House of Commons - Environmental Audit

Select Committee on Environmental Audit Minutes of Evidence

Memorandum submitted by EDF Energy

ABOUT EDF ENERGY

EDF Energy is one of the UK's largest energy companies. We are a vertically integrated company with a balanced portfolio of business throughout the energy chain—from generation to supply. Most pertinent to this inquiry:

— We are the 5th largest electricity generator in the UK. We own and operate an 800MW CCGT (combined cycle gas turbine) power station at Sutton Bridge and 4 GW of coal-fired generation assets that are currently being fitted with Flue Gas Desulphurisation (FGD) equipment, as well as small CHP and renewable generation assets.

— EDF Energy is a major supplier of gas and electricity, with 5 million electricity and gas customer accounts throughout the UK, supplied through our retail brands EDF Energy, London Energy, Seeboard Energy and SWEB Energy.

EDF Energy also:

— Owns and operates the electricity distribution networks serving London, the East and South East of England, which means that around one quarter of the UK population relies on our distribution networks for their electricity. This makes EDF Energy the largest distribution network operator (DNO) in the UK.

— Is a major owner and provider of private electricity infrastructures in the UK including those for the major London airports, the London Underground, the channel tunnel rail link, the Docklands Light Railway and Canary Wharf. We are also a partner in the Metronet consortium.

As a company EDF Energy is committed to finding the right balance between providing sustainable financial returns and continually investing in serving our customers better. EDF Energy is pleased to have the opportunity to contribute to the Environmental Audit Committee's inquiry into "Keeping the Lights On".

SUMMARY

25-35[1] GW of new generation (in addition to new renewable capacity delivered through the Renewables Obligation) will be required in the UK by 2018 to replace closing coal and nuclear power stations and meet demand. The large range is due to uncertainty surrounding demand growth, reserve requirements for intermittent renewables and the impact of environmental legislation on coal plant. Despite currently high gas prices and small margins for gas-fired plants the most likely replacement technology is CCGT due to its relatively low capital costs and intermediate Carbon Dioxide (CO2) emissions. If CCGT build alone replaces the closing capacity, some of which is zero carbon, the UK electricity sector will not deliver major reductions in CO2 and, based on DTI projections, CO2 emissions in 2020 will be similar to the level of CO2 allowances distributed in 2005.

It is the responsibility of Government to identify its desired environmental outcome and put in place the required regulatory framework and allow the market to support the development of low carbon plant in the UK. Diversity in the fuel-mix in the electricity sector also needs to be incentivised, since a UK electricity generation portfolio dominated by CCGTs creates risks to physical security of supply and electricity prices. EDF Energy believes that the general mix of fuels and technologies is a legitimate matter for Government interest and policy action.

EDF Energy believes the construction of new nuclear power stations in the UK, particularly in view of the forthcoming closure of existing nuclear power stations, should be part of the solution to the challenge of reducing CO2 emissions. It will also increase security of supply and reduce energy price volatility. Potential investors in nuclear power need a stable long-term energy policy framework within the UK before they can invest. This should include appropriate and reliable incentives that recognise the role nuclear and other carbon-free technologies can play in achieving the UK's climate change objectives. There are many barriers to new nuclear build including licensing, planning and waste management and disposal. These barriers need to be tackled now if nuclear is to directly replace some of the closing plant because new nuclear stations will take approximately ten years to become operational.

EDF Energy supports the Renewables Obligation (RO) provided it delivers against the current targets for renewable energy at a reasonable cost to the customer. Large volumes of intermittent renewable generation capacity will entail significant additional reserve costs. Renewable targets should not be increased at this stage beyond those currently in place until a significant volume has been built and the technical and economic impact has been assessed.

Proven clean coal technologies with reduced CO2 emissions due to major increases in thermal efficiency, as well as CO2 sequestration technologies, also have the potential to provide low CO2 generation in the future.

In conclusion, new nuclear, renewables, clean coal and carbon sequestration along with gas and energy efficiency should all play a role in meeting the predicted electricity generation capacity shortfall while addressing climate change. Diversity is the key to providing security of supply in a low carbon future.

A. THE EXTENT OF THE "GENERATION GAP"

1. What are the latest estimates of the likely shortfall in electricity generating capacity caused by the phase-out of existing nuclear power stations and some older coal plant? How do these relate to electricity demand forecasts and to the effectiveness of energy efficiency policies? [2]

The effect of the Large Combustion Plant Directive (LCPD) will be to limit "opted-out" unabated coal station output from 2008 before total closure by 2016 of 19 GW of coal and oil plant, circa 25% of present GB generation. The exact profile of opted-out plant closures between now and 2016 is uncertain. The capacity of opted-in plant (some 13GW) that will upgrade their NOx abatement equipment and operate beyond 2015 is also uncertain.

Nuclear decommissioning will result in all Magnox (BNFL) stations shutting by 2010, a reduction of 2.5 GW, and the closure of a number of AGRs (Advanced Gas-cooled Reactor—British Energy). If life extensions are not granted to AGRs, 5 GW could close by 2014.

The shortfall in electricity generation capacity is a function of both the closure of plant and the rate of growth of demand. National Grid (NG) assumes average peak demand growth of 0.79% per annum in its 2005 GB Seven Year Statement. On the assumption that a system margin of 20% needs to be maintained then circa 27 GW of new capacity needs to be constructed before 2018 subject to the exact profile of nuclear plant closures. 10 GW of intermittent renewable capacity may be connected by 2018; however, this will require significant additional capacity as back-up. If energy efficiency is assumed to reduce NG's peak demand growth assumption by 1% then this would reduce the level of new capacity required in 2018 by circa 8 GW.

In combination these drivers imply that 25-35 GW of new generation (in addition to new renewable capacity delivered through the Renewables Obligation) will be required in the UK by 2018 to replace closing coal and nuclear power stations and meet demand. Substantially more new plant could be required by 2018 if some or all opted-in plant also close. If life extensions are granted for several nuclear stations then that will cause only a small reduction in the capacity shortfall for a period of a few years.

A major uncertainty in any longer-term electricity demand forecast is the demand for hydrogen (H2) transport fuel, since hydrogen production is either via electrolysis, or via "synthesis" from fuels such as coal, oil or gas. Synthesis itself directly produces CO2, whereas electrolysis produces none, although of course the generation of the electricity may have done. Our figures above assume that either no demand for H2 fuel develops, or such fuel is synthesised from hydrocarbons rather than produced through the electrolysis of water. If there is a significant demand for H2 fuels using electrolysis then the size of the generation gap will be significantly greater than indicated above, as the current UK road transport fleet has primary energy usage broadly equivalent to the energy used in national electricity generation.

In the longer-term, national aspirations for a reduction of CO2 emissions to 60% of 1990 levels by 2050 imply that the UK will need to move towards a virtually-zero-CO2 generation fleet as well as making radical emission reductions in space heating and transportation. Once established, low carbon electricity supply could also help make a significant contribution to CO2 reduction emissions in other sectors by substituting for the use of fossil fuels. It is important to note that assets constructed to replace the shortfall caused by nuclear and coal plant closures before 2020 are likely to be operational in 2050 when the Government's goal of 60% reduction needs to be delivered.

B. FINANCIAL COSTS AND INVESTMENT CONSIDERATIONS

2. What are the main investment options for electricity generating capacity? What would be the likely costs and timescales of different generating technologies?

What are the likely construction and on-going operating costs of different large-scale technologies (eg nuclear new build, CCGT, clean coal, on-shore wind, off-shore wind, wave and tidal) in terms of the total investment required and in terms of the likely costs of generation (p/kWh)? Over what timescale could they become operational?

A number of recent studies have explored this question. The main investment options are CCGT, OCGT (open-cycle gas turbine), clean coal, wind and standalone biomass. Nuclear, whilst a proven technology, has barriers to development in the UK at present. We expand on this point later in our submission. Wave and tidal technologies (apart from tidal barrages which can have major environmental impacts) are currently still in development. The table below summarises central capital and operating cost views from these studies and our own internal analysis. More detailed cost estimates for nuclear are included later in our submission.

Table 1

Advanced CCGT Clean
Coal
(IGCC)
Advanced OCGT

Nuclear On
shore
wind Off
shore
wind

Marine

Biomass

Capital Costs (£/kW) 440 974 210 1,150 715 1,250 1,750 est 1,500

Fixed costs (£/kW pa) 25 27 14 41 15 24 56 80

Efficiency (HHV) % 54 45 37.5 39 — — — 35

Start of construction to commissioning (years) 2.5 3 1.5 5 1.5 2 2 2

Total time to commissioning incl planning 4.5 5.5 3.5 8 to 10 3 4 4 4

NB The capital cost comprises all costs covered by the financing of the plant except for interest during construction and debt service reserve.

Sources:

ILEX Energy Consulting "Projections of the price for wholesale electricity in Great Britain", June 2005

ILEX Energy Consulting "The value of renewable electricity in the United Kingdom", June 2005

The Royal Academy of Engineering (RAE) "The costs of generating electricity", March 2004

EDF Energy internal data

Cost of generation is dependent on fuel cost, CO2 cost, site-specific costs and required rate of return as well as capital and operating costs of a plant. It can therefore vary significantly for individual projects using the same technology. The RAE study estimates p/kWh costs (tables 1.1 and 1.2 in their report). In the case of renewables, two costs are cited by the RAE, one of which includes the cost of the resulting extra national reserve ("standby generation") requirement if electricity supplies are to remain secure.

The data listed below are based on the RAE view of generation costs over a reasonable lifespan for new plants of each type, and therefore include both construction and operation costs. The RAE report provides a CCGT generation cost of 2.2p/kWh (excluding the cost of CO2) based on a gas price of 23p/therm. Gas prices in September 2005 are significantly higher at 47p/therm[3]. The gas-fired CCGT cost we quote below factors in this higher gas cost. Coal costs are assumed to be £30/tonne. Discount rate is assumed to be 7.5%. The costs of generation provided below are a guide to the relative cost differences between technologies subject to the uncertainties of fuel and CO2 costs and rate of return described above.

Nuclear costs are subject to greater uncertainty than other technologies relating to both the cost of the plant and the rate of return required by investors. We explore this in more detail later in our submission.

New CCGTS have CO2 emissions of c 0.4 tonnes/MWh, coal IGCCs (Integrated Gasification Combined Cycle) would have emissions of c 0.65 tonnes CO2/MWh and new fluidised bed and pulverised-fuel coal plants would have emissions of c 0.8 tonnes CO2/MWh.

Cost of generating electricity for base-load plant (without/with CO2 cost @ £10/tonne[4])

— Gas-fired CCGT: 3.8/4.2 p/kWh

— Nuclear fission plant: 2.3 p/kWh (unaffected by CO2 cost)

— Coal-fired pulverised-fuel steam plant: 2.5/3.3 p/kWh

— Coal-fired circulating fluidised bed (CFB) steam plant: 2.6/3.4 p/kWh

— Coal-fired integrated gasification combined cycle (IGCC): 3.2/3.9 p/kWh

Cost of generating electricity for selected renewables (without/with standby generation)

— Onshore wind farm: 3.7/5.4p/kWh

— Offshore wind farm: 5.5/7.2p/kWh

— Wave and marine technologies: 6.6/6.6 p/kWh

— Biomass bubbling fluidised bed (BFB) steam plant: 6.8/6.8 p/kWh

Note that wind generation costs are significantly higher where sites are sub-optimal (eg lower wind resource, higher capital costs, etc). Enviros Consulting[5] suggests that 3 TWh of onshore wind can be generated at a cost of less than 5p/kWh (excluding additional reserve costs), 10 TWh at a cost of less than 6p/kWh and 30TWh at a cost of less than 10p/kWh.

Additional interconnection with continental Europe can also play a role in filling the generation shortfall as well as increasing security of supply by increasing the amount of generation available to meet the UK's national demand.

With regard to nuclear new build, how realistic and robust are cost estimates in the light of past experience?

As far as nuclear power is concerned, there are varying estimates of the cost available from around the world. We include below some leading recently-published sources on the cost of nuclear.

Table 2

MIT[6]
(2003) PIU[7]
(2002) Chicago[8]
(2004) RAE[9]
(2004) DGEMP[10]
(2003) Tarjanne[11]
(2003)

Generating cost
(p/kWh) 3.9-4.312 3.0-4.0 3.1-3.6 2.26-2.44 2.013 1.7

Rates of return 15% 8% and 15% 12.5% 7.5% 8% 5%

Capital cost $2,000/kW
(£1,150/kW) $2,000/kW
(£1,150/kW) $1,500/kW
(£865/kW) $2,000/kW
(£1,150/kW) $1,413/kW
(£990/kW) $1,900/kW
(£1,330/kW)

Load factor 85% 75-80% 85% >90% >90% >90%

Economic life 25 and 40 years 20 years 15 years 25 and 40 years 35-50 years 40 years

Construction period 5 years Not identified 5-7 years 5 years 5 years 5 years

Costs for a single nuclear plant are significantly higher per unit than for a series of plant by approximately 0.3-0.4p/kWh. Designs such as EPR are already being constructed in France and Finland (first commissioning: 2009) and so there is the potential for some "first of a kind" costs to be incurred elsewhere. Design UK licensing costs could be low if advance generic design licensing became possible in the UK, leaving constructors only needing to license a site, and not license the new (to the UK) design at the same time. Thus, provided the principle of adopting a vendor's standard design is retained without modification, costs in the region of those shown in the table above could be expected.[12], [13]

The generating costs in the international table above, vary widely from about 1.7p/kWh to 4.3p/kWh. This range is primarily due to differences in the assumed rate of return the investor demands. A high rate of return increases the generating cost whereas mitigating risks drives down the cost of nuclear substantially. A high rate of return would be applied when there is a high level of perceived risk in the project due to, for example, uncertain revenues or low confidence in completion to time and cost. This was the case in the US where nuclear was perceived to be very risky in the 1980's—hence the very substantial risk premium that is used in the Chicago and MIT studies above. In contrast in Finland the rate of return demanded is low (approx. 5%) given the high confidence (low perceived risk) of investing in nuclear and, particularly, the secure long term off-take contracts with industrial consumers in place.

No new nuclear has recently been funded in the UK. Our understanding of the UK market is that:

— for new merchant gas-fired (CCGT) independent power producers (IPPs), a nominal post-tax project return of 8-10% would be considered appropriate; while

— new contracted IPPs might now be undertaken on rates of 7-9%.

The level of premium would be dictated by the relative conservatism of particular sponsors, the extent to which, by the date of any decision, the experience with nuclear new build has been positive, the political/regulatory environment including aspects of the planning regime, and possible new economic/market support for lower-carbon generation. For nuclear, we expect that investors would look at an additional premium of perhaps 1-2% relative to CCGTs associated with the fact that nuclear new build may have special risks—for example, at one American project on a coastal spit, permission to operate was permanently withheld after construction, as it was decided that local evacuation plans could not work after all.

It is therefore clear that in the UK, given a Government desire to mitigate both the perceived and real risks from investment in nuclear energy, nuclear can be economic. However, in the absence of risk mitigation (associated with licensing, planning, etc) by Government, nuclear will not be built in the current market. Pre-development costs are expected to be approximately £250 million for a "first of a kind" reactor (subject to the point made above about the possibility of generic licensing), falling to approximately £100 million for subsequent reactors in the same series. Without reasonable expectation that these costs can be recovered no investment will be made.

What are the hidden costs (eg waste, insurance, security) associated with nuclear? How do the waste and decommissioning costs of nuclear new build relate to the costs of dealing with the current nuclear waste legacy, and how confident can we be that the nuclear industry would invest adequately in funds ring-fenced for future waste disposal?

We would assume that the UK Government would set a waste disposal "levy" or fee on the basis of nuclear power generated (MWh) and charge for this at the time of such generation. We understand that this is the approach taken in the USA and Finland, for example. To determine this fee, the government would make assumptions about the waste disposal cost, when the cost would be incurred, and the return realised on levy monies between the date of receipt and the date of incurring the cost.

The Committee will be aware that the Government cancelled the search for a deep waste depository in February 1997, from which time there has been no plan or strategy to deal with the existing waste inventory from the Royal Navy, hospitals, industry and the civil power programme. It is hoped that a clear national plan leading to an identified location will quickly be put in place when CORWM reports in July 2006. The issue is increasingly pressing and exists irrespective of new build, which would make very little difference to its scale as the lifetime operation of a fleet of 10 GW of new nuclear stations would add only 10% to the existing volume of high-level radioactive waste.

Is there the technical and physical capacity for renewables to deliver the scale of generation required? If there is the capacity, are any policy changes required to enable it to do so?

The UK has a renewable resource (wind, marine, biomass) that is theoretically large enough to replace the output being lost from coal and nuclear plant closures. However, unlike the closing plant, a number of renewable technologies are characterised by intermittent output that limits their ability to act as a direct substitute. Renewable intermittency places a cap on the amount of capacity that can be accommodated in the UK without incurring significant costs for additional reserve or increased interconnection.

The most economic renewable technology at present is onshore wind. Current UK wind generation is c 1% of the national total. Wind penetration of greater than circa 10% capacity carries significant security of supply difficulties without significant additional reserve. OXERA, the energy consultancy, illustrated the magnitude of the intermittency problem in a report in June 2003 entitled, "The Non-Market Value of Generation Technologies". OXERA reported in its forecast that although average wind output is up to 30% of capacity, there will be at least 23 one-hour periods in a year when the output from all wind turbines in the UK is less than 10% of declared wind capacity at the same time that demand is 90% or more of annual peak demand. This is after making allowance for the benefits of wind turbines being distributed around the UK including offshore. Across the entire year, OXERA's model showed that UK wind fleet output would fall below 10% of total "nameplate"" capacity of the wind fleet for 18.7% of the time. In other words, wind is relatively unreliable and by itself cannot substitute for closing capacity.

The UK has limited interconnection to neighbouring countries and therefore additional UK reserve plant is required to back up intermittent wind output. Additional reserve to back up intermittent wind output is expensive. The RAE quantifies the cost of this additional reserve as 1.7p/kWh.

EDF Energy does not believe that any significant policy change is required at present with respect to renewables, which receive support (either directly or indirectly) from a range of instruments including the Renewables Obligation, Climate Change Levy exemption certificates, Fuel Mix Disclosure, European Union Emissions Trading Scheme and direct grants.

The Renewables Obligation (RO) requires suppliers to source 15.4% of their electricity from eligible renewable generation by 2015-16 or pay a 3p/kWh (at 2002 prices) "buyout" penalty, which is paid to suppliers to the extent that they were compliant, thus increasing the true value of the renewables obligation considerably above 3p/kWh). As a direct consequence of this obligation, UK RO renewable output has increased from 5.6TWh in 2002-03 to 10.8TWh in 2004-05 at high cost to consumers (now 3.23pkWh of the renewable generation target in 2005/06, equivalent to 0.18p/kWh on customers' bills). The RO is clearly working and will deliver significant additional generation (forecast to be between 25 and 30TWh in 2010). Physical constraints (the availability of sites with planning consent, as well as transmission network infrastructure, connections, etc) rather than Government policy are likely to be the limiting factor for renewable build in the short to medium term and are already being addressed.

Stability is a vital component of support mechanisms such as the RO to provide investors with the confidence to provide capital. One area of the RO that could be improved to boost confidence are the arrangements that apply in the event that a supplier defaults on its payments into the buyout fund. The DTI has recently introduced a mutualisation scheme whereby non-defaulting suppliers have to recover the default from their customers. This increases the cost of the RO to customers; and there is no guarantee that a supplier will be able to recover the full cost of the default from its customers in a competitive market. As a result suppliers are likely to continue to factor the risk of supplier default into the price they are prepared to pay to generators for ROCs, reducing the total volume of renewable generation that will be delivered by the RO. A preferable solution would be one in which suppliers provided letters of credit or made buy-out payments more frequently to eliminate the risks associated with supplier default.

What are the relative efficiencies of different generating technologies? In particular, what contribution can micro-generation (micro-CHP, micro-wind, PV) make, and how would it affect investment in large-scale generating capacity?

We believe that there are many barriers to be overcome before micro-generation can make a significant contribution in the short-to-medium term. For widespread adoption of micro-generation to be feasible, the devices must be reliable, economic to purchase, and above all easy to maintain with, crucially, sufficient trained maintainers/installers available. Increased penetration of small-scale distributed generation will reduce investment in large-scale generating capacity to the extent that it reduces national transmission system demand. It is highly probable that micro-generation will replace only a small fraction of the generation shortfall caused by the large capacity of closing plant.

3. What is the attitude of financial institutions to investment in different forms of generation?

What is the attitude of financial institutions to the risks involved in nuclear new build and the scale of the investment required? How does this compare with attitudes towards investment in CCGT and renewables?

We understand that financial institutions regard new nuclear in the UK as potentially competitive with new CCGTs.

At present, investors in renewables require projects to have off-take contracts for power, ROCs (Renewables Obligation Certificates) and LECs (climate change Levy Exemption Certificates) before they are prepared to provide finance owing to the perceived risks surrounding ROC prices. Very few merchant renewables projects that will sell their output on a short-term basis into the market are being developed at present. Similarly large CCGTs being developed by non-vertically integrated companies typically seek offtake contracts to lower the risk profile associated with the project. It seems reasonable to assume that similar levels of certainty regarding revenue streams, to reduce risk, would be a requirement of financiers before they would lend to new nuclear projects.

How much Government financial support would be required to facilitate private sector investment in nuclear new build? How would such support be provided? How compatible is such support with liberalised energy markets?

A range of instruments could be used by Government to support new nuclear build including capital support, revenue support, obligations on suppliers to source a percentage of their output from low CO2 sources (including CO2 sequestration and nuclear) or long-term contracts for carbon emissions avoidance. Similar support mechanisms for particular technologies already exist in the liberalised UK energy market, for example the Renewables Obligation, capital grants to Round 1 offshore projects and revenue support to marine renewables and via Climate Change Levy exemption certificates.

In its implementation of phase 1 (2005-07) of the EU ETS (emissions trading scheme), the UK has set aside a New Entrant Reserve for distributing CO2 allowances for new installations. Any operator commissioning a new installation will receive allowances proportional to its projected output. However nuclear generation is excluded from EU ETS and does not qualify to receive free allowances. Government financial support that recognised the extent and magnitude of CO2 savings delivered by new nuclear could be used to facilitate private sector investment in new build. This could be achieved by offering operators of new nuclear plant a carbon avoidance contract that would pay operators at a predetermined rate on output achieved (and CO2 emissions saved). The payments could be funded by revenues raised from the auctioning of CO2 allowances.

The retention of a new entrant reserve (NER) in its present form in ETS would discriminate against carbon free technology and support the development of non-carbon free technology through the issuing of free allowances to new build (eg CCGT), and would significantly increase the complexity of the scheme and reduce certainty for participants.

As previously suggested, one of the most valuable contributions that Government could provide would be, through working with industry, to reduce the risks associated with licensing, planning, etc. This could be achieved through a joint Government-industry project that shared these licensing and planning costs for a "first of a kind" reactor in the UK. This would reduce the risk a company would take in incurring large pre-development costs with no return being delivered if the process failed to deliver nuclear new build and also reduce the rate of return required on the main construction project by investors.

What impact would a major programme of investment in nuclear have on investment in renewables and energy efficiency?

Investment in new nuclear will not have any effect on renewables or energy efficiency measures in the short-term before 2010. Investment in renewables is driven by the distinct Renewables Obligation mechanism. Similarly, investment in energy efficiency is currently driven through the EEC mechanism. Given the lead times for new nuclear generation associated with licensing, planning, etc physical construction and major commitment of capital is unlikely to happen until 2010 or later. At that point in time commercial or supply licence condition/obligation-based drivers are likely to maintain significant investment in renewables and energy efficiency.

C. STRATEGIC BENEFITS

4. If nuclear new build requires Government financial support, on what basis would such support be justified? What public good(s) would it deliver?

The public good delivered would in one sense be comparable to the public good delivered from support for renewables—zero carbon generation. However, there are a number of key differences:

— The good would be delivered far more cheaply.

— The good would be delivered in a way that enhanced security of supply.

— Land use would be minimal.

— There would be more long-term high-tech employment/training in rural areas.

— The potential volume of carbon-free generation would be larger.

— If existing (closing) nuclear sites are used, extensive, expensive new high- or low-voltage transmission infrastructure from remote sites is less likely to be required.

Relative to meeting the generation gap using CCGTs burning increasing volumes of imported gas, nuclear build could also be justified on the grounds that it enhances economic and physical security of energy supplies in the UK.

Nuclear generation is not part of the EU ETS and does not receive any direct benefit for reducing CO2 emissions. Government could justify support on the basis that new nuclear prevents CO2 emissions that would otherwise have an associated cost in the EU ETS.

To what extent and over what timeframe would nuclear new build reduce carbon emissions?

Nuclear output would either displace closing coal generation or prevent the need for additional gas fired generation to replace closing nuclear plants. Coal generation currently emits roughly 0.95 tonne CO2/MWh and CCGTs emit approximately 0.4 tonne CO2/MWh. The electricity sector accounts for roughly 25% of UK CO2 emissions and the replacement of fossil fired generation with nuclear generation could contribute significantly to achieve the UK's targets on climate change. A 10 GW replacement nuclear programme could prevent an increase in CO2 emissions of c 30 Mt CO2 per annum that would occur if CCGTs replaced the closing capacity instead.

To what extent would nuclear new build contribute to security of supply (ie keeping the lights on)?

Nuclear new build would contribute significantly to increasing security of supply by reducing dependence on imported fossil fuel supplies.

There is a body of evidence that identifies specific security of supply deficiencies for renewables and CCGTs. In respect of renewables, we have covered this in our earlier answer. In respect of gas, the House of Lords' "Renewables: the practicalities" report (14 July 2004) states in paragraph 2.5 that by 2020 we will be reliant on imported gas, "more than half" of which will come from Russia. "Interruptions in these supplies may occur once every eight years with a duration of the interruption of up to 180 days: The UK can at most only store 14 days' worth". The House of Lords committee cites OXERA as the source for this information and urge urgent [but unspecified] action. The drawbacks of extensive national reliance on imported gas with very limited ability to store it are self-evident. A number of new storage and LNG import facilities are being constructed. However the storage facilities are for short to mid-range storage and are not of sufficient size to materially benefit the UK in the event of a prolonged, major gas supply interruption. The LNG ships are themselves a potentially vulnerable supply route; there has been a recent case of a successful attack on an oil tanker[14]. If an incident occurred affecting the gas piped into Europe from the East, the UK would face strong competition for LNG supplies.

Large percentages of world gas reserves are held in just a few nations, Russia having over a quarter of world reserves, and Quatar and Iran having a further 30% between them. The UK has less than 1% of world gas reserves. Russia in particular, which has become closer to Iran recently, has from time to time spoken publicly of her desire for an OPEC-like gas cartel[15].

Is nuclear new build compatible with the Government's aims on security and terrorism both within the UK and worldwide?

New nuclear build is capable of reducing the existing inventory of Plutonium 239, which is a key ingredient of atomic weapons, by converting it to other elements in the nuclear fission process. To this extent, proliferation concerns can be ameliorated.

We understand that new PWRs with a containment dome are proof against a design basis threat that generally includes hijacked airliner crashes.

New nuclear build cannot be viewed in isolation when considering security and terrorism risks associated with the UK energy industry. There are major security and terrorism risks associated with the transport and storage of LNG which the UK Government advocates as a major contributor to replacing depleting supplies of gas from the UK continental shelf. [16]

Existing nuclear risks are well managed. The Office of Civil Nuclear Security's Annual Report (July 05) [17]states that security arrangements applied within the nuclear companies and bodies regulated by OCNS are comprehensive, well-managed and effective [para 138, p 35 of the report]. We see no reason to believe that risks associated with new build would be any less well managed.

5. In respect of these issues [Q 4], how does the nuclear option compare with a major programme of investment in renewables, microgeneration, and energy efficiency? How compatible are the various options with each other and with the strategy set out in the Energy White Paper?

It is not credible that the UK can achieve a significant reduction in the carbon intensity of its UK fleet if it allows present nuclear stations to close without replacement except through the use of carbon sequestration (which itself has significant uncertainties, which may be resolved over time, associated with the transport and enduring, safe storage of CO2). As for demand, the Government has ambitions to permit extensive building of new housing in the UK and the evidence is of public expectations of winter warmth and even domestic summer air-conditioning becoming more onerous as society becomes wealthier. Significant improvements in energy efficiency at a level that can reverse demand growth have been the general policy aim for two decades now, without success. Renewables, with their penetration limited by intermittency, are likely to, at best, service increased demand and cannot compensate for the closing zero-CO2 nuclear output, let alone supplement it and displace fossil-fired generation.

The Energy White Paper sets out four energy policy objectives:

1. to put ourselves on a path to cut the UK's carbon dioxide emissions—the main contributor to global warming—by some 60% by about 2050 with real progress by 2020;

2. to maintain the reliability of energy supplies;

3. to promote competitive markets in the UK and beyond, helping to raise the rate of sustainable economic growth and to improve our productivity; and

4. to ensure that every home is adequately and affordably heated.

Replacement nuclear power could clearly play a role in delivering all four objectives due to its negligible CO2 emissions, diversifying effect in the UK energy mix and relatively low price volatility compared with gas.

In contrast most renewable technologies have a higher generation cost and some have intermittent or unpredictable output, leading to a less good fit than nuclear with objectives 2, 3 and 4, and limitations on their total potential to contribute to the first objective.

D: OTHER ISSUES

6. How carbon-free is nuclear energy? What level of carbon emissions would be associated with (a) construction and (b) operation of a new nuclear power station? How carbon-intensive is the mining and processing of uranium ore?

Nuclear energy itself is 100% carbon-free, although when you take into account other processes such as fuel production and construction then there is a small amount of CO2 that can be attributed to nuclear power. The actual emissions however from the different processes will be very site specific and depend on factors such as the type of plant and the process used for the enrichment of the uranium. For example, the centrifuge approach to uranium enrichment, which is used in the UK, uses only 1/30th as much energy as the gas diffusion approach. The overall performance of the plant itself (in terms of load factor) will also have an effect on the emissions per kWh, as a plant with a greater annual output will have lower overall emissions. More detailed information on these issues can be found in Vattenfall's[18] paper on the electricity production system.

A report by the Energy Technology Support Unit (ETSU) in 1995 found that the CO2 emissions associated with nuclear power amounted to approximately 4 g/kWh[19]. More recent data released by the World Nuclear Association (WNA) [20]suggests that anywhere between nine and 21grams of CO2 equivalent per kWh can be attributed to nuclear generation, although these figures include all greenhouse gas emissions, not just CO2. EDF Group calculations show a range of 3-40 g/kWh with EDF Group's own emission factor based on actual plant performance equal to 4.5 g/kWh. Energy use in the mining and milling of uranium ore is significant, and although this occurs outside the UK, the WNA data accounts for this as it attempts to quantify the environmental emissions from all stages of electricity generation.

EDF Group's 4.5 g/kWh figure breaks down in the following relative proportions:

— Construction of nuclear power station = 8%.

— Operation of the nuclear power stations = 9%.

— Mining and treatment = 22%.

— Enrichment = 54%.

— Other/fuel fabrication = 7%.

This compares extremely favourably to emissions of 950 g/kWh from existing coal-fired power stations and 400 g/kWh for gas burned in a CCGT. The CCGT carbon-intensity we quote here understates the real emission factor when the UK becomes reliant on a diverse range of gas imports as there is a considerable amount of energy involved21[21] in the chilling, liquefaction, transportation, regasification and compression of natural gas that is transported as LNG. Also there is a global warming potential associated with methane emissions along long Russian gas pipelines to the West, which have been said to be very porous by Western standards.

7: Should nuclear new build be conditional on the development of scientifically and publicly acceptable solutions to the problems of managing nuclear waste, as recommended in 2000 by the RCEP?

The waste problem already exists and according to CORWM, building 10 GW of new nuclear plant would only add 10% to the existing high-level waste inventory during the lifetime of the new nuclear plant. However, the waste problem is pressing and Government should move to identify the optimum long-term solution at the earliest possible moment. A number of scientifically acceptable solutions do exist and the resolution of this debate should not hold up the development of new stations.

23 September 2005

4303_uk_coal_producers_summer_interuptions.pdf

1 EDF Energy assessment, more detail later in submission. Back

2 In this section, except where stated, capacity and demand assumptions are based on EDF Energy's own analysis. Back

3 Argus gas price 2006-10 (14 September 2005). Back

4 Carbon is presently trading at prices closer to £16/tonne, but we have taken a deliberately conservative approach here. Back

5 Report to the DTI "The Costs of Supplying Renewable Energy" 17 February 2005. Back

6 MIT Study, the Future of Nuclear Power. Back

7 Performance and Innovation Unit (PIU) Energy Review Working Paper, The Economics of Nuclear Power. Back

8 University of Chicago Study, The Economic Future of Nuclear Power/ Back

9 Royal Academy of Engineering, The Cost of Generating Electricity, A Commentary. Back

10 General Directorate for Energy and Raw Materials (DGEMP) of the French Ministry of the Economy, Finance and Industry. Back