Reportby the Comptroller
and Auditor General

The Department of Energy & Climate Change

Nuclear power in the UK

HC 511 SESSION 2016-17 13 JULY 2016

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The Department of Energy & Climate Change

Nuclear power in the UK
Report by the Comptroller and Auditor General
Ordered by the House of Commons
to be printed on 13 July 2016
This report has been prepared under Section 6 of the
National Audit Act 1983 for presentation to the House ofCommons in accordance with Section 9 of the Act
Sir Amyas Morse KCB
Comptroller and Auditor General
National Audit Office
12 July 2016

HC 511 | £10.00

This report sets out how the Department of Energy& Climate Change is encouraging investment in new
generating capacity to meet the UK’s electricity systemchallenges, focusing on its measures for investment in
nuclear power, and considers the value-for-money risks
it needs to manage.

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Contents
Overview 4Part OneUK electricity system challenges 11
Part Two
The Department’s policies fora secure, affordable and clean
electricity supply 21
Part Three
Value-for-money risks 36

The National Audit Office study teamconsisted of:Simon Bittlestone, Andrea Demurtas,
Ken Foreman and Peter Kitson,
under the direction of Michael Kell.
This report can be found on the
National Audit Office website atwww.nao.org.uk
For further information about the
National Audit Office please contact:
National Audit Office
Press Office
157–197 Buckingham Palace Road
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LondonSW1W 9SP
Tel: 020 7798 7400
Enquiries: www.nao.org.uk/contact-us
Website: www.nao.org.uk
Twitter: @NAOorguk4 Overview Nuclear power in the UK

Overview

Context
1
The Department of Energy & Climate Change (the Department) is responsible
for maintaining a secure supply of electricity to power the UK. The UK’s policy andregulatory framework for electricity has created a system that has historically provided
a secure and reliable supply. But the electricity generating sector is undergoing a majortransition from old, polluting technologies, to cleaner low-carbon sources. Much of
the UK’s existing electricity generation plant is set to close over the next two decades.
At the same time, the government expects electricity demand will increase due totake‑up of electricity-based technologies, particularly for transport and heating homes
and buildings.
2
According to the Department’s strategic aims, as well as securing the supplyof electricity the UK needs, new sources of electricity should support its ambitious
greenhouse-gas emissions target and be affordable for bill payers. These threeaims can be in tension; they are often described as the Department’s ‘trilemma’.
For example, some low-carbon generation is intermittent and some is more expensive
than traditional fossil‑fuel power. Additionally, the cost of building new generating
capacity is passed onto energy consumers, rather than being funded through generaltaxation. The UK also has an ambitious target to reduce greenhouse gas emissions
by 80% from 1990 levels by 2050.
3
Since the UK’s electricity market was privatised in the late 1980s, the private
sector has been responsible for financing and building the infrastructure to generate andtransport electricity. The Department does not seek to determine the precise future mixof generating technologies. It oversees policies aimed at helping developers overcome
barriers to investment to encourage competition, leading to a supply mix that supports
its decarbonisation objectives.
4
The Department wants nuclear power to form an important part of a “balancedmix” of generating technologies, so it provides reliable, low-carbon and cost-competitiveelectricity. New nuclear investment faces particular challenges, including high upfront
costs, which can make financing projects difficult. In the last 10 years, UK governments
have developed measures to reduce these challenges for investors.

Nuclear power in the UK Overview 5

5The Department has provisionally agreed terms on a deal to support constructionof Hinkley Point C (HPC), a new nuclear power station that could generate around
7% of the UK’s electricity. The deal is with NNB Generation Company (NNBG), a
subsidiary of French state-owned energy company EDF. China General Nuclear Power
Corporation (CGN) will take 33.5% ownership of NNBG once the deal is finalised. The
deal centres on a ‘contract for difference’ (CfD), whereby the Department has agreed
that NNBG will receive an index‑linked £92.50 per megawatt hour (MWh) (2012 prices)
for the electricity HPC sells for 35 years.1 HM Treasury has also offered to guarantee
up to £2 billion of bonds that NNBG may issue to finance its construction of HPC.
The Department expects EDF to take its final investment decision to build HPC in thenear future, and wants this to be the first in a series of similar deals for new nuclear
power stations.

Scope
6

This report sets out:•some of the main electricity system challenges that the UK faces in the next two
decades, and the aims and responsibilities of the Department in meeting thosechallenges (Part One);•the Department’s policies for encouraging investment in new generating capacity,
including its specific measures for nuclear power stations (Part Two); and•the value-for-money risks that the Department needs to manage (Part Three).

7
This report provides the background for any future National Audit Office reports on
the government’s deal to support construction of HPC. Our intention is to report on thedeal once EDF has taken its final investment decision to build HPC. The report is also
intended to support Parliamentary scrutiny of the Department’s role.

Key points
Electricity system challenges
8
The Department’s central projection is that 95 Gigawatts (GW) of new
generating capacity will be constructed by 2035 – equivalent to 90% of the grid’s
current capacity (Figure 1 overleaf). Future electricity generation scenarios are subject
to uncertainty, so the Department produces a range of projections. Its central projection
is based on:•

a 20% increase in demand for electricity over the next two decades becauseof demographic changes, economic growth and the electrification of heatand transport;•

ageing coal and nuclear power stations worth nearly 30 GW of capacity shutting
as they reach the end of their technical lives;1£92.50 is the strike price in 2012 prices. This will reduce to £89.50 if EDF builds another nuclear power station at Sizewell.

6 Overview Nuclear power in the UK•

new capacity replacing existing generating sources which, while not at the end of
their technical life, are less efficient than new sources meaning they are priced outof the market; and•an increasing proportion of generation coming from intermittent sources such as
wind and solar power, meaning the total generating capacity needs to be higher toensure there is sufficient capacity to meet demand.

There is, however, significant uncertainty over these factors, particularly future electricity
demand (paragraphs 1.2 to 1.6; and Figures 1 to 4).

Figure 1
The UK’s energy challenge up to 2035
The Department projects that electricity demand may increase at the same time that a large
proportion of existing generating capacity retires
Installed capacity (Gigawatts, GW)
160

140
14
31

120

100
81

80

64

60

40
42

20

0

Current
generating
capacity

42

Increasein capacity
neededDemand increase

Plant retirements

New nuclear power stations

Existing capacity

Minimum generating
capacity requiredin 2035

New generation sources
Notes
1 The Department projects a range of scenarios for the future of electricity generation. This figure uses the scenario
based on its central estimate of economic growth and fossil-fuel prices and shows the generating capacity required
to meet the Department’s security of electricity supply and decarbonisation objectives.
2

The figure shows total installed capacity – the maximum electrical output that power generators can produce
unadjusted for plant availability and outages.

3

New generation sources includes 17 GW from European electricity interconnectors.

Source: National Audit Office analysis of Department of Energy & Climate Change energy and emissions projections dataNuclear power in the UK Overview 7

9
At the same time, the UK is committed to ambitious reductions of its
greenhouse‑gas emissions. The Climate Change Act 2008 requires the UK to reducegreenhouse-gas emissions by 80% from 1990 levels by 2050. Existing power stations
emit around 25% of the UK’s greenhouse gases. The Department wants new generating
capacity to come mainly from lower-carbon sources, such as wind, solar, nuclear and gas,
to help meet its decarbonisation goal (paragraphs 1.13 to 1.15; and Figures 7 and 8).
10 The costs of new generating capacity will largely be passed on to consumers
through their electricity bills. The government predicts that investment in new generating
capacity may cost around £140 billion to 2030. A further £40 billion of investment could
be needed in electricity transmission and distribution. The impact of this and other energy
policies on bills is uncertain. The Department estimates that by 2030 the total cost of its
policies could add £230 to the average annual electricity bill. However the Department
predicts that its policies for increasing energy efficiency, creating a more flexible energy
system and other price effects of its policies could offset these increases. Taking thesepolicies into account, the Department expects a net impact on annual bills of between adecrease of £26 and an increase of £117 by 2030 (paragraphs 1.11 and 1.12; and Figure 6).
11 Developers of many new generating sources face investment barriers given
current and expected wholesale electricity prices as well as other long-term risks.
Wholesale electricity prices, which determine revenues, are uncertain and have reduced
dramatically in recent years. ‘Levelised cost of electricity’ (LCOE) estimates lifetime costs
on a comparable basis across technologies. LCOE forecasts for new generation sourcesin the 2020s are in the region of £60 to £100 per megawatt hour (MWh). While this cost is
falling, it is still higher than the current wholesale electricity prices of around £45 per MWh.
For large-scale projects, such as nuclear and offshore wind, the risks can be even greater
due to construction risks and the potential for changes in government policy to affect theircommercial viability. In these conditions, developers require financial support for theirinvestment to be profitable (paragraph 1.7; and Figures 12 and 19).

The Department’s strategy and recent progress
12 The Department aims to overcome market failures so that there is a competitivemarket of private investment in new and existing generating capacity. The Department
has agreed 35 CfDs for new low-carbon power sources. Through CfDs, the generator is paid
the difference for electricity sold between a contractual ‘strike price’ and the ‘reference price’– a measure of the average market price for electricity in the UK. If the strike price is higher
than the reference price then the developer will receive a top‑up. At times when the reference
price exceeds the strike price, the generator is required to pay back the difference. Throughthe Capacity Market, the Department auctions capacity agreements whereby it commits
to providing future revenue certainty to new or existing power generators. This is in returnfor guarantees that capacity will be available at a certain time in the future, even if it not
actually called on to provide power. The Department expects this will ensure there is enoughcapacity to maintain security of supply while the wholesale market may not be sufficient
to keep some plant in operation. The Department aims for these policies to encourage
competition to drive down generators’ costs, which are passed onto consumers throughtheir electricity bills (paragraphs 2.2 to 2.9; Figures 9 to 11; and Figures 13 and 14).

8 Overview Nuclear power in the UK

13 The government introduced the Levy Control Framework to manage
spending on its consumer-funded support for low-carbon generation. The Levy
Control Framework places a cap on the amount the Department can raise throughlevies on energy bills in each year. The cap in 2020-21 is £7.6 billion, equivalent
to around £92 (7%) of the forecast average bill in 2020. However, the most recent
forecasts suggest that the cap will be breached by around £1.1 billion a year(paragraphs 3.13 and 3.14).

New nuclear
14 The Department wants nuclear power to form an important part of a‘balanced mix’ of generating technologies over the long term, as it could provide
reliable, low‑carbon and cost-competitive electricity. The Department projects
that between now and 2035, around 14 GW of new nuclear generating capacity
may be built. The government wants to support a renaissance of the UK nuclear
industry – the last new nuclear power station in the UK was completed in 1995
(paragraph 2.10; and Figures 4 and 8).
15 There are specific barriers to investment in nuclear power. Nuclear power
plants have high upfront costs and take a long time to build. EDF expects HPC to cost
£18 billion to build over 10 years, excluding financing costs. There are also costs to deal
with spent nuclear fuel, and decommissioning the facility once it has stopped generating
power. The costs of new nuclear power plants are expected to be higher in the UK
than other countries, in part because the UK has not built any nuclear plants since the1990s. Nuclear power plants also have long payback periods, which increases investor
exposure to changes in government policy that would reduce operating revenues. The
risks associated with nuclear projects (including policy, technology and construction
risks) make finance difficult to raise (paragraphs 2.11 and 2.12).
16 The government has introduced measures aimed at removing barriers toinvestment in new nuclear power stations. These include planning guidance, site
licensing and a standard regulatory approvals process for new reactor designs. The
HPC CfD will last 35 years, while most existing CfDs for other low-carbon technologies
last 15 years. The government negotiated the contract bilaterally with EDF, rather thanits preferred practice of relying on competition to minimise the strike price and so
reduce the cost to consumers. It aims to mitigate this risk by negotiating ‘gainshare’mechanisms as part of the CfD. These mean consumers benefit if construction costs
are lower or returns on the project are higher than anticipated. The Department hopesthat concluding the deal will generate wider investor confidence to pave the way for
subsequent new nuclear projects (paragraph 2.13; and Figures 15 and 16).
17 Progress in encouraging investment in new nuclear power stations has beenslower than for other low-carbon technologies. The deal to build HPC is the mostadvanced nuclear project as it is the only one with development consent, a site licenceand regulatory approval. However, EDF’s final investment decision has been subject
to ongoing delays and it is still uncertain when EDF will begin constructing the facility(paragraphs 2.14 to 2.18; and Figure 17).

Nuclear power in the UK Overview 9

Value-for-money risks
18 The Department’s strategy is subject to value-for-money risks for
consumers. In particular:•

Demand uncertainty: It is difficult to predict how much demand for electricity
will increase, as it is subject to economic trends, technological developments andchanges in consumer behaviour. If the Department overestimates demand, it could
provide support and incentives for more projects than necessary, resulting in poor
value for money. Equally, if the Department underestimates demand, it may needto take short‑term remedial action in the future, which could be more expensive
to consumers, or more polluting (paragraphs 3.3 to 3.9).

•

Market conditions: The government relies on the private sector to build newcapacity, which means it is exposed to market conditions that influence investor
confidence. If investor confidence falls there could be less competitive pressure tominimise costs, resulting in consumers paying more. Political and regulatory risks
can particularly impact on investor confidence. Some stakeholders have said thatrecent changes in the emphasis of government policy has had a negative effecton investors committing to building new generating capacity. The two Capacity
Market auctions to date, although competitive for existing generators, resulted
in relatively little investment in new generation sources. The Department expects
this to change in future auctions when there are fewer existing sources able to bid
for capacity agreements. There has been little competition for nuclear support.
The Department negotiated the HPC contract for difference bilaterally with EDF
as it considered this preferable to waiting for alternative nuclear options. The
uncertainty following the EU Referendum could also impact investment decisions(paragraphs 3.10, 3.11 and 3.25; and Figure 18).

•

Wholesale electricity prices: CfDs fix the cost to consumers of the electricity
from new generating sources, regardless of the market price. Since 2012, theDepartment has revised downwards its projections of future wholesale electricity
prices, mainly because of a global reduction in the prices of fossil-fuels. While CfDs
reduce the risk to consumers of market price volatility, they also mean consumers
benefit less from wholesale price falls, which are offset by increased top-up
payments. The present value of future top-up payments through existing CfDs has
increased by £5.6 billion in the 2015-16 financial year because of lower projected
wholesale electricity prices. We estimate that future top-up payments through the
HPC CfD have increased from £6.1 billion to £29.7 billion since the Department and
EDF agreed the strike price in 2013 (paragraphs 3.15 to 3.17; and Figures 19 and 20).

•

Total delivery costs: UK infrastructure costs have historically been higher than thoseoverseas, including for energy infrastructure. Private finance is more expensive thanif the government funded new generating sources, but can be value for money
provided the benefits from risk transfer (such as construction risk) and commercial
disciplines outweigh the costs (paragraphs 3.21 to 3.24; and Figure 21).

10 Overview Nuclear power in the UK

19 There are particular value-for-money considerations for nuclear powercompared to other generating technologies. The government is offering longer‑term
CfDs for new nuclear investment than other low-carbon technologies, reflecting thelonger payback periods for nuclear power stations. This adds to price certainty for
consumers but increases the risk that they do not benefit as much from any long-termchanges, such as technological advances that reduce the cost of other low-carbon
sources. The greater complexity and risk of nuclear power projects also could lead
investors to require a higher return than for other low-carbon technologies. This means
careful consideration is needed of the allocation of risks between the government andinvestor, such as including gainshare mechanisms (paragraphs 3.18; and 3.23 to 3.25).
20 The government’s new nuclear strategy means there are also particularvalue‑for-money risks to taxpayers (as distinct from consumers) compared withother technologies. With CfDs, taxpayers are not exposed to project risks such ascost overruns during construction. However, as part of the government’s deal for
HPC, HM Treasury has provisionally agreed to guarantee up to £2 billion of bonds that
NNBG will issue to finance HPC’s construction repayable by NNBG’s shareholders in
2020. If the shareholders fail to repay and the government’s guarantee is ever called,
or if the developer manages to negotiate further guarantees that are called, the funds
required would be drawn from government budgets. Additionally, the HPC deal includes
a Funded Decommissioning Programme, whereby the Department stipulates anamount that NNBG must set aside to cover decommissioning costs. The government
will be liable for any decommissioning costs above the amount NNBG sets aside. The
Department calculates the risk of this happening is very low (paragraphs 3.19 and 3.20).

Nuclear power in the UK Part One 11

Part OneUK electricity system challenges
1.1 This part of the report describes some of the main challenges that the UK faces insecuring electricity supply over the next two decades and the Department of Energy &Climate Change’s (the Department’s) responsibilities and objectives in that context.

The electricity supply challenge
1.2 Future electricity generation scenerios are subject to uncertainty, so the
Department produces a range of projections. The Department’s central projection isaround 95 gigawatts (GW) of new generating capacity will be built over the next two
decades to meet the government’s decarbonisation objectives and ensure security ofthe electricity supply. It estimates that the UK may need almost 140 GW of electricity
generating capacity to meet demand in 2035, an increase of nearly a third comparedwith 106 GW in 2015.2 The Department’s projection shows 64 GW of current generating
capacity retiring by 2035 (Figure 1 on page 6). It estimates that less than half of theseretirements will be due to plant reaching the end of their technical life. Economic
retirements – where existing plants are out competed and displaced by new generating
capacity – account for the remainder. If some of the expected new plant does notcome forward then some of the projected closures may not happen.

Long-term demand for electricity
1.3 The Department’s projections show electricity demand increasing in the next
two decades. The central scenario of its 2015 updated energy projections shows theUK’s electricity demand increasing by 20% by 2035 to 376 terawatt hours (TWh) a year
(Figure 2 overleaf). The Department also looked at the effects of varying economic
growth and assumptions about fossil-fuel price. This analysis shows growth indemand by 2035 ranges between 14% and 25%.

2

These capacity totals are not adjusted for availability, and outages for repair and maintenance, and include
electricity interconnectors.

2016

2017

2012 central projection2015 central projection

Uncertainty range

2015

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

The uncertainty range estimates the expected impact of high and low economic growth and fossil-fuel price projections on the central projection.

4

Source: National Audit Office analysis of Department of Energy & Climate Change energy and emissions projections data

The 2012 central projection was modelled only up to 2030.

The central projection is based on central estimates of economic growth and fossil-fuel prices. It contains all agreed and planned energy policies where decisions on policy design
are sufficiently advanced to allow robust estimates of impact.

2033

2

2032

3

Notes
1 The projections show final energy demand. Conversion to final demand involves some loss of energy used in the generation and transmission of electricity.

290

310

330

350

370

390

410

Final consumption (TWh)The Department’s latest demand projections are significantly lower than those it made in 2012

Figure 2
Total electricity consumption projections for the UK under alternative fossil-fuel price and growthscenarios, 2015 to 2035

2034

2035

12 Part One Nuclear power in the UK

Nuclear power in the UK Part One 13

1.4 The Department expects demand to increase from 2020 because domestic
heating will increasingly be generated by electricity rather than gas, and there will be
more electric vehicles. The Department’s view is that annual demand from heat pumps
to heat homes could be between 23 TWh and 50 TWh, with demand from electricvehicles between 5 TWh and 14 TWh by 2030.3
1.5 The Department’s latest projections of electricity demand after 2022 are significantly
lower than those it made in 2012 (Figure 2). The change is due, among other factors, tolower household growth, higher ambient temperature projections and greater predicted
impact of energy efficiency policies. The Department has also improved its underlying
energy forecasting models as part of its work to improve the accuracy of its projections.

Existing supply retirements
1.6 A large amount of the UK’s electricity generation plant is set to close over the
next two decades. In particular, the Department expects almost all existing nuclear
and coal‑fired power stations, which together generate almost half of the UK’s power,
to close by the end of the 2020s.4 The government announced in November 2015
its intention to consult on plans to ensure that all UK unabated coal-fired facilities will
be phased out by 2025, provided new lower-carbon capacity such as gas can fill thegap. All but one of Britain’s nuclear power stations are set to close by 2030 as they
are reaching the end of their operational lifecycle (Figure 3 overleaf). The ownersof these power stations will decide the precise timing of their closure. This createssome uncertainty in the Department’s projections, but also creates some flexibility
in the electricity system’s capacity during the transition to low-carbon technologies(Figure 4 on page 15).

New generating capacity
1.7 It is the government’s policy that the private sector should finance and build
new generating capacity, with the costs ultimately passed on to consumers throughtheir energy bills. However, current market conditions mean that all low-carbon
generating sources require government support to be viable for investors. Levelised
cost of electricity (LCOE) estimates consider lifetime costs on a comparable basis
across technologies. LCOE estimates for new generation sources in the 2020s are
between £60 and £100 per megawatt hour (MWh). This compares with current
wholesale prices, which will determine the revenues generators receive, at around£45 per MWh. Part Two sets out how the government is providing support toensure there is sufficient new generating capacity.

34

Department of Energy & Climate Change, Electricity System: Assessment of Future Challenges – Annex, August 2012.
While nuclear and coal power stations represent less than a third of the UK’s capacity, they generate electricity at ahigh and almost continuous rate. They therefore represent a high proportion of the UK’s electricity supply.

18.7

Coal-fired power
capacity

17.7

8.9

12.9

8.9

2017

12.9

8.9

2018

12.9

8.9

2019

10.9

8.9

2020

7.3

8.9
6.3

8.9

2021 2022

2.4

8.9
1.9

7.0

2023 2024

1.9

4.6

2025

0.6

4.6

2026

0.6

4.6

2027

–

4.6

–

3.6

2028 2029

–

3.6

2030

–

1.2

2031

–

1.2

2032

The coal power station projections do not incorporate the government’s November 2015 announcement that coal-fired facilities will be phased out by 2025.

Source: National Audit Office analysis of Department of Energy & Climate Change energy projections data

2

Notes
1 The figure excludes new nuclear build but incorporates EDF’s announcement in February 2016 that it would extend the operating lives of four of its nuclear power stations.
This will make an additional capacity of 4.7 GW available to 2024, 2.4 GW will be available until 2030.

9.4

Nuclear power
capacity

2015 2016

0

5

10

15

20

25

30

Installed capacity (Gigawatts, GW)

Coal-fired power plants will close by 2025. The life of some nuclear plants has been extended to 2030, but total capacity is due to fall sharply by 2025

Figure 3
Projected nuclear and coal-fired power capacity, 2015 to 2035

–

1.2

2033

–

1.2

2034

–

1.2

2035

14 Part One Nuclear power in the UK

New renewables

All renewables current capacity

New gasGas current capacity

2015 2016 2017

Projected

2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

The projected fall in generation from currently installed nuclear, gas and renewables is calculated using different assumptions. For nuclear, we assume that generation will fall according toplanned plant closures. For gas, we assume that generation will fall by 3% per year by 2020 onwards. For renewables we assume that generating sources close after 20 years.

Projected new generating capacity is based on the Department’s Updated Energy and Emissions Projections minus existing generation that will still be in operation in 2035.

3

4

Source: National Audit Office analysis of Department of Energy & Climate Change data (Digest of UK Energy Statistics and Updated Energy and Emissions Projections)

Projected generation from gas includes unabated gas and carbon capture and storage plants.

2

Notes
1 The chart is an indicative scenario. Generation from new sources includes extending the life of existing plants.

Nuclear current capacity

Coal

2009 2010 2011 2012 2013 2014

New nuclear

2006 2007 2008

Historic

Other fuels

0

50

100

150

200

250

300

350

400

Electricity supply, by fuel type – annual supply (TWh)Most of the electricity produced in 2035 will be from new sources

Figure 4
Electricity generation by fuel type – historic and projected as at November 2015

Nuclear power in the UK Part One 15

16 Part One Nuclear power in the UK

The Department’s responsibilities and objectives
Security of supply
1.8 The government’s highest priority in this Parliament is to ensure that the UK has asecure and resilient energy system. In a November 2015 speech, the Secretary of State
for Energy and Climate Change signalled that the Department would prioritise security ofsupply. The Department’s Single Departmental Plan, published in February 2016, states thatits priority during this Parliament would be to make the UK energy system more resilient.5
1.9 The Department has two additional objectives for the electricity system. These are to:•keep energy bills as low as possible for households and businesses; and•secure ambitious international action on climate change and reduce carbon
emissions cost-effectively at home.

The Department’s three objectives for the electricity system are in tension with one
another. They are often described as the Department’s ‘trilemma’ (Figure 5).
1.10 The Department is also responsible for managing the UK’s energy legacy safely
and responsibly. This includes coal, oil and gas decommissioning and other liabilities.
The largest share of the Department’s legacy costs are for decommissioning retired
nuclear power stations and storing radioactive waste.

Figure 5
The Department’s ‘trilemma’The three objectives are in tension with each other
Security
Security of supply requires a mix ofcomplementary generation types.
Fossil-fuelled power may be required tooffset the intermittency and inflexibilityof some low-carbon renewables

Decarbonisation

Cost of new generating capacity
is borne by consumers. Ensuring
higher levels of security requires
more investment and higher costs

Affordability
Some low- and zero-carbon
technologies are still expensive
compared to fossil-fuels, particularly
under the low international price ofoil and gas and low-cost penalties
for emitting carbon dioxide

Source: National Audit Office5

Department of Energy & Climate Change, Single departmental plan, 2016. Available at: www.gov.uk/government/
publications/decc-single-departmental-plan-2015-to-2020/single-departmental-plan-2015-to-2020

Nuclear power in the UK Part One 17

Affordable bills
1.11 The Department’s aim to maintain secure supply is in tension with keeping
people’s bills affordable because consumers ultimately pay for the building and runningof new generating capacity through their electricity bills. The government’s National
Infrastructure Delivery Plan (2016) states that planned investment in new generating
capacity could cost £138 billion to 2030. A further £40 billion of investment may
be needed in electricity transmission and distribution.6 These costs will be added
to consumers’ bills. The average UK electricity bill has increased 15% in real terms
between 1996 and 2015. Bills have continued to increase in recent years at a time
when real wages have been falling (Figure 6).7

Figure 6
Average domestic electricity bill
Since 2008 electricity bills have increased while real wages have fallen. In real terms, the annual electricity bill has
increased £80 since 2004
£ per year

Real wages (2000=100)

650

130

600

125

550

120

500

115

450
110
400
105
350
100

300

95

250

90

200

Annual electricity bill1
Real wages

1996

1999

2002

2005

2008

2011

2014

507

426

377

394

542

542

593

–

–

106

114

119

113

110

Note
1 Real 2015 prices.
Sources: Department of Energy & Climate Change, Average annual domestic electricity bills for UK countries (QEP 2.2.2), March 2016 and Office for
National Statistics, Monthly Wages and Salaries Survey 2015

6
7

HM Treasury and Infrastructure and Projects Authority, National Infrastructure Pipeline Spring 2016, March 2016.
In 2013 real terms. Available at: www.gov.uk/government/statistical-data-sets/annual-domestic-energy-price-statistics

18 Part One Nuclear power in the UK

1.12 The Department estimates that its support for low-carbon electricity generationaccounted for around £41 (7%) of the average annual household electricity bill of £586
in 2014 (2014 prices). The Department estimates that its policies to ensure a secure,
low‑carbon supply of electricity will add a further £228 to the average electricity bill by
2030. This increase will be partly offset by the Department’s other policies, such as
improving energy efficiency. According to the Department’s central scenario, its policies
will result in a net increase of £40.8 This is uncertain: the Department says the impact
could be between a reduction of £26 to an increase of £117. Moreover, these estimates
are two years old and do not reflect recent developments, such as a fall in fossil-fuelprices, nor the future impact of smart technology, which could make the energy system
more efficient.

Decarbonisation
1.13 The Department wants new generating capacity to contribute to the UK meetingits targets for reducing greenhouse-gas emissions. The Climate Change Act 2008
set a target for the UK to reduce its greenhouse-gas emissions by at least 80%
from 1990 levels by 2050. The power sector accounted for around 25% of the UK’s
greenhouse‑gas emissions in 2014 (Figure 7).9

Figure 7
UK emissions of greenhouse gases, million metric tons of carbon dixide
equivalent (MtCO2e), 2014
The power sector accounts for nearly 25% of UK’s Greenhouse gas emissions
Waste andfluorinated gases, 39
Agriculture and Land Use,
Land Use Change
and Forestry, 47

Power, 122

Buildings, 85

Transport, 118
Industry, 109
Source: Committee on Climate Change, The fifth carbon budget – the next step towards a low-carbon economy,
November 201589

Department of Energy & Climate Change, Impacts of policies on the energy bills, 2014. Figures are in 2014 real terms.
Department of Energy & Climate Change, Provisional estimates of UK Greenhouse Gas emissions for 2015,
Statistical release, March 2016.

Nuclear power in the UK Part One 19

1.14 The Department wants new generating capacity to be mainly lower-carbon
technologies, such as wind, solar, nuclear and gas. By 2035, the Department projects
that renewable and nuclear power will account for 273 TWh of the UK’s electricity
generation (75% of total generation compared with 46% in 2015) (Figure 8).

Figure 8
Outturn and projected power generation by source –all power producers, 2015 and 2035
Renewable sources and nuclear will replace coal-fired plants and a large part of gas generation
Generation (TWh)
400
9
350

8

39

300

44

100
250
200

121
70
Renewables andnuclear power,
154 TWh150

Renewables andnuclear power,
273 TWh

83
100
152
50

0

76

2015

2035

Other
Coal and natural gas CCS
Natural gas
NuclearRenewables
Coal
Note
1 The Department’s central projection assumes that coal and natural gas carbon capture and storage (CCS) begin
generating on a small scale from 2019. By 2035, CCS is projected to produce almost 40 TWh of electricty(11% of total UK generation).
Source: National Audit Office analysis of Department of Energy & Climate Change energy trends and projections data

20 Part One Nuclear power in the UK

1.15 The Department’s objective to decarbonise the power supply is in tension with
its objectives to provide a secure supply while keeping bills affordable:•

security of supply: Most renewable sources can only generate electricity in theright conditions, such as when the wind is blowing or the sun is shining. Other
generating sources, such as gas, may be needed to ensure sufficient supply attimes of peak demand.

•affordability: The lifetime cost of renewable generation is generally higher than
generating power with traditional, fossil-fuelled technologies (Figure 12 on page 26).
Having a greater proportion of the supply from renewable sources is therefore
likely to increase people’s bills. The government has created a ‘Carbon Price
Floor’ requiring fossil-fuel generators to pay for their emissions to improve thecost competitiveness of renewable sources.

Nuclear power in the UK Part Two 21

Part Two

The Department’s policies for a secure,affordable and clean electricity supply
2.1 This part sets out the Department of Energy & Climate Change’s (the Department’s)
strategy for supporting investors in new generating capacity that is mainly low-carbon
and affordable for consumers.

Contracts for Difference (CfDs)
2.2 Through Contracts for Difference (CfDs) low‑carbon generators are paid
the difference between the ‘strike price’ they receive for electricity sold and the‘reference price’ – a measure of the average market price for electricity in the UK
market. If the reference price for electricity in the UK falls below this ‘strike price’,a government company, the Low Carbon Contracts Company (LCCC) will pay
generators the difference between the reference price and the strike price. LCCC
will then recover these costs through a levy on energy suppliers. If the reference
price is above the strike price, generators will pay LCCC the difference, which it thenpasses on to suppliers. This means the costs or savings can ultimately impact on
consumers’ bills (Figure 9 overleaf). Typically the contracts last for 15 years fromwhen generation begins.
2.3 By using CfDs, the Department aims to make investments viable where market
prices for electricity are lower than what developers require. The Department also
wants CfDs to create competition between projects and technologies and intends
to award contracts through competitive auctions. It expects this to bring down thecost of constructing and running new generating sources, minimising the impact onbills. We previously reported that CfDs should offer better value for money than the
Renewables Obligation, which they replace, as guaranteeing the price of each unitof electricity sold should reduce financing costs.10

10 Comptroller and Auditor General, Early contracts for renewable electricity, Session 2014-15, HC 172,
National Audit Office, June 2014.

Year 1

Year 2

Year 3

Year 4

Year 5

Year 6

Year 7

Year 8Year 9Year 10Source: National Audit OfficeNote
1 For nuclear CfDs, the reference price is based on the year-ahead average, meaning it is fixed and spread evenly across each year.

Strike price

Energy generator receives payments

Energy generator pays

Reference electricity price

0

20

40

60

80

100

120

140

£ per MWh

The difference between reference price and wholesale energy price determine the direction of payments

Figure 9
How Contracts for Difference work

Year 11

Year 12

Year 13

Year 14

Year 1522 Part Two Nuclear power in the UK

Nuclear power in the UK Part Two 23

2.4 So far, the Department has awarded contracts to 35 projects. This has generated
investment in up to 6.7 GW of new generating capacity (Figure 10). It awarded thefirst round of eight contracts in 2014 based on administratively set prices rather thana competitive basis to prevent a hiatus in investment in renewable electricity. These
contracts enabled the developers to take final investment decisions before the full CfD
regime began. We previously reported on the Department’s awarding of these contracts,and found that the strike prices may provide higher returns for investors than wereneeded to secure investment.11 Strike prices awarded through the competitive auctions
were lower than those that the Department set for the early CfDs.

Figure 10
Contracts for Difference awarded

Negotiated contracts –May 20142

Auction February 2015 3

Technology

GW

Number of
projects

Strike price(£/MWh)Delivery year

Offshore wind

3.18

5

144–154

2017–2021

Biomass conversion

1.07

2

103–108

2015-16

Biomass combined heat and power

0.30

1

129

2018

Total

4.55

8

Offshore wind

1.16

2

114–120

2017–2019

Onshore wind

0.75

15

79–83

2016–2019

Energy from waste with combined
heat and power

0.10

2

80

2018-19

Energy from waste – advanced
conversion technologies

0.06

3

114–120

2017–2019

Solar PV0.07

550–7942015–2017

Total

2.14

27

Total

6.65

35

Notes
1 Figures may not add up due to rounding2

2013-14 real prices.

3

2012 real prices.

4

Following the Round 1 CfD allocation auction, two solar projects that had bid for CfDs with a strike price of £50 per MWh announced that they would not
be proceeding to signature of the CfD with LCCC. A further solar project was terminated by LCCC as a result of the project’s failure to meet the milestonedelivery requirements within the contracted delivery date. The remaining two solar projects both have a strike price of £79.23 per MWh (2012 prices).

Source: Comptroller and Auditor General, Early contracts for renewable electricity, Session 2014-15, HC 172, National Audit Office, June 2014;
Department of Energy & Climate Change, Contracts for Difference (CFD) Allocation Round One Outcome, February 201511

See footnote 10.

24 Part Two Nuclear power in the UK

Progress on renewables
2.5 Progress in deploying the low-carbon technologies that CfDs support is ahead of
the Department’s previous expectations. The Department publishes annual projectionsof the amount of electricity generated by different sources, including renewables. The
Department now projects that the share of electricity generated by renewable sources at
its peak in 2026 will be eight percentage points higher than it thought in 2012 (Figure 11).
2.6 The costs of wind and solar are also falling. The Department estimates the total
cost necessary to generate electricity for each technology, known as the levelised costof energy (LCOE). The LCOE usually falls with time as new technologies become moreestablished. This has been the case with wind and solar, which are now substantiallycheaper than they were 10 years ago. However, investment decisions are taken
many years in advance. The Department therefore estimates the LCOE of different
technologies for future years, which allows it to understand which are likely to be morecompetitive. The Department’s forecasts for the LCOE of wind and solar in 2025 havedecreased since 2010. The cost forecast for gas has not changed, while for nuclear it
has increased (Figure 12 on page 26).
2.7 LCOE provides an incomplete picture. It does not reflect that wind and solar
are intermittent, unlike more flexible sources such as gas-fired power stations.
Intermittent sources, as well as inflexible sources like nuclear, could also require
additional investment in new ways of distributing electricity to customers compared
to traditional fossil-fuelled sources.

The Capacity Market
2.8 Through the Capacity Market, the Department commits to providing revenue
certainty to power generators in return for guarantees that power will be available ata certain time in the future. Like CfDs, Capacity Market agreements are auctioned.
The Secretary of State sets the amount of capacity required four years ahead of eachauction, following technical recommendations from National Grid. Bidders then present
their offer for an amount of capacity with a price, with the Department accepting bids
from the cheapest upwards until the total capacity offered equals the auctioned amount.
All successful bidders then receive the most expensive bid price required to reach thenecessary capacity. Auctioned contracts are for between 1 and 15 years of capacity
availability. Energy suppliers pay capacity operators and recover the cost throughelectricity bills. The Capacity Market is technology-neutral: plant characteristics such ascarbon-dioxide emissions do not factor in whether a capacity agreement is awarded.

2012 projection

20122015 projection

2015

2008 2009 20102011 20122013 20142015 20162017 20182019 2020 2021

2022 2023

Source: Department of Energy & Climate Change, Energy & Emissions Projections 2012 and Updated Energy & Emissions Projections 2015

0

5

10

15

20

25

30

35

40

45

50

Renewables as a share of total electricity generation (%)

Compared to 2012, the Department now predicts that renewable sources will generate more electricity

Figure 11
Changes in the Department’s projections for renewable electricity generation

2024

2025 2026

2027 2028 2029 2030

Nuclear power in the UK Part Two 25

26 Part Two Nuclear power in the UK

Figure 12
Levelised cost of generating 1MWh with different technologies in 2025:
changes in Department’s estimates
The Department has revised downwards its estimate for the cost of generating electricity from solar and wind in 2025
£/MWh
250

200
150

100
50

0

2010

2013

2016

Offshore wind

2010

2013

2016

Onshore wind

2010

2013

2016

Large solar

2012

2013

Gas – CCGT

2012

2013

2015

Nuclear FOAK

Forecast range
Central estimate
Notes
1 Figures in 2014 real prices.
2

Levelised costs exclude the wider system and external costs typically associated with intermittent generation.

3

FOAK: First of a kind.

Source: National Audit Office analysis on data from: Department of Energy & Climate Change, Review of the generation costs and deployment potential ofrenewable electricity technologies in the UK, October 2011; Electricity Generation Costs, October 2012; Electricity Generation Costs 2013, July 2013;
Review of Renewable Electricity Generation Cost and Technical Assumptions, March 2016

2.9 As well as ensuring there will be enough capacity to meet peak demand in futureyears, the Department wants the Capacity Market to incentivise developers to invest
in new generation when it is needed. To date, there have been two Capacity Market
auctions, which have secured 94 GW of capacity agreements although relatively littleof this is for new generation (Figures 13 and Figure 14 on page 28). In these auctions,existing generation sources were able to fulfil the majority of the capacity required,
meaning bid prices did not rise high enough to make investment in new plant viable.
The Department expects future auctions to lead to more investment in new plant,
particularly gas generation to replace coal plants due to close by 2025.

Nuclear power in the UK Part Two 27

Figure 13
Results of the 2014 and 2015 Capacity Market auctions
Technology

Capacity(GW)

2014 auction
2018‑19 capacity(GW)

2015 auction
2019‑20 capacity
(GW)

(GW)

Combined Cycle
Gas Turbines

22.3

21.8

44.1

Combined Heatand Power andautogeneration

4.2

4.2

8.4

Coal/Biomass

9.2

4.7

13.9

Demand-side
response

0.2

0.5

0.7

Hydro

0.7

0.7

1.4

Nuclear

7.9

7.6

15.5

Open Cycle Gas
Turbines andreciprocating engines

2.1

2.4

4.5

Storage

2.7

2.6

5.3

–

1.9

1.9

Total

49.3

46.4

93.8

1 year89%

98%

3 years

6%–

15 years

5%2%£19.4 per kW
per year£18 per kW
per year

£9992

£8341

Interconnector

Duration

Cost

Clearance price(£m)

Total cost

Total

£1,833Notes
1 2014-15 prices.
2

2012 prices.

Source: National Audit Office analysis on National Grid, Final Auction Results, T-4 Capacity Market Auction for 2019-20
and National Grid, Final Auction Results, T-4 Capacity Market Auction 2014

28 Part Two Nuclear power in the UK

Figure 14
Sources of capacity procured through Capacity Market auctions
New-build generation was 5% of capacity procured in the 2014 auction and 4% of the capacity procured in the 2015 auction
Gigawatts
45
42.0

40
35
33.6
30
25
20
15

12.9

10
5

0.1
0

Existing generation

2014

Refurbished generation

2.6

1.9

New-build generation

0.2

1.9

Interconnector

0.5

Demand-side
response

2015

Source: National Audit Office analysis on National Grid, Final Auction Results, T-4 Capacity Market Auction for 2019-20 and National Grid,
Final Auction Results, T-4 Capacity Market Auction 2014

Nuclear power
2.10 The government wants nuclear power to be a significant part of a balanced power
generation mix. It wants to stimulate a renaissance in building nuclear power stations in
the UK – there has not been a new one built since 1995. The Department believes that
nuclear contributes to all three objectives of its ‘trilemma’:•secure supply: it provides baseload electricity irrespective of whether the sun isshining or the wind is blowing;•

decarbonisation: it is a low-carbon technology that can be delivered at scale.
The Department’s modelling concludes that having nuclear power in the UK’s
future energy mix reduces the costs of meeting the UK’s 2050 decarbonisation
target; and•affordability: it is cheaper than some other low-carbon alternatives, andcomparable with gas-fired power stations (including government-set carbon
prices), over the lifetime of generation.

Nuclear power in the UK Part Two 29

The challenges of nuclear power
2.11 There are specific challenges in ensuring that nuclear power is on an equal footingin the market with other low-carbon technologies:•

Nuclear power plants have very high upfront costs and take a long time to build.
Costs have increased in recent years given the extra safety considerations following
the Fukushima disaster and increasing terrorist threats. These are offset to someextent by low running costs, which are not linked to the price of fuel in the way thatgas, coal and oil power plants are. This means investments in nuclear power havea very long payback period.

•

Nuclear power investments are therefore exposed to external risks, includingchanges in government policy and market fluctuations, such as falls in thewholesale price of electricity. This could result, for example, from technologicaladvances in how electricity is generated, stored or distributed.

•

Nuclear power plants are ideal for providing baseload capacity, but are inflexible.
Running them at less than full capacity generates few cost savings.

•

The disposal of nuclear waste poses particular challenges and is expensive. Spentnuclear fuel remains radioactive for millennia and it is not yet possible to guarantee
complete decontamination.

•

The costs to decommission nuclear power stations are very high relative toother low-carbon technologies. These costs are generally far in the future andtherefore uncertain.

2.12 Furthermore, there are some challenges specific to building new nuclear power
stations in the UK:•

No new nuclear power stations have been built in the UK for over 20 years. The
UK lacks a proven, skilled supply chain to support the construction of a new power
station. The costs to build ‘first-of-a-kind’ power stations will be much higher thanin countries that have rolled out new facilities, where learning and expertise canbe shared.

•

The government’s policy is that new nuclear generation should be privately‑financed.
There are very few private companies able to risk such large upfront investmentswith such a long payback period. Many companies in the European utility sector,
which would be potential investors, have faced financial pressures in recent years,
partly due to falls in wholesale electricity prices.

30 Part Two Nuclear power in the UK

Government strategy
2.13 The government has a package of measures to overcome barriers to investment
in new nuclear power stations (Figure 15). In 2011, the Department identified eight sites
it considered potentially suitable for constructing new nuclear power stations by 2025
(Figure 16).

Figure 15
Government’s policies to facilitate new nuclear power stations
MeasureDescription

Planning laws

The Planning Act 2008 streamlined the process to facilitate the siting and buildingof significant new infrastructure projects such as nuclear power stations, railways,
airports and sewage treatment works.

Siting

The Department published a national nuclear policy statement in July 2011 saying
planning decisions for new nuclear power stations should give ‘substantial weightto the benefits’ (including the benefits of displacing carbon dioxide emissions).
The Department identified eight sites in the policy statement that it consideredpotentially suitable for constructing new nuclear power stations by the end of2025 (Figure 16).

Site licensing

Construction of a new nuclear power station cannot commence until a site licencehas been granted to a corporate body by the Office for Nuclear Regulation (ONR).
ONR granted a licence to NNB Generation Company Ltd in November 2012 toconstruct and operate a nuclear reactor at the Hinkley Point C site.

Generic Design
Assessment

ONR and the Environment Agency (for sites in England) conduct an assessment
process, which considers the safety, security and environmental implications of
new reactor designs. So far, only the EDF/Areva UK European Pressurised Water
Reactor has received a Design Acceptance Confirmation.

Bespoke contracts
for difference

The Department has negotiated bilaterally with EDF a contract for difference (CfD)
for the building of HPC. The CfD will last for 35 years, longer than the typical
timeframe of existing CfDs (15 years). It also includes a Secretary of State Investor
Agreement, which means the government will compensate investors if the plant isshut shown for reasons that are political, or due to certain changes in insurance
arrangements or certain changes in law.

UK guarantee
scheme

The government will provide a guarantee to help support crucial infrastructure
projects (not just in energy) seeking finance and investment. It has provisionallyagreed a £2 billion loan guarantee for Hinkley Point C.

FundedDecommissioning
Programme (FDP)The Department has established a model agreement whereby investors ensure
decommissioning and waste management liabilities are funded out of theiroperational revenues. Part of the fund will go towards costs of transferringintermediate-level waste and spent fuel to a geological disposal facility. The
government will take on liability for transferring waste, but it expects that investors’
contributions will be sufficient to cover the costs. An independent board, theNuclear Liabilities Financing Assurance Board, advises the Secretary of Stateon the suitability of an operator’s proposed FDP.

Source: National Audit OfficeNuclear power in the UK Part Two 31

Figure 16
Nuclear existing capacity and newly licensed sites
The government identified eight sites suitable for new nuclear power plants

Hunterston, North Ayrshire
Existing station in operation
until 2023

Moorside, Cumbria

Torness, East LothianExisting station in operation
until 2030

Hartlepool, County Durham
Heysham, Lancashire

Existing station in operation
until 2024

Existing station in operation
until 2024 (Heysham I)
and 2030 (Heysham II)
Sizewell, Suffolk
Wylfa, Anglesey

Existing station in operation
until 2035

Oldbury, Gloucestershire

Bradwell, Essex

Hinkley Point, Somerset

Dungeness, Kent

Existing station in operation
until 2023

Existing station in operation
until 2028

Licensed site
Existing site, scheduled for decommissioning
Source: National Audit Office analysis

32 Part Two Nuclear power in the UK

Progress of the new nuclear strategy
2.14 The Department has negotiated commercial terms on a deal with NNB Generation
Company (NNBG) for Hinkley Point C (HPC). NNBG is owned by EDF, the Frenchstate-owned energy company. Once the deal is finalised, China General Nuclear Power
Corporation (CGN) will take 33.5% ownership of NNBG. Although contracts will not
be signed until EDF’s final investment decision, the Department notified Parliament ofpotential contingent liabilities relating to the HPC deal in October 2015. This included:•

A 35-year CfD, with a strike price of £92.50. The Department calculated atthat time that top-up payments under the contract would be between £4billion and £19 billion depending on future wholesale prices.12 The contract has
some mechanisms which mean the strike price could be adjusted in certain
circumstances. For example, if the costs to build HPC are less than expected,
or the costs to run it once built are higher or lower than forecast.

•

A Secretary of State Investor Agreement, which provides protection if there
is a change in government policy that means HPC would be shut down.
The Department calculated that this could cost up to £22 billion (2012 prices).

•

Waste Transfer Contracts, through which the government takes on the liability forthe spent fuel and intermediate-level waste from HPC. NNBG will be required to
pay a ‘risk fee’ at the start of power generation, and a further waste transfer fee,
which the government will set around 25 years after the start of power generation.
The Department will incur a liability if the total fees are less than the actual costs.
It states this risk is ‘very low’.

2.15 Also as part of the deal, HM Treasury has agreed provisionally to guarantee up
to £2 billion of NNBG’s bonds issued to finance construction. The guarantee would be
repayable first by NNBG’s shareholders (EDF and CGN) in 2020 with any unmet liabilities
then falling to the government.
2.16 EDF’s current expectation is that two reactors at HPC will begin generating 3.2 GW
of electricity in 2025, fulfilling around 7% of the UK’s total electricity demand. EDF’s final
decision on whether to proceed with HPC has been delayed and it is still uncertain when
EDF will begin constructing the facility. EDF expects HPC to cost £18 billion to build,
excluding financing costs.

12 2012 prices, discounted to 2012 using discount rate of 3.5%. Low estimate is based on high fossil-fuel price series
and rising carbon prices. High estimate is based on low fossil-fuel prices and flat carbon price increases.

Nuclear power in the UK Part Two 33

2.17 Two other new nuclear projects have direct links to the HPC deal. EDF and
CGN have reached a provisional agreement on jointly developing two more nuclear
power stations, at Sizewell and Bradwell. If Sizewell goes ahead, the HPC contractfor difference strike price will be £89.50 rather than £92.50. Also as part of the samedeal, CGN intend to lead the development of a nuclear power station in Bradwell inpartnership with EDF who would hold a 33.5% stake in the project. CGN plans tobegin the Generic Design Assessment process for its Hualong reactor once the HPC
deal has concluded. It will need to achieve regulators’ entry requirements and be
given permission by ministers to proceed.
2.18 Two further nuclear reactor vendors, Hitachi-GE and Westinghouse, are going
through the Generic Design Assessment process for their reactor designs. Both designs
are expected to gain approval by 2018 or earlier (Figure 17 on pages 34 and 35). At thesame time, Horizon Ltd and NuGen are seeking nuclear site licences in 2018 for Wylfa
Newydd and Moorside respectively. Under current plans, both consortia could have a
new nuclear plant up and running by the mid-2020s.

34 Part Two Nuclear power in the UK

Figure 17
New nuclear pipeline
Six projects are currently in development

Planned nuclear
new build

1995

Hinkley Point C

Last nuclear
power station
built atSizewell B

NNBG (EDF/CGN)

Jul 2006

Sizewell C

2006 Energy
Challenge
Review
published

NNBG (EDF/CGN)

Reintroduced
the prospectof new nuclear
power stationsin the UK

2 x 1.6 GW EPR reactors

Completionof GDA

Site
licenceAug 2007 – EDF/
Areva submits EPR
design to regulators forregulatory assessment

Dec 2012

Nov 2012

EPR design – See Hinkley
Point C

No details yet

Aug 2007 – Westinghousesubmits AP1000 design to
the regulators

Expected to be completedby Mar 2017

Nov 2012

2 x 1.6 GW EPR reactors

Moorside
NuGen (Toshiba/Engie)
3 x AP1000 reactors
providing up 3.8 GW

Jan 2008
Meeting
the Energy
Challenge:
A White Paper
on Nuclear
Power published
Sets out the
government’s
strategic casefor new nuclear

Generic Design Assessment(GDA) process started

December 2011 – Interim
design acceptances
given before pause in
GDA process

NuGen to submit site
licence application
by 2017
Licence expected to
be granted 2018

August 2014 – GDA
process recommenced

Bradwell B
CGN
2 x 1.2 GW Hualong One
reactors

GDA process will startfollowing Hinkley Point C
final investment decision

No decision dateNo details yet

Apr 2013 – Hitachi-GE
submits ABWR design
to the regulators

Expected to be completed
by the end of 2017

Horizon to submit site
licence application
by 2017

Jul 2011
National Policy
Statement for
Nuclear Power
Generation
published

Wylfa Newydd
Horizon (Hitachi Ltd)2 x 1.35 GW ABWR
reactors

Oldbury
Horizon (Hitachi Ltd)

Licence expected to
be granted 2018

ABWR design –See Wylfa Newydd

No decision dateNo details yet

2 x 1.35 GW ABWR
reactors

Note
1 Future milestones are based on best estimates provided by the Office for Nuclear Regulation and developers. No contingency has
been built in for delays in obtaining the necessary approvals, agreeing a CfD or construction.
Source: Office for Nuclear Regulation and nuclear power station developersNuclear power in the UK Part Two 35

Contract fordifference

Final investment
decision

Construction
beginsGeneration
beginsOct 2013 – Keyterms agreed

Scheduled
Jul 2016–Sep 2016

Scheduled 2017-18

Scheduled2025

No details yet

No details yet

Pencilled infor 2018-19

Possibly 2028

Expected 2018

Followingsite licence(expected 2018 )Pencilled infor 2019

Scheduled
mid-2020s

No details yet

No decision date

No start date

No start date

Expected 2019

Scheduled 2019

Pencilled infor 2019

Scheduled
mid-2020s

No details yet

No details yet

No start date

No start date36 Part Three Nuclear power in the UK

Part Three

Value-for-money risks
3.1 We have previously reported on the main risks to value for money arising fromgovernment’s planning for economic infrastructure, including energy. These are:•inaccurate identification of the need for infrastructure;•policy uncertainty;•

failure to assess the cumulative impact on consumers of funding infrastructure
through bills;•

taxpayers’ exposure to losses; and•delivery costs that are higher than they should be.13

3.2 This part of the report describes the relevance of these risks to the Departmentof Energy & Climate Change’s (the Department’s) approach to securing investment in
new generating capacity, particularly nuclear power.

Identifying the need for infrastructure
Demand uncertainties
3.3 The Department’s strategy is underpinned by its projections for electricity demand.
Predicting demand is challenging as it is subject to particular risks and uncertainties,
such as technological changes, economic trends and consumer behaviour. If the
Department overestimates demand, it could provide support and incentives to more
projects than is necessary, which would result in poor value for money. Equally, if it
underestimates demand, it may need to take short-term remedial action in the futurethat could be more expensive to consumers, or more polluting.

13 Comptroller and Auditor General, Planning for economic infrastructure, Session 2012-13, HC 595, National Audit Office,January 2013.

Nuclear power in the UK Part Three 37

3.4 In Part One, we explained that the Department’s projections of electricity
demand have fallen significantly since 2012. National Grid, which runs the country’s
core electricity and gas transmission networks, produces its own projections, which
are different to the Department’s. Its 2016 Future Energy Scenarios assume slower
electrification of heat and transportation and therefore predict slower increases
in electricity demand than the Department. National Grid predicts that demand
will increase by 10% at most by 2035, compared with the Department’s central
scenario prediction of a 20% increase.

Supply uncertainties
3.5 The rate that existing generating sources will close is also uncertain. The
Department predicts that 64 GW of the UK’s existing generating capacity may closeon technical or economic grounds over the next two decades. But some of these aredecisions for the power station owners, rather than government. For example, EDF
announced plans in February 2016 to extend the operating lives of four of its nuclear
power stations – Hartlepool, Heysham I and II, and Torness – for up to seven years.
This will make an extra 4.7 GW available until 2024, of which 2.4 GW will be available
until 2030. However, if the projected closures of existing plants happen more quickly,
for example because power stations fail, increased pressure will be put on securityof supply.

New technologies
3.6 The nature of demand for electricity in future could change as a result oftechnological advances. The rate of change and the reliability of new technologies
are uncertain but could have an impact on the future generating mix.
Storage
3.7 The government’s National Infrastructure Commission recently reported that infuture storage could be used at every level, from the whole network down to individual
households. This could be through a mix of batteries, hydropower and supercapacitors.
The National Infrastructure Commission points out that the cost of some of thesetechnologies have fallen dramatically in recent years: lithium ion batteries cost less than
7% now of what they did in 1990.14 However, the ability of current electricity storage
technologies to provide power over long time periods remains limited.

14 National Infrastructure Commission, Smart Power, March 2016, p. 10.

38 Part Three Nuclear power in the UK

Demand-side response
3.8 Demand-side response is where households and businesses use electricity more
flexibly, so that they use less during times of peak demand and more during timesof low demand. Reducing electricity use at peak times reduces the total capacity
required. The National Infrastructure Commission calculates that if 5% of current peakdemand were met by demand flexibility then the power saved would be equivalent to a
new nuclear power station.15 Spreading out people’s use of electricity would increase
the value of generation sources that can only generate power in certain conditions,such as wind and solar.
Impact on nuclear power’s role
3.9 Developments in storage technology and increased use of demand-side response
could change the role that nuclear power plays in the generating mix, but this is
uncertain. One of the Department’s main reasons for including nuclear power in thegenerating mix is that it provides baseload capacity to complement the intermittencyof renewable sources like wind and solar. If major advances are made in storage
technology, electricity from wind and solar could be captured and used when the windstops blowing or the sun stops shining. The need for baseload could then reduce.
Alternatively, storage technology may enable baseload to be absorbed during dipsin demand and released during peaks when it is needed. If demand for electricity
is also more flexible or evenly spread, this would counter the relative inflexibility of
nuclear power.

Policy uncertainty
3.10 The government relies on market conditions and investor confidence to minimise
the support needed for private investment in new generating sources. Securing
investment depends critically on developers’ perspectives of future trends in fossil-fuel,wholesale-power and carbon prices, and cost trajectories of low-carbon generating
technologies. Developers determine the return they require according to the perceived
risk of investing in a project (hurdle rate). If they calculate that returns will be lower thanthe hurdle rate they will not invest without government support, such as through CfDs.
However, if investors perceive the risks are still too high compared to the likely returnthen few will come forward. This could mean more government support is needed,which could increase costs to consumers.

15 National Infrastructure Commission, Smart Power, March 2016, p. 48.

Nuclear power in the UK Part Three 39

3.11 A lack of certainty could lead to project sponsors, lenders and contractors
deferring or abandoning UK projects in favour of opportunities elsewhere. We havepreviously described the need for greater certainty in the government’s and regulators’decisions to improve market confidence in the pipeline of investment and contracting
opportunities.16 Some stakeholders have raised concerns about the impact of recent
government decisions on investor confidence. A recent Energy and Climate Change
Committee inquiry identified several factors that have combined to damage investors’
confidence. These include sudden policy changes, an inconsistent approach, lack oftransparency and lack of a long-term vision.17 The UK’s position in the EY Renewable
Energy Country Attractiveness Index, a measure of investor confidence, has steadily
declined over the past two years (Figure 18). Investor confidence could also be
impacted by factors outside the Department’s control, such as the uncertainty
following the EU Referendum.

Impact on consumers
3.12 The costs of the Department’s interventions to ensure enough new generating
capacity is built will ultimately be passed onto consumers’ bills. If the Department
fails to assess the cumulative impact on bills of its policies there is a risk of financial
hardship for consumers, or the need for unplanned taxpayer support.
3.13 The government introduced the Levy Control Framework to control the costsof supporting investment in low-carbon generation and to protect consumers. The
Levy Control Framework caps aggregate spending on consumer-funded support
for low‑carbon projects in 2020-21 at £7.6 billion (2011-12 prices). The Department
estimates that this will add, on average, around £92 (7%) to annual household energy
bills in 2020 (real 2014 prices).18

Figure 18
UK position on EY Renewable Energy Country Attractiveness Index
The UK slid from eighth to thirteenth position following 2015 policy announcements

UK rank

September
2014

March
2015

June
2015

September
2015

May
2016

7

8

8

11

13

Source: EY, Renewable Energy Country Attractiveness Index

16 Comptroller and Auditor General, Planning for economic infrastructure, Session 2012-13, HC 595, National Audit Office,January 2013, paragraph 4.3.
17 Energy and Climate Change Committee, Investor confidence in the UK energy sector, Third report of Session 2015-16,
HC 542, March 2016.
18 Department of Energy & Climate Change, Estimated impacts of energy and climate change policies on energy prices
and bills, November 2014, available at: www.gov.uk/government/publications/estimated-impacts-of-energy-andclimate-change-policies-on-energy-prices-and-bills-2014, Department of Energy & Climate Change prices and bills
report 2014.

40 Part Three Nuclear power in the UK

3.14 The most recent forecasts of Levy Control Framework spending suggest the cap
will be breached. The Office for Budget Responsibility released forecasts alongside the2016 Budget showing that the £7.6 billion cap will be exceeded by more than £1.1 billion(2011‑12 prices) in 2020-21. This is within the 20% headroom that is permissible in the
Framework, but is equivalent to an additional £20 on the average bill. We will report on
the Department’s management of the Levy Control Framework later this year.
3.15 Falls in wholesale prices would increase the level of support that consumers
provide through CfDs. CfDs fix the cost of electricity from new generating sources sothat investments in low-carbon technology are viable. Falls in the market price therefore
need to be offset by top-up payments. While this reduces the risks to consumers fromprice volatility, it means they benefit less from wholesale price reductions.
3.16 The Department has revised downwards its projections of wholesale electricity
prices since 2012. The Department publishes projections of electricity wholesale prices
up to 20 years ahead. In 2015, the Department projected wholesale electricity to cost
£65.58 per megawatt hour in 2030, a 22% fall compared with its 2012 projection(Figure 19). The fall stems mainly from reductions in expected price of fossil fuels. The
proliferation of renewable sources, such as wind and solar, also dampens down wholesale
prices as their marginal cost to produce electricity is less than fossil-fuelled sources.

Figure 19
The Department’s projections of wholesale electricity prices
The Department projects lower wholesale electricity prices compared to its 2012 projection£ per MWh
90
80
70
60
50
40
30
20
10
0

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
2012 projection2015 projection

Source: National Audit Office analysis, Department of Energy & Climate Change

Nuclear power in the UK Part Three 41

3.17 The predicted value of top-up payments under existing and proposed CfDs has
increased due to reductions in projected wholesale prices. The Department calculates
that in the 2015-16 financial year the current value of future top-up payments throughexisting CfDs have increased by £5.6 billion because of lower wholesale electricity
prices. We estimate that the value of future top-up payments under the proposed
HPC CfD have increased from £6.1 billion in October 2013, when the strike price
was agreed, to £29.7 billion in March 2016 (Figure 20).

Figure 20
Top-up payments under the Hinkley Point C CfD
Top-up payments that consumers will make have more than quadrupled since 2013as wholesale price projections have fallen£ million discounted, 2015-16 prices
35,00030,00029,72325,00020,00015,00010,0005,000

10,888
6,092
2,723

0

October 2013

April 2014

March 2015

March 2016

Wholesale electricity price projection
Notes
1 HPC strike price will decrease from £92.50 to £89.50 if NNGB builds a second plant at Sizewell. This will also
reduce the forecast difference payments.
2

The October 2013 and April 2014 estimates are based upon the Department’s successive projections ofwholesale electricity prices, using their central fossil fuel price trajectory and a rising carbon price assumption.
The April 2014 price series was used to value the existing CfD contracts at the date of their signature.

3

The price projections for March 2015 and March 2016 are the series used to value the signed CfD contracts
at those dates for the Department’s financial statements.

4

Difference payments have been expressed in 2015-16 prices. They have been discounted at 0.7%, which is
the rate HM Treasury specifies for valuing financial liabilities.

Source: National Audit Office analysis; Department of Energy & Climate Change42 Part Three Nuclear power in the UK

3.18 The longer duration of the HPC CfD compared with existing CfDs means consumers
are exposed to greater uncertainty. The range of potential wholesale electricity prices
35 years from when generation begins (currently expected to be 2025) is very uncertain– the Department only projects wholesale electricity prices for 20 years. Additionally,
over a longer timeframe there is greater potential for technological changes that reducethe competitiveness of nuclear compared to other power sources. We previously
recommended that the Department should ensure there are effective arrangements for
actively managing contracts to minimise their costs to consumers.19 This is especiallythe case where the contracts last longer.

Taxpayer exposure to losses
3.19 Neither taxpayers nor energy consumers pay anything towards construction under
CfDs, meaning they are not exposed to project risks. Difference payments are only
made once generation begins. However, taxpayers could be exposed to losses if thegovernment guarantees to bear or share the project risks, such as cost overruns, andthat risk subsequently materialises.
3.20 The government’s approach to supporting construction of new nuclear power
stations could expose taxpayers to losses:•

Its debt guarantee for HPC covers up to £2 billion of bonds NNBG issues
between 2018 and 2020. If the guarantee were ever called on, this could lead to
taxpayer losses, although NNBG’s shareholders will be liable before it would fallto government. NNBG will pay a guarantee fee for the risk that the governmentis taking.

•The government will take on the liability for disposing of spent fuel andintermediate-level waste from HPC, and must provide a waste disposal service.
The Department told Parliament that it expects the costs of this liability to be met
through NNBG’s Funded Decommissioning Programme. The Department requires
NNBG to set aside a certain level of revenues to cover decommissioning costs,
including contingency. The Department calculates the risk of taxpayer losses as‘very low’.

•

International and UK law requires nuclear operators to hold insurance or othersecurity to meet claims in the event of a nuclear accident at their site. However,this only covers the first 1,200 million euros of costs in the event of an incident.
Costs over and above that amount would have to be met by the taxpayer.

19 Comptroller and Auditor General, Early contracts for renewable electricity, Session 2014-15, HC 172,
National Audit Office, June 2014.

Nuclear power in the UK Part Three 43

Total delivery costs
3.21 UK infrastructure costs have historically been higher than those overseas, including
for energy infrastructure. Infrastructure UK (IUK) reported in 2010 that there is a UK
cost premium of between 10% and 100% for different types of project. IUK’s review
found that there was no single reason for this premium. It cited stop-start contracting,fragmentation of the construction industry, and complex procurement approaches as
major contributors.20
3.22 Although like-for-like comparisons are difficult, the cost of building new nuclear
power stations in the UK may be higher than in other countries (Figure 21). Reasonsfor this include the lack of recent nuclear programmes, with associated shortage ofskills and supply chain; cost of labour; and higher safety requirements comparedwith other countries.

Figure 21
Levelised cost of electricity for nuclear plants in OECD countries
The costs to build nuclear power stations in the UK may be higher than in other countries
US dollars per MWh
160
140
120
100
80
60
40
20
0

UnitedKingdom

Hungary

Belgium

SlovakRepublic

FranceJapan

FinlandUnitedStates

South
Korea

10% discount rate
3% discount rate
Source: National Audit Office analysis, © OECD/IEA and OECD/NEA 2015, Projected costs of generating electricity, IEA publishing. Licence: www.iea.org/t&c

20 Comptroller and Auditor General, Planning for economic infrastructure, Session 2012-13, HC 595, National Audit Office,January 2013, paragraph 4.7.

44 Part Three Nuclear power in the UK

3.23 Costs could be higher as a result of the government’s policy that nuclear projects
should be privately financed. We have previously found that the effective interest rateof all private finance deals across government (7%–8%) is double that of government
borrowing (3%–4%). However, private finance can be value for money provided thebenefits from risk transfer (such as construction risk) and commercial disciplines
outweigh the costs.21
3.24 Supporting early new nuclear projects could lead to higher costs in the short-term
than continuing to support wind and solar. The cost competitiveness of nuclear power isweakening as wind and solar become more established. The levelised cost of electricity
from wind and solar has reduced in recent years as these technologies have been
deployed more widely (Figure 12 on page 26). The decision to proceed with support for
nuclear power therefore relies more on strategic than financial grounds: nuclear power
is needed in the supply mix to complement the intermittent nature of wind and solar. It isalso more easily scalable. For wind and solar to generate the same amount of electricity
as a nuclear power plant would mean covering large areas of sea or land, which could
cause public opposition and technical challenges.
3.25 There is less competition in the market to build nuclear power stations than forother low-carbon technologies like wind and solar, meaning costs could be higher. At thetime the Department negotiated the HPC contract for difference, it was the only potential
new nuclear power station with development consent. EDF’s chosen technology – theAreva/EDF EPR pressurised water reactor – was also the only design at an advanced
stage for regulatory approval. The Department chose to enter into bilateral negotiations
rather than its preferred approach of relying on competition to minimise costs. It thought
delays in bringing forward a new nuclear build would be costly in terms of additional
carbon and risks to future supply. The Department mitigated the risk that costs could
be higher by setting up a cost discovery and verification process that sought to validate
expected construction costs and project cash flows. It also negotiated a ‘gainshare’mechanism as part of the CfD, so consumers benefit if construction costs are lower
or returns on the project are higher than anticipated.

21 National Audit Office, The choice of finance for capital investment, March 2015.

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