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Value-Cost appraisal of wind energy applying portfolio analysis

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Value-Cost Appraisal of Wind Energy Applying Portfolio

Analysis

Oliver Moran

Submitted to the Office of Graduate Studies of

Gotland University

in partial fulfilment of the requirements for the degree of

MSc Wind Power Project Management

Master Thesis 15 ECTS

Supervisor: Assoc. Prof. Bahri Uzunoglu

Examiner: Prof. Jens N. Sørensen

Master of Science Programme in Wind Power Project Management,

Department of Wind Energy,

Gotland University

Cramérgatan 3

621 57 Visby,

Sweden


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Press release on 23 June 2011 by

Charles Hendry, former Minister

of State for Energy regarding next

generation of UK nuclear plants:

"Around a quarter of the UK's

generating capacity is due to

close by the end of this decade.

We need to replace this with

secure, low carbon, affordable

energy. This will require over

£100bn worth of investment in

electricity generation alone. This

means twice as much investment

in energy infrastructure in this

decade as was achieved in the

last decade."

Executive Summary

To meet electricity demand, electric utilities develop

portfolio strategies for generation, transmission, and

distributions systems. Portfolio strategies combine different

assets in a portfolio (getting the average returns from the

assets) but the risk or in other words the variability of these

returns is expected to cancel each other out, since one

asset is likely to be up when another is down. Throughout

this analysis the energy consumption for the last 40 years is

examined from a Levelised Generation Cost (LGC) and

portfolio diversity aspect using certain parameters.

When monitoring the gas field productions in UK waters the

decline in production from the start of the decade can be

noticed. Questions have been asked including what will the

UK government invest in next? People are often told if they

want to receive higher returns from their investment, they

should increase the proportion of stocks in their portfolio or

change the mix and invest in more aggressive asset/stock

combinations. So can the United Kingdom rely on more

imports from a perilously volatile market? When the

situation is analysed closely and past events are scrutinised,

such as when Russia stopped all gas supplies across the

Ukraine (which carried about a fifth of the EU's gas needs)

and more presently the conflicts in the Middle East which

have affected oil prices, the answer is simple. The United

Kingdom investing in more imports is akin to telling people

to drive 100 miles per hour if they want to get somewhere

sooner. While it's possible that they will arrive faster, it also

dramatically increases the likelihood that they won't arrive

at all. So where does this leave the future of energy

consumption in the British Isles? To counteract this problem

the government has looked towards wind power, with focus

on offshore wind and in June 2011 they announced the

largest nuclear programme for a generation with eight new

sites having been proposed. The UK however has gained

financially from the northern gas fields with calculated

CCGTs LCG of £30.31 MWh provideding affordable

electricity for its customers during the last decade

(Department of Trade and Industry, 2000). With the gas

production declining however a move to nuclear with

£175.95 LCG seems costly. Onshore wind £28.62 MWh

expected return with £40 MWh income generation used

and £34.82 Renewables Obligation Certificates (ROCs)

shows why developers are constructing wind farms

throughout the British Isles. The Modern Portfolio Theory

(MPT) analysis has also shown the overall economical

diversity of fuels since 1970 has improved.


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List of Figures

Figure 2.1: Electricity Transportation Process and Voltage Transformation 34

Figure 2.2: Map of DNOs 34

Figure 2.3: Overview of Market Structure under NETA/BETTA 38

Figure 2.4: Energy Imbalance 39

Figure 3.1: Risk and Return for Portfolio of 2 Assets 48

Figure 4.1: Risk and Return for Portfolio 1 against Portfolio 2 59

Figure 4.2: Risk and Return for the Portfolio Mix Adding New Assets 60

List of Tables

Table 2.1: Import of Coal in 2010 14

Table 2.2: Inland Consumption of Solid Fuels – Producers 15

Table 2.3: Inland Consumption of Solid Fuels - Final Consumption 15

Table 2.4: Natural Gas Imports 20

Table 2.5: Natural Gas Exports 20

Table 2.6: Overall Fuel Used to Generate Electricity and Heat in CHP Installations 25

Table 2.7: Percentage Distribution of Capacity of Major Players 36

Table 2.8: United Kingdom- Licensing Process 41

Table 2.9: UK Submission Statistics Onshore 42

Table 2.10: UK Approval Statistics Onshore 43

Table 2.11: UK Refusal Statistics Onshore 43

Table 2.12: UK Built Statistics Onshore 43

Table 2.13: Renewables Obligation Certificates 44

Table 2.14: Feed in Tariffs 44

Table 3.1: Technology Input Assumptions 46

Table 3.2 Technology Input Assumptions 46

Table 3.3: Two-Asset Portfolio Problem 47

Table 3.4: One Portfolio 47

Table 3.5: Data of Portfolio Return as Function of Percentage of Asset 1 48

Table 4.1: Results for Generators 49

Table 4.2: Results for Generators 50

Table 4.3: Individual Assets 52

Table 4.4: Variance-Covariance Matrix - Capital Cost 52


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Table 4.5: Portfolios 52

Table 4.6: Categorising the Technologies 53

Table 4.7: Electricity supplied GWh and Percentage 54

Table 4.8: Variance-Covariance Matrix - Capital Cost 54

Table 4.9: Individual Assets 54


Table 4.11: Electricity Supplied Analysis adding WTG to 2010 Production 56


Table 4.13: Return on Assets 57

Table 4.14: Percentage of Assets 57

Table 4.15: Two-Asset Mix 57

Table 4.16: Offsetting Portfolio 1 57

Table 4.17: Data Percentage of Portfolio 1 58

Table 4.18: Introducing New Portfolio Combinations Assets to Current Portfolio 59

Table 4.19: Mean Return, Variance and Sigma of New Assets 60

List of Graphs

Graph 2.1: Coal Production and Imports 1970-2010 13

Graph 2.2: Production, Exports and Imports of Crude Oil 1970-2010 16

Graph 2.3: Refinery Output, Exports & Imports of Oil Products 1970-2010 17

Graph 2.4: Inland Deliveries Petroleum - Electricity Generators 1970-2010 18

Graph 2.5: Production, Exports and Imports of Natural Gas 1970-2010 19

Graph 2.6: Total Demand of Gas 2010 21

Graph 2.7: Nuclear Generated and Supplied 1970-2010 23

Graph 2.8: CHP Electricity and Heat Generation 1977-2010 24

Graph 2.9: Electricity Generated from Renewables 1990-2010 27

Graph 2.10: Used to Generate Electricity 1990-2010 27

Graph 2.11: Fuel Input for Electricity Generation 1970-2010 29

Graph 2.12: Electricity Generated and Supplied 1970-2010 30

Graph 2.13: Generating Capacity of Major Power Producers 1996-2010 31

Graph 4.1: Technologies Expected Return from LCG and Risk 50

Graph 4.2: Technologies Expected Return from LCG and Risk including ROCs 51


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List of Acronyms

AGRs Advanced Gas-cooled Reactors

BETTA British Electricity Trading and Transmission Arrangement

CCGT Combined Cycle Gas Turbines

CCS Carbon Capture and Storage

CHP Combined Heat and Power

DECC Department of Energy & Climate Change

DNOs Distribution Network Operators

DUKES Digest of United Kingdom Energy Statistics

EEA European Economic Area

FITs Feed-In Tariff Scheme

GB Great Britain (England, Scotland and Wales)

GDP Gross Domestic Products

HLW High-Level Waste

IGCC Integrated Gasification Combined Cycle

ILW Intermediate-Level Waste

kWh kiloWatt Hour

LCG Levelised Cost of Generation

LLW Low-Level Waste

LNG Liquefied Natural Gas

MPPs Major Power Producers

MPT Modern Portfolio Theory

MWh Megawatt hour

NDA Nuclear Decommissioning Authority

NETA New Electricity Trading Arrangement

NGC National Grid Company

NPV Net Present Value

NPVG NPV of Net Electricity Generation

O&M Operations and Maintenance

OFGEM Office of Gas and Electricity Markets

OTC Cover-The-Counter

PWR Pressure Water Reactor

RO Renewable Obligation

ROCs Renewables Obligation Certificates


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SBP System Buy Price

SD Standard Deviation

TOTC Net Present Value of Total Costs (Capital and Operating)

TWh Terawatt hour

WTG Wind Turbine Generator

UK United Kingdom

WTG Wind Turbine Generator

Acknowledgements

I would like to acknowledge the support and assistance of the academic staff in the Department of

Wind Energy at Gotland University, particularly would like to thank Assoc. Prof. Bahri Uzunoglu for

the guidance throughout my thesis research.

Next, I would like to thank my family, especially my parents for their inspiration and support to

accomplish this goal in my life. This list would be incomplete without my friends and relatives; I thank

them for making my life easier during this time, for giving me the support and encouragement when I

needed them the most.

Last but not least, I want to dedicate this work to my cousin Niall, who regrettably never got a chance

to complete his own manuscript. An chuid eile i síocháin.

Visby, June 2012

Oliver Moran


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Contents

Executive Summary ................................................................................................................................. 2

List of Figures ........................................................................................................................................... 3

List of Tables ............................................................................................................................................ 3

List of Graphs ........................................................................................................................................... 4

List of Acronyms ...................................................................................................................................... 5

Acknowledgements ................................................................................................................................. 6

1.0 Introduction ................................................................................................................................. 8

1.1 Study Objective ....................................................................................................................... 8

1.3 Limitations ............................................................................................................................... 9

2.0 Theoretical Background and Motivation ................................................................................... 10

2.1 United Kingdom Baseline Energy Statistics ........................................................................... 13

2.1.1 Solid Fuels and Derived Gases ....................................................................................... 13

2.1.2 Petroleum ...................................................................................................................... 16

2.1.3 Natural Gas .................................................................................................................... 19

2.1.4 Nuclear .......................................................................................................................... 22

2.1.5 Combined Heat and Power ........................................................................................... 24

2.1.6 Renewable Sources ....................................................................................................... 26

2.1.7 Consumption Tread of Electricity .................................................................................. 28

2.2 Electricity Contributors and Marketplace ............................................................................. 33

2.3 Wind Energy in the UK........................................................................................................... 40

3.0 Methodology ............................................................................................................................. 45

3.1 LCG- Levelised Bus-Bar Cost .................................................................................................. 45

3.2 Modern Portfolio Theory Basics ............................................................................................ 47

4.0 Results ....................................................................................................................................... 49

4.1 LCG Results ............................................................................................................................ 49

4.2 MPT Results ........................................................................................................................... 52

5.0 Discussion .................................................................................................................................. 61

6.0 Conclusion ................................................................................................................................. 62

7.0 Bibliography ............................................................................................................................... 64

8.0 Appendix 1 Energy Statistics .................................................................................................... 65

10.0 Appendix 2 Levelised Cost of Generation ................................................................................. 75


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1.0 Introduction

The energy industrials in the United Kingdom (UK) play a vital role in the economy by producing,

transforming and supplying energy in its various forms to all different sectors. The way we produce

our energy in the future has significant importance. Increasing populations resulting in more and

more households connecting to the electricity and gas grids led to a demand for energy that was

never so high. This has tested the existing transmission grid. The challenges for energy producers are

great and immediate with society relying on energy every minute of every day. If the lights go out the

costs are colossal, factories and workplaces cannot operate, perishable food would be lost, computer

industry would hit meltdown and anti social behaviour would be a concern.

It is also widely accepted that the UK’s carbon dioxide levels need to be reduced to protect the

environment. From families to government parties everyone is concerned with the rising energy

prices. High energy costs have a damaging effect on the job industry and people’s quality of life in

general. Every energy production comes with a price, they must be environmentally acceptable.

Climate change, acid rain, possible radioactive emissions, effects of electricity pylons and wind

turbines are just a few of the possible environmental issues that have been raised with the

introduction of a new energy source. The energy policy challenges are often tested with the

increased import of energy consumption while the UK’s own reserve runs short. The government

could decide to open up more coal mines, however that may be more expensive in the long term

while there is still abundant of carbon resources. The issue here is the cut of temperature increase on

the Gross Domestic Product (GDP). Nuclear energy may be the answer, with low carbon dioxide

emissions, although this creates radioactive waste and has from time to time been politically

unpopular, especially following the recent event of the nuclear accident at Fukushima in March 2011.

1.1 Study Objective

This investigation focuses solely on how the levelised cost of generation (LCG) of a wind power

project has an effect on the modern portfolio diversity in the UK. It also analysis the energy

consumption in the UK, and how it changed in the last 40 years. With energy security a hot topic due

to declining resources, relatively cleaner carbon sources, could wind energy change the portfolio and

provide more energy protection for the UK.

The study aims to analyse LCG and different portfolio diversity of past, present and future portfolio

generation

The central questions to be addressed are as follows:

• Are the internal resources running out in the UK?

• With the UK government pressing ahead with the largest nuclear programme for a

generation, is this a good initiative?

• Would the rejected wind energy make any difference on this portfolio?

• Can wind energy affect our future consumption?


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1.3 Limitations

• The presented data for these generating costs are taken from “UK Electricity generation costs

update” published in June 2010 by Mott MacDonald engineering and development

consultancy. All standard deviations, variance and covariance are calculated from “1st OF A

KIND” appendix in the document.

• Due to lack of resources and time restrictions certain parameters have not been considered

throughout the MPT calculations (see section for more information).

• A discount rate was taken as 12 percent

• Only ROCs are considered in calculations with no capital grants for other generators

investigated

• ROCs is taken at £38.69 per ROC


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2.0 Theoretical Background and Motivation

Modern portfolio theory or portfolio diversity is a strategy used by electric utilities for combining

different electricity generator assets to one portfolio. The goal of this dissertation is to determine the

rate for the LCG of different generators and learn how to maximise the expected return from a

portfolio diversification while minimising the risk. Refused wind energy throughout the UK and future

exploited wind farms is examined and how it could improve the current portfolio.

Levelised Cost of Electricity

The levelised cost of electricity generation is defined as the proportion of the net present value of

total capital and operating costs of a generation plant to the net present value of the net generated

electricity by the generator over its operating life. From this definition we can derive the following

equation (Mott MacDonald, 2010).

LCG = TOTC / NPVEG (1.1)

LCG Levelised Cost of Generation (£/MWh)

TOTC Net Present Value (NPV) of total costs (capital and operating) (£)

NPVG NPV of net electricity generation (MWh)

TOTC = Σ (TCn / (1 + r) n

) (1.2)

n = 1

TOTCn Net Present Value (NPV) of total costs (capital and operating) (£)

TCn Total costs for Power in operating year n (capital and operating costs) (£)

Gn Net generation in operation year n

n Operation year

r Annual discount rate

I Operating life of plant

NPVG = Σ (Gn / (1 + r) n) (1.3)

n = 1


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Modern Portfolio Theory (MPT)

MPT is commonly used by financial investors to create a vigorous portfolio mix that maximise profit

working under a variety of uncertainties and volatile economic outcomes. MPT was first introduced

by Harry Markowitz in 1952 in a paper titled “Portfolio Selection” published in the Journal of Finance.

MPT’s purpose is to show diversification in the number of mix of different generators in this study. To

phrase it differently, efficient portfolios are described as the following: they maximise the expected

return for any given level of risk, while minimising risk for every given level of expected return

(Awerbuch, 2003). One of the most important items when considering MPT is that portfolios should

not be selected by just considering the characteristics of certain securities; instead, portfolio has to

be selected by considering the overall risk of proposed portfolios on how the correlation affects

them.

MPT was originally envisioned in the context of financial portfolios, where it refers E(rp), the

expected portfolio return, to σp, the total portfolio risk, defined as the standard deviation of past

returns. A basic illustration below using a simple, two generator/stock portfolio were the expected

portfolio return E(rp), is weighted average of the individual expected returns E(ri) of the two

securities (Awerbuch, 2003).

E (rp) = X1.E(r1) + X2.E(r2) (1.4)

Where:

E (rp) is the expected portfolio return

X1,X2 are the proportions (%) of the assets 1 and 2 in the portfolio; and

E(r1), E(r2) are the expected returns for assets 1 and 2; particularly the mean of all possible

outcomes weighted by the probability of occurrence. An example, for asset 1 it can

be written: E(r1) = ∑piri where pi is the probability that outcome i will occur, and ri is

the return under that outcome.

Portfolio risk, σp, is also a weighted average of the two securities in these two generators, but is

tempered by the correlation coefficient between the two returns:

σp = √(x12σ1

2+x2

2σ2

2+2x1x2ρ12 σ1 σ2) (1.5)

Where ρ12 is the correlation coefficient between the two return streams and σ1 σ2 is the SD of the

periodic returns to asset 1 and 2 respectively. From this the co-variation of two return assets can be

calculated by COV12 = ρ12 σ1 σ2. From this the equation can be written as

σp = √(x12σ1

2+x2

2σ2

2+2x1x2COV12) (1.6)

Properly designed portfolios yield a portfolio effect with less risk achieved in the portfolio through

diversification. Diversification occurs whenever the returns of two or more securities are less than

perfectly correlated (ρ<1.0).


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Multiple-Asset Portfolio

The portfolio selection method outlined for the two asset portfolio mix can easily be extended to

portfolios with 3 or more securities or assets. The mathematical formula in equation 1.5 is extended

where each square SD is multiplied with its square proportion in the mix. The relevant covariation

terms are added according to the pattern 2.Xi.Xj.COVij. Therefore for multiple assets equation 1.5

becomes

N N

σp2

= ∑ ∑ Xi Xj ρij σi σj (1.7)

i=1 j=1

Equation 1.1 is extended to

N

E(rp) = ∑ Xi E (ri) (1.8)

i=1

From this we can calculate the portfolio expected return and the portfolio standard deviation. Also

using the solver function in Microsoft Excel to maximise the sharpe ratio which is the ratio of

expected return to standard deviation. Sharpe ratio is how much excess return can be received for

the extra volatility that is endured for holding more risky portfolio.


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2.1 United Kingdom Baseline Energy Statistics for Energy Sources used in

the Portfolio

Since the main aspect of this dissertation is showing the result of unexploited wind potential, a closer

synopsis of energy sources that will be used in our portfolio analysis will be reviewed first. The

information sourced throughout this chapter is from Department of Energy & Climate Change (DECC)

Digest of United Kingdom Energy Statistics (DUKES) 2011 and Long term treads 2011 unless otherwise

stated. (Department of Energy & Climate Change, 2011).

2.1.1 Solid Fuels and Derived Gases

Coal Production and Trade

Solid fuel such as coal has a history throughout the UK that would match any confrontation of

countries throughout the world. Due to its large abundance in Britain, coal accounted for the

majority of the energy consumption in the middle 1900s. From Graph 2.1 below the consumption of

coal was 84% of total energy produced in 1970. This however changed when the supply of oil and

natural gas became more accessible and many pits were considered uneconomic. A bitter coal

miner’s strike occurred in 1984, with the government, under the leadership of Margaret Thatcher,

determined to close the uneconomical mines. A triumphant government saw employed miners

returning to work exactly a year later and restoring the coal production in close proximity to 1983

levels. When the phasing out began and petroleum and natural gas production was offset against

the coal energy production, consumption fell in 1998 to a merely 10%.

Today’s tread shows coal producing 7.3% of total energy production while imports have exceeded UK

coal production since 2001. This rapid growth in imports after 2001 continued and in 2006 reached a

record high level of 51 million tonnes. Since 2005 nearly half of UK’s coal is imported with the

majority of it being used for coal-fired power stations.

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Coal Production

Imported

Graph 2.1: Coal Production and Imports 1970-2010 (Thousand tonnes)


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Deep, Surface Mined and Imported Coal

As with coal production, coal consumption within the UK has also seen a general decline over the last

40 years, as the UK’s energy mix has become more diverse. With higher coal prices, natural gas and

oil production has become more attractive to purchase for generation use. This resulted in the coal

industry in Britain to enter a state of neglect. Power stations, coke ovens and blast furnaces have

diverted from using coal for their energy consumption with the domestic customer relying on gas.

Coal is however still mined at a number of locations in the Midlands and the North. In the 1970

when solid fuels supplied 31.7% of the final energy consumption 136,686 thousand tonnes of coal

was deep mined while 10,509 thousand tonnes was surfaced mined. This figure has changed

significantly in the last decade. At present 7,390 thousand tonnes deep mined while 11,026 mined

from the surface. This shows surface mining has remained constant with its average from the 40

year span of 15,354 thousand tonnes. So where is coal imported from? 9,750 thousand tonnes is

sourced in Russia with the remainder coming from Australia, Columbia, United States and South

Africa (Table 2.1).

Table 2.1: Import of Coal in 20101

(Thousand tonnes)

Country

Steam

Coal

Coking

Coal Anthracite Total

Russia 9,356 351 43 9,750

Colombia 6,360 66 11 6,437

United States of America 2,390 2,132 - 4,522

Australia - 3,235 12 3,247

European Union2 881 1 72 954

Republic of South Africa 781 - - 781

Canada - 434 - 434

Indonesia 275 - - 275

Other countries 87 16 - 103

People's Republic of

China - - 17 17

Total all countries 20,130 6,235 155 26,520

1. Country of origin basis

2. Includes non-EU coal routed through the Netherlands


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Coal Consumption

The top two coal consuming EU countries are Poland and Germany, which account for 26 percent

and 18 percent of the EU consumption, respectively. Even though the production of coal has declined

in the UK, it still remains the third largest consumer of coal in the EU, trailing behind Germany by

only one percent. 95% of the coal consumption was from the transformation sector (Energy Sector)

in 2010. This was a result of greater use for coal fired generators. The largest final consumer is the

industry sector, accounting for 69 percent of the total consumption in 2010. Within the industrial

sector steam coal was most utilized for cement, glass and brick production. With the major shift on

reducing C02 emissions coal consumption has dropped from 147,195 thousand tonnes consumed in

1970 to 18,417 in 2010. From Table 2.2 it can be observed that the power stations are utilising coal in

large quantities, while in Table 2.3 the industry abandoned coal as its main fuel source.

Table 2.2: Inland Consumption of Solid Fuels (2)

- Producers (Thousand tonnes)

Coal consumption by fuel producers

Primary Secondary

Collieries Power

stations (1)

Coke ovens

and blast

furnaces

Other solid

fuel plants (3)

Gas works Total

1970 1,916 77,237 25,340 4,150 4,280 112,923

1980 663 89,569 11,610 3,022 - 104,864

1990 117 84,014 10,852 1,544 - 96,527

2000 12 46,853 8,685 540 - 56,090

2010 5 41,505 6,632 831 - 48,973

Table 2.3: Inland consumption of solid Fuels (2)

- Final Consumption (Thousand tonnes)

Final consumption

Coal (1)

Coke and

breeze

Other

solid

fuel (3)

Industry Domestic Other Total

1970 19,613 20,190 4,159 43,962 18,090 3,203

1980 7,898 8,946 1,752 18,596 6,221 2,252

1990 6,280 4,239 1,211 11,730 7,637 1,214

2000 1,876 1,883 82 3,841 6,301 521

2010 1,715 718 58 2,491 3,424 311

(1) Up to 1986 power stations include those in the public electricity supply, railways and transport industries. Consumption by other

generators is included in final coal consumption. From 1987, coal consumption at power stations also includes other

generators' consumption, which is therefore excluded from final coal consumption (see also Table 2.7). From 1999 includes

coal consumption for heat sold to third parties.

(2) 2008 is 4 days longer than the standard 52 week statistical reporting period (SRP) for January to December 2008. This is to

enable a smooth transition to publishing data on a calendar month basis from January 2009 rather than 4 and 5 week SRPs used

for previous years.

(3) Low temperature carbonisation and patent fuel plants and their products.


16

2.1.2 Petroleum

Past to Present

Hydrocarbon and other substances such as sulphur form one of the most important products we use

everyday, Petroleum. In its natural form when first extracted from the earth’s crust it is usually

named as crude oil, which can be discovered clear, green or black. There is several major oil

producing regions throughout the world, with Kuwait and Saudi Arabia having the lion’s share of

crude oil fields. Other bordering countries such as Iran and Iraq also supply a large portion of the

world’s crude oil production.

Petroleum consumption in the UK is one of the most unstable sources of energy in the country’s

market as seen in graph 2.2. From 1970 until 1973 petroleum rose steadily, even though there was

strong growth of natural gas and nuclear energy. Following the same pattern as coal the industry

saw a decline in consumption for the next ten years. Before 1974 the indigenous production of crude

was negligible until the discovery of the Northern sea resource. From the imports peaking in 1973, a

rapid shift of imports and production emerged with its indigenous production peaking in 1986,

showing the transformation of surface net imports to exports. Production of the northern sea oil

refinery declined in the following years particularly in 1988 due the effects of the Piper Alpha

platform explosion resulting in 167 deaths. Regarded as one of the worst offshore oil disasters in the

modern era, the production of oil stayed relatively low until 1991. This was due to more stringent

safety measures. The industry recovered after that with its record peak of 137,099 million tonnes in

1999 but since then it has spiralled downwards to 62,962 million tonnes in 2010. On average, crude

oil production in the UK has been decreasing by around 7 percent a year while the North Sea

production remains high. At present the UK’s production capacity is the largest within the EU, trailing

behind Norway in the EEA. Questions have been raised as to why the UK imports so much oil when

its production is sufficient to meet the demands. Crude oil is imported into the UK for various

commercial reasons, one of the principal reasons being its sulphur content. Lighter hydrocarbon fuels

from the North Sea crude oil produce products such as motor spirits and other transport fuels which

have a greater financial gain.

(1) Includes natural gas liquids and feedstocks

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Imported

Production

Exports

Graph 2.2: Production, Exports and Imports of Crude Oil 1970-2010 (1)

(Thousand tonnes)


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Imported

Refinery output

Exports

Imports, Exports and Refinery Output

In 1991 crude oil imports exceeded exports for the first time since 1980, but the exporting tread

regained normality and continued to rise reaching their highest net export production during 1999 as

seen in graph 2.3. However, the declining level of crude oil production since 2000 has seen the

export of crude oil falling over the last 10 years. From 2005 the UK has become a net importer of

primary oils for the first time since 1981 apart from the early 1990s scenario when imports

outweighed exports during 1991. UK’s imported crude oil is sourced from Norway due to its

similarity; the crude oil type matches well with the existing refineries based in the UK.

A large proportion of the UK’s primary oil production was processed into petroleum products by the

UK’s refineries. From peaking in 1973 the refinery throughput fell to pre-1970 levels together with

the refinery output. The dissimilarity between refinery throughput and output is refinery use of fuel

and its gains/losses; this however is not shown in Graph 2.3. Since 1983 the oil refinery throughput

has increased production to new pinnacle levels of 97,023 thousand tonnes in 1997, but closures to

the Gulf Oil refinery late that year resulted in 4% reduction in output the following year. The

following year saw the output reduced by an even further 6% making it comparable to 1989

statistics. The existing refineries raised their capacity to offset the difference left by the closure of

Gulf Oil and Shell Haven refineries to 89,821 thousand tonnes in 2004, but since then in 2010 the

refinery throughput is the lowest since 1970, 5% lower than the previous low in 1983.

(1) Excludes products used as fuel within refinery processes

Graph 2.3: Refinery Output(1)

, Exports & Imports of Oil Products 1970-2010(Thousand tonnes)


18

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Since the late 1970s the UK was a net exporter of oil products apart from the increased demand for

oil products during the coal strike in 1984. The increased net exports of products during the early and

mid 1990s came about due to the increase of refinery outputs. However, following the closure of oil

refineries in 1997, exportation was abridged for a number of years. The industry recovered and

exported oil products reached a new peak of 26,755 thousand tonnes in 1997. Apart from the 1984

episode, exports of oil products have exceeded imports every year since 1974.

Since the main aspect of this dissertation is showing the results of unexploited wind potential, a

closer synopsis of petroleum within the electricity generation system must be analysed. Petroleum

products delivered for usage by power producers has reduced significantly from 12.60 million tonnes

in 1970 to 1.14 million tonnes in 2010. The only notable change happened during the 1984 coal strike

when 20.91 million tonnes was utilized. This shows the main usage of petroleum products remains

concentrated in the transport sector.

Graph 2.4: Inland Deliveries Petroleum - Electricity Generators 1970-2010 (Thousand tonnes)


19

2.1.3 Natural Gas

Dash for gas

Compared with coal, natural gas consumption in 1970 only accounted for 5.5 percent of all fuels

consumed. The steady growth in gas consumption with an indigenous production bolster showed

how valuable the product was when it outstripped petroleum consumption in 1996. Natural gas

peaked during 2004 when it accounted for more than 41 percent of all fuel consumed in the United

Kingdom. However the increase in gas prices resulted in consumption being reduced to 38 percent,

mainly due to gas fired electricity production changing to coal generation. Its level in 2010 did

recover to 43 percent but this was due to some production changing back from coal to gas due to the

high demand required for the cold winter. The production of natural gas however has been in

decline since the turn of the decade, with its production at about half the level that was produced in

2000. Relatively speaking the gas production has fallen off at a rate of about 6 percent per year, but

the UK is still one of the largest gas producers in the EU and accounting for 2 percent of global

production.

Imports and Exports

In 1992 the UK first started to export natural gas from its share of the Markham gas field, first to the

Netherlands and then in 1995 to the Republic of Ireland. The volume of exports was almost six times

the volume of imports in 2000 assisted by the UK-Belgium interconnector opening in 1998. Norway,

Belgium and the Netherlands contribute to the UK’s imported gas by pipelines while the increasing

import of Liquefied natural gas (LNG) is transported by ship. Since 2004 the UK has been a net

importer of gas with imported LNG increasing in 2005. This was the first time the UK imported LNG

since the early 1980s. By 2009 with two new LNG import facilities operating, LNG accounted for 25

percent of gas imports. This figure increased to 35 percent in 2010 with LNG imports exceeding

pipeline natural gas for the first time in September 2010.

(1) In most years production of town gas is less than consumption because of transfers into town gas of North Sea and imported methane.

(2) Includes colliery methane.

(3) Before 1977 imports were of liquefied natural gas. These imports continued until the early 1980s.

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Graph 2.5: Production(1)(2)

, Exports and Imports(3)

of Natural Gas 1970-2010 (GWh)


20

Table 2.4: Natural Gas Imports (GWh)

2006 2007 2008 2009 2010

Imports from:

Belgium (2) 30,505 6,471 12,174 7,945 13,568

Netherlands (3) 9,135 76,602 90,563 69,529 87,120

Norway (4) 157,035 225,764 283,722 260,438 276,807

Liquefied Natural Gas (5) 37,576 14,903 8,912 110,579 203,789

Total Imports 234,251 323,740 395,371 448,491 581,284

Table 2.5: Natural Gas Exports (GWh)

2006 2007 2008 2009 2010

Exports to:

Belgium (2) 60,195 51,390 45,949 62,084 95,932

Netherlands (6) 3,371 6,358 10,389 13,094 15,830

Norway (7) - 153 389 266 158

Republic of Ireland (8) 47,247 50,972 54,260 54,357 56,266

Total Exports 110,813 108,873 110,987 129,801 168,186

Total Net Imports

(1) 123,438 214,867 284,384 318,690 413,098

(1) A negative figure means the UK was a net exporter of gas.

(2) Physical flows of gas through the Bacton-Zeebrugge Interconnector. In tables 4.1 to 4.3 the commercial flows of

gas through the pipeline are used. Commercial flows are the amounts of gas that companies requested be

supplied through the pipeline. Net imports are the same whichever measurement is used.

(3) Via the Bacton-Balgzand (BBL) pipeline. Commissioned in November 2006.

(4) Currently via the Langeled and Vesterled pipelines, the Tampen Link (from Statfjord to FLAGS) and Gjoa/Vega

(to FLAGS).

(5) From various sources to the Isle of Grain and Gasport Teesside.

(6) Direct exports from the Grove, Chiswick, Markham, Minke, Stamford and Windermere offshore gas fields using

the Dutch offshore gas pipeline infrastructure.

(7) With effect from September 2007, UK gas from the Blane field to the Norwegian Ula field for injection into

the Ula reservoir.

(8) Includes gas to the Isle of Man for which separate figures are not available.


21

Utilization of Natural Gas & LNG

During 2010 natural gas demand was 34 percent for the operation of electricity generation. Most gas

used in electricity generation is for combined cycle gas turbines (CCGT) stations. The usage of gas

station depends on relative price of coal and gas. During 2005 and 2006 gas use fell but in 2007 it

rose again by 14 percent. The domestic sector consumed over a third of gas demand in 2010, while

public services such as schools and hospitals accounted for 3.5 percent of total demand. The use of

gas in the domestic sector is reliant on harsh winter conditions. Freezing conditions in December

2010 saw an increase of 17 percent compared to the same time in 2009. As for the industrial use of

gas it was on a downward trend from 2000-2007, apart from a minor recovery during 2003. The

economic crisis in 2008 saw the demand fall by an incredible 16 percent in 2009, from 139 TWh to

116 TWh. The outlook in 2010 was more promising showing a growth of 4.8 percent to make the

overall consumption of 122 TWh. The usage in the public administration and commercial sector

increased also in 2010, with an increase of 3.5 percent and 8.4 percent respectively mainly due to the

freezing wintery conditions.

Graph 1 illustrates the consumption of gas within each sector which amounted to 1,092,507 GWh

during 2010. The Transformation sector which includes electricity generation, blast furnaces used

395,625 GWh, while it used 69,462 (Energy industry use) for internal usage during that year. Losses

amounted to 18,737 GWh whereas the industry sector consumed 121,963 GWh on Iron, steel,

textiles and other engineering areas. The vast sector in the graph of consumption of gas came from

the domestic, public administration and commercial division which is merged together into the

“Other” category.

Other: Domestic, public administration, commercial, agriculture, Miscellaneous

Transformation

Energy industry use

Losses

Industry

Other

Non energy use

Graph 2.6: Total Demand of Gas 2010


22

2.1.4 Nuclear

The British nuclear industry plays an important role in the United Kingdom energy balance. Its low

carbon emissions helps the UK meet important EU goals while having a secure supply of electricity.

Independent studies have shown nuclear energy’s full lifecycle carbon emissions, including

construction of plant, uranium mining, milling and enrichment, fuel fabrication as well as

decommissioning, are an insignificant proportion in relation to those caused by fossil fuels (Nuclear

Industry Association, 2012). According to the Nuclear Industry Association 70 percent of the UKs low-

carbon electricity is sourced from nuclear. The power generated by existing power stations avoids 40

million tonnes of carbon dioxide emissions a year, which is comparable to taking nearly half of

Britain’s cars off the road.

Production

The UK currently has 10 operating power stations with 18 reactors. With the exception of one station

all have twin reactors. Oldbury power station in South Gloucestershire has two reactors with only

one working. There are three different types of stations, 2 Magnox stations which were the first

operational power stations in UK, 7 Advanced Gas-cooled Reactors (AGRs) which were the second

generation of built power stations and the latest addition is western European’s newest reactor

coming on stream in 1995, the Pressure Water Reactor (PWR) at Sizewell in Suffolk. Nuclear

Decommissioning Authority (NDA) owns the two Magnox stations while the seven AGRs and the new

PWR are owned and operated by EdF Energy (Nuclear Industry Association, 2012).

With gas and coal prices fluctuating, nuclear energy is perceived much more attractively now than it

has been in the past. One positive aspect regarding nuclear energy is that uranium is a widespread

resource which can be located in stable and friendly countries like Australia, Canada and USA where

the likelihood of conflict is at a minimum. Uranium enhancement in the UK is provided by Urenco

using highly competent technology. The manufacturing of the power reactor fuel is located at one of

UK oldest historically renowned plants, Sellafield.

Waste Supervision and Decommissioning

Due to the UK entering the nuclear industry at an early stage the move for decommissioning plants

has started. In 2005 the NDA was created to manage the cleanup of old historic nuclear power

stations. The organisations are responsible for the operation of the two stations as mentioned before

but also taking down of nuclear facilities which are no longer operational. Within the next 15 years

nine of UKs nuclear power stations are due to close. Large investment by the government or

subsidies agreed is required to support the development of new nuclear power stations.

Waste management is also a very important issue when looking at nuclear energy. Nuclear waste is

divided into three types:

Low-level waste (LLW) includes radioactive materials which might be contaminated such as

protective clothing from nuclear facilities or hospitals. The majority of UKs LLW is compacted and

stored in a secure storage facility near Drigg in Cumbria.

Intermediate-level waste (ILW) consists of solid and liquid materials from the furl reprocessing in a

nuclear power station. This is also stored in stainless steel containers and stored at the site where it

is produced.


23

High-level waste (HLW) is the concentrated waste produced when reprocessing nuclear fuel. It is

store in liquid form in stainless steel tanks before it is turned into glass blocks and encapsulated into

welded stainless steel containers.

Nuclear energy has being a primary substitute for the coal industry in the 1980s and 90s when it

peaked at 90,590 GWh in 1998. Since then the usage has been descending due to the

decommissioning of plants and maintenance work.

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Graph 2.7: Nuclear Generated and Supplied 1970-2010 (Thousand tonnes)


24

2.1.5 Combined Heat and Power

The Variations

Combined heat and power (CHP) is the simultaneous generation process of using heat and power in

the same process. CHP utilizes a variety of technologies ranging in different size and capacity for fuel

consumption. There are a few basic elements involved in the production of CHP, a main delivery

service such as a gas turbine or steam engine which drives an electrical generator, with the heat

generated from the process captured and used for additional production in the industry. This heat

could be used for hot water, space heating or cooling proposes. There are two major factors affecting

the production of CHP in an economical aspect, the relative cost of fuel primarily gas and the value of

producing the electricity from the fuel. Energy price trends that are related to CHP schemes vary

from scheme to scheme, depending on the size and sector of the scheme. In the last few years there

has been an increase in CHP schemes due to the increase in the price of electricity relative to that of

gas. CHP is typically sized to make use of the heat available in the system while connecting to a low

voltage distribution system. The loss through transmission and distribution are kept to a minimum

compared with large scale conventional power stations. There are four different types of CHP, steam

turbine, gas turbine, combined cycle systems and reciprocating engines.

Fluctuation within the CHP Capacity

CHP installed electrical capacity at the end of 2010 was 5,989 MWe, an increase of 375 MWe from

2009. During 2010, 107 new CHP schemes came into action while 34 existing schemes operating

during 2009 closed or were left stationary during 2010. However the 26,083 GWh of electricity

generated in 2010 was a decrease of 1.4 percent on 2009 figures. In 2010 the commercial and

industrial sectors electrical output from CHP accounted for 12 percent of its overall electricity

consumption. CHP generated more heat than electricity in 2010 recording a 47,815 GWh, an

increase of 340 GWh from 2009.

(1) Heat generated: These are calculated using gross calorific values; overall net efficiencies are some 5 percentage

points higher.

(2) Electricity generate: (CHP QHO ) basis from 1995 onwards

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Graph 2.8: CHP Electricity and Heat Generation 1977-2010 (1)(2)

(GWh)


25

CHP Installation and Usage

A vast portion of fuel used in CHP schemes to generate electricity and heat are from natural gas with

75,481 GWh used to generate electricity and heat in 2010. The consumption of natural gas in general

for CHP has been on the decline for the last number of years. Coal and oil are following the same

trend as gas with the renewable fuels sector increasing its capacity from 3,183 GWh in 2006 to 6,518

in 2010. Over the last 10 years the refineries sector has increased the use of natural gas instead of

oil. There has also been an increase of refinery gas used since 2005, which coincides with the market

increase of heavy fuel oil. This illustrates an economical benefit for refineries selling rather than

burning the heavy fuel oil it produces.

Table 2.6: Overall Fuel Used to Generate Electricity and Heat in CHP Installations (GWh)

2006 2007 2008 2009 2010

Coal (2) 4,356 4,120 4,274 3,679 3,548

Fuel oil 3,558 2,140 2,065 2,146 1,859

Natural gas 86,126 85,016 84,103 77,936 75,481

Renewable fuels (3) 3,183 3,219 4,717 5,458 6,518

Other fuels (1) 25,124 24,142 23,674 22,293 22,916

Total all fuels 122,347 118,637 118,833 111,512 110,322


26

2.1.6 Renewable Sources

In this section the consumption of renewable energy contribution to the United Kingdom’s energy

requirement is investigated. Renewable energy provided 6.8 percent of the electricity generated in

the UK in 2010. To insure every source of energy is counted for in the system, digest covered all

aspects of renewables from geothermal, active solar even the use of liquid biofuels for transport.

Some of these sources under international definitions are not counted as renewable sources or only

partly counted but are in Digest. To meet the UK’s 15 percent target introduced in the 2009 EU

renewables directive a large increase on electricity generated in the renewable sector has been

recorded.

Setting The Scales

The volume of renewables used to generate electricity was at a steady rate of 6.5 percent between

1990 and 1996 but this rate swiftly elevated in the following seven years averaging a 14.5 percent

increase. Since 2003 the figure reduced to 11 percent per annum. In 2010 the largest contribution to

renewables in input terms was from biomass, accounting for nearly 83 percent, with wind generation

and large scale hydro electricity production providing to the majority of the remainder. The rate of

increase in the volume of renewables used is subjective to the usage of each fuel. Renewable sources

such as wind and hydro consume similar volumes of power to create electricity whereas biomass

resources need large resources of power during their transformation into electricity. As a result, with

the overall figures, an increase in volume of biofuel used throughout the years had a more significant

effect on the end result.

The development of the wind industry since 2000 has been the main contributor to the growth in

electricity generated renewables, with an average of 27 percent annually. The rate of growth in

electricity generation from renewables has averaged 10 percent a year. This takes into consideration

a slight increase of 2.2 percent between 2009-2010, due to low wind speeds.

At the end of 2010 the installed renewable generation capacity reached 9,202 MW an increase of 15

percent for the previous year even though this excluded the capacity within conventional generation

stations that used 390 MW for co-firing (Co-firing is the combustion of two different types of

materials at the same time). The main provider to this increase was onshore and offshore wind,

contributing 553 MW and 400 MW respectively. In capacity terms, wind was the most significant

renewable technology for the last number of years. It provided 58 percent of renewable capacity in

2010 with hydro in second place supplying 18 percent.

Biomass Renewable Source Described Briefly

Landfill gas: Methane-rich gas formed from the decomposition of organic material is used to fuel

reciprocating engines or turbines to generate electricity or used directly in kilns and boilers.

Sewage sludge digestion: In these projects the gas produced is used to maintain the optimum

temperature, for example in CHP systems.

Domestic wood combustion: This is the use of logs in open fires, ”AGA”- type cooker boilers and

other wood burning stoves.

Non-domestic wood combustion: This category is includes sawmill residues and furniture

manufacturing wastages.

Energy crops and forestry residues: 1000s of hectares planted throughout the UK that contributes to

a large portion of Biomass percentage. Short rotation Willow Coppice and Miscanthus are the most

common crops used.


27

Straw combustion: Straw can be burnt in very high temperature boilers to supply heat, hot water

and hot air systems.

All waste combustion: Waste from paper, cardboard, scrap tyres, poultry litter may be used in

purpose built incinerators.

Co-firing of biomass with fossil fuels: This can be used to substitute 25 percent fossil fuels in a boiler

without any major changes occurring.

Other biomass: Sewage sludge digestion, municipal solid waste combustion, animal biomass, plant biomass and co-firing with fossil fuels

Other biomass: Sewage sludge digestion, municipal solid waste combustion, animal biomass, plant biomass and co-firing with fossil fuels

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Graph 2.9: Electricity Generated from Renewables 1990-2010 (GWh)

Graph 2.10: Used to Generate Electricity 1990-2010 (Thousand tonnes)


28

2.1.7 Consumption Tread of Electricity

The United Kingdom trend in inland consumption of electricity has changed since the 1970s era (See

Graph 2.11). One important fact that must be mentioned before figures are discussed is that for a

period up to 1987 data for conventional thermal electricity generated by industrial producers was

not available.

Oil fuel input in 1972 hit its peak of 29 percent and had been on the decline since, apart from the

glitch during the miner’s strike. The percentage of oil in fuel input since diminished from 11 percent

in 1990 to 1.5 percent in 2010. Used in several co-firing petroleum coke with coal stations the figure

is 0.4 percent lower than 2009.

Nuclear generation has a major part to play in the fuel input for electricity generation. From 1970

until 1998 nuclear has grown from 11 percent to its peak of 29 percent. The main hindrance with

nuclear is outages for maintenance and closure of some older nuclear stations which affect its overall

percent. From the early 2000s period nuclear has since reduced to an 18 percent share in 2010

market.

Natural gas use in supplying public power stations was only 0.11 million tonnes of oil equivalent in

1970 and didn’t increase considerably until the early 1990s. The main reason for this was legislation

set down by the European Community restricted the use of natural gas. After this gas in electricity

generation grew rapidly with its share of 2 percent in 1992 growing to 28 percent in 1998. During

1999 it surpassed nuclear (22.22 million tonnes of oil equivalent) and coal (25.51 million tonnes of oil

equivalent) by having a 34 percent stake in the inland consumption of electricity, recording an input

of 27.13 million tonnes of oil equivalent to the system. In 2010 its share had increased to 40 percent.

Coal has been a primary source supplying the largest fuel input for electricity generation during the

1970s until the early 1990s. In 1999 its share had fallen to 32 percent a significant difference from 65

percent ten years earlier in 1989. With outages in nuclear plants occurring in the 2000s and high gas

prices, coal has being a regular substitute providing up to 28 percent electricity generation until

2005. A large increase in price of gas in 2006 saw coal utilized even more contributing 41 percent of

production, but this figure has fallen back to 32 percent in 2010.

Other fuels such as biomass renewable sources, wind and hydro are the result of the gradually

increasing percent of this division. In 1990 other fuels generated 1.7 percent compared with 8.1 per

in 2010. The government objective of increasing renewable energy to meet EU targets has played a

pivotal role in this increase, especially with the large creation of offshore wind farms.


29

(1) Fuel inputs have been calculated on an energy supplied basis -

(2) Oil: Includes oil used in gas turbine and diesel plant or for lighting up coal fired boilers, Orimulsion (until 1997), and refinery gas (from 1987).

(3) Natural gas: Includes colliery methane from 1987 onwards.

(4) Other fuel: Main fuels included are coke oven gas, blast furnace gas, waste products from chemical processes, refuse derived fuels and

other renewable sources.

Electricity Supply, Availability and Consumption

When an interconnector between France and the UK came on stream in 1986, the period where the

UK was internally resourceful came to an end. This is not to say that they are reliant on other

countries to source their electricity needs, at the peak of imported electricity in 1994 France

contributed only over 5 percent of total electricity available in the UK. In 2010 net imports stands at

2.66 TWh compared with 16.89 TWh in 1994.

Consumption of electricity by the industry has remained fairly constant from 1975 accounting for a

third of total consumption to just less than a third in 2010. Even though there has being an overall

consumption percentage constant, there has been a 55 percent rise in electricity consumption from

1985-2005. During 2006 and 2007 the industry electricity consumption fell by 1 percent, before a

small industry increase in 2008. The global recession affected the industry in 2009 when the

consumption declined from 115.07 TWh in 2008 to 101.44 TWh in 2009, the lowest level seen since

1994. The outcome in 2010 was healthier with an increase to 104.92 TWh. The domestic sectors total

consumption share was around 40 percent during the 1970s, declining to just over third in the 1980s.

The domestic consumption stayed relatively stable during the 1990s until reaching a high of 36

percent in 2004. Since then it has remained around 34 to 35 percent apart from 2009 when the

industry was affected by the recession and saw domestic consumption increasing to 36 percent. The

overall volume of electricity consumed in the domestic sector has increased by 38 percent in the last

30 years.

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Graph 2.11: Fuel Input for Electricity Generation 1970-2010(1)(2)(3)(4)

(Million tonnes of oil equivalent)


30

Electricity Generated and Supplied

The total gross electricity supplied by all generating companies has increased at an annual rate of 1.1

percent from 1970 until 2010. Conventional thermal power stations in 1970 created 88 percent of

the gross electricity supplied. These stations output remained high until 1990 when new generating

technologies came on stream. The development of nuclear generation increased from 10 percent of

the gross electricity supplied by UK generators in 1970 to 27 percent in 1997. However as mentioned

before nuclear’s share varied with outages for repairs and maintenance during the 2000 decade and

stands at 15 percent in 2010. The growth in combined cycle gas turbine stations (CCGTs) has changed

the course of gross electricity supplied, from its introduction in 1989; to supplying 36 percent in 1997

it has remained the front runner supplying 46 percent in 2010.

(1) Includes electricity supplied by gas turbines and oil engines. From 1988 also includes electricity produced by plants using

renewable sources.

(2) Natural flow hydro, wind, wave and solar photovoltaic’s.

Commodity Balance of Electricity at Present

The total electricity supply in 2010 was 384 TWh, an increase of 1.1 percent on 2009. Over 99

percent of this electricity was home produced while under 1 percent was imports. Electricity supply is

totally driven by demand, so with a recovering economy and a colder winter in 2010 supply demand

increased.

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CCGT

Nuclear

Non-thermal (2)

Total

Graph 2.12: Electricity Generated and Supplied 1970-2010


31

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Losses

In the commodity balances losses, as a proportion of electricity demand in 2010 was 7.5 percent

(27,042 GWh), which was slightly lower than in 2009 in which 27, 083 GWh was lost. There are three

areas involved in losses. 22 percent was lost in transmission of high voltage transmission systems in

2010. The largest percentage came from the gateway to the public supply systems network and the

customer’s meters. This figure amounted to 74 percent of losses. Theft or meter fraud made up the

final 4 percent.

Plant Capacity

In 2010 there was an increase of 5,522 MW in the capacity of major power producers (MPPs). “Major

power producers” is the terminology used to define companies whose prime purpose is the

generation of electricity. “Other generator companies” classify companies who produce electricity as

part of their manufacturing but whose main business is not to produce electricity. With the increase

of wind capacity from 2008 major wind farm companies were included in MPPs.

The main reason for the increase in 2010 MPP capacity was the result of five new CCGT stations

opening up. Wind industry also had a part to play in this increase, with a further 571 MW produced,

largely due to Thanet offshore wind farm of 100 wind turbines with 300MW generated coming

online. MPPs accounted for 92 percent of the total generating capacity in 2010. 85 percent of this

capacity was from MPPs in England and Wales. Scotland produced 12 percent while the remainder 3

percent from Northern Ireland.

(1) Other generators as mentioned in plant capacity paragraph.

Graph 2.13: Generating Capacity of Major Power Producers 1996-2010 (1)

(MW)


32

Plant Loads, Demand and Efficiency

On the 7

th of December 2010 the maximum demand of 60,893 MW occurred, this being 1.1 percent

higher than the previous winter maximum. Also needing to be considered when meeting this

demand is how intensively each type of plant is used, in other words the measurement of the plant

load factor. In 2010 the load factor for nuclear stations was 59.4 percent which was 6.2 percent

lower than 2009. The main factor for this was due to maintenance outages at several stations. Load

factor in general fell largely due to lower electricity demand in the past few years, coupled with an

increase in capacity. The wind industry suffered in 2010, very low wind speeds reduced lower

generation despite the increase in wind capacity (for more information see renewable sources

section).


33

2.2 Electricity Contributors and Marketplace

Since the liberalisation of the electricity market in 1990 the market has developed rapidly with

competitive prices between suppliers without administrative price caps or other regulatory

interventions.

The energy industry is split up into five main parts:

1. Generators

2. The National Grid

3. Distribution companies

4. Supply companies

5. Consumers

The UK market is divided into:

• The wholesale market, this is where the generators, suppliers and large customers

buy and sell electricity;

• The transmission and distribution networks at national and regional levels;

• The retail market, where energy suppliers sell to domestic and business customers

throughout the UK.

From a supply approach the system works from 1 to 5, but wind being a generator often skips step

number 2 and connects to the system locally compared to coal, gas and nuclear. The name describing

this electricity generation is known as “embedded generation”.

Electricity Supply System in the UK distributed generation.

Generators

The source of all our power the generators are responsible for supplying the electricity. As

mentioned in section 2.7 the UK major generators changed from burning massive amounts of coal, to

the nuclear plants evolution and currently changing to gas controlling the capacity in the last 10

years. The decline in availability of these fuel resources and nuclear plants aging has seen renewable

methods of generating faring more favourably.

The National Grid

The high voltage electricity transmission network which enable the bulk transfer of high voltage

electricity around the country is owned and operated by the National Grid Transmission plc in

England and Wales, while it’s the operator of the two electricity transmission networks in North and

South Scotland who are owned by Scottish and Southern Energy and Scottish Power respectively. In

Northern Ireland the transmission is run and owned by the Northern Ireland Electricity network. The

electricity network comprises a mixture of underground cables to overhead power lines which are

transported to regional electricity distribution networks that then deliver energy to the consumers

on behalf of the suppliers. Additionally to these transmission cables there are 338 sub-stations where

the voltage transformation interface between The National Grid and the Distribution Network

Operator (DNOs) takes place. The National Grid charges electricity suppliers and generators for its

service; with approximately 90 percent of the overall electricity demand is transmitted across its

system (The National Grid, 2010).


34

Figure 2.1: Electricity transportation process and voltage transformation © The National Grid

Distribution Companies

Distribution companies which are also known as DNOs (Distribution Network Operators) are

responsible for the pipes or cables in the road and the meters within customer’s property. Effectively

the suppliers and distributors have contracts for the usage of these electrical services, where they

offset the price to the paying customers. There are seven distribution companies operating twelve

licensed distribution areas where they have a statutory duty to connect any customers requiring

electricity within their area and to maintain the electricity supply to them.

ID Area Company

10 East England UK Power Networks

11 East Midlands Western Power Distribution

12 London UK Power Networks

13 North Wales, Merseyside

and Cheshire Scottish Power Energy Networks

14 West Midlands Western Power Distribution

15 North East England Northern Power Grid

16 North West England Electricity North West

17 North Scotland Scottish Hydro Electric Power Distribution

18 South Scotland Scottish Power Energy Networks

19 South East England UK Power Networks

20 Southern England Southern Electric Power Distribution

21 South Wales Western Power Distribution

22 South West England Western Power Distribution

23 Yorkshire Northern Power Grid

Figure 2.2: Map of DNOs © wiki


35

Supply Companies

In the UK there are over seventy licensed suppliers of electricity and gas that sell electricity to

customers. These companies are branded products of the 18 Energy companies that control the

supply throughout the UK. Some of these companies supply both gas and electricity. Customers can

switch their electricity supplier at any time which promotes competition between companies. The

distributers and supplies are sometimes owned by the same company who also may be involved in

renewable projects throughout the country or offshore. This monopoly allows larger companies to

offer lower electricity prices due to no DNOs electricity service tariff in their areas.

Other Electricity Industry Groups

ELEXON

In Great Britain Elexon administrates the wholesale of electricity balance and settlements. They

handle all of the Great Britain’s electricity users as well as the energy companies that generate and

supply the electricity. The Balancing and Settlement Code (BSC) documentation oversees these

arrangements.

ENERGYWATCH

This free service provides advice to customers on gas and electricity supplier issues that cannot be

solved directly with their suppliers. Its aim is to make sure customers are getting value for money.

OFGEM

OFGEM is the official independent regulating body for both electricity and gas industries with its

primary purpose to protect the customers of electricity and gas services. It does this by trying to

prevent industry monopolies taking place and ensuring competition between providers with prices

available.


36

Wholesale Market and Fuel Mix

The design of the electricity wholesale market is much like a typical commodity market. Those who

produce electricity sell it to suppliers who are the most important group as these are the contacts

the customers have with the energy industry. The selling of electricity between generators and

suppliers is done through bilateral contracts, over the counter trades and spot markets.

The inherent nature of electricity is an important issue since electricity cannot be stored in significant

quantities. To ensure a secure supply of electricity the amount being produced and the amount being

consumed on demand must equal at all times, in other words the system must balance. The

electricity is traded in 30-minute blocks which continue until an hour before the start of each block,

which is also known as the gate closure. Contracts on the amount of generation energy they agreed

to produce is recorded and if it’s not generated they have to pay an imbalance penalty to cover the

supply to the customers. The system operator which is the National grid has the responsibility of

ensuring supply equals demand continuously as through bilateral trading this could not be sustained

(Change, Department of Energy and Climate, 2010).

Investment in new technologies with relative low cost and low risk is supported by the government

to improve competition between generators. It is a requirement from energy regulator OFGEM that

customers are informed about the breakdown of how the electricity supplied to their homes has

been generated. With renewable obligations, a certain percentage of green energy is acquired or

significant penalties will arise.

NETA to BETTA – A Single Wholesale Electricity Market

Without looking into the whole evolution of the British electricity market throughout the last 50

years, we will skip forward to 27th

March 2001 when the New Electricity Trading Arrangement (NETA)

was introduced in England and Wales. This voluntary bilateral market and power exchange was a sign

of the government trying to reduce high electricity prices and reduce the concentration among

generators. ELEXON was the operator of NETA, where all licensed electricity companies would abide

by certain balancing and settlement codes. The majority of electricity traded under NETA was done

through OTC (cover-the-counter) market and power exchanges. A trend started to follow in the

coming years with generating and supply companies merging together and by 2005 the generation

sector was decentralised leaving more than 40 major generators of which there were six major

players dominating the British gas and electricity market (Cui, 2010).

Table 2.7: Percentage Distribution of Capacity of Major Players (end May 2005)

Company Capacity (% of British ESI total capacity)

British Energy 15%

RWE 12.30%

E.on UK 11.80%

Scottish & Southern

Energy 11.30%

Scottish Power 8%

EDF 6%


37

The introduction of the NETA system was extended to Scotland on the 1st

April 2005 to form the

current British Electricity Trading and Transmission Arrangement (BETTA). With the same principles

as the NETA, BETTA’s role is to facilitate the creation of a single, competitive electricity market but

covering the whole of Great Britain (GB). This involves a control of the GB system, applying common

rules and charging mechanisms for connecting to and using the transmission system and the most

important aspect, setting out balancing and settlement arrangements. The balancing market has

been developed to keep the electricity system in order so security and quality of supply is

maintained. In everyday life both demand and supply are subject to some variations that cause

imbalance of the system which is costly and is resolved by the system operator. This defect lets

BETTA have access to spinning or immediately available reserves, which would cost more on the

market. The electricity companies and traders enter the market buying and selling at the spot

market, by means of adjusting their supply electricity level to equal their bilateral contract volume.

In some cases a supplier may need to buy extra electricity to meet their current contract while a

generator may need to sell surplus electricity (a wind farm generator during time of high wind

speeds) to gain extra revenue. Due to this the main price and reverse price within the balancing

mechanism becomes very volatile.

Market Arrangement NETA/BETTA

There are four different sectors in the NETA/BETTA market, firstly, a forward and future market

which allow contracts for electricity to be negotiated (see Figure 2.3) over timescales ranging from

several years up to 24 hours ahead of the given half hour period. Usually power is traded through

long-term confidential contracts, meaning that only the trading quantity of electricity is disclosed and

not the price, ruling out market price. The second sector is the short term power exchanges, which is

between 1 to 24 hours before the electricity consumption. In this area contributors have the

opportunity to fine tune their contracts in bilateral deals which are price registered on the power

exchange. Thirdly there is a balancing mechanism market where the National Grid Company (NGC)

accepts offers and bids for electricity to balance to supply and demand. NGC is informed by

generators about the plants they are contracted to, and the output from the plants without the

contract prices declared, prior to the gate closure. Alternatively the retailers must state the amount

they are contracted to buy, which in turn should be the amount their customers should consume.

The concluding part is an imbalance settlement process, were payments between participants whose

contracted positions aren’t equivalent to their actual metered electricity production or consumption.

This area also settles the costs of balancing the system (National Grid Company).

The NGC take all responsibility for the security of the electricity under the current NETA/BETTA

arrangements, which diverts all liability away from brokers and speculators. This gives the NGC the

opportunity to buy and sell electricity close to real time to maintain energy balance and also consider

other operational constraints throughout the transmission grid, such as diverting large amounts of

electricity from northern regions to the demand areas in the southern part of GB.


38

Figure 2.3: Overview of market structure under NETA/BETTA © National Grid Company

Time

Gate Closure

1hr before

delivery

Balancing Mechanism

Balancing Arrangements

Generator, supplier and traders buy and

sell electricity as they wish

Spot bilateral market

(power exchange)

Trading Arrangements

Half hour

delivery

Imbalancing

settlement

24hr

before

delivery

Forward/

Future contract

market

Settlement of

cash flows

arising from

the balancing

process

NGC accepts

offers and

bids for

system and

energy

balancing

Notification of contract

volumes (to Settlement) and

Final Physical Notification to

NGC (as System Operator)


Energy generated may be over or under supplied

through bilateral contracts. Also suppliers may purchase more or less electricity through their

bilateral contracts than their cus

sold. Such circumstances are known as ‘imbalance’ which will be bought and sold from or to the

system. This balancing mechanism

sell electricity by increasing its generation or decreasing its consumption to the system. These

participants can also do the opposite

increasing consumption from the system. The process is kn

requires it to accept offers and bids in order to balance the system,

offered while accepting the highest bids. Within the cash

price (SBP) and also the system sell price (SSP) which are applied to imbalances are developed largely

as the weighted average price of these accepted for balancing the mechanism offers and bids

(National Grid Company).

metered

contracted

Electricity

Volume

(MWh)

Accept BM bid or offer volume

Bilateral Contract Volume

Figure 2.4

Cost appraisal of wind energy applying portfolio analysis

39

over or under supplied by generators than that which


ts than their customers require, with traders buying more or less than they have


system. This balancing mechanism allows electricity companies and also traders to accept offers t


opposite by trading to buy electricity from decreasing generation or

increasing consumption from the system. The process is known as ‘imbalance cash

requires it to accept offers and bids in order to balance the system, thus taking the lowest price being

while accepting the highest bids. Within the cash-out or imbalance prices, the system buy

d also the system sell price (SSP) which are applied to imbalances are developed largely


Imbalance Volume

imbalance price

(SSP)

Accept BM bid or offer volume

Balancing bid or

offer price

Bilateral Contract Volume

Bilateral contract

price

.4: Energy imbalance © National Grid Company

Cost appraisal of wind energy applying portfolio analysis

that which they have agreed


, with traders buying more or less than they have


allows electricity companies and also traders to accept offers to


decreasing generation or

own as ‘imbalance cash-out’. NGC role

taking the lowest price being

out or imbalance prices, the system buy

d also the system sell price (SSP) which are applied to imbalances are developed largely


imbalance price

Balancing bid or

offer price

Bilateral contract


40

2.3 Wind Energy in the UK

Electricity generation consents were not a particular problem until recently. The large privatised

electricity companies have been able to obtain consent for new gas-fired power stations without any

objection from the community or councils. However the same trend doesn’t seem to work for WTG

farms throughout the UK. The result has been considerable delays in application or rejection. Not

everyone views wind-farm refusals as appalling; opponents to these structures would say that some

proposals would have damaged the landscape to a disproportionate extent thus requiring it to be

rejected.

On the 30th

of June 2011, 5,560MW of wind capacity was operational throughout the UK with a

further 3,615MW under construction. On top of these figures 5,437MW have being approved but are

awaiting construction. Between July 2010 and June 2011 an additional 44 projects containing

985MW will become active across the UK. This figure is an increase of nearly 20 percent from the

previous figures between July 2009 and June 2010 which saw 794MW generated from 37 schemes.

The deployment of wind farms was positive for the calendar year of 2011 with a region of 980MW

expected to be online with 550MW coming from the onshore industry while 333.6MW is expected

from offshore schemes (renewableUK, October 2011).

Decision Making Review

Each council area is covered by a local development plan, which sets out locations where most new

WTG developments could be developed and the policies that will guide the decision-making on

planning applications (renewableUK, October 2011). Developers applying for planning permission to

local planning authorities will be required to submit applications to district councils, county councils

or unitary authorities. There is then a planning consultation which allows people and organisations to

make concerns heard. There is a standard list of bodies that are notified about the planning

application. The planning officer makes a report where he/she will recommend approving or refusing

the planning application. The matter is then put to the Councillors on the planning committee which

is now known as the Development and Control Committee who take a decision. If the resultant

decision is refusal, the disappointed applicant has the right to appeal to the Secretary of State, in

practice to a planning inspector who will decide if the applicant is in line with Government guidance.

This consequence makes local planning authorities seriously consider planning applications prior to

rejection because they risk not only having their decision overturned on appeal but also the costs

awarded against them if it ruled that an unreasonable decision was given. Developers and

occasionally landscape protection groups have asked for a public inquiry, which involves the

government to ‘call in’ an application which will take the decision.


41

Offshore Onshore

NO

NO YES

YES NO NO

YES NO

YES NO

Table 2.8 United Kingom - Licensing Process

PROCEED TO IMPLEMENTATION STAGE

PROJECT REFUSED

Developer must reconsider the

proposed application providing

major changes or abandon the

site

DECISION

Scotland

Northern Ireland

At any point in the process

above, the secretary of state

with responsibility for local

government and planning issues

(for projects in England, Wales

and Northern Ireland), or the

Scottish Executive (for projects in

Scotland) can 'Call in' the

planning application to be

YES

DECISION

National consent decision The Crown Estate Consent and Planning

Wind farm projects above the

50MW threshold in England,

Scotland and Wales are

automatically referred to the

relevant national authority for

a decision under Section 36 of

the Electricity Act 1989. The

Department of Business,

Enterprise and Regulatory

Reform, in consultation with

Local Planning Authorities

deals with projects in England

and Wales and Scottish

Executive with those in

Scotland.

YES

DECISION Northern Ireland Planning

Appeals Commission

Projects 'called in'

England & Wales

Planning appeal

The Planning Inspectorate

Appeal will be heard by the

relevant national body

Scottish Executive Inquiry

Reporters Unit

DECISION

DECISION

The Crown Estate (CE)

who are the landlord

of the seabed. A lease

can be signed

between the Crown

Estate and the wind

farm developer only

after all the necessary

statutory consents for

the development

have been obtained

from the relevant

Government

Departments.

England, Scotland And Wales Nothern Ireland

OffshoreOnshore

Projects over 50 MW All projects

Local Planning Decisions

For projects under 50MW, local

planning authority (LPA) will

handle the planning application

for a wind power development.

For larger projects, this will be

accompanied by an

Environmental Statement (ES).

All wind developments require

planning permission from the

Department of Environment

v


42

Even though the largest number of onshore schemes have been submitted to councils a new trend is

being set with the average size of new scheme in England falling to just 7MW, compared with 23MW

in Scotland. Onshore wind capacity being approved in planning rates has continued to drop for the

third year in a row, with the approved capacity falling from 1.564MW in 2007/08 to 1,114MW in

2010/11 which represents 72 projects. Both England and Scotland saw its overall approval rate the

lowest since 2006/07.

Approval Rates

In Northern Ireland the Department of Environment deals with all applications. As shown in Table 4.1

under Section 36 of the Electricity Act, all electricity generation schemes over 50MW are decided by

the Secretary of State for Energy in England and Wales and by the Scottish Government Ministers in

Scotland. There have been four schemes with a capacity of 381MW submitted from June 2010 to July

2011 with all four gaining approval. Onshore approval rates at local authority have declined further

the last number of years with England reaching a critically low level. In England, smaller schemes are

receiving more favourable decisions compared with larger schemes rejected. From July 2010 to July

2011 none of the three schemes between 20-50MW were approved, with projects between 5-20MW

achieving a 43 percent approval rate. The most successful projects were projects below 5MW, with

79 percent of capacity of 2-5MW approved and 83 percent granted for schemes below 2MW. The

average decision times currently standing in the UK is 52 months for projects in the 50MW bracket

and above determined by the Secretary of State, just over 38 months for wind farm schemes at

appeal level and 15.5 months for projects at the local level.

Scotland has surpassed other UK countries with approved onshore planning applications since 2004

as shown in Table 4.3. 2008 was the most significant year so far with 1293.45MW approved

throughout Scotland compared with 345.18MW and 104.90MW granted in England and Northern

Ireland respectively. Objections and slow planning process (BBC News, 2011) have prevented a large

portion of wind farms being built in Wales to date, with only 36.25MW granted in the year previously

mentioned. While Scotland has been the leader in approved applications it has also had the highest

number of refusals from 2004 to 2011. The main explanation for this is that in 2008 1101.70MW was

refused. The latest trend has shown however England refusing more applications than Scotland since

2008.

Table 2.9: UK Submission Statistics Onshore (MW)

Year England Scotland Northern

Ireland Wales

2004 27 385.96 35 2272.10 11 158.05 6 63.95

2005 27 470.53 48 1671.90 17 318.20 2 23.90

2006 47 629.05 41 962.00 19 329.05 16 270.05

2007 48 430.76 49 966.20 16 309.40 8 213.40

2008 69 685.90 48 823.15 14 150.35 12 395.45

2009 64 854.88 57 1446.60 8 79.03 8 614.80

2010 69 613.69 63 1124.21 3 85.00 8 242.90

2011 80 562.13 109 1691.09 7 72.50 12 221.55

Total 431 4632.90 450 10957.25 95 1501.58 72 2046.00


43

Table 2.10: UK Approval Statistics Onshore (MW)


Ireland Wales

2004 15 153.20 13 449.43 1 16.90 2 15.60

2005 20 251.31 15 390.10 3 22.90 2 7.25

2006 13 91.35 19 679.10 5 90.50 1 15.60

2007 20 240.85 26 643.00 9 153.40 8 108.00

2008 27 345.18 34 1293.45 7 104.90 4 36.25

2009 35 428.75 47 603.92 7 121.80 8 169.60

2010 37 420.83 28 723.50 13 175.90 2 37.60

2011 38 274.85 36 719.96 6 84.40 4 27.60

Total 205 2206.32 218 5502.46 51 770.70 31 417.50

Table 2.11: UK Refusal Statistics Onshore (MW)


Ireland Wales

2004 16 134.30 5 61.75 - - 7 83.60

2005 8 116.50 18 517.75 - - 3 40.20

2006 17 273.50 11 351.90 - - 3 43.50

2007 26 257.78 18 553.30 1 9.10 3 48.40

2008 34 364.50 13 1101.70 - - 4 96.00

2009 39 358.60 21 298.20 5 93.85 2 8.90

2010 50 727.40 26 402.60 2 42.23 4 65.40

2011 51 529.43 26 319.91 1 0.15 2 38.45

Total 241 2762.01 138 3607.11 9 145.33 28 424.45

Table 2.12: UK Built Statistics Onshore (MW)


Ireland Wales

2004 4 18.56 5 152.73 - - 2 9.85

2005 9 37.84 7 214.85 4 37.29 2 79.75

2006 8 103.20 9 380.75 - - 4 47.55

2007 9 84.40 15 236.35 4 38.50 - -

2008 20 192.45 12 266.50 5 69.70 2 15.60

2009 7 145.75 23 535.78 4 79.00 5 51.60

2010 12 98.75 22 395.80 2 35.00 2 9.70

2011 17 61.21 14 383.15 3 62.60 4 36.30

Total 86 742.16 107 2565.91 22 322.09 21 250.35


44

Renewable Obligation Certificates and Feed in Tariff

Renewable Obligation (RO) is the main support mechanism to enable renewable electricity schemes

to enter into the UK market. In 2002 RO came into effect throughout England, Scotland and Wales

while NI introduced it in 2005. This obligation forces the UK electricity suppliers to source a

proportion of their electricity supply from renewable resources for their customers. Renewables

Obligation Certificates (ROCs) are green certificates accredited by the Authority to renewable

generating stations that generate adequate renewable electricity. Different technologies receive

different number of ROCs and operators can then trade the ROCs with other parties who are unable

to meet their obligation quota. A ‘band’ RO presently exists to promote different renewable schemes

for example, 2 ROCs for offshore wind farms while only 0.9 ROCs onshore per MWh produced (See

Figure 2.13).

Buy out penalties are the main driving force behind ROCs with electricity suppliers needing to obtain

the certificates to avoid paying penalties. Such ‘buy out’ fines are payable for missing the required

number of ROCs that they are supposed to hold to achieve the obligation amount of renewable

electricity in their system. An extra incentive to invest in renewable energy is that the penalties

obtained are recycled to the holders of ROCs. Smaller scale generation is mainly supported by Feed-

In Tariff schemes (FITs) which are below the 5MW bracket. Presently the FITs are only present in

England, Scotland and Wales with NI using a more straightforward ROCs approach (See Figure 2.14).

Table 2.13: Renewables Obligation Certificates

England, Scotland and Wales

Onshore Wind 0.9

Offshore Wind 2

Northern Ireland

Onshore Wind 4 < 250kW 1>250kW 0.9 > 5MW

Offshore Wind 2

Table 2.14: Feed in Tariffs

Scale Import Tariffs (p/kWhr) Years

< 1.5kW 36.20 20

>1.5 - 15kW 28.00 20

>15 - 100kW 25.30 20

>100 - 500kW 19.70 20

>500kW - 1.5MW 9.90 20

>1.5MW - 5MW 4.70 20


45

3.0 Methodology

To meet the electricity energy needs of the customers for the future, certain targets and electricity

resource planning is required. The introduction of generation planning deals with future decisions

that have to be made with a degree of uncertainty. The main factors of these uncertainties are

electricity demand, fuel prices, investment costs, unit operation, regulatory developments and

government initiatives such as the ROCs. To introduce more wind energy into the system basic

functions should be applied including energy and demand forecasting.

The planning process is an elongated procedure spanning across years, so forecasting of the

electricity demands of the future needs to be considered. Closure of some older nuclear stations and

the decline of gas resource initiate action from the utilities to add or reconsider submitting refused

planning applications for generators. Due to this long time process from getting a granted planning

application, decisions must to compiled 2 to 10 years in advance for large new power plants.

Resource mix is important since it requires least-cost planning assessment. Load and energy

demands are adjusted so it can integrate with the existing energy generators. These resource

additions are used to construct expansion strategies which can prolong existing resources but have

to be examined based on fixed and variable costs. The approach on a year to year basis is an optimal

strategy or portfolio to meet the load demand forecasted. The selected portfolio will include a

financial analysis which will include the impact on the revised resource mix for the utilities finances.

The financial analysis for utility companies on a renewable investment decision would look at

earnings and tax reduction through ROCs. Least-cost planning has different methods a few more

advance than others; however one of the more utilized methods is the level bus-bar analysis

(Beltran, 2009).

3.1 LCG- Levelised Bus-Bar Cost

Levelised bus-bar cost involves calculating the LCG in £/MWh produced by different types of power

generator. There are three main components to consider for levelised costs. These are the capital

costs for bringing the generator online, on-going fixed costs to keep the plant available to generate

(commonly known as fuel costs) and variable costs of operation which involves O&M expenditure.

The calculation method involves comparing the economic comparison of different generators to

determine which is more financially beneficial. The presented data for these generating costs are

taken from UK Electricity generation costs update published in June 2010 by Mott MacDonald

Engineering and Development Consultancy (Mott MacDonald, 2010). All necessary information, types

of technology, investment schedule, average load factor, economic life and other significant data is

presented in Table 3.1 and 3.2 for the LCG calculations and appendix 2. The discount factor is taken

as 12 percent.

The importance of Portfolio analysis is comparing existing assets with new generation technologies in

the market such as new gas turbines may have lower electricity generation costs in the form of lower

O&M requirements and improved efficiencies compared to when it was first manufactured. Most

generators capital costs are self explanatory apart from Offshore wind which is 25km from the shore

line (in 20m of water using monopiles) and Offshore wind Round 3 is 75km from the shore in a water

depth of 50 meters. The figures do not take into account balancing requirements such as ROCs or

capital grants. One difficult area to categorise is decommissioning costs, especially when considering

nuclear. Throughout these calculations a fixed decommissioning charges per MWh for a nuclear plant

is calculated into its operating life value.


46

Table 3.1 Technology Input Assumptions

Gas

CCGT

CCGT

with CCS

Coal

Plant

Coal with

CCS IGCC

Gross Power Output (MW) 830 830 1,600 1,600 870

Gross efficiency (%) 56.0 47.5 43.9 35.1 43.9

Load factor (%) 90.0 90.0 90.0 90.0 90.0

Discount rate (%) 12 12 12 12 12

Project lifetime (years) 25 27 36 36 25

Construction time(years) 2.8 4.2 4.8 5.4 4.8

Total Capital cost (£/kW) 808.9 1,372.0 1,998.1 3,072.5 2,669.3

Operation (£m/yr) 36.8 79.0 140.5 284.0 70.7

O&M cost (£m/yr) 26.6 45.0 106.9 163.9 55.0

Table 3.2 Technology Input Assumptions

IGCC

with CCS

Onshore

Wind

Offshore

wind

Offshore

wind

Round 3

Nuclear

Gross Power Output (MW) 870 100 200 400 1,600

Gross efficiency (%) 35.1 100.0 100.0 100.0 100.0

Load factor (%) 90.0 28.0 39.0 39.0 90.0

Discount rate (%) 12 12 12 12 12

Project lifetime (years) 25 22 22 22 60

Construction time(years) 4.8 2 2 2 6

Total Capital cost (£/kW) 3,186.5 1,701.3 3,110.0 3,625.0 3,743.8

Operation (£m/yr) 154.0 3.8 22.8 56.7 146.6

O&M cost (£m/yr) 87.8 1.6 16.0 39.1 101.8


47

3.2 Modern Portfolio Theory Basics

Portfolio selection is generally based on mean-variance portfolio theory which enables the formation

of minimum-variance portfolio for any given level of expected mean return. Proficient portfolios rely

on minimising the associated risk, so for more accurate readings results are measured by the

standard deviation (SD) of periodic returns which is between 2-5 years. The SD is basically the square

root of the variance.

Investments in new generators can be unpredictable and perilous, but while utilising co-movement

or covariance of returns from the individual assets it can help protect the portfolio while creating

higher return with little or no additional risk. To illustrate the MPT effect in the case of two financial

assets, consider an imaginary portfolio (Ω) with set parameters. A portfolio consisting entirely of

asset A has an expected return of 6 percent fixed with a SD of its historic returns of 0.10. Asset B is

more risky but has a higher expected return of 15 percent with a SD of 0.12. From Figure 3.1 taking a

portfolio of 100 percent of asset A and introducing asset B into the mix we can observe that the

portfolio risk starts to decline as well as the expected return until the minimum variance portfolio is

reached – Portfolio 7 (see Table 3.5). Taking risk and reward into account it makes little sense to

invest solely in asset A since combinations of A and B will produce better results. An investor may

choose any point along the curve but it must lie between portfolios 1 to 7. The rest of the points

between portfolios 7 to 11 cannot be an optimal portfolio because for the risk σΩ along this portion

of the curve, a higher expected return can be obtained by choosing a point between portfolios 7 to 1.

This portion of the curve is known as the efficient frontier or the envelope (Awerbuch, 2003).

Table 3.3: Two-Asset Portfolio Problem

Mean Sigma /SD

Asset A (Coal) 6% 0.10

Asset B (Gas) 15% 0.12

Correlation 0.2

Covariance 0.0024

Table 3.4: One Portfolio

% of Asset 1 100%

Mean 6.000%

Variance σΩ2 0.01

Sigma σΩ 0.1


48

Table 3.5: Data of Portfolio Return as Function of Percentage of Asset 1 (Coal)

% of 1 Sigma (p) SD Mean (p) Variance σΩ2

0.1 6.000%

Portfolio 1 0% 12.00% 15.00% 0.014

Portfolio 2 10% 11.04% 14.10% 0.012

Portfolio 3 20% 10.19% 13.20% 0.010

Portfolio 4 30% 9.47% 12.30% 0.009

Portfolio 5 40% 8.91% 11.40% 0.008

Portfolio 6 50% 8.54% 10.50% 0.007

Portfolio 7 60% 8.40% 9.60% 0.007

Portfolio 8 70% 8.49% 8.70% 0.007

Portfolio 9 80% 8.80% 7.80% 0.008

Portfolio 10 90% 9.31% 6.90% 0.009

Portfolio 11 100% 10.00% 6.00% 0.010

Figure 3.1: Risk and Return for Portfolio of 2 Assets.

Portfolio 1

Gas 100%

Portfolio 7

Portfolio 11

Coal 100%

5.00%

7.00%

9.00%

11.00%

13.00%

15.00%

17.00%

7.00% 8.00% 9.00% 10.00% 11.00% 12.00%

Po

rtfo

lio

ex

pe

cte

d r

etu

rn µ

Portfolio Risk σ


49

4.0 Results

4.1 LCG Results

Based on the assumptions in the Mott Macdonald UK generation costs (Mott MacDonald, 2010) and

the discount rate chosen, the LCG represents a minimum breakeven tariff expressed in £/MWh for

each plant as shown in 4.1

Table 4.1: Results for Generators

NPVEG (MWh) TOTC (£) LCG (£/MWh)

Gas CCGT 39,573.01 1,199,528,903.98 30.31

Gas CCGT with CCS 31,572.12 2,118,244,966.89 67.09

Coal Plant 64,316.24 5,570,393,633.34 86.61

Coal with CCS 57,242.00 9,244,637,603.50 161.50

IGCC 32,310.06 3,785,822,497.59 117.17

IGCC with CCS 32,310.06 4,908,309,159.56 151.91

Onshore Wind 5,216.22 240,992,789.12 46.20

Offshore Wind 10,432.45 994,555,715.37 95.33

Offshore Wind R3 20,864.90 2,350,354,174.75 112.65

Nuclear 59,044.39 10,389,006,431.08 175.95

Based on the results the LCG for Gas CCGT should be considered as the primary energy source. This

result strengthens the UK’s position on changing from more coal based energy to gas. Onshore wind

has a 46.20 LCG (£/MWh) which proves how important the technology is compared with building

new nuclear plants which has a 175.95 LCG (£/MWh). As mentioned earlier decommissioning of a

nuclear plant makes the technology inefficient but still will be considered due to energy security.

With these LCG results the expected return can be calculated considering the risk of the asset by

calculating the Standard deviation (SD). From the APX Power UK Spot results obtained over a period

of two years £40 MW/h is taken as the income for generation (APX, 2012). With this income to the

LCG of the generators most technologies are losing money every year apart from Gas CCGT £9.69

MWh. The most risk taken by technologies is nuclear and offshore wind, as shown in graph 4.1.


50

Graph 4.1: Technologies Expected Return from LCG and Risk (Please note values of the x-axis at 0).

The gas era is understandable with these results but as noted in an earlier chapter the resources in

UK gas fields has peaked where imports will outshine production in the near future. In a world with

carbon constraints and rising fuel prices the energy security of the UK government needs to be

considered. Prices can be erratic when importing so measures to reduce this dilemma have been

taken by the UK government by the ROCs. Penalties for not having ROCs is known as buy price.

Currently this is set at £38.69 for 2011/12. Price received for ROCs can be lower if there is an

agreement between a generator & supplier. For the purpose of this exercise £38.69 is taken as the

ROC benchmark. This income makes generators such as Wind, onshore (0.9 ROC) and offshore (2

ROC) more feasible.

Table 4.2: Results for Generators with ROCs

LCG

(£/MWh)

Income

from

generation

£/MWh

Income

from

ROC

£/MWh

expected

return

Gas CCGT 30.31 40 9.69

Gas CCGT with CCS 67.09 40 -27.09

Coal Plant 86.61 40 -46.61

Coal with CCS 161.50 40 -121.50

IGCC 117.17 40 -77.17

IGCC with CCS 151.91 40 -111.91

Onshore Wind 46.20 40 34.821 28.62

Offshore Wind 95.33 40 77.380 22.05

Offshore Wind R3 112.65 40 77.380 4.73

Nuclear 175.95 40

-135.95

Gas CCGTGas CCGTGas CCGTGas CCGTGas CCGTGas CCGTGas CCGTGas CCGTGas CCGTGas CCGTGas CCGT

CCGT with CCSCCGT with CCSCCGT with CCSCCGT with CCSCCGT with CCSCCGT with CCSCCGT with CCSCCGT with CCSCCGT with CCSCCGT with CCSCCGT with CCS

Coal PlantCoal PlantCoal PlantCoal PlantCoal PlantCoal PlantCoal PlantCoal PlantCoal PlantCoal PlantCoal Plant

Coal with CCSCoal with CCSCoal with CCSCoal with CCSCoal with CCSCoal with CCSCoal with CCSCoal with CCSCoal with CCSCoal with CCSCoal with CCS

IGCCIGCCIGCCIGCCIGCCIGCCIGCCIGCCIGCCIGCCIGCC

IGCC with CCSIGCC with CCSIGCC with CCSIGCC with CCSIGCC with CCSIGCC with CCSIGCC with CCSIGCC with CCSIGCC with CCSIGCC with CCSIGCC with CCS

Offshore WindOffshore WindOffshore WindOffshore WindOffshore WindOffshore WindOffshore WindOffshore WindOffshore WindOffshore WindOffshore Wind

Offshore Wind Round 3Offshore Wind Round 3Offshore Wind Round 3Offshore Wind Round 3Offshore Wind Round 3Offshore Wind Round 3Offshore Wind Round 3Offshore Wind Round 3Offshore Wind Round 3Offshore Wind Round 3Offshore Wind Round 3

NuclearNuclearNuclearNuclearNuclearNuclearNuclearNuclearNuclearNuclearNuclear

Onshore WindOnshore WindOnshore WindOnshore WindOnshore WindOnshore WindOnshore WindOnshore WindOnshore WindOnshore WindOnshore Wind

-150.00

-130.00

-110.00

-90.00

-70.00

-50.00

-30.00

-10.00

10.00

0.00% 15.00% 30.00% 45.00% 60.00% 75.00% 90.00%

ex

pe

cte

d r

etu

rn µ

Risk σ


51

Graph 4.2: Technologies Expected Return from LCG and Risk Including ROCs

(Please note values of the x-axis at 0)

Gas CCGT clearly is the most dominant technology but onshore wind technology proves to have a

higher expected return when ROCs are included. This shows why developers throughout the country

are investing in onshore wind even taking into account all the problems with planning and grid

connections. Offshore wind requires more risk and slightly less expected return than onshore, but

still can be profitable with the 2 ROCs per MWh received.

In this graph no other capital grants have been considered for CCGT, IGCC or Coal with CCS. This has a

major bearing on showing the importance of wind technology in the energy sector. Subsides for

other available technologies may prove beneficial and prove that CCGT, IGCC or Coal with CCS is

important to future UK energy security but due to time restrictions they were not investigated.

Gas CCGTGas CCGTGas CCGTGas CCGTGas CCGTGas CCGTGas CCGTGas CCGTGas CCGTGas CCGTGas CCGT

CCGT with CCSCCGT with CCSCCGT with CCSCCGT with CCSCCGT with CCSCCGT with CCSCCGT with CCSCCGT with CCSCCGT with CCSCCGT with CCSCCGT with CCS

Coal PlantCoal PlantCoal PlantCoal PlantCoal PlantCoal PlantCoal PlantCoal PlantCoal PlantCoal PlantCoal Plant

Coal with CCSCoal with CCSCoal with CCSCoal with CCSCoal with CCSCoal with CCSCoal with CCSCoal with CCSCoal with CCSCoal with CCSCoal with CCS

IGCCIGCCIGCCIGCCIGCCIGCCIGCCIGCCIGCCIGCCIGCC

IGCC with CCSIGCC with CCSIGCC with CCSIGCC with CCSIGCC with CCSIGCC with CCSIGCC with CCSIGCC with CCSIGCC with CCSIGCC with CCSIGCC with CCS

Offshore WindOffshore WindOffshore WindOffshore WindOffshore WindOffshore WindOffshore WindOffshore WindOffshore WindOffshore WindOffshore Wind

Offshore Wind Round 3Offshore Wind Round 3Offshore Wind Round 3Offshore Wind Round 3Offshore Wind Round 3Offshore Wind Round 3Offshore Wind Round 3Offshore Wind Round 3Offshore Wind Round 3Offshore Wind Round 3Offshore Wind Round 3

NuclearNuclearNuclearNuclearNuclearNuclearNuclearNuclearNuclearNuclearNuclear

Onshore WindOnshore WindOnshore WindOnshore WindOnshore WindOnshore WindOnshore WindOnshore WindOnshore WindOnshore WindOnshore Wind

-150.00

-130.00

-110.00

-90.00

-70.00

-50.00

-30.00

-10.00

10.00

30.00

50.00

0.00% 15.00% 30.00% 45.00% 60.00% 75.00% 90.00%

exp

ect

ed

re

turn

µ

Risk σ


52

4.2 Modern Portfolio Theory Results

Multiple-Asset Portfolio

With the UK government pressing ahead with the largest nuclear programme for a generation, eight

new sites have been proposed. Ministers say the new reactors will maintain electricity supplies and

cut greenhouse gas emissions as the old ones are shut down. The future of nuclear power was has a

lot of opposition after the Japanese earthquake and tsunami rocked the reactors at Fukushima,

causing radioactivity to leak from the plant. With energy security for the future so important,

calculations involving 3 wind energy categories and nuclear is calculated. Offshore Wind R3 is

explained in 3.1 LCG- Levelised Bus-Bar Cost.

Table 4.3: Individual Assets

Return (µ) (£/MWh) SD σ µ/SD

Onshore Wind 28.62 18.06% 158.44

Offshore Wind 22.05 52.00% 42.40

Offshore Wind R3 4.73 52.75% 8.97

Nuclear -135.95 80.66% -168.56

Also calculated is the variance covariance matrix (See Table 4.4). Along the diagonal is the variance of

these assets and on the off diagonal is the covariance. Variance is how spread out returns are,

showing how risk an investment is while covariance is a measure of how much two random variables

change together (i.e. the correlation between two or more investment in a portfolio).

Table 4.4: Variance-Covariance Matrix - Capital Cost

Onshore Wind Offshore wind Offshore wind R3 Nuclear

Onshore Wind 0.033 0.062 0.063 0.097

Offshore wind 0.062 0.270 0.183 0.278

Offshore wind R3 0.063 0.183 0.278 0.282

Nuclear 0.097 0.278 0.282 0.651

Table 4.5: Portfolios

Equal Wt. Max Ret Max Sharpe Ratio

Constraining Variable None AT σ <= None

Value of Constraint N/a 18.064% N/A

Portfolio Weights

Onshore Wind 25.00% 100.00% 84.53%

Offshore Wind 25.00% 0.00% 0.00%

Offshore Wind R3 25.00% 0.00% 8.56%

Nuclear 25.00% 0.00% 6.92%

∑w 100% 100% 100%

µ (£/MWh) -20.14 28.62 15.20

σp 44.47% 18.06% 22.87%

µ/SD -45.28 158.44 66.44


53

The first calculation shows an equal weighted portfolio of 25 percent which shows the portfolio

losing money with an expected return of £-20.14 MWh. To maximise the return, the investment

should contain 100 percent onshore wind giving an expected return of £28.62 MWh. To maximise

the expected return for a more diverse portfolio with a highest possible sharpe ratio (SR) as defined

in chapter 2.0, the largest amount of weight used is 84.53 percent in onshore wind.

Applying Portfolio Diversity to Existing Statistics

Using the formulas we can find out how the energy consumption throughout the UK has changed in

the last forty years. From an earlier chapter we noticed that coal was the driving force in electricity

generation up until the early 80s when it was phased out, with nuclear increasing its capacity.

From the data received from DUKES generators were classified into different categories. The

combined cycle gas turbines (CCGTs) generating 46 percent in 2010 along with Nuclear have their

own section while everything else is categorised into conventional thermal and non-thermal

renewable (see Table 4.6).

Table 4.6: Categorising the Technologies

Gas CCGT CCGT

Gas CCGT with CCS Conventional thermal

Coal Plant Conventional thermal

Coal with CCS Conventional thermal

IGCC Conventional thermal

IGCC with CCS Conventional thermal

Onshore Wind Non-thermal renewables

Offshore Wind Non-thermal renewables

Offshore Wind R3 Non-thermal renewables

Nuclear Nuclear

With Conventional thermal power stations in 1970 creating nearly 88 percent of the gross electricity

it has being on a rapid decline since. The discovery of the northern gas field has changed the way

electricity has being produced in the UK. It wasn’t until 1990 it started to appear on the energy chart

and since then its volume has increased. The production of natural gas however has been in decline

since the turn of the decade, with imports looking to outstrip production. Relatively speaking the gas

production has fallen off at a rate of about 6 percent per year which diminishes the UK’s energy

security. From Table 4.7 we can also notice nuclear share declined at the end of 2000 decade and

stands at 15 percent in 2010. This is due to outages for repairs and maintenance of old nuclear

plants.


54

Table 4.7: Electricity Supplied GWh and Percentage

Non- thermal

renewables Nuclear CCGT

Conventional

thermal Total

1970 (GWh) 5,647 22,805 0 203,171 231,623

1970 (%) 2.44% 9.85% 0.00% 87.72% 100.00%

1980 (GWh) 5,094 32,291 0 228,927 266,312

1980 (%) 1.91% 12.13% 0.00% 85.96% 100.00%

1990 (GWh) 7,082 58,664 280 234,101 300,128

1990 (%) 2.36% 19.55% 0.09% 78.00% 100.00%

2000 (GWh) 8,609 78,334 126,428 147,394 360,765

2000 (%) 2.39% 21.71% 35.04% 40.86% 100.00%

2010 (GWh) 8,982 56,475 167,500 132,367 365,324

2010 (%) 2.46% 15.46% 45.85% 36.23% 100.00%

Table 4.8: Variance-Covariance Matrix - Capital Cost

Gas

CCGT

Conventional

thermal

Non-thermal

renewables Nuclear

Gas CCGT 0.0054 0.0128 0.0170 0.0394

Conventional thermal 0.0128 0.0775 0.0623 0.1420

Non-thermal renewables 0.0170 0.0623 0.1515 0.1878

Nuclear 0.0394 0.1420 0.1878 0.6505

For the purpose of the calculation of the expected return of these four assets an average LCG was

obtained for conventional thermal and non-thermal renewables (See Table 4.9). Non-thermal

renewables didn’t consider offshore round 3 into the equation since the 50km offshore and 50 meter

water depth is something further into the future. Its new LCG and ROCs using onshore and offshore

was taken as £70.77 MWh and £56.10 MWh respectively. Using the same process from the LCG for

calculating the expected return of portfolio diversity, £40 MW/h is taken as the income for

generation. A new variance-covariance matrix was calculated as shown in Table 4.8.

Table 4.9: Individual Assets

Return (µ)

(£/MWh) SD σ µ/SD

Gas CCGT 9.69 7.33% 132.22

Conventional thermal -76.86 27.19% -282.63

Non-thermal renewables 25.33 35.03% 72.32

Nuclear -135.95 80.66% -168.56


55

With most electricity generators losing money especially conventional thermal we can understand

why the UK government started to phase out coal plants and look at alternative energy such as gas.

The expected return even though still in the negative has nearly halved since 1970 with a more

diverse portfolio even though Gas CCGT and Conventional thermal still produces over 80 percent of

energy generated. Its sharpe ratio has also improved from -261.40 to -185.77 (See Table 4.10).


1970 1980 1990 2000 2010

Constraining Variable None None None None None

Value of Constraint N/a N/A N/A N/A N/A

Portfolio Weights

Gas CCGT 0.00% 0.00% 0.09% 35.04% 45.85%

Conventional thermal 87.72% 85.96% 78.00% 40.86% 36.23%

Non-thermal renewables 2.44% 1.91% 2.36% 2.39% 2.46%

Nuclear 9.85% 12.13% 19.55% 21.71% 15.46%

∑w 100% 100% 100% 100% 100%

µ (£/MWh) -80.18 -82.07 -85.92 -56.92 -43.80

σp 30.67% 31.53% 34.56% 28.75% 23.58%

µ/SD -261.40 -260.33 -248.62 -198.02 -185.77

The same concept was used to look at the 4572.57GW of refused wind and adding additional wind in

blocks of 10GW looking at the outcome of the expected return and the sharpe ratio (See Table 4.11

and Table 4.12). As before the offset energy is taken from the nuclear production. Adding the

refused wind shows a modest 1.27 percent increase in non thermal renewable whereas adding wind

in blocks of 10GW shows non thermal renewable percentage rising to over 10 percent of the overall

production of the 2010 statistics (See Figure 4.12).


56

Table 4.11: Electricity Supplied Analysis Adding WTG to 2010 Production

Non- thermal

renewables Nuclear CCGT Conventional thermal Total

2010 (GWh) 8,982 56,475 167,500 132,367 365,324

4572.57 GW Refused

Wind added 13,555 51,902

% 3.71% 14.21% 45.85% 36.23% 100.00%

2010 (GWh) 8,982 56,475 167,500 132,367 365,324

10,000 10,000

10 GW Wind added 18,982 46,475

% 5.20% 12.72% 45.85% 36.23% 100.00%

2010 (GWh) 8,982 56,475 167,500 132,367 365,324

20,000 20,000

20 GW Wind added 28,982 36,475

% 7.93% 9.98% 45.85% 36.23% 100.00%

2010 (GWh) 8,982 56,475 167,500 132,367 365,324

30,000 30,000

30 GW Wind added 38,982 26,475

% 10.67% 7.25% 45.85% 36.23% 100.00%

Even with such an increase in wind with 30GW added, negative results are still achieved.

Conventional thermal and nuclear producing nearly 50 percent and having a high negative LCG steers

the result into non profitable production. The positive outlook from the results is the standard

deviation and sharpe ratio improving.


2010 Rejected

Wind

2010 10GW

Wind added

2010 20GW

Wind added

2010 30GW Wind

added

Constraining Variable None None None None

Value of Constraint N/A N/A N/A N/A

Portfolio Weights

Gas CCGT 45.85% 45.85% 45.85% 45.85%

Conventional thermal 36.23% 36.23% 36.23% 36.23%

Non-thermal

renewables 3.71% 5.20% 7.93% 10.67%

Nuclear 14.21% 12.72% 9.98% 7.25%

∑w 100% 100% 100% 100%

µ (£/MWh) -41.78 -39.38 -34.97 -30.55

σp 22.99% 22.32% 21.13% 20.04%

µ/SD -181.72 -176.49 -165.49 -152.51


57

Exercise Portfolio Theory on Current Energy Mix

Now the 2010 portfolio discussed at the end of the previous section will be further investigated. As

previously discussed, MPT analysis looks at the change from a risk-return asset to a more cost-risk

efficient frontier asset to create an appropriate framework for electricity generation for the future.

From the model presented there exists an infinite number of portfolio choices and the created

version mainly focuses on finding the optimal one to construct the efficient frontier. Figure 4.1 and

Table 4.18 displays the efficient frontier looking at the existing energy generation in 2010 to a more

renewable driven mix with Gas CCGT and wind energy controlling 90 percent of the electricity

generation.

Table 4.13: Return on Assets

Table 4.14: Percentage of Assets

Return (µ) (£/MWh)

2010 Energy

consumption

(Portfolio 1)

New

Portfolio mix

(Portfolio 2)

Gas CCGT 9,69

Gas CCGT 45,85% 40,00%

Conventional

thermal -76,86

Conventional

thermal 36,23% 10,00%

Non-thermal

renewables 25,33

Non-thermal

renewables 2,46% 50,00%

Nuclear -135,95

Nuclear 15,46% 0,00%

Table 4.15: Two-Asset Mix

Table 4.16: Offsetting Portfolio 1

Return (µ)

(£/MWh) Variance

Sample portfolio calculation

Port1 -43.80 0.056

% of port 1 100%

Port2 8.86 0.054

% of port 2 0%

Cov(1,2) 0.04

Return (µ)

(£/MWh) -43.80

Variance 0.055586434

Sigma/SD 23.58%


58

Table 4.17: Data Percentage of Portfolio 1

sigma Return (µ) (£/MWh)

% port1 23.58% -43.80

0% 23.14% 8.86

5% 22.92% 6.22

10% 22.72% 3.59

15% 22.55% 0.96

20% 22.40% -1.67

25% 22.28% -4.31

30% 22.18% -6.94

35% 22.11% -9.57

40% 22.06% -12.21

45% 22.05% -14.84

50% 22.06% -17.47

55% 22.09% -20.10

60% 22.16% -22.74

65% 22.25% -25.37

70% 22.36% -28.00

75% 22.50% -30.64

80% 22.67% -33.27

85% 22.86% -35.90

90% 23.08% -38.53

95% 23.32% -41.17

100% 23.58% -43.80

With 100 percent of the current electricity generation used, the cost return and risk for the portfolio

is pessimistic but when introducing the new asset the cost return improves with the risk decreasing.

Once 45 percent of the current 2010 Energy consumption portfolio and 55 percent of the new

portfolio mix is utilised, a point with the least risk arises, but the expected return still is negative. It’s

not until portfolio one is phased out and the new asset is used that the expected return becomes

more generous and starts making profit. This outlines the importance of renewable energy such as

wind energy for the UKs electricity security.


59

Figure 4.1: Risk and Return for Portfolio 1 against Portfolio 2

From this we can look at adding new assets to the portfolio and review which can be considered

feasible. The given results show Portfolio 4 as a feasible portfolio since it’s inside the envelope but

it’s not efficient as observed in Table 4.18, 4.19 and Figure 4.2. Portfolio 3 and 7 is outside the

envelope so are considered infeasible. The two efficient portfolios are 5 and 6 which are located on

the envelope. With practically the same risk involved in Portfolio 5 and 6 the return from Portfolio 5

is better since it’s on the efficient frontier and less risky.

Table 4.18: Introducing New Portfolio Combinations Assets to Current Portfolio

Portfolio 3 Portfolio 4 Portfolio 5 Portfolio 6 Portfolio 7

Gas CCGT 63,00% 26,00% 61,70% 77,00% 42,15%

Conventional

thermal 14,00% 42,00% 1,07% 0,00% 8,10%

Non-thermal

renewables 5,00% 32,00% 22,55% 1,00% 48,75%

Nuclear 18,00% 0,00% 14,68% 22,00% 1,00%

0%

5%

10%

15%

20%25%

30%

35%

40%

45%

50%

55%

60%

65%

70%

75%

80%

85%

90%

95%

100%

-50,00

-40,00

-30,00

-20,00

-10,00

0,00

10,00

20,00

22,00% 22,50% 23,00% 23,50% 24,00%

Po

rtfo

lio

ex

pe

cte

d r

etu

rn µ

Portfolio Risk σ


60

Table 4.19: Mean Return, Variance and Sigma of New Assets

Return (µ)

(£/MWh) Variance Sigma/SD

Portfolio 3 -27,86 0,049 22,08%

Portfolio 4 -21,65 0,052 22,78%

Portfolio 5 -9,09 0,049 22,13%

Portfolio 6 -22,20 0,049 22,16%

Portfolio 7 8,85 0,053 22,96%

Figure 4.2: Risk and Return for the Portfolio Mix adding New Assets.

0%

5%

10%

15%

20%25%

30%

35%

40%

45%

50%

55%

60%

65%

70%

75%

80%

85%

90%

95%

100%

Portfolio 3

Portfolio 4

Portfolio 5

Portfolio 6

Portfolio 7

-50,00

-40,00

-30,00

-20,00

-10,00

0,00

10,00

20,00

22,00% 22,50% 23,00% 23,50% 24,00%

Po

rtfo

lio

ex

pe

cte

d r

etu

rn µ

Portfolio Risk σ


61

The German government has decided to

phase out nuclear power plants by 2022.

5.0 Discussion

Analysing the carbon constraint cast of primary fuels, there is a

strong need to consider the diversification of electric

generation sources for future requirements. This dissertation

has introduced LCG and portfolio diversity in a world where

carbon constraints and rising fuel prices need to be considered.

The results provided show that the UK shifted from phasing

out coal in the 1990s to utilise other fuel resources such as non

thermal renewables especially wind. As a consequence of this,

the energy policy challenge will be tested in the next few

decades which are taking a lot of investment in UK. Repairs and

maintenance of old nuclear plants will require more use from

combined cycle power plants that burn the declining natural

gas resources.

In the context of renewables such as wind, the Government

announcement of eight sites where new reactors will be built

might ease the dilemma but at what cost? The future of

nuclear power around the world has a lot of opposition after

the Japanese earthquake and tsunami rocked the reactors at

Fukushima, causing radioactivity to leak from the plant. A

growing number of our European competitors have turned

their backs on nuclear power after calculating that it's just not

worth the risk. The German government has decided to phase

out nuclear power plants by 2022. The economic cost of a

nuclear plant needs to be also considered.

Results from the levelised cost of generation show nuclear cost

£175.95 MWh to produce. If the government decide to open

up more coal mines, which may prove less expensive costing

£86.61 MWh, they will have to consider whether or not they

can afford CO2 fines for emissions of carbon dioxide. The LCG

and MPT containing ROCs benchmark of £38.69 MWh could be

different if an agreement is reached between the generator

and the supplier. The current ‘band’ RO was used throughout

the lifetime of the cycle which makes onshore and offshore

wind more financial feasible.


62

Onshore produces £28.62MWh with

£34.82MWh coming from Renewables

Obligation Certificates

6.0 Conclusion

The CCGTs levelised generator cost of £30.31 MWh has the

lowest levelised cost ahead of any other base-load generator

when government subsidies are not calculated into the

equation. This result strengthens the UK’s position on changing

from more coal based energy to gas. Taking into consideration

the projected increase in imports required in future gas sales,

with volatility expected for running cost, it only illustrates an

ever increasingly unpredictable energy security in the coming

decades.

Adding the £40 MWh income for generation from the APX

Power UK shows most technologies are losing money every

year apart from Gas CCGT £9.69 MWh. To help promote a

greener renewable future the UK government provides

Renewables Obligation Certificates, this income makes

generators such as wind, onshore and offshore more feasible.

From this onshore wind forecasted £34.82 MWh per ROCs,

proves to have a higher expected return than Gas CCGT. This

shows why developers throughout the country are investing in

this generation. Offshore wind and offshore wind Round 3 can

be profitable with the 2 ROCs per MWh received but is a more

risky asset than onshore.

After the levelised costs were obtained a diversification of

different assets was calculated. This showed how energy

consumption throughout the UK has changed in the last forty

years. The expected return, though still in the negative, has

nearly halved since 1970 with a more diverse portfolio even

though Gas CCGT and Conventional thermal still produces over

80 percent of energy generated. Its Sharpe Ratio has also

increased from -261.40 to -185.77. The same concept was used

to analyse the 4572.57GW of refused wind. Even with a slight

increase in expected return of £2.02 MWh from the 2010

figure it could reduce the amount of nuclear or gas in the

system. Forecasting the wind trend expectations for future

consumption demonstrates an increase of 30GW added to the

system still produces negative results. Conventional Thermal

and nuclear producing nearly 50 percent of production has a

high negative effect on the LCG pushing the results into non

profitable production. The positive outlook from the results is

the Sharpe Ratio improving to -152.51.

The final part of the dissertation looked at MPT analysis; the

change from a risk-return asset to a more cost-risk efficient

frontier asset to create an appropriate framework for

electricity generation for the future. The model presented

existing 2010 generation to a more renewable driven mix with

Gas CCGT and wind energy controlling 90 percent of the

electricity generation. With 100 percent of the current 2010


63

Refused wind improves expected

return by £2.02 MWh

electricity generation used, the cost return and risk for the

portfolio is pessimistic, but introducing the new asset the cost

return improves with the risk decreasing. At 45 percent of the

current portfolio and 55 percent of the new asset a point is

reached with the least risk, but the expected return is still

negative at £-14.84 MWh. It’s not until portfolio one is phased

out and the new asset is utilised that the expected return

becomes more generous and starts making profit at a cost of

£8.86MWh. Including new portfolio mixes to this scenario

show how feasible and unfeasible portfolio could be used

while a portfolio asset with the same risk may produce higher

returns. This however is without considering subsidies for

other energy resources.

To conclude, the relative ranking of generator technology

available shows that wind energy has an important part to play

in the UK’s electricity security in the future. Coal, gas and

nuclear energy have contributed throughout the years and the

move back into nuclear may have resistance due to its high

cost, but energy security has to be a major apprehension if the

UK rely on large quantity of import fuels.


64

7.0 Bibliography

APX. (2012, 05 04). APX Power UK Spot results. Retrieved 05 04, 2012, from Apxendex:

http://www.apxendex.com/?id=49

Awerbuch, S. (2003). Applying Portfolio theory to EU electricity planning and policy-making. Paris:

International Energy Agency.

BBC News. (2011, 11 03). Energy firms warn about 'slow' Welsh planning process. Retrieved 04 12 ,

2012, from BBC: http://www.bbc.co.uk/news/uk-wales-politics-15575037

Beltran, H. (2009). Modern Portfolio theory applied to electricity generation planning. Illinois:

University of Illinois at Urbana-Champaign.

Change, Department of Energy and Climate. (2010). Electricity Market Reform. London: A National

publication.

Cui, X. (2010). The UK Electricity Markets: Its Evolution, Wholesale Prices and Challenge of Wind

Energy. Stirling: University of Stirling.

Department of Energy & Climate Change. (2011). Digest of United Kingdom Energy Statistics. London:

A National Statistics publication.

Department of Trade and Industry. (2000). Energy Policy, Technology, Analysis and Coal Directorate.

London.

Mott MacDonald. (2010). UK Electricity Generation Costs Update. Brighton: Mott MacDonald.

National Grid Company. (n.d.). British Electricity Trading And Transmission Arrangements. Retrieved

04 03, 2012, from National Grid:

http://www.nationalgrid.com/uk/sys_09/default.asp?action=mnch10_3.htm&Node=SYS&Snode=10_

3&E=Y

Nuclear Industry Association. (2012, 03 12). Facts and Figures. Retrieved 03 12, 2012, from Nuclear

Industry Association: http://www.niauk.org/

renewableUK. (October 2011). State of the Industry Report- Onshore and Offshore: A Progress

Update. London: renewableUK.

The National Grid. (2010). Climate Change Adaptation Report . London: National Grid.


65

8.0 Appendix 1 Energy Statistics

Coal production and stocks(1) Thousand tonnes

Coal Production Coal stocks (at year end) (5)

Total Deep-

mined

Surface

mining(2,3) Imports(4) Exports Total Distributed Undistributed

1970 147,195 136,686 10,509 79 3,191 20,630 13,414 7,216

1971 153,683 136,478 17,205 4,241 2,667 28,664 18,271 10,393

1972 126,834 109,086 17,748 4,998 1,796 30,460 19,351 11,110

1973 131,984 120,030 11,954 1,675 2,693 27,886 17,035 10,850

1974 110,452 99,993 10,459 3,547 1,865 21,807 15,827 5,979

1975 128,683 117,412 11,271 5,083 2,182 31,159 20,541 10,618

1976 123,801 110,265 13,536 2,837 1,436 33,115 22,457 10,658

1977 122,150 107,123 15,027 2,439 1,835 31,444 21,704 9,740

1978 123,577 107,528 16,049 2,352 2,253 34,475 22,038 12,437

1979 122,369 107,775 14,594 4,375 2,175 27,908 18,339 9,569

1980 130,097 112,430 17,667 7,334 3,809 37,687 20,370 17,317

1981 127,469 110,473 16,996 4,290 9,113 42,253 20,136 22,117

1982 124,711 106,161 18,550 4,063 7,447 52,377 30,422 21,955

1983 119,254 101,742 17,512 4,456 6,561 57,960 33,964 23,996

1984 51,182 35,243 15,939 8,894 2,293 36,548 15,794 20,753

1985 94,111 75,289 18,822 12,732 2,432 34,979 25,752 9,228

1986 108,099 90,366 17,733 10,554 2,677 38,481 29,776 8,704

1987 104,533 85,957 18,576 9,781 2,353 33,246 27,104 6,142

1988 104,066 83,762 20,304 11,685 1,822 36,166 28,834 7,332

1989 99,820 79,628 20,192 12,137 2,049 39,244 29,191 10,053

1990 92,762 72,899 19,863 14,783 2,307 37,760 28,747 9,013

1991 94,202 73,357 20,845 19,611 1,824 43,321 32,343 10,977

1992 84,493 65,800 18,693 20,339 973 47,207 33,493 13,714

1993 68,199 50,457 17,742 18,400 1,114 45,860 29,872 15,989

1994 49,785 31,854 17,931 15,088 1,236 26,572 15,301 11,271

1995 53,037 35,150 17,887 15,896 859 20,230 13,126 7,104

1996 50,197 32,223 17,974 17,799 988 16,405 12,252 4,153

1997 48,495 30,281 18,214 19,757 1,146 20,088 15,285 4,803

1998 41,177 25,731 15,446 21,244 971 18,767 14,202 4,565

1999 37,077 20,888 16,189 20,293 761 19,931 14,774 5,157

2000 31,198 17,188 14,010 23,446 660 14,077 12,431 1,646

2001 31,930 17,347 14,583 35,542 550 17,468 15,885 1,583

2002 29,989 16,391 13,598 28,686 537 16,968 14,486 2,482

2003 28,279 15,633 12,646 31,891 543 13,731 12,107 1,624

2004 25,096 12,542 12,554 36,153 622 13,791 12,598 1,192

2005 20,498 9,563 10,935 43,968 536 15,628 14,527 1,101

2006 18,517 9,444 9,073 50,528 443 17,210 16,427 783

2007 17,007 7,674 9,333 43,364 544 14,155 13,420 734

2008 18,053 8,096 9,958 43,875 599 17,262 16,408r 854

2009 17,874 7,520 10,354 38,167 646 24,090 22,640 1,450

2010 18,417 7,390 11,026 26,521 715 16,883 15,366 1,517


66

Crude oil and petroleum products: production, imports and exports

Thousand tonnes

Crude oil (1)

Oil products

Imports Indigenous production Exports

Refinery

throughput

Refinery

output (2)

Exports Imports

Inland

deliveries (2)

Total Landward

1970 102,155 156 83 1,182 101,911 94,696 17,424 20,428 91,151

1971 107,736 212 85 1,569 105,342 98,245 17,166 19,369 91,991

1972 107,706 333 85 3,558 106,980 99,368 15,979 20,827 98,469

1973 115,472 372 88 3,235 114,338 105,954 17,404 18,300 99,786

1974 112,822 410 107 1,404 111,217 103,060 14,631 14,537 93,409

1975 91,366 1,564 99 1,524 93,597 86,647 13,924 12,786 82,824

1976 80,466 12,169 99 4,285 97,784 90,284 15,988 10,709 81,579

1977 70,697 38,265 99 16,793 93,615 86,338 14,160 13,050 82,759

1978 68,144 54,006 88 25,200 96,390 89,156 13,194 11,586 84,141

1979 60,380 77,748 121 40,569 97,806 90,583 12,988 12,035 84,554

1980 46,717 80,467 237 40,180 86,341 79,227 14,110 9,245 71,177

1981 36,855 89,454 232 52,206 78,287 72,006 12,256 9,402 66,256

1982 33,754 103,211 253 61,670 77,130 70,747 12,637 12,524 67,246

1983 30,324 114,960 316 69,923 76,876 70,927 13,331 9,907 64,464

1984 32,272 126,065 345 80,143 79,117 73,187 12,478 23,082 81,435

1985 35,576 127,611 380 82,980 78,431 72,904 14,828 13,101 69,781

1986 41,209 127,068 504 87,437 80,155 74,089 15,283 11,767 69,227

1987 41,541 123,351 578 83,220 80,449 74,656 14,980 8,570 67,701

1988 44,272 114,459 761 73,330 85,662 79,837 15,802 9,219 72,317

1989 49,500 91,710 722 51,664 87,669 81,392 16,683 9,479 73,028

1990 52,710 91,604 1,758 56,999 88,692 82,286 16,899 11,005 73,943

1991 57,084 91,261 3,703 55,131 92,001 85,476 19,351 10,140 74,506

1992 57,683 94,251 3,962 57,627 92,334 85,783 20,250 10,567 75,470

1993 61,701 100,189 3,737 64,415 96,273 89,584 23,031 10,064 75,790

1994 53,096 126,542 4,649 82,393 93,161 86,644 22,156 10,441 74,957

1995 48,749 129,894 5,051 84,577 92,743 86,133 21,614 9,878 73,694

1996 50,099 129,742 5,251 81,563 96,660 89,885 23,681 9,315 75,390

1997 49,994 128,234 4,981 79,400 97,023 90,366 26,755 8,706 72,501

1998 47,958 132,633 5,161 84,610 93,797 86,615 24,375 11,418 72,261

1999 44,869 137,099 4,285 91,797 88,286 81,195 21,730 13,896 72,436

2000 54,386 126,245 3,247 92,917 88,013 81,130 20,677 14,212 71,944

2001 53,551 116,678 2,921 86,930 83,343 77,051 19,088 17,234 71,354

2002 56,968 115,944 2,673 87,144 84,784 78,319 23,444 14,900 70,557

2003 54,177 106,073 2,198 74,898 84,585 79,073 23,323 16,472 71,697

2004 62,517 95,374 1,938 64,504 89,821 84,411 30,495 18,545 73,649

2005 58,885 84,721 1,648 54,099 86,134 80,161 29,722 22,512 75,345

2006 59,443 76,578 1,380 50,195 83,213 77,960 29,009 26,828 74,933

2007 57,357 76,575 1,271 50,999 81,477 76,596 30,017 25,093 72,747

2008 60,041 71,665 1,248 48,401 80,740 75,673 28,791 24,186 71,367

2009 54,387 68,199 1,181 45,202 75,225 70,494 25,733 22,407 67,563

2010 54,587 62,962 941 42,196 73,200 68,394 26,065 24,210 67,213

(1) Includes natural gas liquids and feedstocks.

(2) Excludes products used as fuels within refinery processes.


67

Inland deliveries of petroleum

Thousand tonnes

Energy industry use Final users

Electricity

generators

Gas

works Refineries

Other energy

industry uses (1)

Iron and

Steel

Other

industries Transport Domestic

Other final

users (2)

1970 12,600 4,560 6,030 4,250 1,420 21,550 25,000 3,050 8,590

1971 14,680 2,590 6,180 3,970 1,320 21,550 26,070 3,010 8,670

1972 18,870 2,210 6,420 3,780 1,260 22,140 27,140 3,480 8,910

1973 16,950 2,320 7,050 3,740 1,250 22,180 28,960 3,800 9,000

1974 17,210 1,280 6,950 3,020 1,010 19,820 27,920 3,380 7,950

1975 12,820 590 6,030 2,480 830 17,890 27,570 3,270 7,930

1976 10,180 250 6,340 2,480 830 18,060 28,600 3,270 7,800

1977 10,600 160 6,240 2,210 740 18,060 29,370 3,310 8,600

1978 11,640 350 6,420 2,120 710 17,550 30,870 3,260 8,240

1979 11,120 420 6,490 2,140 710 17,620 31,580 3,210 8,270

1980 6,520 310 6,270 1,190 400 14,510 31,740 2,550 7,010

1981 4,860 250 5,450 1,000 330 12,670 30,630 2,310 6,650

1982 6,870 210 5,550 890 300 11,640 31,310 2,150 6,280

1983 4,650 160 5,300 770 260 10,230 32,250 2,140 6,000

1984 20,910 160 5,350 630 210 9,390 33,820 2,140 6,000

1985 9,720 150 5,180 520 170 8,430 34,460 2,200 5,650

1986 5,660 170 5,400 500 170 9,020 36,660 2,320 5,360

1987 5,360 90 5,050 420 140 7,360 38,220 2,210 4,670

1988 6,070 60 5,290 550 180 8,230 40,620 2,130 4,670

1989 6,170 50 5,620 560 190 7,520 42,540 2,110 4,210

1990 7,980 50 5,070 530 180 7,030 43,450 2,220 4,110

1991 7,560 50 5,260 530 180 7,490 42,860 2,520 4,170

1992 8,320 40 4,160 510 170 7,130 43,790 2,580 4,220

1993 6,020 40 5,890 640 210 7,170 44,560 2,710 4,210

1994 4,040 50 6,040 670 220 7,470 44,820 2,700 4,030

1995 4,370 50 5,990 620 210 6,410 44,810 2,700 3,690

1996 3,570 50 6,500 650 90 6,410 46,640 3,170 3,650

1997 2,240 50 6,160 570 110 5,680 47,320 3,060 3,120

1998 1,400 50 6,180 270 80 5,750 47,920 3,200 2,920

1999 1,170 50 5,540 980 60 5,280 48,850 2,850 2,470

2000 980 40 5,250 900 140 5,350 49,450 2,920 2,110

2001 970 0 5,060 820 80 5,980 49,110 3,180 2,320

2002 670 0 5,680 440 80 5,620 49,640 2,780 1,660

2003 540 0 5,460 380 20 6,250 50,290 2,760 1,050

2004 590 0 5,420 360 30 6,270 51,550 2,940 1,320

2005 1,270 0 5,600 330 20 5,670 52,740 2,780 1,620

2006 1,240 0 4,880 290 20 5,500 53,370 2,930 1,400

2007 1,130 0 4,680 260 60 5,460 53,490 2,590 1,380

2008 1,710 0 4,750 270 60 5,020 51,900 2,730 1,300

2009 1,560 0 4,400 220 50 4,450 49,600 2,710 1,140

2010 1,140 0 4,480 200 60 4,470 49,090 3,080 1,160

(1) Use of gas oil & fuel oil by iron & steel industry in blast furnaces. Data from 1999

provided by the Iron & Steel Statistics. Bureau and include estimates of fuel used to

generate heat that is sold to third parties.

(2) Mainly agriculture, public administration, commerce and other services.


68

Natural gas and colliery methane production and consumption

GWh

Production Import Exports Total for consumption Domestic

Town gas (1)

Methane (2)

Methane (3)

Methane Total Town gas Methane (2)

Town gas Methane

1970 49,617 121,712 9,759 - 171,564 125,933 45,631 85,430 18,376

1971 24,882 201,721 9,730 - 222,616 104,245 118,371 73,502 41,675

1972 17,848 291,078 8,968 - 290,287 95,834 194,453 64,974 67,172

1973 21,336 317,132 8,587 - 319,917 68,286 251,631 46,598 94,515

1974 12,221 382,253 7,122 - 377,388 44,840 332,548 30,450 127,339

1975 5,393 397,932 9,818 - 391,250 20,984 370,237 14,507 158,141

1976 1,700 421,700 11,254 - 417,655 6,272 411,120 4,250 177,279

1977 762 440,544 19,548 - 436,793 2,051 434,742 1,290 191,844

1978 615 422,257 55,361 - 460,297 938 459,359 557 212,242

1979 674 425,832 95,424 - 502,382 1,055 501,327 586 240,465

1980 586 404,760 116,291 - 508,684 909 507,775 557 246,766

1981 557 401,742 124,262 - 512,112 791 511,321 469 256,379

1982 557 405,815 115,001 - 518,149 674 517,475 410 255,118

1983 586 416,454 124,497 - 528,642 528 528,114 322 259,661

1984 557 414,314 147,415 - 544,584 498 544,086 293 261,507

1985 498 461,851 147,122 - 581,717 469 581,248 293 283,517

1986 440 483,040 137,099 - 588,691 410 588,281 234 299,929

1987 322 508,126 128,893 - 614,247 322 613,925 147 307,578

1988 88 489,133 115,441 - 594,766 88 594,678 29 300,515

1989 - 478,931 113,770 - 580,522 - 580,522 - 290,557

1990 - 528,843 79,833 - 597,046 - 597,046 - 300,410

1991 - 588,822 72,007 - 641,763 - 641,763 - 333,963

1992 - 598,761 61,255 620 640,818 - 640,818 - 330,101

1993 - 703,971 48,528 6,824 717,357 - 717,357 - 340,162

1994 - 751,588 33,053 9,557 764,667 - 764,667 - 329,710

1995 - 823,336 19,457 11,232 808,786 - 808,786 - 326,010

1996 - 979,019 19,804 15,203 938,848 - 938,848 - 375,841

1997 - 998,871 14,062 21,666 960,243 - 960,243 - 345,532

1998 - 1,048,859 10,582 31,604 1,005,306 - 1,005,306 - 355,895

1999 - 1,152,635 12,862 84,433 1,072,963 - 1,072,963 - 358,066

2000 - 1,260,656 26,032 146,342 1,105,537 - 1,105,537 - 369,909

2001 - 1,231,263 30,464 138,330 1,111,729 - 1,111,729 - 379,426

2002 - 1,205,405 60,493 150,731 1,096,267 - 1,096,267 - 376,372

2003 - 1,197,846 86,298 177,039 1,102,774 - 1,102,774 - 386,486

2004 - 1,121,257 133,033 114,112 1,124,996 - 1,124,996 - 396,411

2005 - 1,025,989 173,328 96,181 1,093,331 - 1,093,331 - 381,879

2006 - 930,538 244,029 120,591 1,035,325 - 1,035,325 - 366,928

2007 - 838,809 338,026 123,158 1,046,817 - 1,046,817 - 352,868

2008 - 810,385 407,054 122,670 1,077,977 - 1,077,977 - 359,554

2009 - 694,740 455,789 137,100 991,769 - 991,769 - 332,499

2010 - 665,083 589,497 176,399 1,073,770 - 1,073,770 - 389,595

(1) In most years production of town gas is less than consumption because of transfers into town gas of North Sea and

imported methane.

(2) Includes colliery methane.

(3) Before 1977 imports were of liquefied natural gas. These imports continued until the early 1980s.


69

Electricity generated and supplied

GWh

Other generators (1) All generating companies

Electricity supplied (gross ) (2) Electricity supplied (gross)

Electricity

Total

Conventional

thermal and

other (3)

CCGT

Non-

thermal

renewable

Total

Conventional

thermal and

other (3)

CCGT Nuclear

Non- thermal

renewables (5)

and

pumped

storage

15,674 14,996 0 678 231,623 203,171 0 22,805 5,647 230,136 1970

15,388 14,837 0 551 238,325 210,018 0 24,013 4,294 237,116 1971

15,746 15,175 0 571 245,150 215,223 0 25,639 4,288 243,966 1972

17,655 17,008 0 647 262,638 233,804 0 24,310 4,524 261,756 1973

17,222 16,660 0 562 254,147 220,138 0 29,232 4,777 253,251 1974

15,766 15,175 0 591 253,714 222,334 0 26,463 4,917 252,284 1975

17,013 16,414 0 599 257,707 221,462 0 31,153 5,092 255,978 1976

16,434 15,848 0 586 263,615 223,752 0 34,660 5,203 262,007 1977

16,034 15,387 0 647 268,804 231,148 0 32,462 5,194 267,375 1978

15,720 15,062 0 658 280,162 241,391 0 33,335 5,436 278,738 1979

14,132 13,509 0 623 266,312 228,927 0 32,291 5,094 264,859 1980

13,264 12,801 0 463 259,939 221,390 0 33,191 5,358 258,743 1981

12,613 11,943 0 670 255,083 210,765 0 38,721 5,597 253,811 1982

12,152 11,486 0 666 259,361 209,086 0 43,911 6,364 257,024 1983

11,319 10,685 0 634 264,148 210,925 0 47,256 5,966 261,535 1984

12,112 11,467 0 645 277,922 217,373 0 53,767 6,781 274,427 1985

12,957 12,278 0 679 281,469 222,730 0 51,843 6,895 278,476 1986

13,551 12,831 0 720 282,512 228,121 0 48,205 6,186 279,708 1987

14,840 14,085 0 755 288,599 226,018 0 55,642 6,939 285,711 1988

15,747 15,007 0 740 294,322 224,176 0 63,602 6,544 291,751 1989

15,824 14,738 280 806 300,128 234,101 280 58,664 7,082 297,502 1990

16,202 15,065 298 839 302,764 233,325 607 62,761 6,071 300,654 1991

16,246 15,020 394 832 300,804 221,265 3,358 69,135 7,046 298,547 1992

16,552 15,196 584 772 303,816 193,969 23,195 80,979 5,673 301,868 1993

18,207 16,700 738 769 308,987 185,021 37,553 79,962 6,451 306,936 1994

20,909 19,243 933 733 319,909 183,567 49,458 80,598 6,286 317,627 1995

23,519 19,091 3,358 1,070 334,787 174,665 68,962 85,820 5,340 332,357 1996

25,384 19,703 4,192 1,489 334,106 147,664 90,874 89,341 6,227 331,629 1997

27,669 20,766 5,157 1,746 345,293 149,001 98,162 90,590 7,540 342,699 1998

30,298 21,769 6,785 1,745 351,445 135,262 119,553 87,672 8,958 347,671 1999

33,934 21,926 10,318 1,690 360,765 147,394 126,428 78,334 8,609 357,266 2000

30,391 20,066 8,531 1,794 367,382 147,185 129,875 82,985 7,337 364,173 2001

31,873 19,716 10,049 2,108 370,120 148,511 131,935 81,090 8,584 366,657 2002

34,220 21,942 10,336 1,941 380,073 162,138 128,882 81,911 7,142 376,528 2003

34,165 20,046 11,260 2,859 376,896 153,653 140,243 73,682 9,319 373,399 2004

34,539 19,494 11,204 3,842 380,486 155,493 139,383 75,173 10,438 376,780 2005

34,578 18,598 10,859 5,121 378,779 170,463 126,554 69,237 12,524 373,861 2006

33,779 19,661 11,470 2,649 379,091 162,107 149,127 57,249 10,608 374,019 2007

31,774 18,143 10,947 2,684 372,425 145,420 168,364 47,673 10,968 367,053 2008

32,519 18,898 10,251 3,370 360,241 126,999 159,159 62,762 11,321 355,398 2009

32,002 19,171 9,682 3,149 365,324 132,367 167,500 56,475 8,982 361,112 2010


70

(1) From 2007, major wind farm companies are included under Major Power Producers,previously wind was covered under other generators.

(2) Electricity generated less electricity used on works.

(3) Includes electricity supplied by gas turbines and oil engines. From 1988 also includes electricity produced by plants using

renewable sources.

(4) Electricity supplied (gross) less electricity used in pumping at pumped storage station.

(5) Natural flow hydro, wind, wave and solar photovoltaics.

Combined Heat and Power: capacity generation and fuel use

Number of

schemes

Electricity

capacity (1)

Heat

capacity

Heat to

power ratio

(2)

Fuel input

Electricity

generation

(3)

Heat

generation (4)

Overall

efficiency (3)

Load factor

Mwe MWth GWh GWh GWh Percent Percent

1977 .. 2,793 .. .. .. 10,450 .. .. 43

1983 .. 2,254 .. .. .. 7,500 .. .. 38

1988 .. 1,793 .. .. .. 8,700 .. .. 55

1991 266 2,293 13,361 5.80 113,537 10,917 65,174 67 54

1993 996 2,893 14,442 4.12 101,650 14,171 58,418 71 56

1994 1,139 3,117 15,704 4.67 97,468 12,853 60,079 75 47

1995 1,220 3,355 15,698 3.85 106,504 14,778 56,833 67 50

1996 1,299 3,041 15,382 3.81 97,994 14,782 56,285 73 56

1997 1,319 3,204 15,025 3.46 97,881 15,699 54,329 72 56

1998 1,329 3,439 15,111 3.16 100,878 17,569 55,579 73 58

1999 1,353 3,669 14,644 2.81 100,551 19,104 53,755 73 59

2000 1,340 4,451 11,606 2.17 106,230 25,246 54,877 75 65

2001 1,369 4,454 11,616 2.61 109,349 21,232 55,411 70 54

2002 1,348 4,565 11,271 2.35 112,669 23,222 54,565 69 58

2003 1,348 4,494 10,933 2.30 113,086 23,933 54,978 70 61

2004 1,335 5,396 11,772 2.10 120,181r 26,853 56,520 69 57

2005 1,364 5,533 11,499 1.96 124,605 28,828 56,442 68 60

2006 1,363 5,432 11,208 1.86 122,348 28,731 53,408 67 60

2007 1,414 5,438 11,068 1.84 118,638 27,844 51,312 67 59

2008 1,434 5,449 10,882 1.89 118,833 27,547 51,945 67 58

2009 1,495 5,614 10,746 1.82 111,511 26,463 48,155 67 54

2010 1,568 5,989 10,522 1.83 110,323 26,083 47,815 67 50

(1) (CHP QPO ) basis from 1995 onwards

(2) Heat to power ratios are calculated from the qualifying heat output (QHO) and the qualifying power output (QPO) (and

their equivalents in the years before the CHPQA scheme was used for CHP statistics).

(3) These are calculated using gross calorific values; overall net efficiencies are some 5 percentage points higher.

(4) (CHP QHO ) basis from 1995 onwards


71

Renewable sources used to generate electricity, heat and transport; electricity generation from renewable sources

Thousand tonnes of oil equivalent

Wind,

wave

and

tidal

(1)

Solar

photo-

voltaics

Hydro (1) Biomass

Total Waste (6)

Small

scale

Large

scale

(2)

Landfill

gas

Sewage

sludge

digestio

n

Municip

al solid

waste

combus

tion (3)

Animal

Biomass

(4)

Plant

Biomass

(5)

Co-

firing

with

fossil

fuels

Total

biomass

Used to generate electricity

1990 0.8 - 10.9 436.8 45.6 103.6 69.8 0.0 - - 219.0 667.5

41.0

1991 0.7 - 12.2 385.4 68.2 107.6 70.5 0.6 - - 246.9 645.2

41.4

1992 2.8 - 12.8 454.1 123.6 107.6 85.9 17.5 - - 334.6 804.3

50.4

1993 18.7 - 13.6 356.2 146.6 123.8 119.1 52.4 - - 442.0 830.4

76.4

1994 29.5 - 13.6 424.3 169.5 118.3 192.0 70.9 - - 550.8 1,018.1

156.3

1995 33.7 - 14.2 401.7 184.3 134.6 198.6 71.2 - - 588.7 1,038.3

178.6

1996 41.9 - 10.1 281.6 232.1 134.6 205.3 67.1 - - 639.1 972.7

184.8

1997 57.4 - 14.1 344.4 301.1 133.7 258.2 67.9 - - 760.8 1,176.8

236.0

1998 75.4 - 17.7 422.3 388.8 126.5 346.5 76.2 0.1 - 938.0 1,453.5

302.8

1999 73.1 - 17.8 441.0 558.4 134.6 345.0 156.8 0.2 - 1,195.0 1,726.9

272.5

2000 81.3 0.1 18.4 418.8 717.6 120.4 350.1 182.5 10.8 - 1,381.3 1,900.0

253.3

2001 83.0 0.2 18.1 330.7 822.2 119.0 387.1 205.3 80.7 - 1,614.4 2,046.3

266.2

2002 108.0 0.2 17.5 394.2 878.5 120.6 420.2 184.4 92.4 94.0 1,790.0 2,310.0

286.1

2003 110.5 0.3 12.9 256.9 1,074.5 129.3 445.8 172.4 136.7 197.3 2,156.1 2,536.6

273.8

2004 166.4 0.3 24.3 392.2 1,313.1 144.3 429.5 182.3 123.1 335.1 2,527.4 3,110.6

263.9

2005 249.7 0.7 38.2 385.0 1,407.2 152.8 426.3 161.5 129.4 830.7 3,107.8 3,781.5

262.0

2006 363.3 0.9 41.1 353.9 1,451.1 145.9 479.0 148.5 122.9 829.0 3,176.4 3,935.6

293.7

2007 453.5 1.2 46.0 391.6 1,533.9 147.4 486.8 222.5 137.8 641.4 3,169.6 4,062.1

298.3

2008 610.3 1.5 48.8 395.5 1,560.3 174.5 506.8 253.3 189.5 528.9 3,218.2 4,269.4

310.3

2009 800.0 1.7 51.4 401.0 1,624.2 196.2 624.5 231.9 367.3 592.3 3,636.4 4,890.5

368.6

2010 875.5 2.9 44.0 265.9 1,652.0 230.3 659.0 259.3 412.3 821.8 4,034.7 5,223.0

388.4


72

Renewable sources used to generate electricity, heat and transport; electricity generation from renewable sources

GWh

Wind,

wave

and

tidal (1)

Solar

photo-

voltaic

s

Hydro (1) Biomass

Total Waste (6)

Smal

l

scale

Large

scale

(2)

Landfil

l gas

Sewage

sludge

digestio

n

Municipal

solid

waste

combustio

n (3)

Animal

Biomas

s (4)

Plant

Biomas

s (5)

Co-

firing

with

fossil

fuels

Total

biomas

s

Electricity generated

1990 9.0 - 127.

0

5,080.

0 139.0 316.0 141.0 - 0.0 - 596.0

5,812.0 83.0

1991 9.0 - 142.

0

4,482.

0 208.0 328.0 150.0 - 1.0 - 688.0

5,320.0 88.0

1992 33.0 - 149.

0

5,282.

0 377.0 328.0 177.0 - 52.0 - 934.0

6,398.0 104.0

1993 217.0 - 159.

0

4,143.

0 447.0 378.0 252.0 - 122.0 - 1,198.0

5,718.0 165.0

1994 344.0 - 159.

0

4,935.

0 517.0 361.0 449.0 - 192.0 - 1,518.0

6,957.0 352.0

1995 392.0 - 166.

0

4,672.

0 562.0 410.0 471.0 - 199.0 - 1,642.0

6,872.0 412.0

1996 488.0 - 118.

0

3,275.

0 708.0 410.0 489.0 - 197.0 - 1,805.0

5,685.0 417.0

1997 667.0 - 164.

0

4,005.

0 918.0 408.0 585.0 - 199.0 0.0 2,110.0

6,946.0 483.0

1998 877.0 - 206.

0

4,911.

0

1,185.

0 386.0 849.0 - 234.0 0.0 2,654.0

8,648.0 583.0

1999 850.0 1.0 207.

0

5,128.

0

1,703.

0 410.0 856.0 - 459.0 1.0 3,429.0

9,615.0 559.0

2000 946.0 1.0 214.

0

4,871.

0

2,188.

0 367.0 840.0 - 456.0 31.0 3,882.0

9,914.0 519.0

2001 965.0 2.0 210.

0

3,845.

0

2,507.

0 363.0 880.0 - 542.0 234.0 4,526.0

9,548.0 528.0

2002 1,256.0 3.0 204.

0

4,584.

0

2,679.

0 368.0 907.0 286.0 568.0 272.0 5,080.0

11,127.

0 545.0

2003 1,285.0 3.0 150.

0

2,987.

0

3,276.

0 394.0 965.0 602.0 535.0 402.0 6,174.0

10,599.

0 579.0

2004 1,935.0 4.0 283.

0

4,561.

0

4,004.

0 440.0 971.0 1,022.0 565.0 362.0 7,364.0

14,147.

0 583.0

2005 2,904.0 8.0 444.

0

4,478.

0

4,290.

0 466.0 964.0 2,533.0 468.0 382.0 9,102.0

16,937.

0 578.0

2006 4,225.0 11.0 478.

0

4,115.

0

4,424.

0 445.0 1,083.0 2,528.0 434.0 363.0 9,277.0

18,106.

0 651.0

2007 5,274.0 14.0 534.

0

4,554.

0

4,677.

0 449.0 1,177.0 1,956.0 555.0 409.0 9,223.0

19,599.

0 707.0

2008 7,097.0 17.0 568.

0

4,600.

0

4,757.

0 532.0 1,226.0 1,613.0 587.0 568.0 9,283.0

21,565.

0 736.0

2009 9,304.0 20.0 598.

0

4,664.

0

4,952.

0 598.0 1,511.0 1,806.0 620.0

1,109.

0

10,596.

0

25,182.

0 874.0

2010 10,182.

0 33.0

511.

0

3,092.

0

5,037.

0 702.0 1,594.0 2,506.0 670.0

1,406.

0

11,915.

0

25,733.

0 922.0

(1) For wind, wave, tidal and hydro, the figures represent the energy content of the electricity supplied, but for biofuels the

figures represent the energy content of the fuel used.

(2) Excluding pumped storage stations.

(3) Biodegradable part only.

(4) Includes electricity from farm waste digestion, anaerobic digestion, poultry litter combustion, and meat & bone combustion

(5) Includes electricity from straw and energy crops.

(6) Non-biodegradable part of municipal solid waste plus waste tyres, hospital waste, and general industrial waste


73

Fuel input for electricity generation(1)

Million tonnes of oil equivalent

Total all Coal Oil (2)

Natural

gas (3)

Electricity

Coke

Other fuels

(4) Nuclear Natural Wind

1970 63.84 43.07 13.27 0.11 7.00 0.39 0.00 0.00 0.00

1971 66.46 42.42 15.63 0.64 7.37 0.29 0.00 0.11 0.00

1972 68.37 38.47 20.13 1.61 7.87 0.29 0.00 0.00 0.00

1973 70.93 44.30 18.09 0.64 7.46 0.33 0.00 0.11 0.00

1974 69.01 38.71 18.41 2.46 8.97 0.35 0.00 0.11 0.00

1975 66.25 41.85 13.70 2.14 8.12 0.33 0.00 0.11 0.00

1976 66.97 44.49 10.92 1.61 9.56 0.39 0.00 0.00 0.00

1977 69.32 45.71 11.35 1.28 10.64 0.34 0.00 0.00 0.00

1978 69.64 46.05 12.31 0.86 9.96 0.35 0.00 0.11 0.00

1979 72.80 50.10 11.45 0.54 10.23 0.37 0.00 0.11 0.00

1980 69.46 51.01 7.67 0.42 9.91 0.34 0.00 0.11 0.00

1981 65.98 49.64 5.46 0.21 10.18 0.38 0.00 0.11 0.00

1982 65.98 46.75 6.64 0.21 11.88 0.39 0.00 0.11 0.00

1983 66.37 47.16 5.14 0.21 13.47 0.39 0.00 0.00 0.00

1984 69.18 31.07 22.80 0.42 14.50 0.39 0.00 0.00 0.00

1985 71.54 42.81 11.35 0.54 16.50 0.34 0.00 0.00 0.00

1986 70.46 47.91 6.51 0.18 15.44 0.41 0.00 0.00 0.00

1987 (5) 74.31 51.58 6.30 0.91 14.44 0.36 0.00 0.00 0.72

1988 75.57 49.83 7.01 0.97 16.57 0.42 0.00 0.00 0.77

1989 75.27 48.59 7.11 0.54 17.74 0.41 0.00 0.00 0.88

1990 76.34 49.84 8.40 0.56 16.26 0.44 0.00 0.00 0.84

1991 76.87 49.98 7.56 0.57 17.43 0.39 0.00 0.00 0.94

1992 76.57 46.94 8.07 1.54 18.45 0.46 0.00 0.00 1.09

1993 75.40 39.61 5.78 7.04 21.58 0.37 0.00 0.00 1.02

1994 74.01 37.10 4.11 10.10 21.20 0.44 0.00 0.00 1.06

1995 77.15 36.29 4.15 13.27 21.25 0.40 0.00 0.00 1.79

1996 79.56 33.67 3.87 17.37 22.18 0.29 0.04 - 2.14

1997 76.76 28.30 2.01 21.74 21.98 0.38 0.06 - 2.29

1998 81.14 29.94 1.69 23.02 23.44 0.44 0.08 - 2.52

1999 79.72 25.51 1.54 27.13 22.22 0.46 0.07 - 2.79

2000 81.21 28.67 1.55 27.91 19.64 0.44 0.08 - 2.93

2001 84.01 31.61 1.42 26.87 20.77 0.35 0.08 - 2.91

2002 83.00 29.63 1.29 28.33 20.10 0.41 0.11 - 3.13

2003 85.95 32.54 1.19 27.85 20.04 0.28 0.11 - 3.93

2004 84.57 31.31 1.10 29.25 18.16 0.42 0.17 - 4.16

2005 86.68 32.58 1.31 28.52 18.37 0.42 0.25 - 5.23

2006 87.06 35.94 1.43 26.78 17.13 0.39 0.36 - 5.02

2007 84.34 32.92 1.16 30.60 14.04 0.44 0.46 - 4.73

2008 81.56 29.97 1.58 32.40 11.91 0.44 0.61 - 4.65

2009 78.55 24.66 1.51 30.89 15.23 0.45 0.80 - 5.00

2010 79.07 25.56 1.17 31.96 13.95 0.31 0.88 - 5.24


74

Electricity generated and supplied

GWh

Other generators (1) All generating companies

Electricity supplied (gross ) (2) Electricity supplied (gross)

Electricity

Total

Conventional

thermal and

other (3)

CCGT

Non-

thermal

renewable

Total

Conventional

thermal and

other (3)

CCGT Nuclear

Non- thermal

renewables (5)

and pumped

storage

15,674 14,996 0 678 231,623 203,171 0 22,805 5,647 230,136 1970

15,388 14,837 0 551 238,325 210,018 0 24,013 4,294 237,116 1971

15,746 15,175 0 571 245,150 215,223 0 25,639 4,288 243,966 1972

17,655 17,008 0 647 262,638 233,804 0 24,310 4,524 261,756 1973

17,222 16,660 0 562 254,147 220,138 0 29,232 4,777 253,251 1974

15,766 15,175 0 591 253,714 222,334 0 26,463 4,917 252,284 1975

17,013 16,414 0 599 257,707 221,462 0 31,153 5,092 255,978 1976

16,434 15,848 0 586 263,615 223,752 0 34,660 5,203 262,007 1977

16,034 15,387 0 647 268,804 231,148 0 32,462 5,194 267,375 1978

15,720 15,062 0 658 280,162 241,391 0 33,335 5,436 278,738 1979

14,132 13,509 0 623 266,312 228,927 0 32,291 5,094 264,859 1980

13,264 12,801 0 463 259,939 221,390 0 33,191 5,358 258,743 1981

12,613 11,943 0 670 255,083 210,765 0 38,721 5,597 253,811 1982

12,152 11,486 0 666 259,361 209,086 0 43,911 6,364 257,024 1983

11,319 10,685 0 634 264,148 210,925 0 47,256 5,966 261,535 1984

12,112 11,467 0 645 277,922 217,373 0 53,767 6,781 274,427 1985

12,957 12,278 0 679 281,469 222,730 0 51,843 6,895 278,476 1986

13,551 12,831 0 720 282,512 228,121 0 48,205 6,186 279,708 1987

14,840 14,085 0 755 288,599 226,018 0 55,642 6,939 285,711 1988

15,747 15,007 0 740 294,322 224,176 0 63,602 6,544 291,751 1989

15,824 14,738 280 806 300,128 234,101 280 58,664 7,082 297,502 1990

16,202 15,065 298 839 302,764 233,325 607 62,761 6,071 300,654 1991

16,246 15,020 394 832 300,804 221,265 3,358 69,135 7,046 298,547 1992

16,552 15,196 584 772 303,816 193,969 23,195 80,979 5,673 301,868 1993

18,207 16,700 738 769 308,987 185,021 37,553 79,962 6,451 306,936 1994

20,909 19,243 933 733 319,909 183,567 49,458 80,598 6,286 317,627 1995

23,519 19,091 3,358 1,070 334,787 174,665 68,962 85,820 5,340 332,357 1996

25,384 19,703 4,192 1,489 334,106 147,664 90,874 89,341 6,227 331,629 1997

27,669 20,766 5,157 1,746 345,293 149,001 98,162 90,590 7,540 342,699 1998

30,298 21,769 6,785 1,745 351,445 135,262 119,553 87,672 8,958 347,671 1999

33,934 21,926 10,318 1,690 360,765 147,394 126,428 78,334 8,609 357,266 2000

30,391 20,066 8,531 1,794 367,382 147,185 129,875 82,985 7,337 364,173 2001

31,873 19,716 10,049 2,108 370,120 148,511 131,935 81,090 8,584 366,657 2002

34,220 21,942 10,336 1,941 380,073 162,138 128,882 81,911 7,142 376,528 2003

34,165 20,046 11,260 2,859 376,896 153,653 140,243 73,682 9,319 373,399 2004

34,539 19,494 11,204 3,842 380,486 155,493 139,383 75,173 10,438 376,780 2005

34,578 18,598 10,859 5,121 378,779 170,463 126,554 69,237 12,524 373,861 2006

33,779 19,661 11,470 2,649 379,091 162,107 149,127 57,249 10,608 374,019 2007

31,774 18,143 10,947 2,684 372,425 145,420 168,364 47,673 10,968 367,053 2008

32,519 18,898 10,251 3,370 360,241 126,999 159,159 62,762 11,321 355,398 2009

32,002 19,171 9,682 3,149 365,324 132,367 167,500 56,475 8,982 361,112 2010

(1) From 2007, major wind farm companies are included under Major Power Producers,previously wind was covered under other

generators.

(2) Electricity generated less electricity used on works.

(3) Includes electricity supplied by gas turbines and oil engines. From 1988 also includes electricity produced by plants using renewable

sources.

(4) Electricity supplied (gross) less electricity used in pumping at pumped storage station.

(5) Natural flow hydro, wind, wave and solar photovoltaics.


75

10.0 Appendix 2 Levelised Cost of Generation

Gas CCGT- Construction, Operation and Production

Gas CCGT O/A and O&M cost

(£)

Construction

Costs (£)

Operating

Costs (£)

Production/yr

(MW) Year

Year O/A O&M

150,390,688.00 0 0 1

1 36,800,000 26,600,000

421,093,926.40 0 0 2

2 36,800,000 26,600,000

282,975,118.54 90,253.74 10.35 3

3 36,800,000 26,600,000

0 40,291,846.17 4,620.72 4

4 36,800,000 26,600,000

0 35,974,862.65 4,125.65 5

5 36,800,000 26,600,000

0 32,120,413.08 3,683.61 6

6 36,800,000 26,600,000

0 28,678,940.25 3,288.94 7

7 36,800,000 26,600,000

0 25,606,196.65 2,936.55 8

8 36,800,000 26,600,000

0 22,862,675.58 2,621.92 9

9 36,800,000 26,600,000

0 20,413,103.20 2,341.00 10

10 36,800,000 26,600,000

0 18,225,985.00 2,090.18 11

11 36,800,000 26,600,000

0 16,273,200.89 1,866.23 12

12 36,800,000 26,600,000

0 14,529,643.65 1,666.28 13

13 36,800,000 26,600,000

0 12,972,896.12 1,487.75 14

14 36,800,000 26,600,000

0 11,582,942.96 1,328.35 15

15 36,800,000 26,600,000

0 10,341,913.36 1,186.02 16

16 36,800,000 26,600,000

0 9,233,851.22 1,058.95 17

17 36,800,000 26,600,000

0 8,244,510.01 945.49 18

18 36,800,000 26,600,000

0 7,361,169.65 844.19 19

19 36,800,000 26,600,000

0 6,572,472.91 753.74 20

20 36,800,000 26,600,000

0 5,868,279.38 672.98 21

21 36,800,000 26,600,000

0 5,239,535.16 600.88 22

22 36,800,000 26,600,000

0 4,678,156.39 536.50 23

23 36,800,000 26,600,000

0 4,176,925.35 479.02 24

24 36,800,000 26,600,000

0 3,729,397.64 427.69 25

25 36,800,000 26,600,000

Gas CCGT Construction cost %

per year

Year %

1.0 0.2

2.0 0.5

0.8 0.3


76

Gas CCGT with CCS- Construction, Operation and

Production

Gas CCGT with CCS O/A and

O&M cost (£)

Construction

Costs (£)

Operating

Costs (£)

Production/yr

(MW) Year

Year O/A O&M

255,082,240.00 0 0 1

1 79,000,000 45,000,000

285,692,108.80 0 0 2

2 79,000,000 45,000,000

479,962,742.78 0 0 3

3 79,000,000 45,000,000

358,372,181.28 0 0 4

4 79,000,000 45,000,000

200,688,421.52 562,887.44 33.01 5

5 79,000,000 45,000,000

0 62,822,259.03 3,683.61 6

6 79,000,000 45,000,000

0 56,091,302.70 3,288.94 7

7 79,000,000 45,000,000

0 50,081,520.27 2,936.55 8

8 79,000,000 45,000,000

0 44,715,643.10 2,621.92 9

9 79,000,000 45,000,000

0 39,924,681.34 2,341.00 10

10 79,000,000 45,000,000

0 35,647,036.91 2,090.18 11

11 79,000,000 45,000,000

0 31,827,711.53 1,866.23 12

12 79,000,000 45,000,000

0 28,417,599.58 1,666.28 13

13 79,000,000 45,000,000

0 25,372,856.76 1,487.75 14

14 79,000,000 45,000,000

0 22,654,336.40 1,328.35 15

15 79,000,000 45,000,000

0 20,227,086.07 1,186.02 16

16 79,000,000 45,000,000

0 18,059,898.28 1,058.95 17

17 79,000,000 45,000,000

0 16,124,909.17 945.49 18

18 79,000,000 45,000,000

0 14,397,240.33 844.19 19

19 79,000,000 45,000,000

0 12,854,678.87 753.74 20

20 79,000,000 45,000,000

0 11,477,391.85 672.98 21

21 79,000,000 45,000,000

0 10,247,671.29 600.88 22

22 79,000,000 45,000,000

0 9,149,706.51 536.50 23

23 79,000,000 45,000,000

0 8,169,380.81 479.02 24

24 79,000,000 45,000,000

0 7,294,090.01 427.69 25

25 79,000,000 45,000,000

0 6,512,580.37 381.87 26

26 79,000,000 45,000,000

0 5,814,803.90 340.95 27

27 79,000,000 45,000,000

Gas CCGT with CCS

Construction cost % per year

Year %

1.0 0.2

2.0 0.2

3.0 0.3

4.0 0.2

0.2 0.1


77

Coal Plant- Construction, Operation and Production

Coal Plant O/A and O&M cost (£)

Construction

Costs (£)

Operating

Costs (£)

Production/yr

(MW) Year

Year O/A O&M

716,119,040.00 0 0 1

1 140,500,000 106,900,000

802,053,324.80 0 0 2

2 140,500,000 106,900,000

1,347,449,585.66 0 0 3

3 140,500,000 106,900,000

1,006,095,690.63 0 0 4

4 140,500,000 106,900,000

563,413,586.75 280,762.81 15.91 5

5 140,500,000 106,900,000

0 125,340,539.38 7,100.94 6

6 140,500,000 106,900,000

0 111,911,195.87 6,340.13 7

7 140,500,000 106,900,000

0 99,920,710.60 5,660.83 8

8 140,500,000 106,900,000

0 89,214,920.18 5,054.31 9

9 140,500,000 106,900,000

0 79,656,178.73 4,512.78 10

10 140,500,000 106,900,000

0 71,121,588.15 4,029.27 11

11 140,500,000 106,900,000

0 63,501,417.99 3,597.56 12

12 140,500,000 106,900,000

0 56,697,694.64 3,212.11 13

13 140,500,000 106,900,000

0 50,622,941.64 2,867.95 14

14 140,500,000 106,900,000

0 45,199,055.04 2,560.67 15

15 140,500,000 106,900,000

0 40,356,299.14 2,286.31 16

16 140,500,000 106,900,000

0 36,032,409.95 2,041.35 17

17 140,500,000 106,900,000

0 32,171,794.59 1,822.63 18

18 140,500,000 106,900,000

0 28,724,816.60 1,627.35 19

19 140,500,000 106,900,000

0 25,647,157.68 1,452.99 20

20 140,500,000 106,900,000

0 22,899,247.93 1,297.32 21

21 140,500,000 106,900,000

0 20,445,757.08 1,158.32 22

22 140,500,000 106,900,000

0 18,255,140.25 1,034.21 23

23 140,500,000 106,900,000

0 16,299,232.37 923.40 24

24 140,500,000 106,900,000

0 14,552,886.04 824.47 25

25 140,500,000 106,900,000

0 12,993,648.25 736.13 26

26 140,500,000 106,900,000

0 11,601,471.65 657.26 27

27 140,500,000 106,900,000

0 10,358,456.83 586.84 28

28 140,500,000 106,900,000

0 9,248,622.17 523.96 29

29 140,500,000 106,900,000

0 8,257,698.37 467.82 30

30 140,500,000 106,900,000

0 7,372,944.97 417.70 31

31 140,500,000 106,900,000

0 6,582,986.58 372.95 32

32 140,500,000 106,900,000

0 5,877,666.59 332.99 33

33 140,500,000 106,900,000

0 5,247,916.60 297.31 34

34 140,500,000 106,900,000

0 4,685,639.82 265.46 35

35 140,500,000 106,900,000

0 4,183,606.98 237.01 36

36 140,500,000 106,900,000


78

Coal Plant Construction cost % per year

Year %

1.0 0.2

2.0 0.2

3.0 0.3

4.0 0.2

0.8 0.1


79

Coal with CCS - Construction, Operation and Production

Coal with CCS O/A and O&M cost

(£)

Construction Costs

(£)

Operating Costs

(£)

Production/yr

(MW) Year

Year O/A O&M

550,592,000.00 0 0 1

1 284,000,000 163,900,000

1,233,326,080.00 0 0 2

2 284,000,000 163,900,000

1,381,325,209.60 0 0 3

3 284,000,000 163,900,000

1,547,084,234.75 0 0 4

4 284,000,000 163,900,000

1,732,734,342.92 0 0 5

5 284,000,000 163,900,000

970,331,232.04 1,361,520.48 42.61 6

6 284,000,000 163,900,000

0 202,607,213.55 6,340.13 7

7 284,000,000 163,900,000

0 180,899,297.81 5,660.83 8

8 284,000,000 163,900,000

0 161,517,230.19 5,054.31 9

9 284,000,000 163,900,000

0 144,211,812.67 4,512.78 10

10 284,000,000 163,900,000

0 128,760,547.03 4,029.27 11

11 284,000,000 163,900,000

0 114,964,774.13 3,597.56 12

12 284,000,000 163,900,000

0 102,647,119.76 3,212.11 13

13 284,000,000 163,900,000

0 91,649,214.07 2,867.95 14

14 284,000,000 163,900,000

0 81,829,655.42 2,560.67 15

15 284,000,000 163,900,000

0 73,062,192.34 2,286.31 16

16 284,000,000 163,900,000

0 65,234,100.30 2,041.35 17

17 284,000,000 163,900,000

0 58,244,732.41 1,822.63 18

18 284,000,000 163,900,000

0 52,004,225.37 1,627.35 19

19 284,000,000 163,900,000

0 46,432,344.08 1,452.99 20

20 284,000,000 163,900,000

0 41,457,450.07 1,297.32 21

21 284,000,000 163,900,000

0 37,015,580.42 1,158.32 22

22 284,000,000 163,900,000

0 33,049,625.38 1,034.21 23

23 284,000,000 163,900,000

0 29,508,594.09 923.40 24

24 284,000,000 163,900,000

0 26,346,959.00 824.47 25

25 284,000,000 163,900,000

0 23,524,070.54 736.13 26

26 284,000,000 163,900,000

0 21,003,634.41 657.26 27

27 284,000,000 163,900,000

0 18,753,245.01 586.84 28

28 284,000,000 163,900,000

0 16,743,968.76 523.96 29

29 284,000,000 163,900,000

0 14,949,972.11 467.82 30

30 284,000,000 163,900,000

0 13,348,189.38 417.70 31

31 284,000,000 163,900,000

0 11,918,026.23 372.95 32

32 284,000,000 163,900,000

0 10,641,094.85 332.99 33

33 284,000,000 163,900,000

0 9,500,977.54 297.31 34

34 284,000,000 163,900,000

0 8,483,015.67 265.46 35

35 284,000,000 163,900,000

0 7,574,121.13 237.01 36

36 284,000,000 163,900,000


80

Coal with CCS Construction cost % per

year

Year %

1.0 0.1

2.0 0.2

3.0 0.2

4.0 0.2

5.0 0.2

0.4 0.1


81

IGCC - Construction, Operation and Production

IGCC O/A and O&M cost (£)

Construction

Costs (£)

Operating

Costs (£)

Production/yr

(MW) Year

Year O/A O&M

260,096,592.00 0 0 1

1 70,700,000 55,000,000

873,924,549.12 0 0 2

2 70,700,000 55,000,000

978,795,495.01 0 0 3

3 70,700,000 55,000,000

730,833,969.61 0 0 4

4 70,700,000 55,000,000

409,267,022.98 142,651.11 8.65 5

5 70,700,000 55,000,000

0 63,683,531.93 3,861.14 6

6 70,700,000 55,000,000

0 56,860,296.37 3,447.44 7

7 70,700,000 55,000,000

0 50,768,121.76 3,078.07 8

8 70,700,000 55,000,000

0 45,328,680.14 2,748.28 9

9 70,700,000 55,000,000

0 40,472,035.84 2,453.82 10

10 70,700,000 55,000,000

0 36,135,746.29 2,190.91 11

11 70,700,000 55,000,000

0 32,264,059.18 1,956.17 12

12 70,700,000 55,000,000

0 28,807,195.70 1,746.58 13

13 70,700,000 55,000,000

0 25,720,710.45 1,559.45 14

14 70,700,000 55,000,000

0 22,964,920.04 1,392.36 15

15 70,700,000 55,000,000

0 20,504,392.89 1,243.18 16

16 70,700,000 55,000,000

0 18,307,493.66 1,109.98 17

17 70,700,000 55,000,000

0 16,345,976.48 991.06 18

18 70,700,000 55,000,000

0 14,594,621.86 884.87 19

19 70,700,000 55,000,000

0 13,030,912.37 790.07 20

20 70,700,000 55,000,000

0 11,634,743.19 705.42 21

21 70,700,000 55,000,000

0 10,388,163.56 629.84 22

22 70,700,000 55,000,000

0 9,275,146.04 562.35 23

23 70,700,000 55,000,000

0 8,281,380.39 502.10 24

24 70,700,000 55,000,000

0 7,394,089.63 448.30 25

25 70,700,000 55,000,000

IGCC Construction cost % per

year

Year %

1.0 0.1

2.0 0.3

3.0 0.3

4.0 0.2

0.8 0.1


82

IGCC with CCS- Construction, Operation and Production

IGCC with CCS O/A and O&M cost

(£)

Construction

Costs (£)

Operating

Costs (£)

Production/yr

(MW) Year

Year O/A O&M

310,492,560.00 0 0 1

1 154,000,000 87,800,000

1,043,255,001.60 0 0 2

2 154,000,000 87,800,000

1,168,445,601.79 0 0 3

3 154,000,000 87,800,000

872,439,382.67 0 0 4

4 154,000,000 87,800,000

488,566,054.30 274,407.63 8.65 5

5 154,000,000 87,800,000

0 122,503,405.10 3,861.14 6

6 154,000,000 87,800,000

0 109,378,040.27 3,447.44 7

7 154,000,000 87,800,000

0 97,658,964.53 3,078.07 8

8 154,000,000 87,800,000

0 87,195,504.04 2,748.28 9

9 154,000,000 87,800,000

0 77,853,128.61 2,453.82 10

10 154,000,000 87,800,000

0 69,511,721.97 2,190.91 11

11 154,000,000 87,800,000

0 62,064,037.47 1,956.17 12

12 154,000,000 87,800,000

0 55,414,319.17 1,746.58 13

13 154,000,000 87,800,000

0 49,477,070.69 1,559.45 14

14 154,000,000 87,800,000

0 44,175,955.97 1,392.36 15

15 154,000,000 87,800,000

0 39,442,817.83 1,243.18 16

16 154,000,000 87,800,000

0 35,216,801.64 1,109.98 17

17 154,000,000 87,800,000

0 31,443,572.89 991.06 18

18 154,000,000 87,800,000

0 28,074,618.65 884.87 19

19 154,000,000 87,800,000

0 25,066,623.80 790.07 20

20 154,000,000 87,800,000

0 22,380,914.10 705.42 21

21 154,000,000 87,800,000

0 19,982,959.02 629.84 22

22 154,000,000 87,800,000

0 17,841,927.70 562.35 23

23 154,000,000 87,800,000

0 15,930,292.59 502.10 24

24 154,000,000 87,800,000

0 14,223,475.52 448.30 25

25 154,000,000 87,800,000

IGCC with CCS Construction cost %

per year

Year %

1.0 0.1

2.0 0.3

3.0 0.3

4.0 0.2

0.8 0.1


83

Onshore Wind - Construction, Operation and

Production

Onshore Wind O/A and O&M cost

(£)

Construction

Costs (£)

Operating

Costs (£)

Production/yr

(MW) Year

Year O/A O&M

38,109,120.00 0 0 1

1 3,800,000 1,600,000

170,728,857.60 0 0 2

2 3,800,000 1,600,000

0 3,843,613.34 623.52 3

3 3,800,000 1,600,000

0 3,431,797.62 556.71 4

4 3,800,000 1,600,000

0 3,064,105.02 497.07 5

5 3,800,000 1,600,000

0 2,735,808.05 443.81 6

6 3,800,000 1,600,000

0 2,442,685.76 396.26 7

7 3,800,000 1,600,000

0 2,180,969.43 353.80 8

8 3,800,000 1,600,000

0 1,947,294.13 315.89 9

9 3,800,000 1,600,000

0 1,738,655.48 282.05 10

10 3,800,000 1,600,000

0 1,552,370.96 251.83 11

11 3,800,000 1,600,000

0 1,386,045.50 224.85 12

12 3,800,000 1,600,000

0 1,237,540.63 200.76 13

13 3,800,000 1,600,000

0 1,104,946.99 179.25 14

14 3,800,000 1,600,000

0 986,559.81 160.04 15

15 3,800,000 1,600,000

0 880,856.97 142.89 16

16 3,800,000 1,600,000

0 786,479.44 127.58 17

17 3,800,000 1,600,000

0 702,213.79 113.91 18

18 3,800,000 1,600,000

0 626,976.60 101.71 19

19 3,800,000 1,600,000

0 559,800.53 90.81 20

20 3,800,000 1,600,000

0 499,821.90 81.08 21

21 3,800,000 1,600,000

0 446,269.56 72.39 22

22 3,800,000 1,600,000

Onshore Wind Construction

cost % per year

Year %

1 0.2

2 0.8


84

Offshore Wind - Construction, Operation and Production

Offshore Wind O/A and O&M cost

(£)

Construction

Costs (£)

Operating Costs

(£)

Production/yr

(MW) Year

Year O/A O&M

139,328,000.00 0 0 1

1 22,800,000 16,000,000

624,189,440.00 0 0 2

2 22,800,000 16,000,000

0 27617073.62 1,247 3

3 22,800,000 16,000,000

0 24658101.44 1,113 4

4 22,800,000 16,000,000

0 22016162 994 5

5 22,800,000 16,000,000

0 19657287.5 888 6

6 22,800,000 16,000,000

0 17551149.56 793 7

7 22,800,000 16,000,000

0 15670669.25 708 8

8 22,800,000 16,000,000

0 13991668.97 632 9

9 22,800,000 16,000,000

0 12492561.58 564 10

10 22,800,000 16,000,000

0 11154072.84 504 11

11 22,800,000 16,000,000

0 9958993.606 450 12

12 22,800,000 16,000,000

0 8891958.577 402 13

13 22,800,000 16,000,000

0 7939248.729 358 14

14 22,800,000 16,000,000

0 7088614.937 320 15

15 22,800,000 16,000,000

0 6329120.48 286 16

16 22,800,000 16,000,000

0 5651000.428 255 17

17 22,800,000 16,000,000

0 5045536.097 228 18

18 22,800,000 16,000,000

0 4504942.943 203 19

19 22,800,000 16,000,000

0 4022270.485 182 20

20 22,800,000 16,000,000

0 3591312.933 162 21

21 22,800,000 16,000,000

0 3206529.405 145 22

22 22,800,000 16,000,000

Offshore Wind Construction cost

% per year

Year %

1 0.2

2 0.8


85

Offshore Wind - Construction, Operation and Production

Offshore Wind O/A and O&M cost (£)

Construction

Costs (£)

Operating

Costs (£)

Production/yr

(MW) Year

Year O/A O&M

324,800,000.00 0.00 0 1

1 56,700,000 39,100,000

1,455,104,000.00 0.00 0 2

2 56,700,000 39,100,000

0 68,188,547.74 2,494 3

3 56,700,000 39,100,000

0 60,882,631.91 2,227 4

4 56,700,000 39,100,000

0 54,359,492.78 1,988 5

5 56,700,000 39,100,000

0 48,535,261.41 1,775 6

6 56,700,000 39,100,000

0 43,335,054.83 1,585 7

7 56,700,000 39,100,000

0 38,692,013.24 1,415 8

8 56,700,000 39,100,000

0 34,546,440.39 1,264 9

9 56,700,000 39,100,000

0 30,845,036.07 1,128 10

10 56,700,000 39,100,000

0 27,540,210.77 1,007 11

11 56,700,000 39,100,000

0 24,589,473.90 899 12

12 56,700,000 39,100,000

0 21,954,887.41 803 13

13 56,700,000 39,100,000

0 19,602,578.05 717 14

14 56,700,000 39,100,000

0 17,502,301.83 640 15

15 56,700,000 39,100,000

0 15,627,055.20 572 16

16 56,700,000 39,100,000

0 13,952,727.86 510 17

17 56,700,000 39,100,000

0 12,457,792.73 456 18

18 56,700,000 39,100,000

0 11,123,029.23 407 19

19 56,700,000 39,100,000

0 9,931,276.09 363 20

20 56,700,000 39,100,000

0 8,867,210.80 324 21

21 56,700,000 39,100,000

0 7,917,152.50 290 22

22 56,700,000 39,100,000

Offshore Wind Construction cost

% per year

Year %

1 0.2

2 0.8


86

Nuclear - Construction, Operation and Production

Nuclear O/A and O&M cost (£)

Construction

Costs (£)

Operating

Costs (£)

Production/yr

(MW) Year

Year O/A O&M

234,811,136.00 0 0 1

1 146,600,000 101,800,000

1,209,746,972.67 0 0 2

2 146,600,000 101,800,000

1,826,191,951.79 0 0 3

3 146,600,000 101,800,000

1,885,101,369.59 0 0 4

4 146,600,000 101,800,000

3,240,866,274.60 0 0 5

5 146,600,000 101,800,000

945,868,463.21 0 0 6

6 146,600,000 101,800,000

0 112,363,545.09 6,340.13 7

7 146,600,000 101,800,000

0 100,324,593.83 5,660.83 8

8 146,600,000 101,800,000

0 89,575,530.21 5,054.31 9

9 146,600,000 101,800,000

0 79,978,151.97 4,512.78 10

10 146,600,000 101,800,000

0 71,409,064.26 4,029.27 11

11 146,600,000 101,800,000

0 63,758,093.09 3,597.56 12

12 146,600,000 101,800,000

0 56,926,868.83 3,212.11 13

13 146,600,000 101,800,000

0 50,827,561.45 2,867.95 14

14 146,600,000 101,800,000

0 45,381,751.30 2,560.67 15

15 146,600,000 101,800,000

0 40,519,420.80 2,286.31 16

16 146,600,000 101,800,000

0 36,178,054.29 2,041.35 17

17 146,600,000 101,800,000

0 32,301,834.19 1,822.63 18

18 146,600,000 101,800,000

0 28,840,923.38 1,627.35 19

19 146,600,000 101,800,000

0 25,750,824.45 1,452.99 20

20 146,600,000 101,800,000

0 22,991,807.54 1,297.32 21

21 146,600,000 101,800,000

0 20,528,399.59 1,158.32 22

22 146,600,000 101,800,000

0 18,328,928.21 1,034.21 23

23 146,600,000 101,800,000

0 16,365,114.47 923.40 24

24 146,600,000 101,800,000

0 14,611,709.35 824.47 25

25 146,600,000 101,800,000

0 13,046,169.06 736.13 26

26 146,600,000 101,800,000

0 11,648,365.23 657.26 27

27 146,600,000 101,800,000

0 10,400,326.10 586.84 28

28 146,600,000 101,800,000

0 9,286,005.45 523.96 29

29 146,600,000 101,800,000

0 8,291,076.29 467.82 30

30 146,600,000 101,800,000

0 7,402,746.69 417.70 31

31 146,600,000 101,800,000

0 6,609,595.26 372.95 32

32 146,600,000 101,800,000

0 5,901,424.34 332.99 33

33 146,600,000 101,800,000

0 5,269,128.87 297.31 34

34 146,600,000 101,800,000

0 4,704,579.35 265.46 35

35 146,600,000 101,800,000

0 4,200,517.28 237.01 36

36 146,600,000 101,800,000

0 3,750,461.85 211.62 37

37 146,600,000 101,800,000

0 3,348,626.66 188.95 38

38 146,600,000 101,800,000

0 2,989,845.23 168.70 39

39 146,600,000 101,800,000

0 2,669,504.67 150.63 40

40 146,600,000 101,800,000


87

0 2,383,486.31 134.49 41

41 146,600,000 101,800,000

0 2,128,112.78 120.08 42

42 146,600,000 101,800,000

0 1,900,100.69 107.21 43

43 146,600,000 101,800,000

0 1,696,518.48 95.73 44

44 146,600,000 101,800,000

0 1,514,748.64 85.47 45

45 146,600,000 101,800,000

0 1,352,454.14 76.31 46

46 146,600,000 101,800,000

0 1,207,548.34 68.14 47

47 146,600,000 101,800,000

0 1,078,168.16 60.84 48

48 146,600,000 101,800,000

0 962,650.15 54.32 49

49 146,600,000 101,800,000

0 859,509.06 48.50 50

50 146,600,000 101,800,000

0 767,418.80 43.30 51

51 146,600,000 101,800,000

0 685,195.36 38.66 52

52 146,600,000 101,800,000

0 611,781.57 34.52 53

53 146,600,000 101,800,000

0 546,233.55 30.82 54

54 146,600,000 101,800,000

0 487,708.52 27.52 55

55 146,600,000 101,800,000

0 435,454.04 24.57 56

56 146,600,000 101,800,000

0 388,798.25 21.94 57

57 146,600,000 101,800,000

0 347,141.29 19.59 58

58 146,600,000 101,800,000

0 309,947.58 17.49 59

59 146,600,000 101,800,000

0 276,738.91 15.62 60

60 146,600,000 101,800,000

Nuclear Construction cost %

per year

Year %

1 0.035

2 0.161

3 0.217

4 0.200

5 0.307

6 0.080


88

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