drilling that would otherwise not happen. For example, the Treasury considers that the long term tax revenues from the ‘Brown Field Allowance’ introduced in September 2012 will “significantly outweigh the initial cost of the allowance"13. For as long as oil and gas extraction is taking place, it is right to tax it heavily. But there is a world of difference between that and actively increasing fossil fuel production in order to get more tax revenue into the Exchequer. It is the very opposite of a green economy.

18. The industry is delighted with the tax breaks. The environmental impact of the Chancellor’s approach can be surmised through the reaction of oil and gas producers themselves.

• The package of measures announced on oil taxation in Budget 2012 – including some of the new field allowances, together with a commitment from the Chancellor to legislate for a fixed rate of tax on decommissioning oil rigs and other assets – was greeted rapturously by the industry. Oil and Gas UK described the package as a "turning point for the industry"14

• Mr Osborne's pledge to introduce a fixed rate of tax for decommissioning was claimed by OGUK to lead to £40 billion of new investment, producing 1.7 billion barrel equivalents of oil and gas. Friends of the Earth calculates that this much oil and gas, when burned, would produce as much carbon dioxide as the UK currently emits in a year.15

• In February 2013 OGUK declared that "after two disappointing years brought about by tax uncertainty and consequent low investment, the UK continental shelf is now benefitting from record investment in new developments and in existing assets and infrastructure, the strongest for more than three decades... The recent introduction of targeted tax allowances to promote the development of a range of difficult projects, coupled with the government's ground-breaking commitment to provide certainty on

13 HM Treasury, ‘Chancellor announces further action to stimulate investment in North Sea’, 2012, retrieved from https://www.gov.uk/government/news/chancellor‐announces‐further‐action‐to‐stimulate‐investment‐in‐north‐sea 14 Energy Voice, ‘2012 Budget a turning point, says O&GUK’, 2012, retrieved from http://www.energyvoice.com/2012/03/2012‐ budget‐a‐turning‐point‐says‐oguk/ 15 Friends of the Earth, ‘Oil and gas tax breaks’, 2012, http://www.foe.co.uk/resource/media_briefing/tax_breaks.pdf

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decommissioning tax relief, has prompted global companies and independent businesses alike to take another look at the UK as an investment destination."16

19. The Government is to conduct a review of how else to attract the oil and gas industry – the diametric opposite of the review it should be conducting. The Government has decided that will send out a clear message to the oil and gas industry that its business is wanted; tax breaks play a symbolic, not just economic, role in creating this message. In June 2013 the Government announced a review, to be led by Sir Ian Wood, into how maximise “economic” extraction of oil and gas from the North Sea17. As HMRC note above, lowering tax rates is evidently seen as a viable mechanism to as part of maximizing the economic viability of fossil fuel production. The review that the Government should be conducting is how to strategically, fairly but urgently wind down high carbon industries like oil and gas production and wean the UK's tax receipts off the revenues it provides – not how to actively keep our economics and revenues hooked on unsustainable dirty energy production.

20. Only 20 per cent of global fossil fuel reserves can be burned. The short term temptation of ramping up domestic production of oil and gas is the UK’s role in a global race to the bottom. Only one fifth of already proven fossil fuel reserves can be burned if we are to keep global temperature rise to be low two degrees18 – the stated aim of UK, EU and G20 climate policy. Investors risk responding to the Chancellor's green light by ploughing money into fossil fuel production that risks being stranded assets if global climate policy tightens as it should – or which hcontributes to potentially runaway climate change if it doesn't.

21. The UK’s impact on climate change extends far beyond how it accounts for its own carbon budgets. The Government states that there is no need to worry about the climate implications of increased domestic supply because it doesn’t affect our domestic carbon accounting: “what the emissions in the UK will be is the thing that is targeted by the Climate Change Act, and other countries are responsible for all the emissions in their territories… the level of activity in the North Sea in such a highly globalised market, as is the case for oil, would be likely to have an impact on UK territorial emissions” (our emphasis)19. Satisfying carbon accountants is one thing, but can ignore the basic physics: if field allowances work, oil and gas that would otherwise have stayed in the ground will be dug up and, presumably, burned as a result of the chancellor's tax breaks. Any international oil displaced from UK markets by increased domestic consumption will be used elsewhere instead.

22. Where is the similar emphasis on renewable energy? This rhetorical support does not stand in isolation from his position on other forms of energy: compare the Chancellor's enthusiasm for fossil fuels (Budget 2012: "gas is cheap… I also want to that ensure we extract the greatest possible amount of oil and gas from our reserves in the North Sea."20)

16 BBC News, ‘North Sea oil investment at 30‐year high, industry says’, February 2013, http://www.bbc.co.uk/news/business‐ 21564947 17 DECC, ‘Economic benefits of offshore oil and gas to be maximized’, June 2013, https://www.gov.uk/government/news/economic‐ benefits‐of‐offshore‐oil‐and‐gas‐to‐be‐maximised 18 Carbon Tracker, Unburnable Carbon 2013: wasted capital and stranded assets, 2013, http://www.carbontracker.org/wastedcapital 19 House of Commons, Corrected Transcript of Oral Evidence taken before the EAC on Budget 2012, retrieved from http://www.publications.parliament.uk/pa/cm201012/cmselect/cmenvaud/c1931i/1931i.htm 20 Friends of the Earth, ‘Budget 2012 reaction’, http://www.foe.co.uk/resource/briefings/budget_2012_reaction.pdf

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with his rhetorical downplaying of the "costs" of renewable subsidies (also Budget 2012: “Renewable energy will play a crucial part in Britain's energy mix - but I will always be alert to the costs we are asking families and businesses to bear. Environmentally sustainable has to be fiscally sustainable too”). In practice, renewable energy support extends little beyond the £7.6 billion allocated within the levy control framework to 2020, an amount sufficient to pay for little more than the amount of renewable energy required under the EU Renewables Directive. What the Chancellor gives with one hand he takes away with the other: support for renewable energy counts for much less than it ought if rhetorical, explicit and implicit subsidies for fossil fuels are still so high on the Government's agenda.

Shale and other unconventional gas

23. The Chancellor's determination to support the UK fossil fuel industry has led him to pledge a 21 consultation on "new tax incentives" for the nascent UK shale gas industry. As the Economist notes, "Nurturing Britain’s oil industry has other advantages too. Convincing investors of the stability of its tax regime will help as the government tries to lure investors onshore to drill for shale gas"22. Tax breaks for offshore oil and gas have created a precedent for onshore: Francis Egan, Chief Executive Officer of Cuadrilla Resources, told the Energy and Climate Change Committee in December 2012 that “we are not asking for a special regime. The Treasury is deciding whether the existing offshore regime should be applied to the onshore”. 23

24. In June 2013 the energy minister, Michael Fallon, gave an update on progress: "the Chancellor has announced the fiscal incentives that will apply, they are being discussed in detail with the industry and they will be firmed up by the summer and they will be in the Autumn Statement and they’ll take effect from next April"24 . In actual fact, however, at the time of writing the Chancellor had not announced details on the tax regime that would apply. The promised “consultation” has been conducted opaquely behind Treasury doors.

25. The Chancellor appears to have decided to publicly offer “generous” tax incentives for shale prior to analyzing whether they are needed. Friends of the Earth submitted Freedom of Information requests to HM Treasury to attempt to understand the extent to which favourable tax treatment is required by the industry. We learned that although the Chancellor first announced his intention to bring in a “generous” new tax regime for shale in early October 201225, the first “introductory meeting” for the shale gas industry to discuss the “economics of the UK shale gas industry; how tax is currently affecting companies’

21 HM Treasury, ‘Autumn Statement 2012: Chancellor’s statement’, retrieved from https://www.gov.uk/government/speeches/autumn‐statement‐2012‐chancellors‐statement 22 The Economist, ‘Drill, maybe, drill’, May 2013, retrieved from http://www.economist.com/news/britain/21577105‐spurt‐oilfield‐ decline‐could‐keep‐economy‐above‐water‐drill‐maybe‐drill 23 House of Commons, Corrected Transcript of Oral Evidence taken before the Energy and Climate Change Committee on ‘the impact of shale gas on energy markets’, 11 December 2012, retrieved from http://www.publications.parliament.uk/pa/cm201213/cmselect/cmenergy/c785‐ii/c78501.htm 24 The House Magazine, ‘Energy Booster’, June 2013, retrieved from http://www.politicshome.com/uk/article/79643/energy_booster.html 25 George Osborne’s speech to Conservative Party Conference 2012.

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investment assumptions; [and] the commercial framework within which companies are considering shale gas investments” was only held on 5 November 201226.

26. Tax may be only a marginal consideration for shale investors. We also learned that industry representatives advised the Government in November that “[although] it was positive that the Government was talking about oil and gas so publicly… the market for gas would probably drive exploration more than tax or technology in the short term” (our emphasis)27. This tallies with Francis Egan’s (op cit) suggestion to the ECC Committee, in response to a question asking how the existing tax regime is affecting Cuadrilla, that “we are not impeded by the tax regime”28. As discussed earlier in this submission, any tax reductions that do not have a material impact on investment decisions are little more than giveaways.

27. Enough is enough. Friends of the Earth opposes shale gas production on environmental and economic grounds. For the same reason as for oil and gas from the North Sea, we do not consider it prudent to be actively pursuing new sources of fossil fuels from unconventional sources, nor building our national tax strategies and the long term health of the public finances upon them. Even if a case could be made for making the most of existing investment in the North Sea as stocks inevitably decline – which we do not believe it can, given the urgent need to turn attention elsewhere – it most certainly could not be made for breaking out into a new frontier of fossil fuel exploration, extraction, and consumption. As an absolute first step, there should be no subsidies for shale gas exploration.

The Capacity Market

28. The current Energy Bill introduces a new policy – the Capacity Market – which is designed to ensure security of power supply as the amount of variable generation capacity increases over time and older coal fired plant is removed from the system due to European air pollution legislation. Auctions run by the National Grid would procure a volume of generation capacity judged necessary to meet projected demand. The cost would be recovered though charges, ultimately feeding through to consumer and business power bills.

29. The Capacity Market was not the best option. Friends of the Earth has made clear its concern that the Capacity Market may not be the best mechanism to achieve its stated objective. If support is needed for any fossil fuel power stations, potentially needed to help meet underpin future demand but no longer otherwise profitable due to lower wholesale prices caused by cheaper renewable energy, then a Strategic Reserve option would provide better value for money. This option has been rejected by DECC. We believe the preparations for the Capacity Market were premature29 and have created the circumstances where its use is

26 Information released by HM Treasury in response to Freedom of Information request, see http://www.foe.co.uk/resource/briefing_notes/foi_on_hm_treasury_engagem.pdf 27 Information released by HM Treasury in response to Freedom of Information request, see http://www.foe.co.uk/resource/briefing_notes/foi_minutes_ogff_2012.pdf 28 Evidence to ECCC, op cit. 29 Friends of the Earth, ‘Don’t panic – why even Ofgem are relaxed about a blackout scare’, October 2012, retrieved from http://www.foe.co.uk/news/ofgem_37741.html

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now essential as power companies have sat on their hands. In addition alternative mechanisms to generation capacity – such as demand side response and reduction, interconnectors, and storage – have been given insufficient priority in the Capacity Market plans or in Government policy more generally.

30. Unnecessary subsidy for fossil fuels will be created by the Capacity Market. According to DECC's Impact Assessment gross revenues to capacity providers are modelled to be up to £2.5 billion per annum, or £10 billion in total between 2024 and 203030 - assuming no payments are made before 2024. Evidence from one existing capacity auction in the United States31 (the PJM market), cited by DECC as a model for its Capacity Market, is that existing fossil-fuel resources (gas, oil and coal-fired) have received 70% of the $42 billion in capacity payment revenues under those auctions, with only 3% going to demand side resources.

12 June 2013

30 DECC, Impact Assessment: Electricity Market Reform –Capacity Market, November 2012, https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/66039/7103‐energy‐bill‐capacity‐market‐impact‐ assessment.pdf 31 M Gottstien, RAP, Beyond Capacity Markets ‐ Delivering Capability Resources to Europe’s Decarbonised Power System’, March 2012, www.raponline.org/document/download/id/4854

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Written evidence submitted by the Nuclear Industry Association

1. The Nuclear Industry Association (NIA) welcomes this opportunity to respond to the Environmental Audit Committee’s inquiry.

2. NIA is the trade association and information and representative body for the civil nuclear industry in the UK. It represents around 270 companies operating in all aspects of the nuclear fuel cycle, including the current and prospective operators of the nuclear power stations, the international designers and vendors of nuclear power stations, and those engaged in decommissioning, waste management and nuclear liabilities management. Members also include nuclear equipment suppliers, engineering and construction firms, nuclear research organisations, and legal, financial and consultancy companies.

3. As the trade association for the nuclear industry the NIA does not have the expertise to provide detailed responses to the five specific questions posed by the Committee, which are essentially a matter for Government. We would however like to make some higher level points relating to the financing of new nuclear plants.

4. As the Oxford Energy Associates (OEA) report to the Committee emphasises the energy subsidies issue is complex. There are diverse views on how they should be defined, and both wider and narrower parameters have been used. In the UK the Government’s approach has been to use a narrower definition for subsidies to the electricity industry, which has had the benefit of providing a clear picture of specific support measures including their impact on the energy economy.

5. Against this background, and our reading of the OEA report, we believe the Government’s Electricity Market Reform proposals are not a key issue for the Committee. We would regard their provisions – including the CfD arrangements and the carbon floor price – not as subsidies but as enablers to facilitate the UK’s wider energy policy.

6. The UK’s current nuclear power stations have been making a major contribution to the UK’s energy supplies over many years, operating in a competitive market and without subsidy. However, with much of our nuclear and coal fired capacity closing over the next few years, the UK needs credible plans to replace that capacity and to decarbonise the power sector if it is to meet its energy security and climate change targets. The EMR proposals are designed to provide investors with the certainty they need to proceed with the low carbon plant – both nuclear, renewables and potentially CCS – needed to achieve this.

7. Whilst nuclear and low carbon generation generally have lower operating costs than fossil generation, their higher up front capital costs mean they are difficult to finance in the current market. The EMR proposals are therefore addressing a market failure. Without such action the UK would be locked into a high carbon energy scenario.

8. In this context the Oxford Energy Associates report comments that subsidies have become synonymous with bad economic practice, and are generally assumed to reduce economic efficiency. The EMR proposals will not have 120

this effect. In the case of nuclear the introduction of new plant will provide long term price stability for consumers, protecting them from high or volatile fossil fuel prices. The Government view is that electricity bills after the implementation of EMR are expected on average to be lower than they would have been in the period up to 2030. Moreover the Climate Change Committee recently concluded that delaying investment in low carbon technologies to the 2030s would be likely to drive up costs – by up to £100bn in some scenarios.

9. To sum up, the EMR proposals are carefully designed to create a level playing field for all low carbon generation technologies at minimum cost to consumers. The NIA believes this will not only help the UK meet its energy security and carbon reduction objectives, but will also protect the consumer from long term price increases.

10. Finally, in relation to the UK’s historic liabilities, we would note that the Nuclear Decommissioning Authority was set up in 2005 to decommission and clean-up these sites. Whilst the cost of this work is being funded from the NDA’s commercial operations and the UK Government, we would suggest this should properly be regarded not as a subsidy but the cost of dealing with a public sector liability from the historic nuclear research and development and public sector operation of the Magnox power station fleet.

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121

Written evidence submitted by Platform

SUMMARY

1. Any discussion of fossil fuel subsidies in the UK context should recognise that the majority of subsidies are off-budget – that is, transfers to energy producers and consumers that do not appear in national accounts as government expenditure. 2. The government should widen its definition of energy subsidies to fit with that given by the International Energy Agency, which describes subsidies as “any government action that concerns primarily the energy sector that lowers the cost of energy production, raises the price received by energy producers or lowers the price paid by consumers.” 3. Platform has identified three main types of off-budget subsidy that need to be quantified and curtailed: Export Credit, Diplomatic and Military. 4. To effectively tackle our dependence on fossil fuels, it is crucial to bring to light and end the existing, wide-ranging government subsidies for fossil fuel companies, whether direct or off-budget.

BACKGROUND

1. Platform is a London-based research organisation that has monitored the social, economic, environmental and human rights impacts of the British oil and gas industry for over fifteen years. Our work is regularly published and cited by governments, academia, media and corporations. We are consulted for expertise by human rights defenders, parliamentarians and journalists. We have in-depth knowledge on British oil companies operating in Nigeria, Iraq, the Caspian and North Africa.

FACTUAL INFORMATION

1. This committee is interested in the scale of energy subsidies in the UK and whether the government has plans to reduce ‘harmful’ subsidies. 2. Currently the government is heavily supporting fossil fuels with energy subsidies and is increasing rather than decreasing this support. The IMF state that current energy subsidies “distort resource allocation by encouraging excessive energy consumption, artificially promoting capital-intensive industries, reducing incentives for investment in renewable energy, and accelerating the depletion of natural

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resources”.1 3. The government is offering tax discounts for new fossil fuel exploration (from the North Sea and, further in the future, Shale Gas). 4. New research by Friends of the Earth revelled that the UK oil and gas industry received tax breaks worth £1.952 billion over five years during the financial year 2012 /13.2 5. In addition there are several types of ‘off-budget’ subsidy provided by the British state that provide significant support for fossil fuel companies.

DEFINING SUBSIDIES

1. This paper also discusses the first and second questions of the inquiry (1) whether the Government has identified the extent of energy subsidies, and measured them and (ii) how well any identification of subsidies by the Government matches up to best practice methodologies in how energy subsidies are defined and scoped. 2. The International Energy Agency (IEA) defines subsidies as “any government action that concerns primarily the energy sector that lowers the cost of energy production, raises the price received by energy producers or lowers the price paid by consumers.”3 3. The OECD also offer a broad definition of a subsidy: “Governments support energy production in a number of ways, including by: intervening in markets in a way that affects costs or prices; transferring funds to recipients directly; assuming part of their risk; selectively reducing, rebating or removing the taxes they would otherwise have to pay; and undercharging for the use of government-supplied goods or assets…the scope of ‘support’ is deliberately…broader than some conceptions of subsidy”4 4. The IMF states that “although energy subsidies do not always appear on the budget, they must ultimately be paid b someone”5 5. However, the UK government only identifies and measures direct energy subsidies rather than considering the other services provided for free by the UK state to British oil companies. The majority of fossil fuel subsidies are off-budget – that is, transfers to energy producers and consumers that do not appear in national accounts as government expenditure.

1 http://www.imf.org/external/np/pp/eng/2013/012813.pdf 2 Friends of The Earth Fossil fuel subsidies additional information, David Powell 3 IEA, Economic Analysis Division, ‘Carrots and Sticks: Taxing and Subsidising Energy’, 17/1/06 http://www.iea.org/papers/2006/oil_subsidies.pdf 4 OECD, An OECD-wide inventory of support to fossil-fuel production or use, 2012 http://www.oecd.org/site/tadffss/PolicyBrief2013.pdf 5 http://www.imf.org/external/np/pp/eng/2013/012813.pdf

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6. Platform has identified three main types of off-budget subsidy that need to be quantified and curtailed: 7. Export credit. The UK government underwrites (takes on the financial risk of) overseas oil and gas projects through UK Export Finance. In June 2012, the UKEF submitted a proposal to the Azeri State Oil Company to underwrite a new oil & gas refining and petrochemicals complex.6 8. Diplomatic. The FCO maintained a consulate in Basra largely to support UK oil companies, with three diplomats on staff and a £6.5 million budget. High-profile UK political figures appear on request of oil companies for deal signing, such as Huhne attending the signing ceremony during BPs first attempt to broker a deal with Rosneft. 9. Military. The UK Government spent £12 million on military aid to Nigeria, at least in part due to Shell’s lobbying effort.7

EXPORT CREDIT SUBSIDIES

1. UK Export Finance (UKEF), previously known as the Export Credits Guarantee Department (ECGD), offers billions of pounds of public money every year as credit lines and insurance for UK companies exporting overseas. 2. This subsidy has been provided to oil and gas companies, despite Coalition commitments to end “investment in dirty fossil-fuel energy production.” 3. ECGD, and now UKEF’s, decision-making has been controversial. Crucial information regarding dangerous impacts is repeatedly - and sometimes consciously - ignored. 4. Offers for credit lines for particular projects are often made first, with the various potential UK exporters only identified later. 5. UKEF has no climate change policy for its projects, nor does it have an emissions reduction target. To this day, UKEF continues to provide financial support to some of the most controversial fossil fuel projects.

Particularly problematic subsidies provided by the ECGD/UKEF include:

6. KBR - Bonny LNG – Nigeria. UKEF decided to finance a UK subsidiary of Halliburton, despite specific allegations of the company’s corruption in relation to the Bonny LNG project being common knowledge. After international investigations started into the bribery, minutes of meetings between UKEF and Halliburton show UKEF failing to ask Halliburton for crucial details of the

6 http://platformlondon.org/2012/06/25/rbs-ecgd-offer-billions-in-public-money-to- expand-caspian-fossil-fuel-infrastructure 7 http://platformlondon.org/wp-content/uploads/2012/07/MoD-Military-training- Amunwa-Response-22.pdf

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allegations, telling the company that it did not wish to ‘delve into the finer details’ of the consortium’s arrangements. The Halliburton subsidiary eventually plead guilty in both the USA and UK8.

7. Shell - Sakhalin II – Russia. Shell’s drilling, pipelines and LNG plant in Arctic conditions on the Sakhalin Island in Russia threatened indigenous populations and highly endangered populations of whales. Nonetheless, UKEF gave a secret but legally-binding commitment to support the project in March 2004 worth £1 billion, before an adequate EIA had been completed and before UKEF’s own assessments were complete.9 The application to UKEF was only withdrawn because of a judicial review over its illegality.

8. BP - Baku-Tbilisi-Ceyhan Pipeline - Azerbaijan / Georgia / Turkey UKEF chose to support this project to the tune of at least £81.7 million, despite a multitude of reported and documented infringements on citizens’ rights. There were over a hundred violations of World Bank standards10, emergency powers were invoked to acquire land in Turkey, and the UK government itself ruled that BP had violated international rules by failing to investigate complaints of intimidation by state security forces in Turkey.11

9. Petrobras – ultra-deep drilling – Atlantic Ocean In 2011-12, UKEF agreed a $1 billion credit line to support Brazil’s state-owned oil company Petrobras conduct ultra-deep drilling in the pre-salt oil deposits in the Atlantic Ocean.12 This drilling is more complicated and dangerous than the deep Gulf of Mexico waters where BP’s Deepwater Horizon disaster took place.

10. Other fossil fuel subsidies provided by the UKEF in the last two years include: £65 million for a petrochemical plant in Saudi Arabia, £22 million to a Norwegian offshore oil contractor, £6m for a petrochemical plant in Azerbaijan and £6m for a gas plant in Nigeria.13

11. Lisa Nandy MP, chair of a parliamentary inquiry into UKEF said: "It is a cause of real concern that, despite the coalition commitment to end all export finance for dirty fossil fuels, particularly the risky Atlantic oil drilling, UKEF still

8 The Next Gulf: Rowell, Marriott, Stockman, Constable and Robinson Ltd. 2005 chapter 6. 9 http://www.thecornerhouse.org.uk/resource/wwf-files-court-proceedings-against- government-department 10 http://www.baku.org.uk/eia_review.htm 11 http://www.thecornerhouse.org.uk/resource/bp-violating-human-rights-rules-says-uk- government 12 http://www.ukexportfinance.gov.uk/assets/ecgd/files/publications/plans-and- reports/ann-reps/uk-export-finance-annual-report-and-accounts-2011-12.pdf 13 http://www.ukexportfinance.gov.uk/assets/ecgd/files/publications/plans-and- reports/ann-reps/uk-export-finance-annual-report-and-accounts-2011-12.pdf

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funds so many fossil-fuel-related projects and has so far failed to support a single green energy project."

DIPLOMATIC SUBSIDIES

1. The British government supports the interests of oil companies operating overseas through various departments including the Department for International Development, the Foreign and Commonwealth Office (FCO), the Department for Business, Innovation & Skills and UK Trade & Investment (UKTI). 2. It is David Cameron’s stated policy that diplomats should prioritise promoting “UK-based” business interests14 and, alongside arms companies, fossil fuels receive the largest share of this support. 3. Day-to-day phone calls and intelligence gathering on behalf of BP and Shell are a key activity of UK embassies abroad, involving commercial attachés, secretaries for energy and ambassadors. 4. These costs add up - until October 2012, the FCO was maintaining a consulate with three diplomats in Basra largely to meet the needs and demands of BP and Shell. At over £2 million per diplomat per year, the £6.5 million annual budget was significant.15 5. Ongoing lobbying is backed up by high-profile ministerial handshakes and official trade missions. 6. Close state backing for oil companies is exerted especially when oil companies are forcing their way into new countries – whether that is Tony Blair’s support for BP and Shell in breaking into Libya in the 2000s, the heavy lobbying on behalf of Western oil interests in occupied Iraq after the invasion, or during the same companies' entry into newly independent states of the Former Soviet Union in the 1990s Other examples of diplomatic support include: 7. A meeting in February 2013 between the UK Prime Minister, David Cameron and Nigeria’s President Goodluck Jonathan. In this meeting they discussed “how to ensure the Nigerian Petroleum Bill encouraged maximum investment from other countries in Nigeria’s energy sector.”16 8. Eighteen months of meetings between Anne Pringle, British ambassador in Moscow, and BP as the company was making its first attempt to broker a deal with Russian oil company Rosneft. This

14 BBC News, David Cameron focuses on foreign trade policy, published 22.07.2010 http://www.bbc.co.uk/news/uk-politics-10722283 15 Petroleum Economist, Update: ExxonMobil ‘to quit West Qurna-1’, 18.10.2012, http://www.petroleum-economist.com/Article/3105120/UPDATE-ExxonMobil-to-quit- West-Qurna-1.html 16 http://www.number10.gov.uk/news/statement-on-president-goodluck-jonathan- meeting-with-prime-minister/

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culminated in Chris Huhne, Energy Secretary, attending the signing ceremony which was later ruled to breach a shareholder agreement.17 9. Foreign Secretary William Hague lobbying “strongly” on behalf of Tullow oil over a dispute over the company’s £175 million unpaid tax bill.18 10. These are just some examples but they point to a system of continuous, systematic diplomatic support for a handful of fossil fuel companies.

MILITARY SUBSIDIES

1. The UK Government provides fossil fuel companies with military subsidies to secure key overseas oil and gas infrastructure and transport routes. 2. For example, figures released under the Freedom of Information Act show that the UK spent close to £12 million in military aid in Nigeria since it revived ties with the regime in 2001. Spending has risen consistently over the last decade.19 3. The UK has established a permanent naval facility in Lagos to train the Nigerian military to secure the Delta’s oil fields in British loaned boats.20 4. Such subsidies are often brought about as a result of corporate lobbying. For example, UK Government documents from 2006 reveal that Shell lobbied the UK and US Governments to increase military aid to secure their oil fields in the Niger Delta.21 Military aid was subsequently increased over the next 4 years.22 5. Similarly, the provision of UK frigates to the NATO and EU flotillas patrolling the waters off Somalia enforces the passage of tankers through the Gulf of Aden. In 2010, Jan Kopernicki, President of the British Chamber of Shipping and also Vice-President of Shell’s shipping arm, was lobbying hard for the UK to increase Navy spending and bring forward the acquisition of a new generation of warships, to support the private oil tankers moving through this ‘vital strategic

17 http://www.telegraph.co.uk/finance/newsbysector/energy/oilandgas/8410043/Foreign-Office- backed-BP-in-Rosneft-talks.html 18 http://www.telegraph.co.uk/news/politics/william-hague/8314345/William-Hague- lobbied-strongly-for-oil-companies-run-by-Tory-donors.html 19 http://platformlondon.org/wp-content/uploads/2012/07/MoD-Military-training- Amunwa-Response-22.pdf 20 http://www.publications.parliament.uk/pa/ld201213/ldhansrd/text/121101w0001.htm# 12110126000244 21 http://platformlondon.org/wp-content/uploads/2012/07/0475-Redacted-note-of- meeting-23-Feb-2004-1-BA-rcd-Sept-13.pdf 22 http://platformlondon.org/wp-content/uploads/2012/07/MoD-Military-training- Amunwa-Response-22.pdf

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artery.’23 6. The UK government does not appear to have made any demands for accountability in the Nigerian armed forces in return for military aid.24 Instead the UK has frequently turned a blind eye to Nigeria’s excessive use of force. 7. For example, on 1 December 2010, Government forces reportedly attacked a town in Delta State called Ayakoromo because there may have been a militant camp near or in the town. The number of dead is still disputed. One report claims that 100 were killed, mostly children, the elderly and women. The Red Cross says that it was barred from entering after the raids. There has been no official inquiry into the tragedy.25 8. Though Nigerian troops have failed to resolve the Delta conflict, the UK actively supported the militarisation of the area and the wider Gulf of Guinea.

RECOMMENDATIONS:

1. When measuring the extent of fossil fuel subsidies it is critical that the government include and address off-budget subsidies rather than only looking at direct subsidies like tax breaks. 2. In particular export credit, diplomatic, military support should be included in definitions of fossil fuel subsidies. It is only by including these areas that a meaningful assessment of fossil fuel subsides can be made. 3. The government should offer a quantitative and qualitative assessment of these subsides and the results of this analysis should be publicly available. 4. Having established the level of fossil fuel subsidies, measures should be taken to rapidly reduce them. 5. The money saved from curtailing fossil fuel subsidies should instead be used to support the development of sustainable, renewable and safe energy technologies.

13 June 2013

23 Combating Somali Piracy: The EU’s Naval Operation Atalanta, House of Lords Select Committee on European Union, April 2010

24 http://www.hrw.org/sites/default/files/related_material/nigeria_2012.pdf 25 http://www.thisdaylive.com/articles/ayakoromo-attack-the-truth-and-fiction/72425

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Written evidence submitted by BSW Timber

BSW Timber BSW Timber is the UK’s largest domestic sawmilling group, processing around 15% of the UK's annual timber harvest. The company has six mills across the UK (and one in Latvia). The group has an annual turnover in excess of £180m, employing over 900 people; indirect employment accounts for another 2,500 jobs. It is one of the largest timber buyers in the UK, annually consuming around 15% of the UK wood harvest.

Impact of Energy Subsidies BSW Timber is extremely concerned about the impact that subsidies for biomass will have on the UK wood market, and the possible distortion it will lead to.

The UK has a very limited wood supply; around 10.2 million tonnes annually. This is almost all used by wood processors. There simply is not enough domestic wood to service a new entrant (biomass) without displacing existing users. Better management of forests will not help to meet this demand; the Forestry Commission estimates that potential increase in production will only be 2‐3 million green tonnes.

Whilst sawlogs are the most expensive part of the tree, and energy generators currently say they do not intend to burn them, we believe that companies like ours are still at risk from biomass subsidy policies. The price premium of saw‐logs will not dissuade energy generators from using them for biomass, as it will increasingly become easier and cheaper to purchase whole trees instead of splitting them into premium and ‘lower value’ parts. Generators will start to purchase saw‐log timber, diverting this wood from the timber industry and undermining the Waste Hierarchy. Whole trees have already been used for pellets in North America.

The entrance of subsidised biomass energy companies into the wood market does not only increase demand for a finite and valuable resource, it will also increase the cost for domestic wood processors. The large subsidises available to energy companies will allow them to purchase wood at a higher rate than those in the wood processing industry, distorting the market. In the 10 years since the introduction of the Renewables Obligation the price of standing timber has increased 72.4% in real terms.

The UK will require many millions of tonnes more wood than it can supply domestically. As a result, this wood will have to be imported. The current subsidies have been set at a level which allows energy companies to pay the higher cost of imported wood, regardless of whether they source that wood from 50 or 5000 miles away. This will give those energy companies a financial incentive to purchase cheaper domestic wood, putting further pressure on domestic wood processors who (for financial and phytosanitary reasons) can only source UK wood.

We believe that subsidising biomass in the same way as other renewable technologies, rather than taking into account its unique characteristics (namely the existing fuel source for which there are 129

competing and existing users) is potentially extremely damaging for UK businesses and jobs, and the environment.

The Committee on Climate Change has recognised that wood has a valuable role to play in green construction, and that this should be prioritised ahead of burning wood for electricity. BSW Timber is a major producer of sustainable and low‐carbon building materials. Wood is the least carbon intensive building material; every cubic metre of wood that is used in place of alternative materials saves between 0.7 and 1.1 tonnes of carbon dioxide. By using a timber frame, it is possible to reduce the carbon footprint of a typical 3 bedroom house by approximately 3 tonnes. 4.2 tonnes of CO2 can be saved per 50 square metre of wall element, by substituting timber frame and softwood weather boarding for brick and block. 13.85 tonnes of CO2 can be saved when softwood weatherboarding is substituted for PVCU weather boarding.

BSW believes the Government must urgently reassess the unintended consequences of its biomass subsidy regime, particularly taking into account the more environmentally friendly uses of wood which are at risk of being displaced.

14 June 2013

130

Written evidence submitted by Alan Simpson

1) Summary of Conclusions and Recommendations

1.1 The overarching conclusion of this submission is that Britain gets poor value from the elaborate web of energy market subsidies it operates; subsidising the past rather than the future, old technologies rather than new, the unsustainable rather than the sustainable, and a closed cartel in preference to a more open energy democracy. The current subsidy framework acts as a roadblock to market transformation, rather than a pathway to it.

1.2 Energy market subsidies should be measured against their ability to transform rather than maintain. All energy market subsidies (including tax exemptions and credits) are market distorting. This is neither a vice nor a virtue. What matters is their contribution to market transformation.

1.3 Subsidies should be treated as transitional mechanisms rather than permanent support; addressing market defects and moving the energy market from its current structure towards the energy systems that will replace it.

1.4 Transformational subsidy policies should therefore

- be targeted towards new technologies rather than established ones - have built-in 'degression' rates, offering diminishing rates of support, towards full market viability, - prioritise renewable over non-renewable energy systems - require all technologies to cover their own environmental clean-up costs - be consistent with government carbon reduction targets - maintain social cohesion and resilience, and - deliver a more open, democratic and sustainable UK energy system.

1.5 The current UK approach to energy market subsidies does not constitute any such market transformation strategy.

2 Background

2.1 The issue of energy market subsidies is certainly political, but it is not ideological. Every government on the planet uses energy market subsidies. Parties of all political hues are locked into energy market subsidies. Even the most ardent champions of deregulated, competitive markets like to make exemptions for their own chosen dependencies.

2.2 Confusion only arises when less-than-honest distinctions are drawn between visible and concealed subsidies; between the use of public spending (of taxes raised) and revenues forgone (in exemptions/credits/accelerated capital depreciation rates, etc). Whatever strategies are pursued, the public ultimately pays. The critical questions revolve around whether the public (society/the planet) gains or loses from the chosen intervention strategies.

2.3 To take a balanced view of the way in which current subsidies impact on overall UK energy policy, the Committee needs to examine energy market subsidies in their broadest 131 context; including both visible and less visible support mechanisms, and incorporating a wider appraisal of their economic and environmental impact; something the Treasury appears constitutionally unable to do.

3 Methodologies

3.1 To be fair to government, there is no international consensus about what constitutes an energy subsidy, let alone any meaningful distinction between what is market distorting and what is market transforming.

3.2 International attempts - by the Institute for Sustainable Development (2010), the World Bank (2010), the OECD (2012), and the IMF (2013) - to evaluate the impact and trade- distorting effects of different subsidy regimes all flounder upon the lack of an agreed view on how direct and indirect subsidies should be judged, let alone measured.

3.3 The OECD study did, however, set out a useful framework (below) of the conventional elements that constitute consumer and producer subsidies. Although limited by a narrow concept of energy (separated from its broader impact on the economy and the environment), it does at least recognise the complexity of both producer and consumer subsidies that are wrapped into existing market support mechanisms -

3.4 The value of this table [OECD (2010) Measuring Support to Energy, in Oxford Energy Associates submission, Table 1.1 [not reproduced here] ]is that it acknowledges that energy market subsidies run far wider than just 'price support' measures going directly to the public (i.e. as Winter Fuel Payments or reduced VAT rates on fuel).

3.5 Parliament has just voted to create a separate welfare state for new nuclear power, guaranteeing it a market and price for the next 35-40 years. It will be a subsidy (in all probability to a single monopoly supplier) that exceeds all other energy subsidies. It also comes on top of the annual taxpayer contribution of £2.3bn for nuclear waste disposal, the £5bn bailout of British Energy in 2005, and government underwriting of insurance liabilities (in excess of £1.2bn) for any nuclear accident. These are barely recognised in the current 'subsidy' debate.

3.6 Whilst Japan is beginning to calculate the full depth and duration of such costs, no similar comparison is being made with the long term costs and consequences of existing UK nuclear subsidies. Contracts for Difference (CfDs) and New Investment Instruments, in the current Energy Bill, will add further subsidies to the only energy sector on a spiralling 'construction cost' curve.

3.7 Whilst the Stern Report made a stab at evaluation of environmental damage, its greater message was about the urgent need to address the market failure (of increasing carbon emissions) in existing UK energy policies and subsidy regimes. It was a message Britain quickly chose to ignore.

3.8 Some of the new incentives the Treasury seems determined to offer to the extraction of ‘unconventional’ gas deposits (Fracking) would turn Stern's alarm bells into sirens.

4 Current breakdown of UK energy subsidies

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4.1 The Committee has already been given a reasonable outline of current UK energy market subsidies by Oxford Energy Associates [Oxford Energy Associates submission, Table 2.5 [not reproduced here] ].

4.2 Even though this breakdown does not address the full OECD checklist of intervention measures, it is clear that the Government puts over £15bn of annual subsidies into its energy sector, over 80% of which go to old, dirty, non-renewable energy sources. The Committee might like to consider the adequacy of the current subsidy framework against the following criteria - a) Does it promote innovation and lower energy production costs? The only parts of the energy market with rapidly falling unit costs of production are in the renewables sector (particularly solar). There is no evidence of UK subsidies to non-renewable energy delivering lower energy-production costs. The recent fall in global coal prices has had little to do with UK support mechanisms. It derived mainly from US prices being (temporarily) driven down by cheap gas, and from a European race to use up coal quotas before the 2016 Large Combustion Plant Directive comes into effect. b) Does it reduce dependency on taxpayer support? Again, with the exception of renewables, most of today's intervention mechanisms invite long-term (and often increasing) public subsidy. There is, for example, evidence that despite huge existing gas subsidies, power companies are already preparing to 'game' the market for further support. In October 2012, Ofgem's 'Electricity Capacity Assessment' noted that

"Some of the most difficult issues to form a firm view on are whether new gas fired generation will be built over the next 4 years, whether gas power stations (CCGTs) that have been taken out of operation ('mothballed') will return, and how interconnectors will flow at times of peak demand." (Ofgem, Electricity Capacity Assessment, 2012, p8) i) Energy companies claim that mothballing of existing plant (and of new planning permits) has been necessary because gas prices are too low (?!). Many suspect that, in an artificially constructed UK 'supply crisis' in 2014/15, utilities will seek new government subsidies to bring this plant back into operation. The channel for doing so will be payments under the Capacity Mechanism of the Energy Bill. ii) DECC's own Impact Assessment calculated that the Capacity Mechanism would cost£2.5bn a year in standby contracts. Experience in the USA is that some 70% of these contracts went to fossil fuel generators, with only 3% going to measures that looked at demand reduction rather than increased consumption. iii) Additional inducements to fossil fuel generators would be a classic example of parliament again being 'suckered' into over-generous subsidy payments to corporate energy interests. Tougher regulatory requirements, a Strategic Reserve provision, (or the prospect of prison sentences) might be more effective ways of 'keeping the lights on'. c) Has it reduced carbon emissions in the energy sector? The energy efficiency and Climate Change Agreement measures in the table (above) have certainly helped reduce UK carbon emissions, as has the support given to renewable energies. i) Though not recognised in the table, the former Warm Front programme directly helped reduce carbon emissions from large parts of the UK housing stock. ii) The nuclear waste subsidy is a legacy issue not a carbon reduction one. And fossil fuel subsidies all unambiguously promote carbon emissions. iii) In carbon reduction terms, the UK subsidy framework looks to be largely regressive. 133

iv) The Committee may wish to compare UK performance with the record of greenhouse gas emissions reductions in Germany over the last decade - d) Have the UK subsidies produced a more open and competitive energy market? No. UK energy market concentration has increased over the last decade. e) Is there a consistent approach to environmental 'clean up' obligations? No. Nuclear receives a massive annual subsidy for its waste management. It also receives insurance support and long term price guarantees given to no other energy source. It is unclear whether the government will subsidise decommissioning costs relating to North Sea oil wells. No such subsidies are offered to renewables. f) Does the subsidy framework promote innovation and market transformation? Tomorrow's energy 'systems' will be smarter, more integrated and more decentralised than the one we have today. They will also be based on using less energy rather than more. UK subsidies have concentrated on increasing energy production/consumption rather than reducing the need for it. i) The only genuinely transformative element in the subsidy framework is to be found in the Feed-in-Tariff (FITs) payments for renewable energy. This is also the main area in which genuine innovation and competition has been taking place. It says a lot about the UK that it is also the one aspect of the energy market in which the government actively constrains growth. ii) Whilst other EU states are seeing renewables deployment at rates of over 5GW p.a. - and with innovation rates and unit cost reductions on the same scale - the UK has 134

iii) It is worth noting that the UK opted to structure FITs in a way that forces it to be counted as a public subsidy. The European Court previously ruled that FITs can operate as a free-standing element within energy sector accounting ... with no public subsidy whatsoever. The effect of this is to allow renewables to play a much bigger role in market transformation across the EU than is allowed in the UK. iv) This is a good example of UK subsidies being used to limit transformational change rather than drive it.

5 Redressing the balance

5.1 All subsidy measures are market distorting or transforming. That is their purpose.

5.2 The most worrying aspect of UK energy market subsidies is just how regressive they are. Whilst high carbon, non-renewable energy sources absorb the bulk of subsidies (often uncapped), demand reduction measures are to be driven by loans. Moreover, the subsidy framework reinforces market concentration rather than dilutes it.

5.3 The UK does not have an open, competitive energy market. The ‘market’ is, in effect, an energy cartel, dominated by the Big 6 power companies, regulated around short-term price considerations, and underpinned by an elaborate (and expensive) system of corporate welfare. All attempts to broaden the ownership of energy production or distribution are fiercely resisted by the same interests. UK energy market subsidies underpin this closed energy cartel.

5.4 Yet, if you were to believe the press coverage, the UK debate about energy market subsidies is whether taxpayers/bill-payers will sink beneath an 'unaffordable' burden of annual (£0.5bn) Feed-in-Tariff payments for renewable energy.

5.5 None of this works in Britain's long term interests. If the Committee is to set itself a benchmark for progressive recommendations arising from this Inquiry, then clarity, transparency, sustainability and consistency will be a far more valuable elements than 'continuity', in a UK approach to energy market interventions.

5.6 It isn't just that throwing subsidies at fossil fuel, non-renewable energy sources is expensive, inefficient and climate damaging. These are yesterdays energy sources, reliant on yesterday's energy thinking. It is a world only losers will try to live in. This is why the a shift into transformational subsidies (outlined in para 1.4) is the key to a more secure UK energy future.

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Written evidence submitted by RenewableUK

1. Government needs to reassess how energy subsidies are defined and make sure that subsidies for all energy technologies that take place throughout their life-cycle are reported transparently. 2. Further consultation is needed on how to implement this process but also to clearly define subsidies and how these will we measured. This is particularly important for subsidies that are complex or difficult to monetise. 3. Despite efforts of the Government to reduce the environmental subsidies to fossil technologies through the Carbon Floor Price and Climate Change Levy, these are only small steps in the right direction and support for Renewable Energy Technologies remains justified, In fact, they appear to be the most cost effective approach to meet decarbonisation objectives. 4. In order to avoid conflicting policies and therefore a possibly inefficient use of public finance, Government needs to ensure that industrial policies are aligned with industry subsidies while making sure that these policies do not contradict each other. Subsidies to the fossil fuel industry are therefore counterproductive to our decarbonisation efforts.

Introduction 5. RenewableUK is the UK’s leading trade association in the field of renewable energy, representing over 650 companies in the wind, wave and tidal stream sectors. Together, these technologies will provide the bulk of the renewable electricity we will need to meet targets in 2020 and through to 2050, and should be the motors of new industrial growth, providing thousands of new jobs and significant export revenue. 6. We believe that the technologies that we represent are, to varying degrees, still developing industries but all offer large-scale, cost-effective low carbon options for the longer term. 7. For the time being, subsidies therefore remain essential, however our members are determined to reduce costs to a point where, in a market underpinned by a strong carbon price, no subsidy is required. However, it is important to understand that the varying technologies will achieve this on different time horizons. 8. This time horizon is directly correlated to Government policy, from subsidies to the long term certitude that accompany these. The recent CCC report1 highlights the ‘clear benefit in committing to invest in low-carbon generation over the next two decades’.

Renewable Energy 9. The technologies that RenewableUK champions could need a total of about £50bn of additional, so far uncommitted investment up to 2020. The result of this and previous investment would be approximately 13GW of onshore wind, 18GW of offshore wind and 200MW of marine renewables, in total generating about 25% of this country’s power. We would also have world-leading industries in offshore wind and marine, which would be starting to earn significant export revenues from about 2020 onwards. 10. Direct support for these technologies is necessary to secure this investment, which is vital to stimulate our economy at this challenging time. This support is justified due to the explicit and implicit support that other technologies have received or continue to receive, and in order to promote new energy technology options.

1 “Next steps on Electricity Market Reform – securing the benefits of low-carbon investment”, Committee on Climate Change, May 2013 http://www.theccc.org.uk/wp-content/uploads/2013/05/1720_EMR_report_web.pdf 136

11. The greatest challenge faced in securing this financing is risk mitigation. Direct support in the form of the Renewables Obligation has provided us with exactly this. Onshore wind is now a mainstream generation technology, with costs approaching those of new-entrant gas generation. Now that some scale is being achieved in Offshore Wind, we believe that we are on the way down the learning curve and RenewableUK is working hard with its members on cost reduction strategies to accelerate this process.

Whether the Government has identified the extent of energy subsidies, and measured them; 12. The challenge of defining and identifying subsidies is complex and requires careful consideration. We believe that only informed policy decisions will yield the sustainable future that we need, and thus we need transparent and clear reporting for all subsidies, for all technologies/energy sources and at all levels (extraction, production, transmission and consumer). 13. These subsidies should be reported online in an easily and freely accessible forum, and reporting should be a carried out using a common metric. It is important that all Government activity and policy that provides competitive advantage to one technology over another be identified, even if the impact is difficult to quantify. For instance, Government guarantees can represent a risk to the public, yet the quantification of such risks is complex, with no clear standard in existence. Such measures may be justified or classed as not harmful, but it is important that they be reported alongside direct subsidy in order to give a complete picture of support that is given. Definition of the reporting system should be subject to further public consultation. 14. Failure to achieve such transparency on all subsidies creates an unfair burden on renewable technologies for which subsidies are direct and transparent. This also has the benefit of allowing clear international comparisons of ‘true’ technology costs, and thus helping to expose and eliminate distortions in cross-border trade.

How well any identification of subsidies by the Government matches up to best practice methodologies in how energy subsidies are defined and scoped; 15. The current Government definition of a “subsidy” (in the context of electricity) appears to be a “levy, direct payment or market support for electricity supplied”. This fails to account for a number of subsidies that exist, particularly in fuel extraction and is ambiguous on what implicit subsidies are measured, if at all, and how this is done. 16. In our view, in the energy industry, a subsidy is either the use of public money, regulation or institutional frameworks to protect or promote a specific industrial sector or technology. The definition of a subsidy should cover the whole life-cycle of a technology and its fuel from production all the way to end-use and waste disposal. This should also include soft measures, such as guarantees provided by Government in order to reduce investor risk. Implicit subsidies such as public health and environmental externalities should also be included, though valuing such externalities can be challenging. 17. Consideration must also be given to understanding historical subsidies for fossil fuel and nuclear power. This is an important part of a decision maker’s tool kit, as it would provide further clarity on the cost of bringing new technologies to market. 18. A more complex indirect subsidy that has not yet been properly identified and costed is institutional rigidity. The current regulatory framework in the energy industry favours traditional generation technologies over innovative and renewable technologies, through history and familiarity. While this situation will slowly change as these new technologies become mainstream, industry codes and practices still impose inappropriate barriers that can add to cost. Even if these cannot be quantified, acknowledging their existence will facilitate the process of resolving these issues. 19. Early research and development is the only area where we believe technology specific accounting of subsidies is not helpful. Strict categorisation of innovative technologies, including disruptive technologies, is restrictive. Early R&D needs flexibility to explore multiple 137

pathways at all times and will inevitably lead to some failures which cannot be allocated to any specific technology. Support of R&D is essential and should be encouraged as widely as possible. Externalities – Carbon costs 20. RenewableUK considers that externalities, or market failures, should be priced. In the absence of pricing this constitutes a subsidy. As such we are supportive of the Carbon Floor Price and Climate Change Levy which are reflections of the polluter pays principle and are steps towards removing legacy subsidies to the fossil fuel industry. 21. In principle, this is an example of how the Government has successfully identified and started to amend a market distorting subsidy, however, the definition of the ‘right price’ for carbon is contentious. While in theory it should be decoupled from economic drivers, becoming a sole reflection of the cost to the environment and society of carbon emissions, in practice this is a complex issue for which we do not yet have a practicable solution. A price which is sufficiently high and stable enough to stimulate investment in low-carbon alternatives will likely have to serve as a proxy for the true external cost of carbon emissions. Reduced VAT 22. As long as the VAT tax break is a blanket tax break across all technologies, and thus does not confer a competitive advantage to any, RenewableUK is agnostic to how the Government deals with this.

The scale of subsidies in the UK, including comparison with other countries; 23. After review of the evidence, RenewableUK generally agrees with the comparisons made, although more detail needs to be provided. For example, how each country deals with the cost of grid reinforcement or the specific use of a technology, such as roof mounted PV or large scale PV, can have a distorting impact on needed level of public money invested. Unlike the UK’s support system for Offshore Wind, under Germany’s feed-in-tariff generators do not pay grid use-of-system costs. Other variables such as the duration of support also change. 24. With that caveat, we feel that international comparison is a useful benchmark to assess the appropriateness of the level of subsidies in the UK. Currently these seem to indicate that our levels of support for Renewable Energies are within the range of support in comparative countries, which gives a level on confidence that the UK is providing an appropriate level. However we must caution that technology specific support must take account of local circumstances, whether these are environmental, economic, social and regulatory. 25. In the context of a competitive investment market, and once local circumstances have been accounted for, we must be careful about reducing levels of subsidies in the UK below our European counterparts. This is particularly true with technologies that are in the early stages of development and for which it is in our economy’s interest to attract the supply chains for these industries. Subsidies should therefore be in line with our industrial strategies. For instance, the opportunity to secure a large part of the offshore wind farm manufacturing and service industry should prompt ‘higher than average’ subsidy. 26. In this context, it is worth highlighting the recent study from the CCC which demonstrates the benefits of having long term ambitious targets as a further driver for the development of technology supply chains in the UK, not just subsidies2. Again, this should be looked at through the lens of our industrial strategy.

Whether the Government has any plans or targets to reduce or eliminate ‘harmful’ subsidies; 27. The clear definition of Government support is essential to identify ‘harmful’ subsidies. In our opinion these are subsidies that are harmful to the environment, do not work towards the long term sustainability of the UK and harm the poor. In the energy sector this means that

2 “Next steps on Electricity Market Reform – securing the benefits of low-carbon investment”, Committee on Climate Change, May 2013 http://www.theccc.org.uk/wp-content/uploads/2013/05/1720_EMR_report_web.pdf 138

subsidies need to be directed to technologies that will decarbonise our electricity sector at the least cost to consumers, whilst maintaining security of supply. In the energy industry, we cannot decouple the concept of a ‘harmful’ subsidy from the technology that subsidy is aimed at. 28. The “On Picking Winners” report from Imperial College London3 clearly highlights that: ‐ Disruptive innovation to the energy generation stock cannot be achieved through stepped increases in carbon pricing alone. ‐ Direct subsidies are necessary to foster this shift, and in-fact, appear to be a more cost effective solution as it attracts investment with a lower cost of capital (i.e. lower risk premium). Additionally, action now helps foster growth and associated cost reductions. ‐ This rule no longer stands true if, and only if, the carbon price is put to a realistic level (the target seems to suggest this would be around £74/tCO2) immediately with long term certainty that this will not be removed or reduced. This would appear to be politically impossible, given that it is likely to be painted as a regressive tax, and undesirable (transition period needed, carbon leakage without global agreement, etc.). 29. Currently it is not obvious that Government is working towards the common goal of removing harmful subsidies. Under the premise of ‘Security of Supply’, subsidies to the fossil fuel sector are the highest especially when we take stock of the un-priced externalities and rigidity of institutional frameworks. Continued subsidies to these industries are difficult to reverse, however, this should be a medium term goal with clear targets for 2020. New subsidies that will lead to legacy investments in fossil fuel extraction and use must be avoided at all costs. 30. The UK gas market is coupled to the global gas market and subject to WTO rules. Domestic production of gas will therefore have limited impact on the price paid by UK consumers, which will be dependent on the global demand/supply balance. Subsidy to this sector is thus unlikely to provide significant security of supply and economic benefits to UK. Additionally, the timeline for the development of this industry in the UK creates very limited additional industrial opportunities for UK businesses; we have missed the boat. 31. Further support to the fossil fuel industry therefore demonstrates limited economic benefits, limited decarbonisation benefits and limited security of supply benefits. Additionally, further investment in shale gas would require subsequent infrastructure investment creating lock-in that seriously threatens our current investments in low-carbon and renewable technologies. 32. Finally, in a systems context, the “golden age of gas” is likely to lead to an international ‘dash for gas’. This will lead to a global boom in demand for gas, with a consequent risk of an ‘overshoot’. If growth of demand outstrips supply, in a competitive market this will prompt higher fuel prices. We believe that countries locked-in to gas generation will be exposed to increasingly volatile and high prices.

Progress in reducing such harmful subsidies, and how current energy policies and DECC’s ‘Energy Pathways’ for the mix of energy sources will influence the magnitude of any subsidies. 33. Progress in the removal of harmful environmental subsidies is a slow and painful process. The Carbon Floor Price and Climate Change Levy are indications of the build-up of momentum in this area which we welcome, however it is obvious that there is a lot of division on these matters which is threatening the long term political support for these initiatives. 34. As the deployment of renewable technologies increases confidence that these technologies can provide us with a secure and economically viable energy supply, the removal of subsidies to harmful industries will become more acceptable. We are confident that a correct (high) carbon price in the future is achievable, however until such a point is reached, direct subsidies to many renewable technologies will remain necessary and indeed desirable. 35. It is also worth noting that subsidies for Renewable Technologies could potentially become harmful if these where pursued indefinitely and did not change to reflect the dynamics of the

3 “On Picking Winners”, Imperial College London, Oct 2012 http://assets.wwf.org.uk/downloads/on_picking_winners_oct_2012.pdf 139

market. This is exactly what happened with feed-in-tariff for roof mounted PV systems in 2010 that did not reflect the dramatic fall in the cost of PV resulting in excessively large pay-outs to owner/developers. This is a clear policy failure that has tarnished the generally well developed support policies for Renewable Technologies. Regular RO band reviews and the planed CfD strike price reviews are essential in guaranteeing that the industry does not benefit unduly from public support. 36. Our members are also committed to the purpose of the long term Government support strategy, cost reduction. RenewableUK works closely with its members to foster opportunities for cost reduction and the report of the Offshore Wind Cost Reduction Task Force4 highlights the industry’s commitment to achieving Government’s £100/MWh cost target by 2020; providing that the support system is not weakened. The long term goal is to reduce costs to a point where, in a market underpinned by a strong carbon price, no subsidy is required.

Conclusion 37. RenewableUK and our membership will strongly welcome and support any Government initiative that seeks to provide transparency on the level of subsidies received by all energy technologies and their fuel sources. We feel very strongly that subsidies to renewable technologies are the clearest and most transparent in the whole energy sector and that this should not be the exception but the rule. Only by achieving full transparency throughout the energy sector’s whole life-cycle will policy makers and the public be empowered to make informed decisions. 38. The investment horizon in the energy sector spans decades, creating lock-in, and therefore the definition of ‘harmful’ subsidies cannot be decoupled from our long term decarbonisation targets to 2050. Doing so would be counterproductive and therefore against the public interest. A consistent strategy for the fossil fuel industry would therefore only focus on assisting it to transition towards renewable technologies. 39. Finally, subsidies should also be in line with our industrial strategies in order to maximise the benefits to our economy and job creation potential. As such their level also needs to be defined within the global context. For solar PV or Onshore Wind, the relocation of manufacturing jobs from abroad to the UK will be hard to achieve. This does not warrant ‘above normal’ subsidy levels, however, as leader in the newer Offshore Wind Industry, which has a growing supply chain, there is real potential for a large UK based supply chain to develop, providing consequent export opportunities, which warrants ‘above normal’ subsidy levels.

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4 Offshore Wind Cost Reduction Task Force Report, RenewableUK, June 2012 http://www.renewableuk.com/en/publications/reports.cfm/Offshore-Wind-Cost-Reduction-Task-Force-Report 140

Written evidence submitted by EDF Energy

Executive Summary

• The UK’s energy system is in a state of flux. The existing electricity market framework has served consumers well by delivering high levels of reliability but is now being stretched in an attempt to deliver outcomes that reflect a different set of policy objectives and a different economic climate.

• The UK needs infrastructure fit for the 21st century and the urgent challenge now is to secure the vital investment required to ensure there is adequate capacity to meet future electricity needs while reducing emissions at least cost to consumers. The Government has taken a clear leadership position in setting the framework for reducing greenhouse gas emissions, and we need to ensure that we maintain the momentum needed to make the transition to a low carbon economy.

• EDF Energy believes that the Electricity Market Reform (EMR) proposals as laid out in the Energy Bill are capable of providing the right framework for the low carbon investment that the country needs, while keeping costs down for consumers.

• Reform of the existing electricity market arrangements is necessary to ensure that investment comes forward to deliver the reliable diverse energy mix required to achieve the UK’s energy policy objectives. The transition to a low carbon economy will mean moving away from a market based on the short run marginal cost of fossil fuel plant to one that is likely to be based on the long run average costs of electricity production.

• The EMR proposals are consistent with the history of the development of UK energy markets, where changes to the objectives of energy policy have necessitated Government action to develop the market.

• We have reviewed the report by Oxford Energy Associates but do not consider that the various definitions of the types of subsidy available could be applied to market redesign and EMR. The EMR package does not confer an economic advantage to market operators and does not represent a subsidy.

• The report demonstrates the difficulty of establishing a universally agreed definition of the term “subsidies”. A wide definition of the term “subsidy” makes it difficult to both identify and measure its impact on the economy. Narrow definitions are able to identify precisely transfers between the Government and other parties, and are able to quantify the impact of a particular measure. EDF Energy notes that the Government’s implied definition of “subsidy” (in the context of nuclear new build) has followed this approach by defining it as a “levy, direct payment or market support for electricity supplied or capacity provided” only available to specific technologies. We welcome the clarity that the Government’s definition provides to investors.

• We would also highlight that the report contains some inaccuracies with respect to the role of the Nuclear Decommissioning Authority and also the restructuring of British Energy in 2005.

• EDF Energy notes that the scope of the inquiry has primarily focussed on the upstream section of the energy system but consider that as much attention needs to paid to the funding of downstream initiatives and their impact on customers’ bills. 141

About EDF Energy

1. EDF Energy is one of the UK’s largest energy companies with activities throughout the energy chain. We provide 50% of the UK’s low carbon generation. Our interests include nuclear, coal and gas-fired electricity generation, renewables, and energy supply to end users. We have over five million electricity and gas customer accounts in the UK, including both residential and business users.

Assessing subsidies

2. EDF Energy welcomes the literature review of subsidies contained within the report by Oxford Energy Associates. However, we believe that the work highlights the fact that much of the debate over the concept of subsidies remains inconclusive, and that an accepted definition of the term is unlikely to achieve universal agreement outside of a technical economics description. We do not agree with the implied assertion that any form of Government guarantee or spending relating to the private sector is a “subsidy” given that there are a number of public policy objectives and imperatives behind such support. In fact, it is normal for Governments to try and attract private sector investment through a number of policy measures, including tax allowances and relief, and yet these are rarely considered “subsidies”.

3. Narrow definitions have the advantage of precisely identifying transfers between the Government and other parties, and we favour such an approach to ensure that like is always being compared with like. Wider definitions are likely to be more subjective in scope and face inherent difficulties in being adequately measured for policy purposes. In addition, a vague definition will face problems in trying to assess overall consumer benefit or detriment.

4. The assessment of the benefits of subsidies has to consider some fundamental properties of the energy market. Electricity supply, for example, has a systemic importance to the economy. Its overall contribution to economic welfare is not related to the profits obtained by generators. In the event of sustained power cuts there would be vast disruptions for downstream industries and consumers, and this would be socially and politically unacceptable.

Role of taxes and subsidies in the context of market reform

5. EDF Energy notes that environmental taxes are generally considered to be an acceptable means by which to penalise harmful environmental impacts. Such taxes work on the basis of restricting market activities that generate negative externalities. As HM Treasury notes, the objective is to help ‘shift the burden of tax from “goods” to “bads”1. Subsidies should be considered as part of this same framework where the objective instead is to support “goods” in contrast to “bads”, and should not have pejorative connotations.

6. It is widely agreed that carbon pricing is a key element of climate change mitigation policy, as it ensures that the environmental and social cost of carbon emissions are internalised and reflected in the price of goods and services. Industry consensus is that greater certainty in the future long-term price of carbon will form an important and significant part of the electricity market framework required to increase investment in low carbon generation.

1 HM Treasury, Statement of Intent. Available at: http://www.hm-treasury.gov.uk/tax_environment_statement_of_intent.htm

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7. However, the current EU ETS price is not providing the long-term signal to make the relevant investments in low carbon generation. EDF Energy therefore welcomed the Government’s introduction of a carbon price floor from 1 April 2013 as part of its reforms to drive low carbon investment. This will ensure that all generators pay a minimum price for their carbon emissions and is consistent with the Government’s commitment to operate a ‘polluter pays principle’. A more transparent and level playing field will prevent distortions to the wholesale electricity price from developing.

8. We agree with the Government that a strong carbon price signal should sit alongside supporting policy frameworks, such as the Electricity Market Reform (EMR) package, that can together help to reduce the costs of decarbonising the electricity sector. If the issue of negative externalities is not adequately addressed (e.g. through a robust carbon price) then this can cause further difficulties for the assessment of any support in the energy sector.

9. Having reviewed the report by Oxford Energy Associates, we do not consider that the various definitions of the types of subsidy available could be applied to market redesign and EMR. This is because the current proposals for energy reform are just that - market reform. They are consistent with the history of the development of the Electricity Pool, New Electricity Trading Arrangements (NETA) and British Electricity Trading Transmission Arrangements (BETTA). In each case, changes to the objectives of energy policy necessitated Government action to develop the market.

10. The existing electricity market framework has served consumers well by delivering high levels of reliability but is now being stretched in an attempt to deliver outcomes that reflect a different set of policy objectives and a different economic climate. As our existing power stations start to close, we are also seeing more fundamental changes in the composition of the industry. The past decade alone has seen the UK become a net importer of gas as its North Sea reserves begin to decline.

11. The Government has stated the direction of travel it wishes to take in terms of its energy policy objectives, and the reality is that this will require a different market solution than the system we currently have. The current ‘energy only’ market is based on a system where generators are only paid when they actually produce and sell electricity, and do not obtain any payments for the economic service of being available to produce energy. Our analysis shows that continuing with an ‘energy only’ market will progressively reduce plant margins and will fail to ensure security of supply.

12. There is general industry agreement that a well designed capacity market will have a key role in ensuring security of supply. As the Government has stated, a capacity market “will provide an insurance policy against the possibility of future blackouts by providing financial incentives to ensure we have enough reliable electricity capacity to meet demand”2. The early introduction of the capacity market will reduce uncertainty for existing plant and will avoid the need for new replacement capacity before it is really needed. This will be a more a cost-effective option for consumers.

13. The analysis informing the EMR process has indicated that the existing ‘energy only’ market framework will not provide a satisfactory solution for the Government’s stated objectives of decarbonisation, security of supply and affordability. Due to the change in the generation mix, the electricity system will be required to move away from

2 DECC, Annex C: Electricity Market Reform: Capacity Market – Design and Implementation Update, May 2012, p3

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competing on marginal costs set by fossil fuel input costs, to a system that is likely to be based on long run average costs. In addition, there will a greater focus on the need for capital investment and repayment. It will not be possible to make this transition without interim arrangements to accommodate a system using a single price reference. This is especially important if conventional plant is not penalised for the true costs of its emissions due to shortcomings in the carbon price.

14. Investors should be allowed to make a reasonable return with an acceptable sharing of risk so that the final outcome represents a fair deal for both consumers and investors. Achieving an efficient allocation of risk is particularly relevant for low carbon generation projects as they tend to require very large upfront investments. In addition, under the existing market arrangements, such plant are largely price takers with volatile revenue streams that are influenced by fluctuating fossil fuel prices and which do not have any direct link to their actual generation costs. By contrast, fossil fuel plants such as CCGTs involve lower sunk costs and their revenue is highly correlated with variable costs. This means that the gas price amounts to a natural hedge for the electricity price, and costs can be passed through to consumers. Since the issue of efficient risk allocation affects both overall investment incentives (which affects security of supply) and also relative incentives of low carbon versus other generation capacity (which affects decarbonisation) not addressing it explicitly could undermine the effectiveness of the measures that are primarily aimed at delivering secure, affordable and low carbon energy supplies.

Contracts for Difference

15. With specific reference to EMR, EDF Energy agrees with the Government that Feed- in tariffs with Contracts for Difference (CfDs), in conjunction with the carbon price floor, are capable of working for all low carbon technologies (including renewables, nuclear and fossil fuels with carbon capture and storage) and, indeed, are designed to do so. They will give all such projects access to the long-term, stable and reliable revenue they need to justify the large upfront investment required. The mechanism will therefore provide a vital underpin to enable financing of low carbon projects.

16. The CfDs will be a key component of ensuring value for money for customers by shielding them from the damaging impacts of high and volatile fossil fuel prices. Offering a fixed price (via the “strike price”) will ensure that consumers pay no more than is necessary when the underlying power price is high. This is because the CfD is designed to be two-way. When the market price is above the agreed strike price, the generator will be required to pay back the difference to electricity suppliers (via the counterparty body). If the reverse is true then generators will receive the price they achieve in the electricity market (the market reference price) plus a ‘top up’ to the agreed strike price from the reference price. This will ensure value for money and price stability for consumers. In this respect the mechanism is a major improvement for customers over the Renewables Obligation.

17. It is important to highlight that, while the strike price will be a fixed price, it is not a guaranteed return or risk-free, as the operators of CfD plant will still be required to (a) construct the plant to budget (b) generate to receive the strike price (and hence will continue to face operational risk) and (c) participate in the wholesale market to achieve the market reference price (and not just the ‘top up’). Therefore under the CfD mechanism, the generator will still be exposed to wholesale market price signals and will be required to efficiently schedule and maintain its plant accordingly.

18. The strike prices for all low carbon technologies will initially be set administratively (or through negotiation) while the new market framework develops, and will be based on

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3. However, the Government has made it clear that it will move to a competitive price discovery process for all low carbon technologies “as soon as practicable”4 (potentially as soon as 2017 for technology-specific auctions and the 2020s for technology-neutral competitions). Either way, the strike prices will be established in an objective and transparent manner. This will provide benefits to consumers by ensuring the effective delivery of a secure diverse mix of low carbon generation plan at the least cost.

19. The CfD mechanism will expose the relative cost positions of generation technologies so it creates an incentive for least cost low carbon generation.

Nuclear New Build

20. EDF Energy is committed to delivering affordable, secure, and low carbon supplies based on a diverse energy mix, including nuclear and renewables. We would clarify that we have never sought a subsidy for nuclear new build and believe that the Government has made clear its position on the matter.

21. Clarification of what was meant by “no public subsidy” for nuclear new build was confirmed in a Written Ministerial Statement on energy policy by Chris Huhne MP, the then Secretary of State for Energy and Climate Change on 18 October 2010. He wrote:

“To be clear, this means that there will be no levy, direct payment or market support for electricity supplied or capacity provided by a private sector new nuclear operator, unless similar support is also made available more widely to other types of generation.”

22. The CfD mechanism, for which nuclear new build is eligible, is therefore consistent with the Secretary of State’s definition of “no public subsidy” for new nuclear operators. We firmly believe that the strike price should be based on delivering a fair deal for both investors and customers, be affordable and provide value for money.

23. In addition, we would highlight that it is the Government’s policy that the operators of new nuclear power stations must set aside funds over the operating life of the power station to cover the full costs of decommissioning and their full share of waste costs. This is a requirement that EDF Energy would fully comply with in the development of its nuclear new build plans.

Existing UK Nuclear assets

24. EDF Energy would highlight that liabilities remaining from the early research and nuclear power development programmes are, and always have been, public liabilities. The costs of dealing with them are therefore the Government’s responsibility and not a subsidy. It is therefore not clear why Oxford Energy Associates report describes these activities in the section headed "Nuclear Subsidies". The Nuclear Decommissioning Authority (NDA) is the public body responsible for the decommissioning and cleaning up of the civil nuclear facilities previously under the control of British Nuclear Fuels Limited (BNFL) and the United Kingdom Atomic Energy Authority (UKAEA). These include the first generation Magnox power stations and associated fuel reprocessing facilities.

3 DECC, Annex B: Feed-in tariff with Contracts for Difference: Draft Operational Framework, May 2012, p14 4 Ibid., p9

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25. There is one particular area of Oxford Energy Associates’ evidence that we feel needs to be corrected. Reference is made to the financial intervention by the Government in British Energy and the resulting waste liabilities. It is suggested that the Government had provided a £5 billion “bail out” but this is not accurate. The Government provided a credit facility of up to £650m but not all of this was used and, in fact, was paid back with interest by British Energy during its restructuring.

26. Finally, we would point the Committee to two separate analyses by the National Audit Office (NAO) of the British Energy restructuring and sale to EDF Energy. In its report of March 2006 titled “The Restructuring of British Energy”, the NAO has a table that shows that, as of 28 February 2006, the “total net benefit to the taxpayer of rescuing British Energy” was positive and worth £2.7 billion.

27. A follow-up NAO report, titled “The sale of the Government’s interest in British Energy”, published in January 2010 noted that “the Government sold its stake in British Energy when energy prices were at a peak, and got a good price”. As a result of the sale, the proceeds were transferred to the Nuclear Liabilities Fund, which was set up to meet the cost of future decommissioning of British Energy’s nuclear power stations. As of March 2009, the Fund was valued at £8.3 billion - significantly higher than the estimated decommissioning costs of £3.6 billion.

28. The restructuring of British Energy was ultimately a profitable deal for the taxpayer. Equally, it was strategically important in that it secured a significant proportion of the UK’s electricity generation, which may have been jeopardised had the company been allowed to go into administration.

29. We would highlight that the existing eight nuclear power stations, now part of EDF Energy, continue to make a key contribution to the UK’s low carbon generation mix and the wider economy. For example, in 2012 the plant generated 60TWh of electricity. This was almost 50% higher than the last year before the stations were acquired by EDF Group in 2009. This performance is a result of the £300 million annual investment in the power stations and this is in addition to £350 million spent on plant operations every year (with 90 per cent of the total being spent in the UK).

30. In February 2012, EDF Energy announced that it would continue to seek life extensions for all its nuclear power stations where it is safe and commercially viable to do so. We are expecting an average life extension of seven years across our Advanced Gas-cooled Reactor (AGR) fleet, and have a strategic target of 20 years for Sizewell B. This will avoid the emission of almost 340 million tonnes of CO2 if the same amount of electricity is generated by fossil fuels - equivalent to removing all the cars from UK roads for nearly five years. In addition extending the plants’ lives will also bring significant training and employment opportunities for a new generation of nuclear engineers and operators as we seek to develop the UK’s position as a primary source for skills and expertise in the industry.

31. Our decision in December 2012 to extend the lives of Hinkley Point B and Hunterston B power stations, which in total employ more than 1500 employees and contractors, by seven years to 2023 will help maintain vital skills in the UK nuclear industry. Above all, the recent performance of the plant, and the planned plant life extensions, demonstrate the key role that the UK’s existing nuclear fleet has in providing the reliable, low carbon electricity that the country needs.

Downstream impacts

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32. EDF Energy notes that the scope of the inquiry has primarily focussed on the upstream section of the energy system but consider that as much attention needs to paid to the funding of downstream initiatives. We support the principle behind Government schemes, such as the Green Deal and Energy Company Obligation (ECO), to increase the installation of energy efficiency and other measures. However, it is vital that the cost implication of these initiatives, in terms of affordability and impact on customers’ bills, is fully evaluated. It is also important that a distinction between energy and social policy objectives is made as there is a risk that conflating the two will lead to more costly outcomes for customers as more expensive solutions are inadvertently prioritised over those that more cost-effective. Customers need to be fully aware of, and understand, the objectives and implications of energy policy (in terms of cost) if we are to build support for market reform and the benefits of the transition to a low carbon economy.

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Written evidence submitted by Oil & Gas UK

Introduction

Oil & Gas UK is the leading representative body for the UK offshore oil and gas industry. It is a not‐ for‐profit organisation, established in April 2007 but with a pedigree stretching back over 40 years.

Membership, which currently exceeds 350, is open to all companies active in the UK continental shelf, from super majors to large contractor businesses and from independent oil companies to SMEs working in the supply chain.

Our aim is to strengthen the long‐term health of the offshore oil and gas industry in the UK by working closely with companies across the sector, governments and all other stakeholders to address the issues that affect our member’s businesses.

Oil & Gas UK welcomes the opportunity to respond to the Environmental Audit Commission’s call for evidence in relation to the inquiry “Energy subsidies in the UK”.

As part of our submission, we have also responded to the written evidence commissioned by the Committee from Dr William Blyth of Oxford Energy Associates entitled “Energy Subsidies in the UK”.

Summary

• Oil & Gas UK strongly advocates that the Committee adopts an approach which explores the balance between the taxation collected from individual energy sectors against the amount of value that is transferred from the taxpayer back to these particular elements of the energy sector • Subsidies are methods of value transfer, from the taxpayer to an individual economic sector, to the extent that that sector benefits a net gain from the taxpayer relative to the tax contribution • Allowances which reduce taxation rates to incentivise activity, and that remain set at such a rate that the effected sector remains a net contributor to the public purse, do not constitute a subsidy • Tax allowances that are available for a small number of oil and gas related activities never bring the overall tax rate to a point lower than that which is applied to businesses generally – and never to a point whereby the sector is a net benefactor from the UK taxpayer

Establishing a definition of ‘subsidy’

Central to the Environmental Audit Committee’s inquiry, and perhaps the most challenging aspect, will be defining what does and what does not constitute a subsidy. The issue of definition has been the subject of substantial recent debate and, as reflected in Dr Blyth’s paper, is an area of significant complexity.

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However, in the context of the Committee’s inquiry, Oil & Gas UK strongly recommends that this interpretation excludes benefits from general public spending (e.g., the employment of state educated staff or use of infrastructure such as the road network) which are available and exploited, to a greater or lesser extent, by all businesses operating in the UK.

Oil & Gas UK strongly advocates that the Committee adopts an approach which explores the balance between levels of taxation collected from individual energy sectors against the amount of value that is transferred from the taxpayer back to these particular elements of the energy sector. It is our belief that to approach this inquiry in this way will allow the Committee to most reasonably, accurately and meaningfully assess the degree by which some areas of the energy sector are subsidised.

What is a subsidy?

Subsidies are methods of value transfer, from the taxpayer to an individual economic sector, to the extent that that sector benefits a net gain from the taxpayer relative to the tax contribution. This can be achieved either through direct value transfer of capital or by indirect means where the burden of taxation is outweighed by Government spend, or regulation is artificially lessened, on a sector as a whole.

What is not a subsidy?

Allowances which reduce taxation rates to incentivise activity, and that remain set at such a rate that the effected sector remains a net contributor to the public purse, do not constitute a subsidy. This is particularly true when an allowance is used to incentivise activity which leads to an increase in the tax revenue generated destined for the Exchequer.

In this regard our views are aligned with comments recently made by the Secretary of State for Energy, the Rt. Hon Edward Davey MP, during the recent press launch of Sir Ian Wood’s review into “the economic benefits of offshore oil and gas production”, when he said:

“Let’s be absolutely clear, the Treasury only agrees to allowances [for the oil and gas sector] if it knows it is going to benefit from the overall tax take going up as a result. I think an important part of the dialogue has been to ensure that fields that wouldn’t have been recovered or wouldn’t have improved their recovery rates, those have now come on and actually the taxpayers are net beneficiaries.”

In the case of the offshore oil and gas sector, where the starting point for tax rates is very high in comparison with those imposed on other sectors, the tax allowances that are available for a small number of activities never bring the overall tax rate to a point lower than that which is applied in the UK to business generally – and never to a point whereby the sector is a net benefactor from the taxpayer.

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If this argument was to be applied to, for example, income tax rates, the logical conclusion would be to describe those paying the basic rate of income tax as being subsidised.

Why reliefs in the UK’s oil and gas tax regime do not constitute a subsidy

As discussed above, there is often a tendency to assume that any tax allowances which lessens the burden of tax for particular activities (especially when these activities are sector specific, rather than, for example, general research and development) constitutes a subsidy. However, Oil & Gas UK would like to take this opportunity to draw the Committee’s attention to the special tax regime which operates for hydrocarbon extraction in the UK, which we have outlined below.

The theory of taxing mineral extraction

The taxation of mineral extraction differs from the corporate taxation regime applied to most other sectors. Reflecting the uniqueness of this activity and in acknowledging that reserves are national assets, the offshore oil and gas industry is subjected to “economic rent”.

The taxation of economic rent is characterised by higher than normal tax rates, reliefs for capital investment and the isolation of these activities from any other commercial operations in which companies may be engaged. By putting these tax rates into isolation, also known as ‘ring‐fencing’, it restricts the opportunity for companies to offset losses arising from non‐mineral extraction activities in order to reduce taxable profits from the oil and gas production business, making tax avoidance activities extraordinarily difficult. Indeed, HMRC themselves treat the sector as a whole as low risk due to the strength of the tax code in this area.

The UK oil and gas fiscal regime

In the UK, businesses involved in oil and gas production are subject to three different taxes on their profits (alongside other indirect liabilities such as VAT, NICs etc.). These taxes are outlined below:

• Ring fence corporation tax (RFCT) – levied on a company’s total taxable profits, computed in the same way as normal corporation tax, but for the offshore sector, the rate is 30% (7% higher than the current ‘main’ corporation tax of 23%) • Supplementary charge (SC) ‐ levied on a company’s total taxable profits, computed in a similar way to normal corporation tax, but finance costs are not deductible. The current supplementary charge rate is 32% • Petroleum Revenue Tax (PRT) – levied on the adjusted profits for the field, rather than the company. Only fields which received their original production consent before March 1993 are liable to PRT and it is only paid by the most profitable, productive fields in the UK. The current PRT rate is 50%.

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In practice, this means that the marginal tax rate applied to fields which are subject to PRT is 81% (50% + (50% * (30% + 32%)) on all production income. The tax rate applied to fields not paying PRT is 62% (30% + 32%).

Oil Allowance

To encourage the recovery of technically or commercially challenging assets that would otherwise remain undeveloped, some fields which received their original production consent before March 1993 are granted an ‘Oil Allowance’. This provides fields that would usually be liable to PRT a certain allocation of hydrocarbons that can be recovered before PRT is payable. Whilst the profits from production covered by Oil Allowance is not taxable to PRT, it still bears RFCT and SC at the usual rate of 62% (30% + 32%).

Field Allowance

A number of new fields which meet certain physical criteria benefit from a ‘Field Allowance’. This allows a certain amount of production income that can be generated by the field to be free of the Supplementary Charge. Field Allowances cannot be used to reduce a company’s liability to RFCT.

Field Allowances have been designed to reduce the marginal rate of tax for companies who want to develop small or technically challenging fields which are less profitable. Without this incentive the fields would remain commercially unviable and, as a result, remain undeveloped. Even if a field’s total production income was covered by a Field Allowance, a company would remain liable for RFCT, charged at a higher rate than the rate that corporation tax is applied to businesses generally.

Thus, ensuring that development of these small and / or difficult fields takes place, aggregate tax revenues from the sector will be increased in due course.

“Energy Subsidies in the UK” – Dr William Blyth

Oil & Gas UK also wanted to take the opportunity to respond to the report commissioned by the Committee and written by Dr William Blyth.

UKCS tax regime

We read Dr Blyth’s report with great interest. We felt it would be helpful to clarify some of the detail explored in the sections relating to the UK’s oil and gas sector and in particular to highlight omissions relating to the tax regime that is applied to this industry.

Dr Blyth’s report fails to acknowledge that companies which recover oil and gas from the region of waters surrounding the United Kingdom, otherwise known as the UK Continental Shelf (UKCS) are subject to three different taxes, as discussed above. As a result, there are factual errors in some of Dr Blyth assertions which suggest that one of the taxes paid across the UKCS, i.e. the Supplementary Charge, levied at 32% on all upstream profits, has been omitted.

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“Baseline” tax rates

We dispute, in the strongest possible terms, the assertion given in the report that:

“The standard PRT therefore defines the ‘normal’ baseline tax rate for oil production in the UK.”1

We disagree that the top rate of tax should be considered the baseline against which other tax rates are measured and with the view that allowances applied to this rate should be considered to be subsidies.

As we have discussed above, even if the most generous tax allowances are applied, the overall value transfer remains to the net benefit of the Exchequer and exceeds the tax rates applied to any other business sector operating in the UK. Indeed, as PRT is only payable on fields which received their original production consent before March 1993 this definition of the “baseline” at PRT is further flawed.

Allowances against PRT

Dr Blyth then claims that:

“Various allowances which partially offset the PRT are available to companies which act as subsidies. These include a new‐field allowance that was introduced in 2009 for small, ultrahigh‐pressure and high‐temperature oil fields, and ultra‐heavy oil fields.” 2

Field Allowances are not a relief against PRT, but against the Supplementary Charge. As we explore above, allowances are necessary in the context of taxing natural resources to ensure that marginal fields are sufficiently commercially viable to be developed. Indeed, elsewhere in his report Dr Blyth acknowledges that such measures for high‐cost fields are not uncommon in tax regimes for oil and gas producing countries.

Promote Licenses

Dr Blyth’s paper also asserts that the licensing regime imposed on the oil and gas sector should be considered a subsidy, stating that:

“Other measures to support certain types of production include Promote licences, which allow small and start‐up companies to obtain a production license first and secure the necessary operating capacity and financial resources later through reduced rent for the first two years.” 3

1 Dr William Blyth, Energy Subsidies in the UK, page 20. 2 ibid 3 Dr William Blyth, Energy Subsidies in the UK, page 20

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Oil & Gas UK considers it strange that an area of the oil and gas licensing regime, administered through DECC, is deemed to have a fiscal benefit and therefore is considered, by Dr Blyth at least, to represent a subsidy. In actual fact the Promote licenses are a way of encouraging more diverse range of companies to operate in the UKCS, with reduced licensing fees, but for shorter term license periods. There are no negative fiscal consequences of the licensing regime a company is operating under.

The use of Promote Licenses is intended to boost activity by encouraging the development of smaller, economically and technically challenging prospects. They are designed to maximise the recovery of remaining oil and gas resources and reflect that barrels left in the ground earn the Treasury zero tax revenues.

Further, the development of challenging assets creates jobs, promotes skills development, benefits the UK’s significant the supply chain industry and inspires technological innovations – all of which contribute economically through domestic activity in the UK and globally as exports.

This was recently acknowledged in the UK Oil and Gas Industrial Strategy produced by the Department for Business, Innovation and Skills, which stated:

“…through the recent extensions to the field allowance regime, the Government has demonstrated it is committed to a fiscal regime that encourages investment and innovation in the UKCS, whilst ensuring a fair return for taxpayers.” 4

The Strategy goes on to assert that:

“…changes to field allowances for new fields…have seen a number of major developments proceed... Since introducing the brownfield allowance, uptake has been strong. Significant field life extension has been realised.” 5

Conclusion

Oil & Gas UK is encouraged by the Environmental Audit Committee’s inquiry and feel that the debate surrounding how to define what is and what is not a subsidy, and how subsidies are applied, is one that would benefit from greater clarity.

We are confident that the Committee will find our evidence of relevance to this inquiry and would welcome the opportunity to provide further information should the Committee feel that it would be beneficial.

17 June 2013

4 Department for Business, Innovation and Skills’ UK Oil and Gas Industrial Strategy, page 29 5 Department for Business, Innovation and Skills’ UK Oil and Gas Industrial Strategy, page 30

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Written evidence submitted by Vestas Wind Systems

Summary of Vestas key points:

• Implicit subsidies for fossil fuelled power stations in the UK are significant. Health and carbon costs of fossil fuelled power stations in the UK amounted to between €6.8bn and €10.4bn in 2009. This is a huge implicit subsidy. Such subsidies distort the electricity market, making it unnecessarily difficult for technologies not in receipt of such subsidies, such as wind, to compete.

• Once the electricity market is a truly level playing field it would be reasonable to expect that subsidies for mature renewable energy technologies such as onshore wind can be phased out. A truly level playing field requires an end to implicit subsidies for fossil stations and a robust and meaningful carbon price to be established.

• Direct, policy based subsidies tend to receive more attention than implicit subsidies, including in the Oxford Economics report used as the basis for the Committee’s inquiry. This tends to distort the impression of politicians, the public and the media of the level of subsidies received by wind generators in the UK.

About Vestas

1. Vestas is the world’s largest supplier of wind turbines, having supplied over 46,000 turbines in more than 70 countries, more turbines in more countries than any other supplier. Vestas designs, manufactures, constructs and maintains wind turbines, both onshore and offshore. We are a pure wind player; we believe in wind and do not have interests in any other technology.

2. Vestas employs around 500 people across the UK, from R+D, construction and operations. We are currently manufacturing and testing the 80 metre blade for our dedicated offshore turbine at our world leading Technology Centre on the Isle of Wight.

3. Vestas has experience across a wide range of markets, most in which wind is subsidised to some extent, others where the dynamics of the market mean that wind is economically viable without support. We would be happy to share our experience with the Committee.

Has the Government identified the extent of energy subsidies and measured them?

4. It is important that this inquiry takes account of the extent to which energy sources do not incur costs which reflect their impact on both society and the environment. Any shortfall between the full societal cost and the costs borne by an electricity generator is an implicit subsidy. For example there are significant health costs as well as environmental costs associated with fossil fuel use which are not borne by fossil generators.

5. The European Environment Agencyi calculated that in 2009 the health costs (excluding carbon costs) of the UK’s thermal power stations were between €2bn and €5.4bn per year. These 154 estimates exclude the cost of heavy metals and organic pollutants. These health costs are not borne by the thermal stations that create them but by society and the health service more widely. This creates an implicit subsidy for those thermal stations. The benefit of avoiding such health costs delivered by non-polluting forms of power generation such as wind deliver are similarly not reflected in the market prices.

Health costs of UK Health costs of UK thermal power stations thermal power stations (excluding carbon) (including carbon)

All thermal €2bn - €5.4bn €6.8bn - €10bn

Coal €1.8bn - €5bn €4.9bn - €8bn

Gas €144m - €400m €1.8bn - €2bn

Source: European Environment Agency report ‘Costs of Air Pollution from Industrial Facilities’ 2011

6. The EEA estimated that in addition to the €2bn to €5.4bn for non-carbon costs, the carbon related health costs of thermal plants amounted to EUR4.8bn. Based on these cost figures and reported electricity generation in 2009, the total implicit subsidies for coal is very approximately €45 to €75/MWhii and for gas very approximately €11/MWh to €12/MWhiii. Regardless of the rudimentary calculation, this represents a significant implicit subsidy.

7. The Government does take into account the health costs of its policies in its impact assessments to some extent (see example from the EMR impact assessment below). The monetised health benefit of renewable energy often, however, fails to gain the same attention as the cost of direct, policy based, subsidy cost. This appears to have been the case in the Oxford Economics report for the Committee, which does not mention health costs and the implicit subsidy given to thermal plants by them not being borne in the market. This is a considerable oversight and one which the Committee should ensure is not reinforced in its final report.

FiT CfD Premium FiT

Relative to updated baseline Range Central Range Central

NPV £505-£732m £643m £347-£503m £442m

Table 32: Monetised benefits of the EMR scenarios relative to the updated Baseline for impacts in 2025 (NPV 2010-2030, real 2009)iv

8. There are also impacts on ecosystems and the natural environment, which are not included in the impact assessment for the Electricity Market Reform. ii. How well does the identification match up to best practice?

9. Vestas is not in a position to comment on this question. 155 iii. How does the scale of subsidies compare with other countries?

10. It is very difficult to do a fair comparison of subsidy costs between the UK and other markets, as the treatment of renewable energy projects is very different. For example in the UK a renewable plant is treated as any other type of plant connected to the system. It pays the same transmission costs, incurs the same balancing costs and is constrained as any other plant is. In many other markets renewable projects are given treated differently. This means they incur more implicit subsidies which means they incur less market costs, so require less subsidy. iv. Does the Government have plans to reduce or eliminate subsidies?

11. Removing implicit and direct subsidies for fossil fuels and nuclear is the first step to creating a truly level playing field. Under a truly level playing field most mature forms of renewable energy such as onshore wind would be able to operate without subsidy. Onshore wind has been receiving subsidy in the UK for around 20 years. This pales into insignificance given that 50 year old coal stations currently receive implicit subsidies for their continued operation. Offshore wind which is globally a much less mature technology than even onshore wind, has been receiving subsidy for less than 15 years.

12. A long term policy that gives investors the certainty to invest in high capital cost technologies such as wind is needed. Investors must be confident that the market environment will remain stable, that the carbon price will be maintained throughout the life of the project, that they will have access to the market through the grid and interconnections with other market. Government plans to develop new interconnections and transmissions lines within the UK will also help remove the implicit subsidies given to existing capacity. The electricity network was built to reflect the location of the UK’s fossil fuel resources. The fact that thermal stations have convenient access to the existing grid should not mean they do not have to pay towards the cost of building lines to locations where new forms of energy resources, such as wind, are located. Socialising the cost of building new transmission lines is no different to socialising the cost of the cost of building the national grid in the 1950s. v. Government progress in reducing harmful subsidies

13. Some measures in the Government’s Electricity Market Reform will help reduce subsidies; others are likely to increase the level of subsidies. It should be expected that as the Carbon Price Floor increases the implicit subsidy to thermal plant will reduce. Similarly as the Emissions Performance Standard prevents new coal stations being built and the Industrial Emissions Directive closes some coal stations, the implicit health cost subsidy should fall.

14. The amount of new capacity likely to be covered by a Contract For Difference is likely to lead to a considerable increase in the amount of direct subsidy in the market, at least in until 2020. The actual level of subsidy will depend on the electricity price, as the subsidy in the contracts is the difference between the electricity price and the contract price. If the electricity price increases above the level of the contract price generators have to pay back the difference, so they would represent a negative subsidy.

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i EEA Report ‘Costs of Air Pollution from Industrial Facilities’ 2011 see http://www.eea.europa.eu/pressroom/publications/cost‐of‐air‐pollution ii Health costs of UK coal stations listed in the European Environment Agency report, divided by UK coal station power generation in 2009 as stated in Digest of UK Energy Statistics iii Health costs of UK gas stations listed in the European Environment Agency report, divided by UK gas station power generation in 2009 as stated in Digest of UK Energy Statistics iv https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/48133/2180‐emr‐impact‐ assessment.pdf

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Written evidence submitted by the Fuel Poverty Advisory Group

The Fuel Poverty Advisory Group is a non-departmental advisory body, which consists of a chairman and senior representatives from the energy industry, charities and consumer bodies. Each member represents their organisation, but is expected to take an impartial view. The role of the Group is to:

• Consider and report on the effectiveness of current policies aiming to reduce fuel poverty; • Consider and report on the case for greater co-ordination; • Identify barriers to reducing fuel poverty and to developing effective partnerships and to propose solutions; • Consider and report on any additional policies needed to achieve the Government’s targets; • Encourage key organisations to tackle fuel poverty, and to consider and report on the results of work to monitor fuel poverty. Note

The diverse nature of the Group’s membership may, on some occasions, prevent unanimity on some of the following points.

The Fuel Poverty Context

Escalating energy prices are the biggest cause of more households going into fuel poverty. The long term trend is for prices to continue rising. With every one per cent increase in energy prices, another 50-60,000 households are added to the numbers in fuel poverty. The average domestic dual fuel bill is now at a record high of £1,365 per annum1 creating severe additional hardship for some six million UK fuel poor households2 . The problem is even more acute for many living off the gas grid using Oil or LPG, where average fuel bills are circa £2,100 per annum3. The Government’s Energy Market Reform (EMR) has no beneficial impact on bills between now and 2016 and adds costs from 2016 onwards.

The recession, unemployment plus the industries overall and longer term investment plans estimated at c. £200 Billion to 20204 and uncertainty over new generating capacity and energy prices will exacerbate the problem. FPAG remains deeply concerned that the costs and implication of the UK’s transition to a low carbon economy, has yet to be sufficiently explored. Meanwhile, the regressive means of collecting costs added to fuel bills to fund a range of related environmental and energy costs creates consumer inequity.

1 Ofgem: Electricity and Gas Supply Market Indicators updated 22 November 2012 2 Consumer Focus 2012 3 DECC, Fuel Poverty Detailed Tables 2010 4 Ofgem Project Discovery

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Professor John Hills, at the request of Government, undertook an independent review of the fuel poverty definition and measurement which completed in April 2012. Professor Hills’ ‘interim findings’ and conclusion that fuel poverty is a: ‘distinct and serious problem; that it deserves and requires attention as recognised by Parliament in adopting the Warm Homes and Energy Conservation Act, were welcomed by FPAG. We also noted and strongly endorsed Professor Hills’ emphasis on the detrimental physical and mental health consequences of living in a cold home.

As part of the Review’s conclusions, they established a ‘Fuel Poverty Gap’ which measures the average and aggregate depth of fuel poverty expressed as the difference between costs faced by the fuel poor and typical costs of achieving a warm home. The Review found that fuel poor households are paying £1.1 billion more for their fuel compared to typical households across England. The fuel poverty gap clearly demonstrates the enormous scale of the problem. In his final report Professor John Hills stated: “It is essential that we improve the energy efficiency of the whole housing stock. But those on low incomes and in the worst housing can neither afford the immediate investment needed nor afford later repayments without additional help.” FPAG unequivocally agrees with Professor Hills.

It remains very clear that irrespective of how fuel poverty is to be eventually defined and measured, the number of households and occupants will still remain in the millions. Consequently, a robust strategy delivering serious measures will be required if the Government is to meet the legally binding target to eradicate fuel poverty by 2016.

Under the current definition of fuel poverty nearly 50 per cent of households are pensioners (10 percent contain a person over the age of 75 or over), 34 per cent contain someone with a disability or long-term illness, 20 per cent have a child aged 5 or under5. Hence the plight of the ever increasing numbers of fuel poor households has never been more serious than it is today. High energy bills cause stress and misery for many and often ill health as well for those living in a damp and poorly insulated property.

At the same time as the energy Industry sets course for a low carbon transformation and EMR, the future of fuel poverty, its measurement, definition, mitigation schemes and the welfare benefits system will all change. For the first time since 1978 there will no longer be a government funded fuel poverty programme in England. The devolved assemblies of Scotland and Wales, however, will keep their funded schemes which will be in addition to a GB wide new energy supplier obligation.

The Green Deal and ECO could offer a new opportunity to assist both those households off the gas grid. However, most FPAG members believe that the Energy Company Obligation (ECO) must be dedicated to the alleviation of fuel poverty and not used to subsidise expensive measures on behalf of ‘Able-to-Pay’ households whilst so many fuel poor household still require measures to be fully funded upfront.

5 Hills Review 2011 2012

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Consultation Questions:

(i) whether the Government has identified the extent of energy subsidies, and measured them; (ii) how well any identification of subsidies by the Government matches up to best practice methodologies in how energy subsidies are defined and scoped; (iii) the scale of subsidies in the UK, including comparison with other countries; (iv) whether the Government has any plans or targets to reduce or eliminate ‘harmful’ subsidies; (v) progress in reducing such harmful subsidies, and how current energy policies and DECC’s ‘Energy Pathways’ for the mix of energy sources will influence the magnitude of any subsidies.

Consultation Response

FPAG will limit it response to the issue of harmful energy subsidies and their distributional impacts and progress in reducing such harmful subsidies.

The UK’s transition to a low carbon economy has profound implications for all consumers, but particularly so for the fuel poor. Many stakeholders, including FPAG, argue for major intergenerational policy change such as this, for it to be funded by the Treasury and not by costs directly added to consumer’s energy bills. Adding costs to energy bills in this way is inherently regressive.

Fuel Poverty and Household Income

Fuel price rises have far outstripped increases in household income and have hit the poorest hardest; many low-income households therefore need urgent and immediate help with rising energy costs.

Those with the lowest incomes are the least able to absorb price rises, as fuel makes up a much more significant proportion of their incomes than is the case for those on higher incomes. The mean annual income of fuel poor households in the UK in 2010 was £11,000 compared to an average income of £32,000 for non-fuel poor households6. In addition, those on the lowest incomes typically pay more for their energy with households with an average income of £6,500 paying £1,954 for their energy, compared to those earning around £42,000 paying £1,244 per annum7.

The table below illustrates the fundamental difficulties faced by fuel-poor households. Not only are they economically disadvantaged, they also need to spend more on fuel, in absolute terms, to achieve a warm and healthy living environment i.e. those who need to spend most on fuel are least able to do so and live in the most thermally inefficient properties.

6 DECC (2012) Annual Report on Fuel Poverty Statistics 2012 7 DECC Fuel Poverty Detailed Tables 2010

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Fuel expenditure Number of % of Average as a % of households whole Average full fuel costs Average income (thousands) stock income (£) (£) SAP <5% 9,900 45.8% 41,963 1,244 59.1 5-10% 8,164 37.8% 19,832 1,338 54.0 10-15% 2,275 10.5% 12,549 1,497 47.0 15-20% 641 3.0% 9,649 1,644 42.0 >20% 620 2.9% 6,567 1,954 36.0 Total 21,600 100.0% 28,526 1,338 54.7 Source: Detailed Tables published by DECC in 2012

Social and Energy Policy cost recovery is disproportionally loaded onto electricity bills.

The sums collected by the Big 6 suppliers to fund some aspects of Government social and energy policy are predominantly loaded onto electricity and not gas bills. The view of the Government’s own Fuel Poverty Advisory Group is that the loading and its disparity of these policy costs by 2020 will, on a £per customer basis, look something like £220 vs £90 per annum (all big suppliers support this view).

250

200 VAT

150 Supplier Policy Costs

100 Renewables Obligation / CfD 50 Carbon

0 Electricity Gas

The inequity of costs added to bills is compounded when the market intervention is effectively a ‘tax’ to facilitate low carbon generation to coexist with fossil fuel generation in the competitive energy market and the sums raised subsumed into Treasury coffers.

The introduction of the Carbon Price Floor, subject to the Annual Budget debate is such an example. This intervention will see the cost of carbon steadily rise in GB to £30 per ton by 2020, compared to circa £3.50 per ton at present. Together with the auctioning of EU emissions trading scheme permits to fossil fuel generators, this will raise around £2 billion in 2013 rising to nearly £7 billion by 2027 an average of £4 billion per year8. Both these measures will lift the market price for energy and hence the consumer will pay more.

8 “Jobs, growth and warmer homes: Evaluating the Economic Stimulus of Investing in Energy Efficiency Measures in Fuel Poor Homes” Cambridge Econometrics & Verco for Consumer Focus, October 2012

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Over the next 15 years c. £63 billion will be added to consumer energy bills through the Carbon Price Floor and EU Emissions Trading System (ETS). Meanwhile, FPAG notes the Chancellor’s recent decision to recycle some £300m of the sums to be received from the carbon price floor (c. £1.4billion to be paid by all consumers) to only industrial energy users of electricity to soften its impact, yet will not do something similar to protect the most financially disadvantaged fuel poor consumer in this context. FPAG further notes that consultation will now take place to explore the extension of compensation to cover Contracts for Differences. Meanwhile, the French9, Estonian10 and Australian11 Governments are recycling some on their carbon revenues back to consumers through insulation measures and in Australia, welfare benefit improvements as well.

The long term and sustainable solution to UK fuel poverty is to radically improve the thermal efficiency of its housing stock and, where required, install an efficient heating system. FPAG robustly challenges any assumption that Government cannot afford to aggressively tackle fuel poverty. It argues that the use of carbon tax revenue to fund fuel poor households in particular would have multiple benefits from having warmer homes including improved health, greater energy efficiency, carbon reduction and economic growth.

In order to give greater perspective of distributional impacts and ‘underline its importance’, FPAG wishes to cite the following research12 and conclusions drawn, commissioned by Consumer Focus as part of its commitment to support the work of FPAG on the distributional impacts of energy tariffs. The study was designed to first assess the impact of the Energy Bill and other social and environmental policies on household energy bills, with particular attention to those not likely to benefit from ameliorative measures funded through costs added to bills; and second explore potential solutions to off-set those worst affected.

The hardest hit

A core objective of this research was the identification of households ‘hardest hit’ by the energy policies.

Electricity, as previously mentioned above, is subject to the majority of policy costs. Households reliant on electricity for heating are likely to have higher than average levels of electricity consumption, compared to the rest of the population, and therefore bear a disproportionate share of policy costs. These households might expect to receive measures to offset the particularly high costs they face, but this does not appear to be the case. The research found that a lower proportion of electrically-heated households (27%) benefit directly from policies when compared to all households (40%). Consumers that use electricity to heat their homes see an average increase in their bill relative to the ‘no policy’ bill, while all other consumers see a decrease on average. Furthermore, the difference between electrically-heated ‘winners’ (defined as households that ‘get support’ and benefit from policy) and

9 http://www.gouvernement.fr/gouvernement/systeme-d-echange-de-quotas-d-emission-de-gaz-a-effet-de-serre-periode-2013- 2020-0 10http://www.urbenergy.eu/fileadmin/urb.energy/medias/Events/Piaseczno2011/ppts/WP5_Piaseczno2011_KredEx.pdf 11 summary of the australian government's climate 12 The hardest hit – Going beyond the mean. Centre for Sustainable Energy Bristol, April 2013

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electrically-heated ‘losers’ (households that do not get any support) is stark, at over £500.

The graph below shows the impact of policies on 2020 household energy bills by household heating fuel for DECC’s ‘central policy scenario’.

Impact of policies on energy bill by heating fuel and those who do and do not receive support £400

£300 Households that 2020 £200 do not get in support bill

£100 Average Impact £0 energy on

‐£100 Households that ‐£200 get support policies

of ‐£300 ‐£258

‐£400 Impact Electric Gas Lpg Solid fuel Biomass Oil

Heating fuel

Across all households that do not benefit from energy policy, electrically-heated homes are subject to the largest increase of £282, whilst households using non- metered fuels experience a decrease (regardless of whether or not they benefit from policy). This is because the benefits of products policy outweigh the total policy costs for this group of consumers.

In 2020, electrically-heated households:

• represent 10.5 per cent of the total share of heating fuel by type • pay 18.9 per cent of the total cost of domestic energy policy • receive 6.8 per cent of all measures deployed.

Furthermore, these householders contribute a significant amount towards large scale infrastructure projects designed to deliver energy security and renewable energy. When combined, the EMR and historical legacy of the Renewables Obligation represent the largest share – some 35% - of total policy costs of £4.8 billion in 2020.

Identifying the hardest hit

The analysis of the impact of Government policies on domestic energy bills by different socio-demographic characteristics highlighted some important distributional issues, not least the implications for low-income households with electric heating.

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Chi-squared Automatic Interaction Detector (CHAID) was used to further explore and identify the characteristics of those ‘hardest hit’. The analysis found that of the five groups ‘hardest hit’ by policy costs, four use electricity to heat their home and hence have above average electricity consumption, compared to the population as a whole.

Reducing harmful subsidies and compensating the hardest hit

The research explored a range of approaches for off-setting the impact of policies on those worst affected and produce a more progressive distributional impact – that is, ensure lower income households are proportionally better off compared to higher income households. The application of an ‘equity charge’ in which a fixed credit is given to all consumers and the cost of this is recovered through raising the unit cost of energy above the median consumption threshold, provides a fairly effective form of compensation. However, the changes to tariff design under this approach do not protect the hardest hit as these are typically low-income households with above average electricity consumption.

A different approach to compensating those worst affected involves targeting electrically-heated purpose-built flats and households with occupants who are over 65. There are 1.1m households in electrically-heated purpose built flats. This group are worse off on average by over £100 as a result of policy costs, yet they have lower than average income and expenditure. Similarly households with occupants that are over 65 are typically lower income, especially those that use electricity for heating.

One approach to compensating these households involves allocating them a lump sum payment. However, the scale of payments required to ensure these households become better off on average is considerable (ranging from £500 to £1,000). Therefore, an alternative approach involves reducing their energy costs by an average of 33 per cent through energy efficiency measures. The distributional impact of this approach is shown in the graph below.

Figure A.1. Average bill impact in 2020 by expenditure decile for the demand reduction packages £150 Bill reduced £100 by 33% by EE 2020 (charge in £50 funded) bill

£0 Average Impact ‐ DECC energy Central ‐£50 on

‐£100 Bill reduced policies

by 33% by EE of ‐£150 (tax funded)

‐£200 Impact 12345678910 Total expenditure decile

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Further work is needed to quantify the cost of measures required to deliver the savings across the 1.68 million households identified for targeting. However, the ‘consumer credit’ package investigated as part of this study generated revenue of £1.1 billion per year from consumer bills, which is similar in scale to the current Energy Company Obligation.

Policy implications

The research explored a number of options for targeting the hardest hit households. It identified two groups that would benefit from targeting; households in purpose built flats with electric heating and all properties with electric heating containing at least one pensioner. The final stage of this research explored options for compensating these households. The research found that providing sustainable energy measures to reduce household energy costs provided the most successful approach to protecting these households and was the most progressive option in terms of distributional impact.

Further analysis reveals towards 30% of the off-peak typical electric heating tariff being required to cover the government’s policy, and with further increases likely, that it is not unrealistic to foresee this increasing to some 50% of off peak unit costs. This is hardly in concert with the government’s strategy to electrify heat and transport.

Conclusion

The review of harmful subsidies and their distributional impacts of the above have shown that there remains a significant gap for the hardest hit by energy policy. In FPAG’s opinion amendments to the current Energy Bill to compensate these households should now be considered.

Options for Government to explore:

• The new Energy Company Obligation and Warm Home Discount levied more towards the gas bill. • Make all off peak units unencumbered with policy costs. This would support Government’s ambition to electrify heat and transport and also create a real price differential for customers to time shift energy appliance usage. • Make the electricity consumption of homes without access to mains gas unencumbered with policy costs. In my opinion, it could be accommodated in Retail Market Reform proposals but it would require a firm government commitment to eliminate these volumes when allocating obligations between suppliers in the future. Liquid Propane Gas and Heating Oil are 50 per cent more expensive that mains gas. It would be an equitable solution of a legacy issue that is fundamentally unfair. • Promoting modern storage heaters to electrically heated flats as a mechanism to balance supply and demand in a future that will have a more system balance challenges e.g. wind, solar, electric vehicles etc.

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• Make all demand side management units of electricity unencumbered with policy costs. This would facilitate a simple ‘level playing field’ message to stimulate this market and also engage more consumers in smart meters and to seek cheaper prices. • Ensure its forthcoming Fuel Poverty Strategy and Heat Strategy also considers policies for compensating these households by, for example, installing solid wall insulation, heat pumps and/or gas district heating as a priority. • In terms of future funding for these measures further consideration of the use of existing carbon revenues or revenues from an EE FiT.

25 June 2013

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Written evidence submitted by Malcolm Grimston

THE FULL COSTS OF GENERATING ELECTRICITY

EXECUTIVE SUMMARY

The recent debate about costs of low-carbon electricity has tended to be based on a rather crude ‘cost of a generating unit divided by number of units produced’ approach. The potentially vast costs associated with managing the inherent intermittency of some renewables, notably wind and solar, are not at present fully reflected either in the stated costs of these energy sources nor in the quoted ‘subsidies’ they are receiving. It is becoming increasingly clear that the full costs – both economic and environmental – of all sources of electricity, most notably variable sources such as renewables like wind and solar, should include not only the direct costs referred to above but also indirect costs caused by, for example, the intermittency of the output. These costs are potentially very large and include the need for grid strengthening (‘grid-level system costs); the effect on the economics of other generators, leading to higher prices (or threats to security of supply, in itself a huge potential cost to consumers); and the greenhouse gas emissions caused by the need vary the output of dispatchable fossil-fuelled power plants, thereby reducing their thermal efficiency. A rational approach to allocating limited resources to deliver maximum supply security and emission reduction would involve ascribing all costs and environmental effects, direct and indirect, to the source which has ultimately given rise to them. This would lead to a very different discussion re the way of achieving economic, security of supply and environmental goals – for example, arguably leading to a reclassification of variable renewables as ‘medium carbon’.

THE UNIQUE CHALLENGES OF ELECTRICIY

Electricity is a unique commodity. Despite over a century of research, it still cannot be stored in significant amounts – pumped storage is feasible in some circumstances but requires appropriate geology and major capital investment and suffers from losses of some 15% - 30% of the power input.1

For most commodities, of course, it is possible to manufacture them when it is convenient, then to stockpile them until they are needed. If it makes sense, for example, to manufacture shoes overnight (say to take advantage of low power prices), the shoes can be stored for a practically unlimited time until someone wants to buy them. But with electricity we have to be able to make exactly the right amount to fill requirements on a moment-by-moment basis. Generating too much puts great strain on the wires which carry electricity from the power station to the customer and can lead to their deforming and ultimately melting, with serious effects – e.g. ‘electrical arcing’ or severe damage to transmission capacity. Generating too little puts us in danger of poor quality electricity supplies and, eventually, power cuts, which are extremely expensive. Among the effects of power cuts are failures in our transport systems, losses of a day’s production in the workplace, loss of a freezer full of food, inability to pump water into our homes or power our hospitals, and severe social disruption, e.g. looting and vandalism if the power cut occurs overnight.

1 http://www.electricitystorage.org/technology/storage_technologies/pumped_hydro/, Electricity Storage Association (2012), Electricity storage – pumped hydro.

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Even if the discrepancy between supply and demand is not sufficient to cause damage to the transmission network or power outages, an excess or shortage of power demand can result in an increase or decrease in frequency of the power supply. (In the UK the National Grid has a statutory duty to maintain the frequency in the range of 49.5 Hz to 50.5 Hz and usually upholds it at between 49.8 to 50.2 Hz.2) If the frequency should become too high this can cause direct damage to a variety of appliances and/or increase wear and tear. If the frequency is too low then equipment will tend to underperform. In turn this may lead operators to increase their demand where they can (e.g. the driver of an electric train opening the throttle to compensate for the lower speed), which may exacerbate the supply/demand discrepancy.

Variations in UK power demand, 2010/113

Power demand varies considerably, both during the day and during the year. The difference between peak demand and lowest demand in the UK is roughly a factor of 3 (60,000 MW to 20,000 MW). Usually demand fluctuation is fairly predictable but variations can be very rapid. The biggest power surge to date in the UK was some 2,800 MW after the penalty shoot-out in the 1990 football World Cup semi-final between England and West Germany in 1990 (when supporters put the kettle on for a consolatory cup of tea). Electricity planners needed to be ready for the moment when coverage of the Royal Wedding in 2011 reverted to the TV studio, when demand surged by 2,400 MW.4

2 http://www.nationalgrid.com/uk/Electricity/Data/Realtime/, National Grid (2013), ‘Electricity – real time operational data.’ 3 http://www.nationalgrid.com/NR/rdonlyres/D4D6B84C-7A9D-4E05-ACF6- D25BC8961915/47015/NETSSYS2011Chapter2.pdf, National Grid (2011), 2011 National Electricity Transmission System (NETS) seven year statement. 4 http://www.clickgreen.org.uk/analysis/general-analysis/122208-royal-wedding-triggered-record-energy- demand-on-uks-national-grid.html, ClickGreen (2011), ‘Royal Wedding triggered record energy demand on National Grid.’

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This balancing act creates considerable challenges, both technical and economic. In a functioning system, the grid operator, who is ultimately responsible for keeping supply and demand in balance, has to be able to order (or ‘dispatch’) enough reliable electricity to fulfil demand, but no more. Furthermore, somebody has to keep power stations available to fill very high levels of demand, say on a cold, still, cloudless winter evening, while knowing that these plants will not be called upon for most of the rest of the year when demand is lower. The costs of failing to fulfil demand are very high – typically the ‘Value of Lost Load’ (VOLL) is estimated at between 50 and 350 times the price of a delivered unit.5

THE IMPORTANCE OF ‘DISPATCHABILITY’

Traditionally, most countries have overcome these problems by building, or encouraging the building of, large power stations whose power can be varied (or which can be turned on and off) in response to changes in demand. Nuclear power stations, which have very low variable costs – in other words, since they use very little fuel they cost very little more when they are operating compared to when they are not – tend to be used for ‘baseload’, i.e. the power demand that never goes away (to keep water pumping systems operating, transport running and so on). The baseload is roughly 20 GW in the UK, considerably more than installed nuclear capacity of around 10 GW, meaning that when the system is being run rationally the nuclear stations will operate continuously whenever they are available. Fossil- fuelled power stations – particularly gas but also coal – are used to ‘load-follow’, since a considerable proportion of their costs is saved when they are not running. However, the important thing is that all of this plant is ‘dispatchable’ – i.e. it will be available to generate if the grid operator requires it to do so (unless it is closed down for maintenance or has broken down unexpectedly). At times of very high demand the real-time power price increases enormously to compensate those companies which do keep power stations ticking over to fulfil that very high demand.

In order to maintain the quality of supply and ultimately to keep the lights on in unforeseen circumstances – say a particularly cold snap or a time when two or three large power stations break down unexpectedly – the grid operator seeks to maintain what is called a ‘capacity margin’ in the system as a whole. So if we expect the highest demand in a particular year to be about 60,000 MW, the ideal situation would be to keep about 72,000 MW of power capacity ready for use, in case the demand should happen to be say 65,000 MW and up to 7,000 MW of power plant was undergoing maintenance or had broken down unexpectedly. A capacity margin of about 20% is generally regarded as sufficient, though from time to time it has exceeded this (and indeed fallen below it).

THE CHALLENGE OF VARIABILITY

However, recently things have begun to change significantly because of growing use of renewable sources of energy, many of which are ‘variable’ (the opposite of ‘dispatchable’) because they depend on unpredictable, or at least very variable, weather conditions. The output from, say, a windfarm will typically be about 25-30% of its ‘rated’ capacity – in other words if the windfarm produces 100 MW of electricity when the wind is blowing at the best speed, the average output will be between 25 and 30 MW. (In 2010 the figure was 23.7% in the UK, in 2011 it was 29.8%.6) However, it is very difficult to predict with any great accuracy or much in advance when the wind will blow – indeed, wind speeds can vary over a few seconds or minutes on a ‘gusty’ day.

5 Cramton P. and Lien J. (2000), Value of lost load, University of Maryland. 6 https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/65850/5956-dukes-2012- chapter-6-renewable.pdf, DECC (2012), Digest of UK Energy Statistics, Chapter 6.

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Short-term variability in wind speed 7

The output can vary very rapidly – sometimes within a matter of seconds or minutes – as weather conditions change. Although the most rapid variations are to some extent compensated for by the inertia of the wind turbine rotor, the phenomenon still creates technical, financial and economic problems. Technically, turbulence necessitates the provision of a great deal more wire capacity in order to accommodate all power being produced when the wind is blowing, but then very rapidly switch supply to another area of the country when the wind drops and other types of power plant are required. In China about half of the energy being produced in windfarms is wasted because the grid connections are not yet in place.8 It also offers challenges to maintain system frequency and imposes more wear and tear on the wind turbines. Wind turbine towers are usually tall enough to avoid the greater wind turbulence encountered close to ground or sea level.

Evidence suggests that low wind speed tends to be weakly correlated with high power demand (cold windless winter evenings and hot windless summer days), further exacerbating the challenges.9 At other times wind or solar generators may be producing close to 100% of their rated output, risking overloading the system and obviating other power sources to close down.

7 University of Strathclyde (2013), 8 http://www.chinadaily.com.cn/bizchina/2011-02/15/content_12019641.htm, China Daily (2011), ‘2.8 billion kWh of wind power wasted’, February 15 2011. 9 http://www.jmt.org/stuart-young-report.asp, Young S. (2011), Analysis of UK Wind Power Generation November 2008 to December 2010, John Muir Trust

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Variation in output from wind generators in Germany, 200310

It is not enough simply to have sufficient generating capacity available to meet demand. If the quality of the supply (especially its frequency) is to be maintained then the capacity available must be able to respond quickly to changes in demand on the system. With the exception of some renewables such as hydropower and biofuels, which are dispatchable, most renewables are unable to provide this responsiveness as the output is determined by wind speeds, tides or sunshine. The output of conventional power stations, by contrast, can be actively varied by increasing or decreasing the amount of steam being generated and fed to the turbines.

Managing a system which includes a lot of variable renewables presents a number of challenges, depending on whether the wind is blowing or is not.

When the wind is blowing (or the sun is out or the tide is in), in order to prevent excess supply and, for example, damage to the transmission wires or unacceptably high frequencies, quite a lot of that energy has to be wasted – in the UK in recent years wind generators have often been paid quite large sums of money to stop generating electricity when the wind is good11 – and/or other companies have to cut their output to compensate.

The latter response undermines the profitability of the gas- or coal-fired plants that are having the market cut from under them. (The economics of nuclear power means that it would be the last to be withdrawn if there was an excess of variable output at any particular time.) But when the wind is not

10 http://www.eonnetz.com/frameset_reloader_homepage.phtml?top=Ressources/frame_head_eng.jsp&bottom=fra meset_english/energy_eng/ene_windenergy_eng/ene_win_windreport_eng/ene_win_windreport_eng.jsp, E.On Netz (2004), Wind Report 2004. 11 http://www.bbc.co.uk/news/uk-scotland-13253876, ‘Scots windfarms paid cash to stop producing energy’, BBC website, May 1 2012.

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blowing we still need almost as many gas- and coal-fired power stations as we would have needed if we have never built the windfarms in the first place. So some way has to be found of compensating the fossil fuel power stations for the market they lose when the wind is blowing. If this is not done they might be closed down or mothballed, and so not be available for when the wind drops. This problem is already being seen in countries like Germany and Spain with a lot of wind energy12 and is also at the heart of some of the contradictions in the UK Energy Bill which was published in draft form in December 2012.

On the one hand, the Energy Bill is responding to the likelihood that, left to a free market, investors would only fund new build combined cycle gas turbines (CCGT). CCGT is quick and cheap to build and maintain and the technology is particularly appropriate for load-following, it being relatively easy and economically worthwhile to vary its output depending on the system demand. Although it is expensive to run (fuel costs dominating overall costs) it is economically quite low risk, because if the gas price does soar (the key economic sensitivity for gas-generated electricity, since most of the cost of that electricity is the cost of gas), then the extra cost can very largely simply be passed on in higher power prices to customers who have nowhere else to go, at least in the short term.

Nuclear and renewables, by contrast, are much more capital intensive (i.e. they cost a lot more to build per unit of installed capacity), though they are cheaper to run. Unmitigated coal capacity lies between CCGT and low-carbon sources, while coal with Carbon Capture and Storage (CCS) also has high capital costs. The key economic sensitivity for these sources, then, is how the initial construction programme is managed. The costs associated with any time or cost overruns in the construction phase cannot be passed on to consumers in the same way. Consumers could simply commission a new CCGT to replace the output from the nuclear or renewable plant while it was being finished. So the Energy Bill proposes a ‘carbon price floor’ (i.e. a guaranteed bonus for sources of electricity like nuclear and renewables that do not emit carbon dioxide) and contracts-for-difference (in effect a guaranteed long-term power price) to promote investment in renewables and nuclear.

On the other hand, however, if these measures work and more variable renewables are brought online, then as noted earlier the economic case for investing in new CCGT or other dispatchable technology is weakened, since these plants would be left without an income during those times when the wind was blowing at the right speed. (This is even more the case with more heavily capital intensive sources such as coal with CCS or nuclear, as their economics are more seriously harmed by being taken off line.13) But eventually we have to have new CCGTs (or other flexible dispatchable capacity) to provide power when the wind drops, or the lights go out. So the government is having to introduce other measures, notably capacity payments (paying companies to keep power capacity available even if it is not being used), to compensate CCGT for the effects of the measures it introduced to deter CCGT in the first place. The vast costs incurred by this need to manage the inherent intermittency of renewables are not at present taken into account when calculating the true costs of renewables and the full subsidies they receive. German energy and environment minister Peter Altmaier has estimated the cost of Germany’s transition to renewables at up to €1 trillion. Feed-in tariffs account for more than half of the total, underpinned by a regime under which customers are forced to take all the renewable electricity being generated at any particular moment. This ‘must-take’ regime represents a major

12 http://www.businessweek.com/news/2013-01-23/eon-rwe-may-have-to-close-down-unprofitable-gas-power- plants, Andresen T. and Nicola S. (2013), ‘EON, RWE may have to close down unprofitable gas power plants’, Bloomberg Business News. 13 http://www.oecd-nea.org/ndd/reports/2011/load-following-npp.pdf, OECD/NEA (2011), Technical and economic aspects of load following with nuclear power plants.

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subsidy to renewables alongside the upfront subsidies but is rarely described as such. Improvements to the German grid will cost an estimated €27.5 billion and €42.5 billion.14 Over 8,000 km of new or upgraded transmission lines (with associated environmental impact) will be required and grid operators have said, “The investments required for expanding the transmission network only represent a fraction of the energy switchover's cost, but they are essential for its successful implementation”.15

The point is emphasised by a table from the UK government’s National Policy Statement on Energy (July 2011).16 Already the UK is running a significant capacity margin (over 40%) because an increasing amount of that capacity is variable and cannot be relied upon to fulfil peak demand. The projected need for generating capacity in 2025 is no less than 113 GW, to cover peak demand unlikely to be more than about 65 GW in that year, even with good economic recovery. That would seem to represent a capacity margin of over 70%, vast by historical standards. It would be necessary purely to cope with the variability of the 33+ GW of new renewable capacity. Whether the cost of building and maintaining such enormous redundancy is borne by the renewables or, by distorting the market, is apportioned to other players (through ‘must take’ contracts for renewable output), it is ultimately going to land on the backs of consumers (and/or the taxpayer).

Total current generating capacity 85 GW Peak electricity demand now & 2020 60 GW Average demand 43 GW Closure of coal plants by 2015 owing to the Large 12 GW Combustion Plant Directive Nuclear closures over next 20 years 10 GW Generating capacity required in 2025 113 GW Of which new build 59 GW Of which renewable 33 GW For industry to determine 26 GW Non-nuclear already under construction 8 GW Current proposals for new reactors 16 GW

So when it comes to looking at the costs of various sources of electricity, it is highly misleading simply to consider the cost of installing the wind generator or solar panel divided by the number of units of electricity it produces. Some sources of electricity, notably the variable renewables, impose huge costs on the system as a whole.

14 http://www.faz.net/aktuell/wirtschaft/wirtschaftspolitik/energiepolitik/umweltminister-altmaier- energiewende-koennte-bis-zu-einer-billion-euro-kosten-12086525.html, Frankfurter Allgemeine (2013), ‘Umweltminister Altmaier, Energiewende könnte bis zu einer Billion Euro kosten’, February 19 2013. 15 http://bigstory.ap.org/content/grid-operators-say-germany-must-invest-25-billion, ‘Grid operators say Germany must invest $25 billion’, The Big Story, May 30 2012. 16 https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/47854/1938-overarching-nps- for-energy-en1.pdf, DECC (2011), Overarching National Policy Statement on Energy (EN-1).

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GRID-LEVEL SYSTEM COSTS

The issue is considered in depth in an OECD/NEA study published in November 2012.17 The report looks at the way various methods of generating electricity interact with each other. Such external costs of particular sources, or ‘system costs’, are defined as the total costs above plant level costs to supply electricity at a given load and given level of security of supply. They can take the form of intermittency, network congestion, greater instability (i.e. higher risk of interruption to supply) etc.. The focus of the report is on system costs associated with nuclear power and renewables such as wind and solar photovoltaics. In particular, the report considers ‘grid-level system costs’, a subset of overall system costs that consists of the costs of network connection, extension and reinforcement, short-term balancing and long-term adequacy in order to ensure continuous matching of supply and demand under all circumstances.

The report considers the complex issues arising from the integration of significant amounts of variable renewables, which profoundly affect the structure, financing and operation of electricity systems, thereby having economic and financial implications well above the ‘plant level’ costs of these sources. It includes the first quantitative study of grid-level system costs in six countries (Finland, France, Germany, South Korea, UK and USA).

The most important effects of a large variable renewable component in a particular electricity system may be:

• lower and more volatile electricity prices in wholesale markets due to the influx of variable renewables with very low marginal costs (including zero fuel costs), leading to the closure or mothballing of existing plant need to maintain secure supplies; • the reduction of load factors of dispatchable power generators (the ‘compression effect’) as renewables with very marginal cost are given priority over dispatchable supply;

17 http://www.oecd-nea.org/ndd/reports/2012/system-effects-exec-sum.pdf, OECD/NEA (2012), Nuclear energy and renewables: system effects in low-carbon electricity systems.

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• the introduction of inefficiencies in existing plants coupled with an influx of renewables, implying an increasing gap between the costs of producing electricity and prices on electricity wholesale markets; • greater physical wear and tear to thermal power plants owing to the greater stress on (especially) metal components – as the metal expands and contracts alongside unnecessary increases and decreases in output and hence core operating temperature it is more likely to crack – thereby shortening the life and/or increasing the maintenance costs of these plants.

The financial implications of variable renewables are therefore potentially profound in both the short term and the long term.

In the short term, the dispatchable power technologies will suffer owing to the compression effect. The effect on nuclear may be less than on other dispatchable technologies, as nuclear has low variable costs. It is therefore likely to continue to run when large amounts of renewable electricity are available (e.g. because the wind is blowing at or near optimum speeds) as there is little economic advantage in taking them offline (while taking CCGT offline saves significant amounts of gas). As noted earlier, gas plants are already experiencing substantial declines in profitability in many countries with high shares of variable renewables.

The threat to security of supply represented by the encroachment of renewables into the market of dispatchable generators are amply demonstrated by recent developments in the UK. Some 4.5 GW of coal-fired capacity at Didcot, Kingsnorth and Cockenzie, and over 2 GW of oil-fired capacity at Fawley and Grain, was closed earlier than expected in 2012/13.18 At the same time capacity margins are projected to fall dramatically in the near future, perhaps as low as 4% by 2015/16, well below the 20% generally regarded as being necessary to ensure secure power supplies.19

18 http://www.argusmedia.com/pages/NewsBody.aspx?id=841211&menu=yes, Argus Media (2013), ‘Coal-fired plant closures to increase UK gas burn.’ 19 http://www.ofgem.gov.uk/Media/PressRel/Documents1/20121005_Capacity_press_release.pdf, Ofgem (2012), ‘Projected tightening of electricity supplies reinforces the need for energy reforms to encourage investment.’

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16% 14% 12% 10% 8% 6% 4% 2% 0% 2012/13 2013/14 2014/15 2015/16 2016/17 Base case High CCGT Low CCGT

Projected UK capacity margins 2012-2017

The inescapable conclusion would seem to be that ‘energy-only’ electricity markets will need to be supplemented with ‘capacity markets’ (or markets with capacity obligations) if dispatchable technologies are to remain in the market to provide back-up for when the wind is not blowing at the right speeds.

In the long term, however, nuclear power is likely to be more seriously affected than gas or coal, owing to the higher capital investment costs and hence higher risks in volatile low-price environments.

Some of these effects are already being noticed. Nuclear power in Germany has in recent years moved away from the traditional and efficient role of operating at stable levels close to full capacity, as the introduction of large amounts of variable renewables has repeatedly led to prices below the marginal costs of nuclear, including several instances of negative prices. (Electricity becomes a good of negative value if so much is being generated that costly measures must be taken to prevent overloading the wire system – good news for customers in the short term but disastrous if it results in dispatchable plant being mothballed or not replaced.)

For different reasons (i.e. that there are times when the available nuclear output is greater than total demand) nuclear power also follows load in France to a considerable extent. Both the French and German experience shows that this can be done technically. Studies suggest that the short-term technological load-following capabilities of nuclear are comparable to coal-fired generation but not as good as CCGT and well behind open cycle gas turbines (OCGT).20 (The overall economics of the last mean that it tends only to be used at times of very high demand.)

20 http://www.templar.co.uk/downloads/0203_Pouret_Nuttall.pdf, Pouret L., Buttery N. and Nuttall W. J. (2009), ‘Is nuclear power inflexible?’, Nuclear Future Vol. 5.

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The study attempts to quantify the grid-level system costs of various electricity sources in the six countries named earlier. There is quite a degree of variation among these countries, reflecting such factors as the siting of plants with respect to demand, the overall mix, the quality e.g. of wind cover and the levels of security of supply demanded. Taking the UK as an example, the calculated grid-level system costs of various sources of electricity are as follows. (The figures are cited for a case where the technology in question provides 10% of total electricity and 30% of total electricity and are in US$ per MWh.)

Technology Nuclear Coal Gas Offshore Onshore Solar wind wind Penetration level 10% 30% 10% 30% 10% 30% 10% 30% 10% 30% 10% 30% Total grid-level system costs 3.10 2.76 1.34 1.34 0.56 0.56 34.0 45.4 18.6 30.2 57.9 71.7

This implies that introducing variable renewables up to 10% of the total electricity supply will increase per MWh costs, depending on the country, by between 5% and 50%, whereas if the penetration level is 30% this may increase per MWh costs by between 16% and 180% (the last figure referring to solar PV in Finland).

The study also looks at the effect on the profitability of dispatchable technology (and therefore the effect on the incentives for companies to invest in new plant) of having wind and solar at penetration levels of 10% or 30%. (Profitability of these plants is affected both by being taken off line, so losing direct income, and by the very low market price of electricity at times when significant amounts of renewables are available.) The results are striking.

Penetration level 10% 30% Technology Wind Solar Wind Solar Load losses CCGT -34% -26% -71% -43% Coal -27% -28% -62% -44% Nuclear -4% -5% -20% -23% Profitability CCGT -42% -31% -79% -46% losses Coal -35% -30% -69% -46% Nuclear -24% -23% -55% -39% Electricity price variation -14% -13% -33% -23%

However the system is organised, these costs will need to be met. An economically rational system would place these costs on the renewable technologies themselves, by mandating variable renewables to compete in the market on equal grounds to dispatchable technologies. As noted earlier, in reality renewables are generally shielded by transferring the costs onto the system as a whole, e.g. through ‘must-take’ contracts that mandate distributors to buy renewable electricity whenever it is available, whatever costs might be incurred on other generators as a result. These market arrangements are just as important, if not more so, as the direct subsidies which have been offered to renewable investors through Renewable Obligation Certificates.

‘Smart grids’, which can for example switch fridges or heating systems off for one or two hours when supply drops, may help to mitigate some of these issues to some extent. However, it is difficult to see how a similar approach could revolutionise practice in industry, where cutting power supply would potentially leave a workforce idle. There seem then to be three broad solutions to this challenge.

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• Capacity payments or markets with capacity obligations, in which variable producers need to buy ‘adequacy services’ from dispatchable providers, which would thus earn additional revenues. • Long-term, fixed-price contract subscribed by governments for guaranteed portions of the output of dispatchable plants whether in the form of contracts for differences or feed-in tariffs. • The gradual phase-out of subsidies to variable renewables, the discontinuation of grid priority and a more direct allocation of additional grid costs to the sources which cause them – this would slow down deployment of renewables (hence reduce costs very considerably) but would also force the internalisation of grid and balancing costs.

THE HIDDEN GREENHOUSE GAS EMISSIONS OF RENEWABLES

Clearly, the need in effect to double the amount of capacity – generating and transmission – to ensure secure supplies in a system with heavy use of variable renewables will result in much higher greenhouse gas emissions (and other resource and environmental impacts) simply from constructing the infrastructure itself. However, the greenhouse gas implications of variable renewables go further. The back-up spinning capacity required to cope with the variability of renewables emits significant amounts of carbon. The inefficiency introduced in fossil generators by having to vary their output to compensate for changes in the output of variable renewables means more emissions of carbon dioxide per unit of electricity generated in these plants. System emissions will therefore be higher than one would believe by simply assuming that when renewables are generating they replace an equivalent amount of carbon-producing capacity. In some cases, at least where coal is the main source of generation, the thermal inefficiency losses outweigh the displacement advantages, resulting in higher emissions than if the wind farms were simply shut down.21 At present these carbon emissions are allocated not to the renewables whose presence causes them but to the back-up capacity itself. This again presents a skewed picture of the true implications of the various sources of electricity.

CONCLUSIONS – A MORE RATIONAL APPROACH

The NEA report makes four recommendations.

1. Increasing the transparency of power generation market costs at the system level, so it is clear to decision-makers the full economic costs of variable renewables. 2. Preparation of regulatory frameworks that minimise system costs and favour their internalisation – i.e. the costs fall where they are incurred. Four points need to be addressed here: • the decrease in revenues for operators of dispatchable capacity owing to the compression effect; • the need to internalise the system costs for balancing and maintain supply adequacy effectively; • allocation of costs to the appropriate technology, insofar as it is possible; • the need for careful monitoring and internalisation of the carbon implications of the requirement for back-up, through a carbon tax again imposed on the causes of the emissions, not necessarily simply the plants that are producing them.

21 http://docs.wind-watch.org/BENTEK-How-Less-Became-More.pdf, Bentek (2010), How less became more – wind, power and unintended consequences in the Colorado energy market.

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3. Better recognition of the value of dispatchable low-carbon technologies in complementing the introduction of variable renewables. 4. Development of flexibility resources for future low-carbon systems, e.g. working on increasing the extent to which nuclear plants can follow load, greater storage capacity and increasing international interconnection (a greater challenge for islands like the UK or Japan than it is for a continental nation like Germany or Switzerland).

Whether or not these recommendations are followed, it is vital that the full costs of use of various sources of electricity are taken into account when planning a system that needs to balance costs alongside system security and environmental implications if the best policies are to be followed. The claim that some variable renewable sources are close to ‘grid parity’ – i.e. are becoming economically competitive with other sources of electricity – tend to be made on the basis that renewables are shielded from their economic and environmental implications. It is of course still a perfectly defensible stance for government to take to argue that certain non-financial advantages of renewables (whatever such advantages might be) merit a very steep increase in power bills or a doubling of the national debt (alongside the much greater land or water area required). But such statements must be made against a realistic assessment of what those costs are and what are the associated reductions, if any, in greenhouse gas emissions from the system as a whole rather than the wind turbine or solar panel taken in isolation. Otherwise we may find consumers paying vastly inflated bills on the basis of promises which cannot be delivered on technically.

30 May 2013

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Written evidence submitted by the Department of Energy and Climate Change and HM Treasury.

Introduction 1. This is the Government’s evidence to the Environmental Audit Committee inquiry into energy subsidies, covering UK government support for energy, following a call for evidence on 24 April 2013. This evidence is a joint response from the Department of Energy and Climate Change (DECC) and HM Treasury (HMT).

Background 2. Currently there is no universally accepted definition of a subsidy. The Organisation for Economic Co‐operation and Development (OECD) describes it as an “elusive concept”1. The spectrum of what could be included in a definition is extremely broad. The narrowest possible definition of subsidy refers to direct budgetary payments by a governmental body to producers or consumers.2 The widest definitions extend to most or all areas of government activity, encompassing the time government officials act for or on behalf of a particular group or industry.

3. Neither extreme would provide the basis for sensible engagement on how, and to what extent the Government incentivises a particular sector to deliver Government objectives.

4. The International Energy Agency (IEA), OECD, the World Trade Organisation (WTO) and others have all undertaken work to look at subsidies, and have endeavoured to provide definitions. However, these definitions have been proposed for specific purposes and studies.

5. The Government has worked with international organisations on a number of these studies into subsidies. Agreeing working definitions of subsidies has been important to progress these areas of inquiry which seek to provide recommendations and advice for governments to reduce the incentives for fossil fuels and encourage low‐carbon alternatives.

6. The Government looks at the support it provides more generally, allowing it to consider development, deployment and management of a clear and coherent package of support to enable the Government to deliver its energy objectives.

7. The UK faces a huge investment challenge to ensure security of supply, and keep energy bills affordable while meeting targets for economy‐wide decarbonisation. To meet our energy objectives, the Government needs to diversify the mix of energy, increasing and accelerating the use of low‐carbon energy in the UK.

8. The Government’s policy therefore is to incentivise the energy industry to bring forward investment where there is a market failure that would act as a barrier to do so in the absence of

1 Overview of key methods used to identify and quantify environmentally harmful Subsidies with a focus on the energy sector page 14 2 ibid page 6

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those incentives. For example, while new mechanisms were introduced to enable renewable generation to compete in the market this left exposure to power price risk. For investors in technologies such as offshore wind, which face substantial initial investments but very low running costs, this can be problematic. Additionally, support available for low‐carbon generation was not considered within a long‐term funding envelope, meaning that investors have not had certainty and consumers have not been protected.

9. The Government has taken decisive action to address these issues and provide a sustainable, long‐term basis for investment in electricity. It is determined to ensure that electricity supplies are secure, produce fewer emissions, and above all are affordable for consumers. It has:

• introduced legislation to provide new support for low‐carbon electricity generation through Contracts for Difference (CfDs) which will provide investors in technologies such as wind for the first time with stable, predictable revenues and protect them from the risks associated with wholesale volatility; • implemented the levy control framework and set a long‐term funding envelope for support available for investment in low‐carbon generation, to up to £7.6 billion (in 2012 prices) in 2020‐21; this provides unprecedented certainty, stretching well beyond existing spending plans; • created incentives for low‐carbon investment further by implementing the Carbon Price Floor; • invested in low‐carbon infrastructure projects through the Green Investment Bank (GIB) which seeks to leverage additional private finance through its lending and aims to multiply the £3 billion lent through its original capitalisation; and • recognised the need to accelerate delivery of schemes in the shorter term. Therefore the Government is using the strength of its balance sheet to provide the £40 billion UK Guarantees facility for infrastructure projects3.

10. Energy taxes on businesses are designed to support wider energy policy in addition to raising revenue and cover both upstream and downstream activities. The main taxes are the oil and gas tax regime, the Carbon Price Floor (CPF), the Climate Change Levy (CCL) and the Carbon Reduction Commitment (CRC), all of which have different objectives. In the case of oil and gas the Government has introduced field allowances for more challenging categories of field that are economic, but commercially marginal at the high rate of tax. Such fields are relieved of tax of 32% for a certain portion of their income – but they still pay ring fence corporation tax at 30% for this portion, higher than the mainstream corporation tax rate. Field allowances do not reduce the cost of oil to consumers; rather increase what is extracted from the UK continental shelf.

11. In the case of the CPF, EU emissions trading scheme, CCL and CRC, the Government does provide support for certain industries or sectors which would be disproportionately impacted or as a transition measure to prevent carbon leakage. It is important the Government provides this kind

3 Details and conditions are on the .gov website: https://www.gov.uk/government/news/government‐uses‐ fiscal‐credibility‐to‐unveil‐new‐infrastructure‐investment‐and‐exports‐plan

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of support to ensure our tax system remains competitive whilst managing the transition to a low‐carbon economy.

12. The Government is open and transparent about where, how, and to what extent it provides support to incentivise the energy sector to help deliver the Government’s objectives, regardless of what that support is called.

13. The Government does not consider that any of its energy policies are ‘harmful’. Furthermore, energy policy (as with other Government policy) is subject to an initial impact assessment and subsequent monitoring, evaluation and review. This ensures that the Government can provide confidence and certainty while ensuring that the policy advances the Government’s objectives in a coherent way that provides best value for money. It also ensures that detrimental consequences can be quickly and effectively addressed.

Extent and measurement of support for energy in the UK

Overall budget control 14. As confirmed in the UK Renewable Energy Roadmap Update 20124 and in Electricity Market Reform: Delivering UK Investment published on 27 June 20135, the amount of market support to be available for low‐carbon electricity investment (under the LCF) up to 2020/21 has now been agreed. This will be set at up to £7.6 billion (real 2011/12 prices) in 2020, and will help diversify the UK’s energy mix by increasing the amount of electricity coming from renewables from 11% today to around 30% by 2020, as well as supporting new nuclear power and carbon capture and storage.6

Departmental spending limits 15. Non‐levy funded support must be provided from within agreed departmental spending limits as set by HM Treasury. Government Departments providing support to the energy sector follow government‐wide guidelines on project and financial management, with projects subject to monitoring to ensure spending delivers value for money for taxpayers, and to prevent overspending.

The Levy Control Framework 16. The LCF places limits on the aggregate amount levied from consumers by energy suppliers to implement Government policy. In effect, it specifies the budget available to levy‐funded policies and helps protect energy consumers from excessive levies on their energy bills.

17. Table 1 shows the annual caps to levies raised for electricity policy agreed under the LCF as announced on 27 June 2013. These caps are upper limits on the levies raised to fund electricity policies such as the Renewables Obligation (RO), Feed‐in Tariffs (FITs) and CfDs, but would apply equally to any future levy‐funded electricity policy.

4 UK Renewable Energy Roadmap Update 2012 5 Electricity Market Reform: Delivering UK Investment, Annex A 6 UK Renewable Energy Roadmap Update 2012, page 4

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18. These caps do not apply to non‐electricity policies that are levy‐funded, such as the Warm Home Discount.

Table 1 ‐ Upper Limits to Electricity Policy Levies under the Levy Control Framework

2015/16 2016/17 2017/18 2018/19 2019/20 2020/21

£ billion (2011/12 prices) 4.30 4.90 5.60 6.45 7.00 7.60

Impact on energy Bills 19. The Government is committed to being open and transparent about the impacts of energy and climate change policies on households and businesses. In March 2013, the Government published the Estimated Impacts of Energy and Climate Change Policies on Energy Prices and Bills 20127. This document assesses the impact of energy and climate change policies on gas and 8 electricity prices and bills and updates analysis published in November 2011 . It shows that the cost of energy and climate change policies account for around nine per cent of household energy bills in 2013.

Support for low‐carbon energy

Renewables Obligation 20. The RO is currently the main financial mechanism by which the Government incentivises the deployment of large‐scale renewable electricity generation in the UK.

21. The RO places an obligation on UK electricity suppliers to source a specified proportion of electricity they supply to customers from renewable sources, or pay a penalty9. This proportion is set each year and has increased annually since the RO was introduced in 2002. The size of the Obligation in 2013‐14 is 61.5 million Renewables Obligation Certificates (ROCs) with the suppliers Obligation for England and Wales set at 0.206 ROCs per megawatt hour (MWh) of electricity supplied.

22. Ofgem issue ROCs to renewable electricity generators for every MWh of eligible renewable electricity they generate. Generators sell their ROCs to suppliers or traders which allows them to receive a premium in addition to the price of their electricity. Suppliers present ROCs to Ofgem to demonstrate their compliance with the Obligation. Suppliers failing to present enough ROCs to meet their obligation in full have to pay a penalty known as the buy‐out price. This is set at £42.02 per ROC for 2013‐14 (linked to RPI) and provides a floor price for a ROC.

23. In April 2009 the RO was moved from a mechanism which offered a single level of support for all renewable technologies to one where support levels vary by technology according to a number of factors, including their costs and level of deployment.

7 See Annex E for web address 8 Estimated impacts of energy and climate change policies on energy prices and bills 9 The RO works on the basis of three complementary Obligations ‐ one covering England and Wales, and one each for Scotland and Northern Ireland. Scotland and Northern Ireland may set their own bands, and there are some minor differences in support levels between the three Obligations to reflect national circumstances.

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24. The Government has stated that the RO will close in 2037. DECC intend to close the scheme to new generation in March 2017 and this will be put in secondary legislation. A generating station accredited under the RO will continue to receive its full lifetime of support (20 years) until the scheme closes in 2037. Introduction of Electricity Market Reform and CfDs will provide support for large‐scale renewable electricity generation beyond 201710.

25. While it is for suppliers to decide whether to pass the cost of ROCs to consumers through their electricity bills, the Government assumes that they do for cost control purposes. The total cost that can be levied on consumers is controlled within agreed limits by the LCF.

Table 2 ‐ The budget for the RO under the Levy Control Framework within the Spending Review period

Year 11/12 12/13 13/14 14/15 Levy Budget (£ million)* 1,750 2,156 2,556 3,114

*2011/12 prices, discounted

26. The total RO annual support costs are expected to rise from around £1.4 billion in 2011/12 to up to £3.5 billion at the peak in 2016/17 (undiscounted , 2011/12 prices)11.

Contracts for Difference 27. CfDs support low‐carbon generation by ensuring that generators will receive a fixed price level for the electricity they produce known as the ‘strike price’12. Generators will receive revenue from selling their electricity into the market as usual. However, when the market reference price is below the strike price they will also receive a top‐up payment from suppliers for the additional amount. Importantly, if the reference price is above the strike price, the generator must pay back the difference.

28. The CfD was identified as the support mechanism for low‐carbon generation as it offered the best balance of results across the four key criteria chosen: cost‐effectiveness, coherence with the rest of the Electricity Market Reform package, durability and practicality13.

29. CfDs for renewables will initially be awarded on a first come first served basis before moving to allocation rounds. This will support a move to a more competitive allocation and price‐setting system later in the decade. The allocation and price‐setting processes for carbon capture and storage (CCS) and nuclear projects that will apply after the final investment decision (FID) enabling window and outside the CCS Commercialisation competitions is being developed. The Government expects to publish further information in the summer. The level of support for different renewables technologies will be set administratively in the first instance.

10 During the transition period between the introduction of CfDs in 2014 and RO closure in 2017, operators will have a one‐off choice of scheme between the RO and CfDs for support for new generating stations and for new additional capacity of over 5 MW. 11 See also the Final Impact Assessment on proposals for the levels of banded support under the renewables Obligation for the period 2013‐17 and the Renewables Obligation Order 2012. July 2012. 12 Electricity Market Reform: Delivering UK Investment. 13 Further information is available in the EMR impact assessment.

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30. The Government’s ultimate aim is to move to a technology‐neutral competitive process as soon as reasonably practicable. Realistically as technologies are at different stages of development this ultimate technology neutral process is likely to be preceded by a technology differentiated competitive process. This technology differentiated process may be introduced as early as 2017. The Government’s ambition is to move to the next phase, in which there will be technology‐ neutral auctions, in the 2020s before ultimately reaching a phase where there is no longer a need to issue CfDs due to the existence of a competitive market which delivers low‐carbon electricity without the need for Government support.

Value of CfDs 31. While it is for suppliers to decide how to pass the cost of the CfD on to consumers through their electricity bills, the Government assumes that they will do so for budgetary and cost control purposes. The total cost that can be levied on consumers through the CfD is therefore controlled within agreed limits by the LCF.

32. The budget for the CfD under the LCF within the Spending Review period is still to be determined, and as a cap has been set for total spend, will depend on spending on the RO and small scale FITs.

Feed‐in Tariffs scheme 33. The FITs scheme was introduced on 1 April 2010, under powers in the Energy Act 2008 to encourage deployment of small‐scale, low‐carbon electricity generation. The technologies supported under FITs are: solar photo voltaic (PV), wind, hydro, anaerobic digestion and micro (less than 2kW) combined heat and power. FITs provide a fixed payment to these small scale generators (per MWh produced).

34. DECC has just completed the first Comprehensive Review of the scheme. This sought to improve value for money and reduce tariffs in light of falling costs. The reforms introduced a system called degression which reduces tariffs over time to ensure the scheme delivers increased value for money.

35. Funding for FITs is delivered through a levy on electricity bills and controlled within agreed limits by the LCF. Suppliers are at liberty to determine how to pass through the cost of the scheme to their consumers.

Value of FITs

Table 3 – Feed‐In Tariffs spend, £ million, 2011/12 prices, undiscounted14

Financial Year 2011/12 2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 Total 155 477 596 729 849 955 1051 1,126 1,179 1,224

14 Modelling from FITs Comprehensive Review Government Responses.

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Heat

Renewable Heat Incentive 36. The purpose of the Renewable Heat Incentive (RHI) scheme is to encourage and support heat users to move away from using fossil fuels for heating and to contribute to the UK’s renewable energy and emissions reduction targets by making it more financially appealing to install renewable heating systems.

37. Renewable heat technologies are currently more expensive than traditional, fossil‐fuelled technologies. The RHI provides financial support in the form of a payment per unit (kilowatt hour) of heat produced.

38. The Government launched the non‐domestic RHI in November 2011. The scheme provides tariff‐ based financial support to commercial, industrial, public, not‐for‐profit and community generators of renewable heat for a 20‐year period. The Government consulted on its proposals for the domestic RHI last autumn, and is intending to introduce the scheme in spring 2014.

39. The RHI Scheme is subject to a degression‐based mechanism which is designed to respond quickly to emerging budget risks (for example, from unexpectedly high levels of deployment) by decreasing tariffs gradually over time; whilst also enabling continued growth towards the heat portion of the 2020 renewables targets15.

Costs

40. The RHI is funded directly from Government spending and has been assigned annual budgets for the four years of this Spending Review period.

Table 4 ‐ RHI annual budgets for the 2011/12 to 14/15 Spending Review period16

Financial year 2011/12 2012/13 2013/14 2014/15 Total Budget (£m) 56 133 251 424 864

41. This includes budget for the Renewable Heat Premium Payment (RHPP) in 2011/12 and a spend of up to £25 million for the second phase of the RHPP (expected to be spent primarily in 2012/13 but with flexibility for some spend in 2013/14).

42. The recently agreed Spending Review settlement for 2015/16 is £430 million, which allows the RHI spend to significantly increase from levels currently being observed.17

15 “The UK is legally committed to delivering 15% of its energy demand from renewable sources by 2020 contributing to our energy security and decarbonisation objectives.” UK Renewable Energy Roadmap Update 2012, paragraph 1.1. 16 The Renewable Heat Incentive: consultation on interim cost control. 17 As of 30 April DECC estimates that expenditure committed to the RHI from applications received to date is just under £50m for the next 12 months.

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Renewable Heat Premium Payment 43. The RHPP scheme was introduced to provide a one‐off payment for householders to install renewable heating systems as a short term measure before the introduction of the domestic RHI.

44. The scheme provides vouchers which can be redeemed against the cost of installing renewable heating technologies, and is mainly targeted at those living off the gas grid, where most money on bills and carbon can be saved.

Fuel poverty and energy efficiency

Addressing fuel poverty 45. Government is committed to doing all that is reasonably practicable to end fuel poverty in England by 2016, and to helping low income and vulnerable households heat their homes more affordably. The support provided comprises:

• The Warm Front scheme provided help to low income vulnerable households to improve the thermal efficiency of their homes. It is expected that around 35,000 households will be assisted from applications received in 2012/1318. • The Warm Home Discount scheme provides rebates on electricity bills to a range of low income and vulnerable customers. Around £283m is expected to have been spent by suppliers providing rebates and other support in 2012/1319. • The Energy Company Obligation runs alongside the Green Deal (see paragraph 47 below) providing support to low income and vulnerable households to improve the thermal efficiency of their homes. The Affordable Warmth and Carbon Saving Communities Obligations together should generate expenditure in home thermal efficiency improvements worth around £540 million and supporting around 230,000 households per year. • The Department for Work and Pensions (DWP) automatic Cold Weather Payments are targeted at the elderly, disabled and those with young children. During the 2012‐13 Cold Weather Payment season20, 5.8 million payments (worth £25 a week) were made to 3,290,800 recipients at a cost of over £146.1 million. DWP also offer automatic annual Winter Fuel Payments of £200 for households with someone who has reached women’s state pension age and is under 80 and £300 for households with someone aged 80 or over. In winter 2011/1221 it helped over 12.6 million older people in over 9 million households with their fuel bills at an estimated cost of £2.1 billion.

Energy efficiency and energy demand reduction 46. The Government has also introduced measures designed to improve energy efficiency and reduce energy demand:

18 The scheme closed to new applications on 19 January 2013, at which time the Energy Company Obligation was already operational. 19 Final spending will be confirmed in Ofgem’s annual report in October 2013. 20 1st November 2012 to 31st March 2013. 21 The latest period for which figures are available.

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• The Green Deal lets consumers pay for some of the cost of energy‐saving property improvements, like insulation, over time through savings on their energy bills. Repayments will be no more than what a typical household should save in energy costs22. • Smart Meters: The roll‐out of smart gas and electricity meters is expected to deliver significant economic benefits, placing consumers in control of their energy use, and more widely to improve the consumer experience and engagement with the energy market23. • Businesses can benefit from 100% first‐year capital allowances for energy saving‐ technologies24, commonly called enhanced capital allowances or ECAs, which were introduced in 2001 to help the UK meet its target for reducing greenhouse gases25. These allowances reduce the effective cost of the machinery for the investor. They do not, however, significantly affect the unit price paid for energy consumed.

Low‐carbon capital investment and research & development

Carbon capture and storage 47. The Government is also supporting CCS, which will allow the use of existing fossil fuel supplies more cleanly by capturing carbon dioxide from fossil fuel power stations (or large industrial sources), transporting it via pipelines and then storing it safely offshore in deep underground structures.

48. Through its CCS Commercialisation Programme, the Government hopes to support up to two CCS projects with the funding available. These projects have potential to support large supply chains with significant UK content, through the capital support the Government is providing, as well as the further approximately £1.9 billion being invested by the winning projects themselves.

49. The Government has allocated £1billion of capital support through its CCS Commercialisation Programme, although the final level of support for each project will be confirmed depending on the outcome of the on‐going competition.

50. This support is provided in the form of capital funding by the Government.

Research and Development Funding for CCS 51. The UK has a four‐year (2011‐2015) £125 million cross‐Government CCS research, development and innovation programme. Funding comes from the DECC, the Technology Strategy Board, the Energy Technologies Institute and the Research Councils.

22 For further information, see the Green Deal impact assessment and the Green Deal consultation. 23 Energy suppliers are obliged, through conditions in their licences, to take all reasonable steps to install smart gas and electricity meters for their customers by the end of 2020. Energy suppliers will continue to be responsible for the costs of metering, as they are today. Similarly, under current arrangements consumers pay for the cost of their metering and meter maintenance through their energy bills, and this will be the same for smart metering. 24 Eligible equipment, and the criteria they have to meet, is published in an “Energy Technology List”. The criteria are reviewed annually by DECC. 25 The Government aims to reduce the UK’s greenhouse gas emissions by at least 80% (from the 1990 baseline) by 2050 (https://www.gov.uk/government/policies/reducing‐the‐uk‐s‐greenhouse‐gas‐emissions‐by‐80‐by‐ 2050).

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52. CCS research, development and innovation will play an important role in reducing the costs of CCS. This is necessary to help bridge the gap to commercial scale demonstration, enable wider scale deployment, as well as developing the supply chain to maintain the industry.

Funding for research and development 53. The Government provides support for research and development, covering early stage research to pre‐commercial deployment with over £1 billion committed over the current Spending Review period.

54. The funding is distributed through a number of organisations. The key sources of funding are detailed in Annex D.

55. In addition, businesses in low‐carbon sectors are encouraged to apply for grants and/or loans from the £2.4 billion Regional Growth Fund (RGF) and the £125 million Advanced Manufacturing Supply Chain Initiative (AMSCI).

Carbon pricing

Energy intensive industry compensation 56. HM Treasury’s 2011 Autumn Statement announced a £250 million package of measures to help electricity intensive industries adjust to the low‐carbon transformation while remaining competitive26. It included:

• £40 million to increase the rate of CCA relief for electricity to 90%; • £110 million to provide compensation for the indirect costs of EU ETS; and • £100 million to provide compensation for the indirect costs of the CPF.

57. The 2013 Budget announced that the Government will continue to provide support to energy‐ intensive industries to compensate for the indirect cost of the CPF in 2015‐16. Further details will be announced at the next spending round. However, support is intended to be transitional while other countries catch up in pricing the costs of carbon emissions.

Climate Change Agreements

58. CCAs allow eligible energy‐intensive businesses to receive up to a 65% discount from the CCL27 in return for meeting energy efficiency or carbon‐saving targets. The discount for electricity will increase to 90% from April 2013.

59. Currently, 51 industrial sectors participate in CCAs which cover some 9,900 facilities or sites28, and in 2011/12, CCL discount awarded by the scheme was £165m29. Budget 2011 announced that the scheme would be extended for all currently eligible sectors until 202330.

26 2011 Autumn Statement, paragraphs 1.105. 27 Climate Change Levy – introduction. 28 Climate Change Agreements Scheme (Environment Agency Website). 29 http://www.hmrc.gov.uk/statistics/expenditures/table1‐5.pdf 30 Budget 2011, page 33.

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European Union Emissions Trading System (EU ETS) Free Allowances and Commercial Support

60. Although auctioning is the default method for allocating emission allowances to companies participating in the EU ETS in Phase III (2013‐2020), industry will continue to receive a share of allowances for free until 2027 under the revised EU ETS Directive. This is a transitional measure for industrial installations to lessen the risk of a ‘shock’ introduction to the carbon price signal. In 2013 those sectors not deemed to be at significant risk of carbon leakage will receive free allowances to cover emissions from 80% of their benchmarked baseline output, decreasing linearly each year to 30% in 2020 and 0% in 2027.

61. In addition, Directive 2003/87/EC sets out two mechanisms to address the risk of carbon leakage31:

• sectors deemed at significant risk of carbon leakage will receive 100% of their EU allowances need for free (based on their average production (e.g. in tonnes of product) over a baseline period), up to a product benchmark based on the average of the 10% most efficient installations in the EU (termed free allocation); and • from January 2013, Member States may choose to compensate sectors at risk of carbon leakage as a result of indirect costs (i.e. through EU ETS related increases in electricity prices), based on revisions to the State Aid guidelines.

Table 5 ‐ Levels of support under the EU ETS for UK industry

Measure Value of mechanism Number of installations Free allocation on a declining trajectory Around £210 million* Around 430 installations** for sectors not deemed to be at significant risk of carbon leakage. Free allocation on a non‐declining Around £4 billion* Around 400 installations** trajectory for sectors deemed to be at significant risk of carbon leakage. Compensation for those sectors at £110 million† 15 sectors‡ significant risk of indirect carbon leakage due to the EU ETS.

*Based on the UK’s draft National Implementation Measures (NIMs), DECC’s short‐term traded carbon values published in October 2012 and expressed in real 2012 prices. ** Based on current draft of the UK’s National Implementation Measures (NIMs). †Over January 2013 ‐ March 2015 ‡No. of companies will be known in July 2013, once the scheme is operational

Carbon Price Floor and Climate Change Levy

62. Putting a price on carbon emissions is at the heart of the Government’s strategy for enabling the UK to reduce emissions over the long term. The CPF firmly establishes the ‘polluter pays principle’. Liability will be directly linked to the environmental damage caused by different types of fossil fuel‐based electricity generation.

31 Carbon leakage is the prospect of an increase in global greenhouse gas emissions when a company shifts production outside a country because they cannot pass on the cost increases induced by climate change policies to their customers without significant loss of market share.

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63. The Carbon Price Support (CPS) rates announced in Budget 2013, of £18.08, are in‐line with the previously announced price CPF. It is important to maintain the commitment to this floor to provide the certainty that investors need to invest now in our ageing electricity infrastructure.

64. Similarly, the CCL encourages businesses to reduce their energy consumption. The CCL is a tax on energy supplies (electricity, natural gas, liquid petroleum gas and coal) to UK business and the public sector.

65. Supplies of electricity from renewable sources (e.g. wind, hydro, wave, waste) are exempt from the CCL. Renewable electricity is exempt from the CCL via a system of levy exemption certificates. These ensure that the amount of renewable electricity supplied to businesses matches up with the amount of renewable electricity generated.

66. Electricity produced from renewable sources is exempt in support of the CCL’s objective, which is to encourage energy efficiency and reduce emissions of carbon dioxide from the energy used by business and the public sector.

Combined Heat and Power 67. Combined Heat and Power (CHP) captures and utilises the heat that is a by‐product of the electricity generation process and can be more efficient and reduce carbon emissions by up to 30% compared to separate generation of heat and power, via a boiler and power station, using the same fuel.

68. Input fuels used to generate ‘good quality’ heat in fossil fuel CHP plants are exempt under the CPF. This reflects the fact that heat generation will not ordinarily be subject to the CPF. Small scale generators, of 2 MW capacity and less, will also be excluded from the CPF. Taken together, this puts CHP electricity generation on a level playing field with alternatives. Fossil fuel CHP remains incentivised through the tax system, as fuel used in ‘good quality’ CHP is exempt from CCL, unlike separate boilers producing heat which will still be liable to the CCL32.

Capacity Market 69. The Government is legislating through the Energy Bill to introduce a Capacity Market to ensure that we can maintain reliable electricity supplies. The first capacity auction will be run in 2014, for delivery in 2018‐19, subject to state aid approval.33

70. A Capacity Market works by providing upfront payments to all providers of capacity (including generation and demand side, and with some exceptions, for example plant receiving the a CfD), in return for which they must commit to be delivering energy when needed or face financial penalties. Capacity agreements will be allocated through a competitive auction, four years ahead of delivery. The costs of the upfront capacity payments will fall to energy suppliers (and therefore consumers), but the Capacity Market will have a dampening effect on wholesale electricity prices that will largely offset the upfront costs.

32 Renewable CHP is one of the technologies eligible for support under the Renewables Obligation or the Renewable Heat Incentive. Government consulted on a CHP specific RHI tariff in 2012 to replace the additional support for renewable CHP (over power‐only plant) currently in the RO banding. A Government response is pending. 33 Electricity Market Reform: Capacity Market proposals.

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71. Consumers already pay the costs of capacity through the wholesale electricity price; the Capacity Market simply means that the costs of capacity are instead made through a separate revenue stream. The costs of the Capacity Market are not included in the agreed £7.6 billion LCF. However, the costs of the Capacity Market will be included within updated LCF totals for purposes of reporting to Parliament. The level of support provided will depend on the clearing price of the auction and the amount of capacity contracted, but as noted above, the net cost to consumers is expected to be lower than the gross cost of the auction as the Capacity Market will result in lower wholesale prices than would have otherwise been the case.

Other support

Support for energy used in transport

Renewable Transport Fuel Obligation 72. The Renewable Transport Fuel Obligation (RTFO) requires transport fuel suppliers to supply biofuel in proportion to fossil fuel. Typically more expensive than the displaced fossil fuel the obligation represents a cash transfer from fuel suppliers to biofuel producers and their supply chains (e.g. farmers, waste cooking oil collectors) rather than direct government support. RTFO costs are assumed to be passed through to end fuel consumers.

73. Some NGOs (and others) consider biofuel support harmful on grounds of environmental sustainability, social sustainability and food price impacts.

74. The total cost to suppliers subject to the obligation is estimated to be £387 million in 2013/14. However, the RTFO value is determined by the market reflecting biofuel and fossil fuel prices at any given point in time.

Low Emission Vehicles 75. The Office for Low Emission Vehicles is a cross Government, industry endorsed, team combining policy and funding streams to support the early market for electric and other ultra‐low emission vehicles (ULEVs).

76. Buyers of ULEVs are able to benefit from a consumer incentive grant if purchasing an eligible new vehicle. This is worth 25% up to £5,000 towards the value of a car and 20% up to £8,000 towards the value of a van. Grants are also available for the installation of recharging points in homes, stations and the public sector estate.

77. Whilst these measures are Government funded they are not classified as support for energy, rather they support the cost of the vehicles powered by the energy, not the electricity on which they run.

National Concessionary Fuel Scheme 78. Under the 1994 Coal Industry Act HMG inherited responsibility for certain employee related benefits stemming from the nationalised coal period (1947‐ 1994). Amongst these is the National Concessionary Fuel Scheme whereby certain former employees of British Coal are entitled to either the supply of solid fuel (coal) or cash in lieu.

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79. The entitlement to receive concessionary coal is linked to the beneficiaries original contract of employment and DECC is not able to vary that arrangement on a unilateral basis. Any change has to be with the consent of the individual concerned. Any wholesale change to the coal services would require legislation and would give rise to human rights implications. Currently DECC has no plans to seek such a legislative change.

80. The majority of the beneficiaries are now in receipt of cash in lieu (around 57,000 currently) but DECC still supplies coal to around 11,000 former employees or their widows. The fuel element of the service is estimated to cost DECC around £16.5 million in 2013/14 and the cash in lieu arrangements around £35m. The amounts of coal supplied are all set out within agreements negotiated between the former British Coal and the mining trade unions.

81. This scheme directly reduces the price paid by a specific group of consumers for energy they receive under specified circumstances.

International comparisons 82. The energy challenge in each country is different. Governments must choose the appropriate support mechanisms, and support them to the appropriate levels depending on their respective energy needs. The UK has an ambitious target to halve emissions from 1990 levels by 2027.34 By comparison, Japan has a 30% target between 2003 and 2030 and Sweden a 20% target between 2008 and 2020.

83. In addition, the UK has a legally binding target to produce 15% of its energy needs from renewables by 2020. Whilst this target is lower than those for other European countries it is nonetheless very ambitious. The UK must secure a factor of ten increase in renewable energy over the period, compared with an average factor of two increase across Europe – all while increasing demand means additional deployment is needed just to ‘stand still’.

84. State Aid guidelines on compensation for those sectors at significant risk of indirect carbon leakage due to the EU ETS were adopted by the European Commission in late 2012. Compensation is voluntary. Only one Member State other than the UK has announced a compensation scheme so far – Germany has €500 million per year. The approach for free allocation is harmonised across all EU member States.

85. It is extremely difficult to directly compare the support for renewable energy between different European countries as regulatory issues, taxation, base load cost of energy and many others factors can all play a role. According to the Status Review of Renewable and Energy Efficiency Support Schemes in Europe conducted by the Council of European Energy regulators, in 2011, the UK had a low level of subsidy per MWh when compared to other member states.35

34 The Government will review the fourth Carbon Budget, covering the years 2023‐2027, in 2014. If at that point our domestic commitments place us on a different emissions trajectory than the ETS trajectory agreed by the EU, we will, as appropriate, revise up our budget to align it with the actual EU trajectory. 35 Status Review of Renewable and Energy Efficiency Support Schemes in Europe.

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86. Most European and OECD countries have some form of Feed‐in Tariff. Spend varies widely, Germany and other well established schemes have spent many billions on support over the past decade. Other countries are only now starting to offer this type of support (notably China).

87. The Global Carbon Capture and Storage Institute (GCCSi) estimate that worldwide up to $40 billion has been committed by Governments to support CCS projects. Governments around the world have provided different levels of financial incentives to support the deployment of CCS. It is difficult to directly compare support levels, as projects in different countries face different market conditions and regulatory and policy frameworks. In addition to direct financial support in the forms of grants, subsidies can be in other forms. For example, in the US, federal and state support for CCS have included investment tax credits and loan guarantees to help offset the higher capital and operating costs of CCS projects.

88. Estimates of levels of funding specifically for carbon capture and storage R&D in other countries are not easily available. However, there is information on publication rankings (a good measure of research activity) and specific initiatives in other countries.

89. A Capacity Market is a type of ‘capacity mechanism’. Capacity mechanisms are a common feature of liberalised energy markets, and indeed when the England and Wales electricity market was first liberalised there was a capacity mechanism in place. France is developing a Capacity Market similar to the one we are legislating for, and there are similar mechanisms already operating in a number of worldwide markets, including in the US and Europe.

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Annexes

Annex A ‐ Reduced (5%) VAT rate on domestic heating and power 90. A reduced rate of VAT applies to domestic and small business heating fuel and electricity. This is a tax, not a subsidy, and increases the price above the world‐market prices. Non‐fossil fuel heating would also be covered under the 5% VAT rate.

Annex B ‐ Nuclear power 91. The UK Government believes that nuclear energy has a vital role to play in the energy mix and is committed to removing unnecessary obstacles to investment in new nuclear power.

92. The Office for Nuclear Development (OND) is part of the Energy Markets and Infrastructure (EMI) group within DECC, and has a key role in helping to ensure that the UK has access to clean, safe, and secure supplies of competitively priced energy.

New nuclear power 93. It is the Government’s policy that there will be no public subsidy for new nuclear power, as defined in a written statement made to Parliament in October 201036, and in a debate in Parliament in February 201337. This means that new nuclear will receive no levy, direct payment or market support for electricity supplied or capacity provided, unless similar support is also made available more widely to other types of generation.

94. New nuclear power will benefit from any general measures that are in place or may be introduced as part of wider reform of the electricity market to encourage investment in low‐ carbon generation. This is about creating a level playing field for all forms of generation, not subsidising nuclear.

95. It will be for private sector energy companies to construct, operate and decommission nuclear power stations. It will be for the Government and the independent regulators to ensure appropriate levels of safety, security and environmental regulation.

Nuclear waste and decommissioning

Legacy waste and decommissioning 96. In terms of financing the legacy waste and decommissioning of old and existing nuclear power stations and facilities, the UK policy operates under cover of and in accordance with European Commission decisions on the restructuring of British Energy (BE) and Nuclear Decommissioning Authority (NDA) / British Nuclear Fuel Limited (BNFL).

36 https://www.gov.uk/government/news/written‐ministerial‐statement‐on‐energy‐policy‐the‐rt‐hon‐chris‐ huhne‐mp‐18‐october‐2010 37 Hansard, 7 Feb 2013 : Debate from Column 485, http://www.publications.parliament.uk/pa/cm201213/cmhansrd/cm130207/debtext/130207‐0003.htm

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97. Responsibility for decommissioning, cleaning up and dealing with the waste from the public sector, civil nuclear legacy sites has been given to the NDA, created in 2005. The NDA’s mission is fully funded by the public sector, through a mixture of direct grant and commercial income from the few facilities in the estate that are still operational. This will decline over time as the remaining operational nuclear plants close and enter decommissioning. Closure of the operational commercial plants was one of the conditions attached to state aid approval, with which we remain in compliance.

98. The European Commission approved the grant of state aid to the restructuring of British Energy plc (BE) in October 2004 (decision 2005/407/EC) on the basis that it was satisfied that the new structure of British Energy would ensure that aid was exclusively used for the decommissioning of BE's nuclear power plants and the discharge of its nuclear liabilities, for example for radioactive waste and spent fuel. Under restructuring agreements scrutinised by the Commission at the time of its original decision, the Nuclear Liabilities Fund (NLF) ‐ a company limited by shares and owned by an independent trust ‐ was made responsible for meeting those decommissioning costs.

99. In January 2009, BE was purchased by EDF. At the time of sale, the UK Government committed to ensuring through the sale process that the conditions for State Aid imposed by the Commission on BE at the time of restructuring would continue to be met. Accordingly, EDF are subject to the BE restructuring agreements. As a consequence EDF must submit their decommissioning plans and any applications for NLF payments to the UK's NDA for prior approval. In providing their approval, the NDA are charged with ensuring that EDF's plans and applications meet the terms of the restructuring agreements including that such funding is directed only to that work deemed qualifying under those agreements.

100. The NLF’s liabilities as stated in the 2011‐12 DECC accounts are £5.1 billion whilst its assets are £8.7 billion. The liabilities are extremely long‐dated, stretching more than 100 years into the future on current plans. And there are a number of uncertainties regarding decommissioning costs, including the applied discount rate, station lifetimes, regulatory changes, inflation and the rate of investment return. Given these uncertainties it is very difficult to predict whether the fund will be sufficient to cover the liabilities. If they do not, the Government has undertaken to meet any shortfall.

101. Any money paid out by the NLF to EDS conform to the conditions imposed by the Commission at the time of British Energy’s restructuring in October 2004, and does not constitute a subsidy or state aid. Neither is the Government’s undertaking to meet any NLF shortfall, should that be necessary. As is the case with NLF payments to EDF, the Government would only meet costs that fall within the conditions imposed by the Commission at the time of British Energy’s restructuring in October 2004.

Decommissioning and waste from new nuclear power stations 102. Geological disposal is the way in which higher activity radioactive waste will be managed in the long term. The Government expects to dispose of spent fuel and intermediate level waste (ILW) from new nuclear power stations in the same geological disposal facility that will be constructed for the disposal of legacy waste.

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103. Before construction of a new nuclear power station begins the Government expects to enter into a contract with the operator regarding the terms on which the Government will take title to and liability for the operator’s waste. This “Waste Transfer Contract” will in particular set out how the price that will be charged for this waste transfer will be determined (the “Waste Transfer Price”).

104. In December 2011 the Government published details of how the Waste Transfer Price is to be determined. This stated that the Government’s objective is to ensure the safe disposal of ILW and spent fuel from new nuclear power stations without cost to the taxpayer and to facilitate investment through providing cost certainty.

105. This arrangement involves the transfer of liabilities and risks from the operator to Government, but the waste transfer pricing methodology sets out how this will be done in a way that does not involve any subsidy to new nuclear power. As set out in the written Ministerial Statement of October 2010, the Government does not consider that taking title to radioactive waste, including spent fuel, for a fixed price is a subsidy to new nuclear power, provided that the price properly reflects any financial risks or liabilities assumed by the state.

Limitation of liabilities 106. The UK is a Contracting Party to the Paris Convention on nuclear third party liability and the Brussels Supplementary Convention. The Conventions establish an internationally agreed framework for compensating victims in the event of a nuclear accident and are implemented in the UK by the Nuclear Installations Act 1965. This regime seeks to ensure access to adequate and fair compensation for victims by requiring operators to take on more onerous obligations than they would under the ordinary law, so that they are bound to pay compensation irrespective of whether they are at fault and are required to put in place insurance or other financial security to cover their liabilities. This is consistent with the no public subsidy policy.

107. As part of the regime, a limit is set on operator third party nuclear liability. Government believes this is justifiable in the public interest and is the right way of ensuring that risk is appropriately managed, and that, overall, any potential cost or risk to the Government can be justified by the corresponding benefits of the Paris/Brussels regime. The UK currently limits operators’ liability at £140 million per incident but this will rise to €1.2 billion once we have implemented the revisions that were made to the Conventions. The UK is also bound, with other Brussels signatory states, to contribute to a fund that will compensate victims both in the UK and other convention countries should a serious nuclear incident happen.

108. Government is working with other parties to the Paris/Brussels regime to amend and update the existing scheme and published a consultation on the changes in 2011. These amendments impose a more stringent regime for operators than the current one. As mentioned in the summary of responses to the consultation38, Government has always acknowledged that a catastrophic accident at a nuclear plant could far exceed the ability of the operator to pay and that Government, as with other natural or man‐made disasters, may have to step in. The most effective way of guarding against large accidents is to have a robust regulatory regime to ensure

38 https://www.gov.uk/government/consultations/compensating‐victims‐of‐nuclear‐accidents

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the risk of a significant incident is kept extremely small. In so doing, the nuclear industry is already paying to protect society for a very low probability but high consequence accident through meeting the exacting regulatory requirements.

Annex C ‐ Oil and gas fiscal regime 109. The tax regime which applies to exploration for, and production of, oil and gas in the UK and on the UK Continental Shelf (UKCS) currently comprises three elements:

• Ring fence corporation tax – this is calculated in the same way as standard corporation tax, but the ring fence prevents taxable profits from oil and gas extraction being reduced by losses from other activities or by excessive interest payments. The current rate of tax on ring fence profits, which is set separately from the rate of mainstream corporation tax, is 30%. • Supplementary charge – this is an additional charge, currently at a rate of 32% on a company’s ring fence profits (increased from 20% from March 2011). • Petroleum revenue tax (PRT) – this is a field based tax charged on profits arising from oil and gas production from individual oil and gas fields which were given development consent before March 1993. The current rate of PRT is 50%. PRT is deductible as an expense in computing profits chargeable to ring fence corporation tax and supplementary charge.

110. Oil and gas produced in the UK is therefore subject to a tax on profits of 62% for new fields and 81% for older fields. This ensures the taxpayer benefits from highly profitable fields. The Government has introduced field allowances for more challenging categories of field that are economic, but commercially marginal at the high rate of tax. Such fields are relieved of tax at 32% for a certain portion of their income – but they still pay ring fence corporation tax at 30% for this portion, higher than the mainstream corporation tax rate. Field allowances do not reduce the cost of oil to consumers.

111. International organisations such as the International Energy Agency (IEA), Organisation for Economic Co‐operation and Development (OECD) and International Monetary Fund (IMF) use a variety of different methodologies to assess support to fossil fuels. The IMF and IEA use versions of a methodology known as the price gap approach, which, similar to the EU definition, compares prices to world market prices. The OECD uses broad measures of Producer and Consumer Support Estimates (PSE & CSE), based on metrics used by the OECD in other sectors, such as agriculture. These measures take account of where lower rates of tax are applied than elsewhere in the economy and so give different results to assessing purely whether fossil fuels are subsidised.

112. For the purposes of G20 work on inefficient fossil fuel subsidies, the UK, along with other EU G20 members, defines a fossil fuel subsidy as any Government measure or programme with the objective or direct consequence of reducing, below world‐market prices, including all costs of transport, refining and distribution, the effective cost of fossil fuels paid by final consumers, or of reducing the costs or increasing the revenues of fossil‐fuel producing companies.

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113. This oil and gas fiscal regime policy ensures the Government maximises the economic production of oil and gas in the UK, without giving undue support to otherwise uneconomic production. For that reason, field allowances cannot be seen as a subsidy.

114. Any profits from shale gas production would be subject to the same ring fence regime, and would have a marginal 62% tax rate. Given that the industry is at an early stage of development, the Government has announced that it will introduce a shale gas allowance to help unlock investment. This allowance will operate in a similar way to existing field allowances – relieving a portion of a company’s income from the supplementary charge. Companies will continue to pay ring fence corporation tax on this portion. The use of allowances to encourage investment in the North Sea has demonstrated the effectiveness of a targeted allowance in stimulating investment and production that would not otherwise have gone ahead. 39

115. The Government will publish a consultation document on proposals for the shale gas allowance to ensure that the final structure is appropriately targeted while maintaining a fair return for the Exchequer.

Annex D ‐ Research and development funding

Research councils 116. The Engineering and Physical Sciences Research Council (EPSRC) is the main UK Government agency for funding research and training in engineering and the physical sciences and leads the Research Councils UK Energy programme, worth over £500 million over the period 2011‐15, bringing strategy to UK energy research in support of Government targets.

Technology Strategy Board 117. The Technology Strategy Board (TSB) tackles barriers to early stage technology development, and supports business‐led innovation. It works across business, academia and government ‐ supporting innovative projects, reducing risk, creating partnerships, and promoting collaboration, knowledge exchange and open innovation.40 It has a budget of around £1 billion over four years, which includes over £200 million of Government funding over the current spending review period for low‐carbon innovation.

118. In addition to sponsoring the Energy Technology Institute, some examples of TSB investments between 2007 and 2012:

• £25.5 million in offshore renewables, including co‐funding of £5.5 million from Scottish Enterprise, Natural Environment Research Council and Regional Development Agencies (RDAs) with a commitment to invest a further £10 million core funding per annum to the Offshore Renewables Catapult centre; • £29.5 million in fuel cells and hydrogen, including £7 million co‐funding from DECC; • £19.5 million in carbon abatement technologies, including £9 million from DECC and RDAs;

39 https://www.gov.uk/government/news/government‐action‐to‐stimulate‐shale‐gas‐investment 40 https://www.innovateuk.org/our‐strategy

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• £17 million in civil nuclear, including £8million from the Nuclear Decommissioning Authority, DECC and EPSRC; and • £11.9 million in grid balancing, management and infrastructure and £6 million in oil and gas.41

DECC innovation funding 119. DECC has made up to £150 million of funding available to cover the 2010 Spending Review period. The spending focus has been on those technologies and programmes where there are clear market failures and where intervention will have greatest impact on meeting our climate change and energy objectives.

120. Funding decisions are subject to the Technology Innovation Needs Assessments (TINAs). TINAs aim to identify and value the main innovation needs of specific low‐carbon technology families to inform the prioritisation of public sector investment in low‐carbon innovation42.

121. The TINAs apply a consistent methodology across a diverse range of technologies, and a comparison of relative values across the different TINAs is as important as the examination of absolute values within each TINA. Once priority areas for funding have been decided, suitable projects are selected. They include projects to reduce the cost of offshore wind, marine innovation, work to reduce the costs of next generation of CCS, work on energy storage, energy efficiency and work on future nuclear R&D. Each project that is funded has an evaluation plan in order to see how much it did achieve against its original aims and to learn lessons that can be used or shared.

Energy Technologies Institute 122. The Energy Technologies Institute (ETI) will receive up to £120 million of public funding and up to £120 million of private funding over the 2011‐15 Spending Review period.

123. The ETI’s goals are to accelerate the development, demonstration and eventual commercial deployment of a focused portfolio of energy technologies, which will increase energy efficiency, reduce greenhouse gas emissions and help achieve energy and climate change goals.43

Waste & Resources Action Programme (WRAP) 124. WRAP’s Business Plan 2011‐15 promotes “working in partnership towards a world without waste”. WRAP’s focus is now on preventing waste being created in the first place. However, where waste is unavoidable, WRAPs expertise can help make sure the material is recycled to maximum value, or used to create energy.

Ofgem – Low‐carbon Networks Fund 125. As part of the electricity distribution price control arrangements that run from 1 April 2010 to 31 March 2015, Ofgem established the Low‐carbon Networks (LCN) Fund. The LCN Fund allows up to £500 million support to projects sponsored by the distribution network operators (DNOs) to

41 https://www.innovateuk.org/energy;jsessionid=C26C4293A0FBB9CE038F294E0329B9AF.3 42 More detail available at: https://www.gov.uk/innovation‐funding‐for‐low‐carbon‐technologies‐ opportunities‐for‐bidders 43 http://eti.co.uk/index.php/technology_strategy

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try out new technology, operating and commercial arrangements. The objective of the projects is to help all DNOs understand what they need to do to provide security of supply at value for money as Great Britain (GB) moves to a low‐carbon economy.

126. Projects awarded funding involve the DNOs partnering with suppliers, generators, technology providers and other parties to explore how networks can facilitate the take up of low‐carbon and energy saving initiatives such as electric vehicles, heat pumps, micro and local generation and demand side management, as well as investigating the opportunities that smart meter roll out provide to network companies. As such the Fund should also provide valuable learning for the wider energy industry and other parties.

OLEV (DfT) 127. Ultra‐low emission vehicle technology is developing fast. The Government is committed to accelerating the pace of change in this area and contributes to the funding of a range of innovative research and development activities. The Office for Low Emission Vehicles (OLEV) is focused on identifying and supporting emerging technologies in the field of ultra‐low emission vehicles.44

128. The Government’s programme of research and development for low‐carbon vehicle technologies is delivered through the Technology Strategy Board’s Low‐Carbon Vehicles Innovation Platform (LCVIP). This platform was launched in 2007 and is funded by the Department for Transport, Department for Business, Innovation and Skills, the TSB and the EPSRC.

Reviewing funding of Research and Development 129. The Low‐carbon Innovation Co‐ordination Group (LCICG) was re‐invigorated following DECC’s leadership of a pan Government review of the innovation landscape and improving its delivery. It brings together the UK’s major public‐sector funding and delivery bodies that are supporting low‐carbon innovation in the UK. The Group aims to maximise the impact of UK public sector funding for low‐carbon technology, in order to:

• deliver affordable, secure, sustainable energy for the UK; • deliver UK economic growth; and • develop the UK’s capabilities, knowledge and skills.

130. It is developing a common evidence base, using the TINA work done for DECC and is developing a joint strategy to ensure focus on those areas where of most impact, and to ensure strong coordination of members work.

Annex E – URLs for documents referenced in this evidence To note – URLs were correct on 27 June 2013

Document Title/Reference URL

44 https://www.gov.uk/ultra‐low‐emission‐vehicle‐research‐and‐development

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Document Title/Reference URL Overview of key methods used to identify http://www.oecd.org/env/outreach/EAP(2012)2_NP_Subsidies% and quantify environmentally harmful 20report_ENG.pdf Subsidies with a focus on the energy sector UK Renewable Energy Roadmap Update https://www.gov.uk/government/uploads/system/uploads/attac 2012 hment_data/file/80246/11‐02‐ 13_UK_Renewable_Energy_Roadmap_Update_FINAL_DRAFT.pdf Investing in Britain’s Future https://www.gov.uk/government/uploads/system/uploads/attac hment_data/file/209279/PU1524_IUK_new_template.pdf Electricity Market Reform: Delivering UK https://www.gov.uk/government/publications/electricity‐market‐ Investment reform‐delivering‐uk‐investment Estimated impacts of energy and climate https://www.gov.uk/government/uploads/system/uploads/attac change policies on energy prices and bills hment_data/file/172923/130326_‐ 2012. _Price_and_Bill_Impacts_Report_Final.pdf Estimated impacts of energy and climate https://www.gov.uk/government/publications/assessment‐of‐ change policies on energy prices and bills the‐impact‐of‐energy‐and‐climate‐change‐policies‐on‐prices‐and‐ bills Final Impact Assessment on proposals for https://www.gov.uk/government/uploads/system/uploads/attac the levels of banded support under the hment_data/file/66181/Renewables_Obligation_consultation_‐ renewables Obligation for the period _impact_assessment.pdf 2013‐17 and the Renewables Obligation Order 2012 EMR Impact Assessment https://www.gov.uk/government/uploads/system/uploads/attac hment_data/file/42637/1042‐ia‐electricity‐market‐reform.pdf UK Renewable Energy Roadmap Update https://www.gov.uk/government/uploads/system/uploads/attac 2012 hment_data/file/80246/11‐02‐ 13_UK_Renewable_Energy_Roadmap_Update_FINAL_DRAFT.pdf The Renewable Heat Incentive: https://www.gov.uk/government/uploads/system/uploads/attac consultation on interim cost control hment_data/file/42906/4729‐rhi‐consultation‐interim‐cost‐ control.pdf 2011 Autumn Statement http://webarchive.nationalarchives.gov.uk/20130129110402/htt p://www.hm‐treasury.gov.uk/as2011_documents.htm Climate Change Levy ‐ introduction http://customs.hmrc.gov.uk/channelsPortalWebApp/channelsPor talWebApp.portal?_nfpb=true&_pageLabel=pageExcise_InfoGuid es&propertyType=document&id=HMCE_CL_001174 Climate Change Agreements Scheme http://www.environment‐ (Environment Agency Website) agency.gov.uk/business/topics/pollution/136236.aspx Budget 2011 http://webarchive.nationalarchives.gov.uk/20130129110402/htt p://cdn.hm‐treasury.gov.uk/2011budget_complete.pdf Electricity Market Reform: Capacity https://www.gov.uk/government/publications/electricity‐market‐ Market proposals reform‐capacity‐market‐proposals Status Review of Renewable and Energy http://www.energy‐ Efficiency Support Schemes in Europe regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATION S/CEER_PAPERS/Electricity/Tab2/C12‐SDE‐33‐03_RES%20SR_3‐ Dec‐2012_Rev19‐Feb‐2013.pdf Green Deal Impact Assessment https://www.gov.uk/government/uploads/system/uploads/attac hment_data/file/43000/3603‐green‐deal‐eco‐ia.pdf Green Deal Consultation https://www.gov.uk/government/consultations/the‐green‐deal‐ and‐energy‐company‐obligation Budget 2013 https://www.gov.uk/government/publications/budget‐2013‐ documents

4 July 2013