23423321 local energy distributed generation of heat and power

IET POWER AND ENERGY SERIES 55

Local EnergyDistributed generation

of heat and power

Other volumes in this series:

Volume 1 Power circuit breaker theory and design C.H. Flurscheim (Editor)Volume 4 Industrial microwave heating A.C. Metaxas and R.J. MeredithVolume 7 Insulators for high voltages J.S.T. LoomsVolume 8 Variable frequency AC motor drive systems D. FinneyVolume 10 SF6 switchgear H.M. Ryan and G.R. JonesVolume 11 Conduction and induction heating E.J. DaviesVolume 13 Statistical techniques for high voltage engineering W. Hauschild and W. MoschVolume 14 Uninterruptible power supplies J. Platts and J.D. St Aubyn (Editors)Volume 15 Digital protection for power systems A.T. Johns and S.K. SalmanVolume 16 Electricity economics and planning T.W. BerrieVolume 18 Vacuum switchgear A. GreenwoodVolume 19 Electrical safety: a guide to causes and prevention of hazards J. Maxwell

AdamsVolume 21 Electricity distribution network design, 2nd edition, E. Lakervi and E.J. HolmesVolume 22 Artificial intelligence techniques in power systems K. Warwick, A.O. Ekwue and

R. Aggarwal (Editors)Volume 24 Power system commissioning and maintenance practice K. HarkerVolume 25 Engineers’ handbook of industrial microwave heating R.J. MeredithVolume 26 Small electric motors H. Moczala et al.Volume 27 AC–DC power system analysis J. Arrillaga and B.C. SmithVolume 29 High voltage direct current transmission, 2nd edition J. ArrillagaVolume 30 Flexible AC Transmission Systems (FACTS) Y-H. Song (Editor)Volume 31 Embedded generation N. Jenkins et al.Volume 32 High voltage engineering and testing, 2nd edition H.M. Ryan (Editor)Volume 33 Overvoltage protection of low-voltage systems, revised edition P. HasseVolume 34 The lightning flash V. CoorayVolume 35 Control techniques drives and controls handbook W. Drury (Editor)Volume 36 Voltage quality in electrical power systems J. Schlabbach et al.Volume 37 Electrical steels for rotating machines P. BeckleyVolume 38 The electric car: development and future of battery, hybrid and fuel-cell cars

M. WestbrookVolume 39 Power systems electromagnetic transients simulation J. Arrillaga and N.

WatsonVolume 40 Advances in high voltage engineering M. Haddad and D. WarneVolume 41 Electrical operation of electrostatic precipitators K. ParkerVolume 43 Thermal power plant simulation and control D. FlynnVolume 44 Economic evaluation of projects in the electricity supply industry H. KhatibVolume 45 Propulsion systems for hybrid vehicles J. MillerVolume 46 Distribution switchgear S. StewartVolume 47 Protection of electricity distribution networks, 2nd edition J. Gers and

E. HolmesVolume 48 Wood pole overhead lines B. WareingVolume 49 Electric fuses, 3rd edition A. Wright and G. NewberyVolume 50 Wind power integration: connection and system operational aspects

B. Fox et al.Volume 51 Short circuit currents J. SchlabbachVolume 52 Nuclear power J. WoodVolume 53 Condition assessment of high voltage insulation in power system equipment

R.E. James and Q. SuVolume 905 Power system protection, 4 volumes

Local EnergyDistributed generation

of heat and power

Janet Wood

The Institution of Engineering and Technology

Published by The Institution of Engineering and Technology, London, United Kingdom

© 2008 The Institution of Engineering and Technology

First published 2008

This publication is copyright under the Berne Convention and the Universal CopyrightConvention. All rights reserved. Apart from any fair dealing for the purposes of researchor private study, or criticism or review, as permitted under the Copyright, Designs andPatents Act, 1988, this publication may be reproduced, stored or transmitted, in anyform or by any means, only with the prior permission in writing of the publishers, or inthe case of reprographic reproduction in accordance with the terms of licences issuedby the Copyright Licensing Agency. Enquiries concerning reproduction outside thoseterms should be sent to the publishers at the undermentioned address:

The Institution of Engineering and TechnologyMichael Faraday HouseSix Hills Way, StevenageHerts, SG1 2AY, United Kingdom

www.theiet.org

While the author and the publishers believe that the information and guidance given inthis work are correct, all parties must rely upon their own skill and judgement whenmaking use of them. Neither the author nor the publishers assume any liability toanyone for any loss or damage caused by any error or omission in the work, whethersuch error or omission is the result of negligence or any other cause. Any and all suchliability is disclaimed.

The moral rights of the author to be identified as author of this work have beenasserted by her in accordance with the Copyright, Designs and Patents Act 1988.

British Library Cataloguing in Publication DataA catalogue record for this product is available from the British Library

ISBN 978-0-86341-739-9

Typeset in India by Newgen Imaging Systems (P) Ltd, ChennaiPrinted in the UK by Athenaeum Press Ltd, Gateshead, Tyne & Wear

Contents

1 Developing the UK’s energy infrastructure 11.1 The development of electric power 11.2 Regulating the industry 21.3 Coordinating the supply 31.4 Centralizing power stations 41.5 Managing the expansion 61.6 The Central Electricity Generating Board 61.7 Monopolies and private companies 71.8 Breaking up the monopoly 91.9 The effect of competition 10Panel 1.1 Generators 12Panel 1.2 AC/DC 13Panel 1.3 Transformers 13Panel 1.4 Power units 14

2 The electricity system 172.1 Supplying and delivering power 172.2 Generating power for the market 172.3 Power-station characteristics 18

2.3.1 Coal 182.3.2 Gas 182.3.3 Nuclear 192.3.4 Hydropower 202.3.5 Wind power 202.3.6 Coping with grid variation 21

2.4 The balancing market 242.5 Distribution network operators 252.6 Regulating the markets 26

3 The heat connection and cogeneration 293.1 Energy use in the UK 303.2 Support for heat and power 303.3 Energy crops 313.4 Domestic heating 323.5 Combined heat and power 32

vi Local energy

3.6 Heat technologies 343.6.1 Biomass 343.6.2 Solar water heating 353.6.3 Ground-source heat 36

Panel 3.1 Ground heat in Cornwall 38

4 Wind power 414.1 Wind-turbine components 414.2 Assessing the wind resource 434.3 Installing a wind turbine 434.4 Rooftop turbines 444.5 Making the connection 46Panel 4.1 Off-grid turbines 46Panel 4.2 Wind across the Mersey 48

5 Hydropower 515.1 Power from water 525.2 The UK’s hydropower potential 535.3 Assessing hydro sites 545.4 Environmental effects 555.5 Adding hydro to the system 565.6 Extracting the energy 56Panel 5.1 Reviving old mills 57Panel 5.2 Hydropower in Snowdonia 58

6 Marine renewables 616.1 Wave and tidal power 616.2 How much energy is there? 616.3 Distributed generation? 626.4 The route from research to industry 62

6.4.1 Marine Current Turbines 636.4.2 PowerBuoy 646.4.3 Pelamis 656.4.4 Fred Olsen 656.4.5 Limpet and Osprey 666.4.6 Stingray 66

6.5 Development issues 66

7 Solar photovoltaics 697.1 Photovoltaic power 697.2 Assembling the PV panels 707.3 Off-grid applications 717.4 Street applications 71Panel 7.1 Sustainable Lambeth 74Panel 7.2 Experience in Grimsby 75

List of contents vii

8 Combined heat and power 778.1 The UK CHP programme 778.2 EU Directive support 788.3 Domestic CHP 798.4 Developing domestic technologies 808.5 Development issues 808.6 Who would buy? 82Panel 8.1 Good projects on paper 83Panel 8.2 London housing 85

9 Biomass 879.1 Biomass fuels 879.2 Heating programmes 889.3 Wood-energy strategies 899.4 Wood for Wales 909.5 Wood-fuel research 919.6 What is pyrolysis? 92

10 Energy storage 9510.1 Diverse energy in the network 9510.2 Pumped storage 9610.3 Gas storage 9810.4 Batteries 9810.5 Centrifuges 9910.6 Moving to a hydrogen economy 99Panel 10.1 Norway’s hydrogen experiment 100Panel 10.2 Hydrogen in Iceland 102Panel 10.3 Battery powered 103

11 Fuel cells 10511.1 How fuel cells work 10511.2 Fuel-cell configuration 10611.3 Solid-oxide fuel cells 10611.4 Fuel-cell applications 10811.5 Developing the industry 109

12 Interacting with the electricity grid 11112.1 Voltage and frequency 11112.2 Voltage 11112.3 Frequency 11212.4 Reactive power 11212.5 Maintaining the supply quality 11312.6 Bringing on the reserve 11412.7 Demand response 11512.8 Dealing with transients 115

viii Local energy

12.9 Transmission/distribution interaction 11712.10 Adding microgeneration 119

13 Making progress on policy 12113.1 Government strategy 12113.2 Planning progress 12213.3 Domestic changes 12413.4 Scotland and Wales approach 12513.5 A microgeneration strategy 12613.6 Re-examining the remaining barriers 12813.7 Licensing 12913.8 Distribution and private wires 129Panel 13.1 How planning works 130

14 Embedded benefits 13514.1 Costs 13514.2 Embedded benefits 13614.3 New incentives 137

14.3.1 Innovation funding incentive 13714.3.2 Registered power zones 137

14.4 Small generators 13814.5 Consolidation 138

15 Connecting and exporting power 14115.1 Connection standards 141

15.1.1 Step 1: Decide on your system 14115.1.2 Step 2: Get a connection agreement 14215.1.3 Step 3: Install suitable metering 14215.1.4 Step 4: Install a ROC meter 14215.1.5 Step 5: Arrange a tariff with your electricity supplier 143

15.2 The connection agreement 14315.3 Rethinking the network 14415.4 Shallowish connection 14515.5 New charging regimes 14615.6 Constraining connection? 147

16 Finance and local generation 14916.1 Renewables Obligation 15016.2 Electricity trading arrangements 15216.3 Climate Change Levy 15316.4 Grants 15416.5 DEFRA support 15516.6 DTI grants 156

List of contents ix

17 Changing the industry: ESCos and cooperative power ownership 15917.1 Energy-services companies 15917.2 The 28-day rule 15917.3 The affinity deal 16217.4 The energy club 16217.5 The CHP scheme 16217.6 Thameswey 16317.7 The legal framework 16317.8 Community Interest Companies 16417.9 Incorporation 16417.10 Not-for-profit 16517.11 Full cooperation 165Panel 17.1 Baywind 166Panel 17.2 Cooperative wind 167

18 Output and generation 16918.1 Load factors and variability 16918.2 Micropower efficiency 17018.3 Progress of the field trial 17118.4 MicroCHP for homes 17118.5 Small-CHP for business 17218.6 Replacing generation? 17318.7 Saving carbon 17418.8 Changing energy patterns 174

19 Putting a price on carbon 17919.1 The EU Emissions Trading Scheme 180

19.1.1 Results from Phase 1 18119.1.2 Setting up the ETS Phase 2 182

19.2 Trading outside Europe 18319.3 Carbon trading for commerce and industry 18419.4 Making the case for local energy 185Panel 19.1 Greenpeace’s wish list 186

Bibliography 187

Index 189

Chapter 1

Developing the UK’s energy infrastructure

1.1 The development of electric power

Scientists first began to understand fully and make use of electricity generation inthe late nineteenth century. Experimenters had been investigating the phenomena ofstatic electricity and magnetism for more than 200 years up to that point and hadreported on a variety of interesting results. Their names are commemorated in someof the units used to measure the effects they discovered – the ohm, tesla and ampere.The IET commemorates one of the most important scientists, Michael Faraday, whoexplored electromagnetic induction during a series of experiments begun in 1831. Hefound that, if he moved a magnet through a loop of wire, an electric current flowedin the wire. The current also flowed if the loop was moved over a stationary magnet.

This is the basic principle of electricity generation: the three ingredients are amagnetic field, an electric current and movement. Any two of these componentstogether will produce the third, so that moving a conductor in a magnetic field willproduce a current, and, equally, passing an electric current through a conductor ina magnetic field will make the conductor move – the principle by which an electricmotor works.

With these three components electricity can be generated – or an electric motorset up – using very simple apparatus and at small or large scale. As a result, once itwas clear that electric current was a useful tool and could be employed in an electriccircuit to produce light or heat, first experimenters and then industry quickly beganto make use of it and, in its very early days, it was produced domestically, in shedsor cellars.

Of course, to generate electricity in a reliable way it was necessary to find a forceto move the conductor within the magnetic field. One way would be to attach theconductor directly to an object moved by some other force. This might be water,for example, falling through a mill wheel, a method that had been directly usedfor centuries to move grindstones for milling flour. In fact, there are mills still inexistence with nineteenth-century electricity-generation apparatus. Using a mill wasparticularly valuable because many had millponds in place, allowing water to beconserved so that it was available at times when the river would otherwise have toolittle water to allow the water-wheel to operate. Dams, ponds and adjustable gates orsluices, used to direct the water and provide a reliable supply for grindstones, could beequally effective at ensuring electricity generation was reliable. Alternative motive

2 Local energy

forces for electricity generators could include wind (‘harvested’ by windmills). Butfor industry, which wanted a 100 per cent reliable source if it was to use electricpower, the most attractive motive force to use to generate electricity was steam.

The steam engine had been invented and developed by Thomas Newcomen andJames Watt, and was already used by many industries. Almost any kind of fuel, butmainly coal or wood, could be used to boil water and produce steam under highpressure, which was originally, in Newcomen’s and Watt’s engines, used to drivepistons. But in 1884 Charles Parsons proposed a steam turbine in which vanes ratherlike those of a windmill (the turbine blades) are connected to a central shaft. Thesteam turns the blades as it expands through them, turning the centre shaft. Thisarrangement can be very efficient, because additional sets of turbine blades can beadded, with each set sized according to how far the steam has expanded. The entiresteam turbine is in a cylindrical casing.

The steam turbine was far more useful for the fledgling electric-power industrythan the earlier steam engines because the result is a rotating shaft ideal for using ina stationary magnet to produce an electric current.

In fact, Parsons’s first model was connected to a dynamo that generated 7.5 kW ofelectricity. That first turbine was soon scaled up, and within Parsons’s lifetime turbineswere built with generating capacity thousands of times bigger. Steam turbines are stillby far the most common method of generating power, whether in so-called ‘thermal’stations, where the steam is produced by burning coal or biomass fuel, or in nuclearstations, where the steam is produced using the heat from nuclear fission. In somecases they are used in conjunction with a gas turbine – known as a combined-cycleplant, or in configurations where waste steam is captured at some point in the processand used for direct heat in a so-called combined-heat-and-power plant. The namesof Parsons and his US competitor George Westinghouse are still to be seen in thecompanies active in the power industry.

The relative simplicity of the electricity-generation process and the use of thesteam turbine meant they were quickly employed in both industrial and domesticapplications. Most were dedicated for use by a single industrial concern, or domesti-cally were used for a few customers of a single site. Initially there was no consistencybetween the different generators: each operated at its chosen current and voltage. Mea-sured in amps, current describes the amount of electric charge moving in the electriccircuit, while the voltage (measured in volts) describes how much energy each unitof charge has – similar to the difference between the number of cars travelling alonga road (current) and the speed at which each is travelling (voltage).

1.2 Regulating the industry

Generation began to come under legislative regulation in the 1880s and 1900s. Thefirst Electricity Act in 1882 allowed the setting up of supply systems by persons,companies or local authorities, and amendments in 1888 made such new enterpriseseasier to set up. A further Act in 1909 regulated planning consent for new powerstations, but by 1914 there were hundreds of independent undertakings, private and

Developing the UK’s energy infrastructure 3

public, in operation. They sold electricity for power and for lighting, meeting demandof nearly 2 TWh over the year. During the First World War, demand increased sharply,as the war machine swung into gear and factories switched to full-scale productionof munitions and machinery.

At this stage there were few connections between local undertakings, and manytechnical differences. Although there were 600 or so generators, they were unableto be fully effective because they were not interconnected. Generators that for onereason or another had to stop producing power were unable to make up the shortfallby importing power from other suppliers, and at the same time companies who wereproducing more than required by their customers could not export the power. Thelack of connecting wires was not the only problem: the different companies stillprovided their power to different specifications and used different technical standards.London alone had 50 electricity supply systems, 24 different voltages and 10 differentfrequencies. Power stations remained unlinked, however, and it was not until 1919that legislation was passed aimed, among other things, at correcting this.

A government committee set up by the Board of Trade and chaired bySir Archibald Williamson had recommended that the electricity supply companiesbe nationalized. The government rejected this proposal, but went ahead with otherproposals to set up an Electricity Commission under the Ministry of Transport and aseries of regional Joint Electricity Boards. The Commissioners regulated the industrybut the joint boards, which were intended to coordinate development, were ineffec-tive. By 1926 total sales of electricity were 5.8 TWh, generated by 478 power stationswith a total capacity of 4 422 MW. Local authorities owned 264 stations and compa-nies owned 215, the biggest of which had more than 100 MW of plant installed. Somegenerators were producing alternating current, while others produced direct current.

1.3 Coordinating the supply

In 1926 the new Electricity Act not only provided for existing undertakings to maintaincontrol of distribution, but also provided for the coordination of new power-stationplanning and the control of power stations. It established a public body, the CentralElectricity Board, which had a remit to standardize electricity supply across thecountry. It also had powers to control power stations’ operations and to establish a‘grid’ of high-voltage transmission lines.

The ‘grid’ was required because small domestic power generation was steadilybeing replaced by larger, more efficient power stations that served hundreds or thou-sands of users. This allowed for economies of scale, but transmitting electricity alongelectric wires can mean that much of the energy is dissipated – depending on the typeof wire, energy can be lost as heat, for example; this is the principle by which thetraditional incandescent light operates.

However, the rate at which energy is dissipated varies depending on the voltageand current measured in the wire. A high current, when lots of charge is moving inthe wire, has a much greater heating effect than a high voltage. The total energy is aproduct of the voltage and the current. Another result of this relationship is that, if

4 Local energy

the energy remains the same, a higher voltage must result in a lower current, and viceversa. At lower current, less energy is dissipated and there is potential to transportmuch more power.

Power designers took advantage of this relationship in designing electricity trans-port networks, along with another well-known property of electricity: the fact that achanging electric current passing through a coil of wire that generates a magnetic fieldcould induce an electric current in a second, unattached, coiled wire (see Panel 1.3) –an arrangement known as a transformer. The transformer could be used to vary thevoltage and current to produce a very high voltage and therefore a very low current –ideal when power had to be transported long distances – and a second transformercould be used to reduce the voltage and increase the current to the levels used topower appliances.

The result was the complex ‘grid’ that began to take shape after the 1926 report andhas been expanding ever since. Now there is a national grid with some long-distancelines operating at 440 000 V (440 kV) and others at 275 000 V (275 kV) that is usedto transfer ‘bulk’ supplies from major power plants to the major load centres, and anetwork of local connections that carry electricity at 110 kV for local distribution.Transformers are used to ‘step up’ power to high voltages for transmission and to‘step down’ the voltage to feed it into the local network. Finally, more step-downtransformers are used to reduce the voltage to a level suitable for domestic users.

Domestic power supply was standardized at 240 V for many years, althoughrecently the UK voltage has been standardized at 230 V to be consistent with the restof the European power network. Large industrial energy users may take power fromthe network at higher voltage levels depending on their requirements.

1.4 Centralizing power stations

Why was it necessary to develop the high-voltage grid? Even back in 1926 it wasclear that, as the electricity industry was developing, the need to transmit power longerdistances was growing. This was not just to allow power to be transferred betweenneighbouring companies among the 400 or so selling electricity: it also enabled thenetwork as a whole to take advantage of economies of scale. Steam turbines couldbe made to work more efficiently as the size of the boiler and turbine increased, sothe cost of a unit of electricity produced decreased. At the same time, economies ofscale could be made, once again reducing the capital cost per unit of electricity.

Other pressures also drove the trend for larger power stations sited further fromthe areas where electricity was used (the ‘load’ centres). For steam turbines, onereason for the shift was the need to transport huge amounts of fuel to the big newstations.

One of the valuable characteristics of coal is that it can be bought, and transported,from many suppliers worldwide. But the downside is that there can be huge financialand environmental costs in transporting coal from the mine to the power station. If thepower station owner is willing to link the plant closely to a single mine, it is much moreefficient to build so-called ‘mine mouth’ power stations to minimize the distance that


the coal has to be transported. There are other potential benefits to the ‘mine mouth’plant. First, the plant operator can contract for long-term fuel supplies and, second,the detailed design of the plant can be optimized to fit with the characteristics of thecoal, which can vary considerably from deposit to deposit.

China has come up against this issue recently, during its rapid growth in the lasttwo decades and resulting need to supply power to its burgeoning industries. Whilemost of the country’s coal deposits are in the north and west of the country, the majorload centres were, and still are, the fast-growing industrial centres and cities of thesouthwest. Instead of choking the country’s train system by transporting millions oftonnes of coal each day, the country announced a ‘coal-by-wire’ policy to site powergeneration closer to the mines and build high-voltage transmission lines instead.

The recognition that power stations can cause local environmental degradationand emit pollutants that affect its immediate surroundings has also tended to aid theshift towards using sites far away from centres of population and hence areas wherethe power load is highest.

While for coal-fired power stations choice of site is a balance between transport-ing power and transporting fuel, other types of power-generating plant may haveless flexibility in deciding on a site. Traditional water (hydro) power, for example,is immediately restricted to sites on a suitable river or near enough to allow waterto be diverted or stored. What is more, the amount of electricity that can be gen-erated depends on the amount of energy available from the moving water, whichusually requires either a significant drop, or a large volume of water moving throughthe turbines. Mountainous terrain is where suitable hydropower sites are most oftenfound, which are seldom the areas where major load centres are found. That can leadto significant power-management requirements in countries that are heavily relianton water power. Norway, for example, which meets upwards of 90 per cent of itselectricity needs from hydropower plants, has to transport most of its electricity fromthe north of the country to the major cities in the south.

The UK is a windy country, and average wind speeds are favourable for build-ing wind farms in many areas of the country. But good winds ‘on average’ are notnecessarily good enough for a wind farm to make economic sense. Instead, power-generating companies have to search out the sites that offer the best possible windspeeds on the maximum number of days each year – maximizing ‘fuel’ availability.That tends to drive major wind-farm development to particular parts of the country,such as Wales and the far north of Scotland. These areas tend to be those where fewerpeople live and where farming or other low-density activities are more common thanindustry, so the electricity system in these areas tends to be on a relatively small scaleand low in capacity – built to serve a few small users.

The Western Isles of Scotland and the island of Lewis are a good example. Theseareas have among the UK’s best wind resources but have in the past been home tofarming and fishing communities. It is thought that Lewis alone could host severalhundred wind turbines providing electricity equivalent to a couple of the UK’s largestpower stations. But transmitting the electricity to places where it will be used inEngland requires some new high-capacity transmission lines to be built – ‘windby wire’.

6 Local energy

New types of water power will also have the problem of location, to a varyingextent. Some devices rely on a so-called ‘tidal race’, which is typically a channelbetween two areas of sea where the effect of the tide is very pronounced, so that thewater moves much faster through the channel. These are of course entirely restrictedon their location. However, some other tidal devices will have much broader appli-cation and could be used to abstract some energy from less dramatic tides along thecoast and in river estuaries. Wave-powered devices will also be less constrained. Forthese power sources it will be a matter of finding the best possible sites and costingthe transport of power back to shore; the chosen sites will be an economic balancebetween the two.

1.5 Managing the expansion

Building ever-larger and more complex networks to subdivide and deliver the elec-tricity output to users did carry significant cost, and still does. What is more, itrequires transmission lines to be installed across both public and private property.Building new lines is always contentious. But the overall effect of the increasingscale of electricity generation and interconnected systems steadily reduced the costof electric light and motive power.

The National Grid was developed rapidly after the 1926 recommendations. By1933 some 4 000 miles of transmission lines had been completed and by 1935 the gridwas regarded as complete. Rated at 110 kV, it was much smaller and operated at a lowervoltage than the grid in operation today. But it signalled a radical shift in managing theelectricity supply. The fact of the grid’s existence meant that all electricity generatorsand electricity users were connected. For it to work successfully, power generatorshad to supply (‘export’) power to the network within strictly controlled current andvoltage limits. What is more, the power stations could no longer operate entirelyindependently. Part of the intention of the grid was to allow electricity to be movedaround the network to meet users’ needs and to provide backup, for example for powerstations that had to shut down. But, in return for access to supplies from the grid,power-plant operators had to accept that part of their own supply could be divertedto other parts of the network as required, and, what was more, they had to be willingto accept a measure of control from the grid.

In 1939 this was formalized when the grid became a nationally integrated networkwith a National Control Centre under the CEB’s direction.

The savings arising from the grid were large and demand grew rapidly. In 1914electricity sales per head of population had been 77 kWh. By 1939 it was 486 kWh. Atthat time the installed capacity of power stations was 9 712 MW, most new generatorsbeing 30 or 50 MW capacity.

1.6 The Central Electricity Generating Board

In April 1948 the entire industry in Great Britain (except the North of Scotland Hydro-Electric Board, already a public board) was nationalized when the assets of 200


companies, 369 local authority undertakings and the Central Electricity GeneratingBoard (CEGB) were brought together under the British Electricity Authority (BEA) –which was known as the Central Electricity Authority (CEA) after 1954 – and 14 areadistribution boards.

At this time work started on building the 275 kV high-voltage grid (known as thesupergrid) that operates today.

The area distribution boards accepted bulk supply from the supergrid and steppedit down to provide power to domestic properties. The power stations and transmissionnetwork were run by a central authority within the BEA.

In January 1958, following examination of the industry by the Herbert Committeeand legislation, the CEA was replaced by an Electricity Council, whose function wasto act as a central policy-making body for the whole of England and Wales; and aCentral Electricity Generating Board, which was to be responsible for generation andmain transmission in England and Wales, owning such assets as the power stationsand the grid.

The CEGB inherited 262 power stations with a capacity of 24.34 GW, and annualsales of 40.3 TWh and it split the country into five operating regions.

Output increased rapidly in the 1960s and was catered for by a huge programmeof power-station and transmission-line construction. By 1971 the CEGB owned 187power stations with a total capacity of 49.28 GW and had annual sales of 184 TWh.At this time power-station sizes were increasing, and some of the country’s largestcoal-fired and nuclear stations came on line. Within each power station there maybe several ‘generating sets’ or units, each producing several hundred megawatts ofpower.

The largest power station of all was Drax, a coal-fired station in the north-eastwith a total rating of 2 000 MW from its six units, but there were several sites pumpingover 1 000 MW into the grid. In the 1970s the increasing demand and the larger powerstations in operation required still more power to be transferred around the country,and in this decade the 400 kV supergrid was completed.

The largest single-turbine generating set on the grid is currently at Sizewell B,which came on line in 1994 and is rated at 1 200 MW.

1.7 Monopolies and private companies

From its earliest days the electricity supply system was seen as a ‘natural monopoly’and it was still being described in this way in the 1980s. This assumption wasboth a cause and effect of the industry’s development. Economies of scale meantthat building large power stations was more cost-efficient for the electricity gen-erator. But bigger power stations meant more customers were required, withever-greater costs for installing and maintaining an extensive fixed network ofwires.

The industry was capital-intensive: building the generating stations and the net-work was relatively expensive, while producing and delivering the product once theinfrastructure was in place were relatively cheap. A power-generating company had

8 Local energy

to be able to rely on customers over terms of many years to make a return on thecapital invested – and, in any case, electricity supply was quickly seen as a ‘publicgood’, and a requirement almost as basic as a water supply. The result was that it wasassumed that power companies should be awarded monopoly supply rights withintheir areas.

In the UK, that meant a single supplier over the whole of England and Wales –eventually known as the Central Electricity Generating Board – and two othermonopoly suppliers in Scotland: the South of Scotland Electricity Board and theNorth of Scotland Hydro-Electric Board. Within these power monopolies were gen-erating stations, a high-voltage transmission network and local ‘area boards’ thatoperated the low-voltage network and supplied power to domestic customers.

This industry structure was largely replicated worldwide. Local or nationalmonopolies generated and supplied electricity within a defined area and manywere owned by the national or local government corresponding to theirservice area.

Since they were monopolies, their investments and customer pricing were over-seen by the government. In some cases – notably in the USA – power companieswere privately owned, but their ability to decide investment and set customer priceswas limited by independent Public Utility Boards, who scrutinized utilities’ work andinvestment programmes and agreed what prices were allowable.

The monopoly structure helped determine the industry’s development. It workedextremely well and customers – especially domestic customers – could assume thata reliable and unlimited supply of electricity was available at all times. Once areliable supply of electricity could be assumed to exist in every house, appliancescould be developed to make use of it. From fridges and irons, to PlayStations andhome cinemas, there was no restriction on domestic electricity use. Demand couldgrow ever higher, while suppliers with large service areas tended to invest in ever-larger power-generating stations, to meet their customer needs, and build them atthe most economic site, generally near the fuel source and away from populationcentres.

A similar development had been under way in the supply of gas. A networkof pipes had been installed, supplied at first by local ‘gas works’ and later directfrom North Sea and other reserves. As with the electricity network, a state-ownedmonopoly – British Gas – was set up to procure gas and supply it to domestic andindustrial customers. The UK’s gas network is still less extensive than the electricitynetwork, thanks partly to the high cost of burying pipes to serve small groups ofisolated customers, but also partly because once an electricity supply is in placeit can provide the heat that the gas would supply, both for space heating and forcooking, while also powering all kinds of other appliances. With an electricity supplyin place the arguments for a gas supply become still less favourable. Nevertheless,the UK’s gas network is very extensive, and this is an important factor in electricitydecentralization.

The monopoly paradigm began to change at the end of the 1980s. In the UK,a series of publicly owned industries had already been sold to private investors,including the gas network. The CEGB was next on the list.


1.8 Breaking up the monopoly

As well as privatizing the CEGB, the Conservative government under Prime Minis-ter Margaret Thatcher also wanted to shake up its monopoly supply function, on thegrounds that competition would be more efficient, would lower prices and encourageinnovation. Clearly, there would be limited areas where competition was possible:building new wires alongside those already existing and inviting customers to switchbetween them was no efficiency improvement. Nor could the government achieve itsaims by simply splitting the CEGB geographically: that would result in a patchwork ofmonopoly suppliers instead of just one. Instead, the government split the industry byfunction. Electricity generation and supply to customers were two areas where compe-tition could be introduced. Operating the high- and low-voltage networks constitutedmonopoly activities and would remain so.

The result was a split into generation, transmission, distribution and supply thathas been widely copied among other countries that have also been changing theoperating model of their power industries. This model conceives the industry not asunique, but as very similar to other industries where manufacturers sell their productswholesale to retailers who supply individual customers. In this model, products aretransferred from manufacturer to retailer to customer via road, rail, post, etc., using,but not owning, other freight infrastructure.

Similarly, in the so-called ‘deregulated’ electricity industry, a group of generatingcompanies build and operate electricity-generating plants to manufacture electricity.They sell their electricity in bulk to supply companies with thousands or millionsof small customers (or sometimes direct to very large users such as heavy industry).The supply companies, or electricity retailers, are the industry face that domesticusers see, and customers can switch between them without needing to make physicalchanges to their supply.

The electricity networks play the role of, say, the road network. Bulk power istransmitted across the high-voltage ‘motorways’ – owned (in England and Wales)and operated by a company now called National Grid Electricity Transmission(or just National Grid) – and is then stepped down on to the distribution net-work. These local, low-voltage networks are owned and operated by so-calleddistribution network operators (DNOs), which step down the power still furtherand distribute it to individual premises and houses. The National Grid and theDNOs are monopolies, whose income is from ‘tolls’ paid by the generating andsupply companies and who supply various other services to keep the networkrunning.

The result is that what were parts of the same industry now have very differentfunctions and operate in very different ways. The companies that retail electricityare more like other major consumer companies such as banks, focused on providingservices for thousands or millions of customers. Among their major functions ascompanies are managing their customer information, billing and collecting payment.In the 1990s this reinvention as ‘home service’ companies led them to expand intoother services, such as providing vehicle-breakdown cover or financial services. Atthat time the strategy was not very successful, except in closely related industries so

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that most energy retailers supplied both gas and electricity. Now, however, the modelhas been revived, as other consumer companies such as supermarkets have begun tooffer electricity supply deals.

The transmission and distribution companies remain superficially similar asbusinesses. They maintain, and where appropriate expand, a fixed network andare paid via tolling fees that are governed by an independent regulator, the Officeof Gas and Electricity Markets (Ofgem). The transmission operator National Gridhas additional roles in balancing supply and demand and managing an active net-work, whereas the local networks are passive, as we will see (Chapter 5). Bothare seen as relatively stable industries with low risk and relatively low returns oninvestment.

The generation companies have operations that are still rather similar to thoseof the corresponding section of the CEGB, but the market in which they operate isvery different. Building generating plants under a monopoly supplier was a low-riskactivity, centrally planned and with assured customers for the life of the plant. Nowgenerators compete on price to sell their supplies to retailers, and their investment isdriven by a market that may provide very little information about trading conditionsover the life of any new plant built. So-called ‘forward prices’ give some indicationof whether the electricity price is likely to rise (responding to a shortage of powerstations) or fall (in response to overcapacity). But this indication extends only a fewyears ahead, whereas power stations are immense capital investments that requirecustomers over two to four decades to provide their owners with a return on invest-ment. Since a number of companies are making investment decisions in response tosimilar market conditions, the industry tends to swing from boom to bust and backagain. The UK generating market was described as ‘bust’ by one generating com-pany in 2002, for example, but by the winter of 2005–6 generating capacity was verynear demand, leaving little margin for emergencies, and prices had risen to recordlevels.

Although companies are required to keep activities in the different parts of theindustry separate, many large utility companies now have interests in both retail andgenerating sectors. A stake in the generating sector ensures that companies will havesufficient electricity to meet their customers’ needs even in times of shortage, andthe peaks and troughs of retail and generating businesses will be different, givingcompanies more surety over their long-term return.

1.9 The effect of competition

The industry privatization was successfully completed in the early 1990s, and com-petition did, as planned, take effect in the generating and retailing of electricity. Whatit did not do was open the industry to different forms of generation and models ofelectricity supply – in fact, the reverse happened. With a customer base of millionsand guaranteed income in perpetuity, the CEGB had an enormous research budgetand could – in theory – invest in new forms of generation that might not providean economic return for many years. One continuing complaint against the company,


however, was that public-sector inertia and an institutional belief in the existing modelof ever-larger central power stations combined to stifle innovation.

But when the private electricity generators took over, the basis on which theycould compete for customers among the retail companies was mainly the price ofthe electricity they supplied. This drove down electricity prices for the whole of thelate 1990s and the early years after 2000, partly because efficiency improvementsmeant there were savings to be made, but also because oversupply drove pricesdown further. Investment decisions were driven not by the possibility of changingthe power system but by the need to build any new power-generating capacity asfast as possible, and at as low a capital cost as possible, so it could start earningincome for the company immediately. The result was a so-called ‘dash for gas’ dur-ing the 1990s. Gas-fired electricity generation was very well understood, but hadnever been favoured – in fact was under a moratorium – under the CEGB, whichconsidered that gas was far too expensive and useful in direct supply to be convertedto electricity. But for private electricity generators gas was ideal. The gas-turbinestations could be built extremely quickly – within 18 months, once planning permis-sion had been obtained – so they began paying back on their investment very fast.The investment was relatively low, as gas-fired stations were cheap to build. Whatwas more, gas was a ‘clean’ fuel: it did not produce the emissions associated withcoal-fired plants, including sulphur dioxide and particulates, that were the subject ofincreasingly stringent regulations, requiring ‘cleanup’ technologies to be fitted to theplant and both incurring new capital costs and reducing the plant efficiency. It wastrue that running costs of gas plant could be high, and it was very vulnerable to highgas prices, but the plants could be started up and switched off fairly quickly, so itwas possible to stop operating them at times of oversupply when electricity priceswere low.

As with the electricity generators, so with the retailers. They compete on price,and, what is more, their domestic customers traditionally had little interest in orunderstanding of how or where their electricity was generated. The retailers wereunlikely to find much take-up for different supplies, and this was borne out by theexperience of so-called ‘green’ tariffs, which offered customers access to electricityproduced from renewable sources – but at a higher price. The proportion of customerstaking up the option was vanishingly small.

Elsewhere, an alternative model for electricity generation was being exploredthat went right back to the UK’s early electricity industry. Countries where therewas no electricity infrastructure already existing were developing one that lookedrather like the UK’s early industry, with local electricity generation for local use, andgradual linkages forming between local areas to exchange supply and supply backupwhere necessary. This ‘distributed’ model was somewhat different from the earlydays in the UK. First, with standards in place across the developed world, electricitysystems tended to be able to link. Second, new forms of electricity generation werebeing developed, and old ones updated, that could be employed at very small scaleand without the drawbacks of previous technologies. Solar photovoltaic panels andbattery storage, for example, offered clean generation and minimal running costs,compared with using a diesel generator.

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There was a second benefit to generating and using electricity locally: transmis-sion, at high or low voltage, necessarily involves significant energy loss throughthe wires. Using the electricity at or near the generation point could balance out theeconomies of scale and be more efficient. What is more, if a heat process was used,such as a steam turbine, the excess heat that would otherwise have to be dissipatedvia a cooling tower or other ‘heat sink’ could be used. It was available for industrialprocesses, if some were or could be sited near the power plant, or it could be used tosupply heat to local buildings. This type of combined-heat-and-power (CHP) plantwas overall much more efficient.

Neither the UK’s privatized system nor its power market supported this type oflocal generation. By 2000 it was clear that government intervention would be neededto change the market structure to force it to invest not only in new types of generationsuch as renewables, but also to shift the balance in the UK away from a centralizedsystem so that electricity could be generated at whatever scale and site it was mostefficient. That would mean that, as well as central power stations, there would beelectricity fed into the system from a huge variety of local projects ‘embedded’ intothe lower-voltage parts of the network. It could make the network more efficient, morereliable and cheaper to operate – but it would clearly require government interventionand financial incentives to make the shift.

Panel 1.1 Generators

Most metals have electrons that can detach from their atoms and move around.The loose electrons make it easy for electricity to flow through these materi-als, so they are known as electrical conductors. They conduct electricity. Themoving electrons transmit electrical energy from one point to another.

Electricity needs a conductor in order to move. There also has to be somethingto make the electricity flow from one point to another through the conductor.One way to get electricity flowing is to use a generator.

A generator works by electrical induction. It consists of a coil of wire rotatedbetween the poles of a magnet. Because the coil is rotating, it produces an elec-tric current that varies regularly, known as an alternating current. As the coilmakes one revolution, one cycle is produced, so that the frequency of the cur-rent equals the number of revolutions per second made by the coil. In practicethe coils are wound in a soft iron cylinder known as an armature. In a powerstation the armature containing the coils remains stationary and is known as thestator, and instead the magnetic field is rotated around it and is referred to asthe rotor. A turbine turned by steam pressure, falling water, wind, etc. is usedto provide the rotation, which in large power stations can be at 50 turns persecond, the same as the grid supply (‘synchronized’).

In an AC generator the current is supplied to the external circuit by twoso-called ‘brushes’, spring-loaded graphite blocks that press against two copper‘slip rings’, which rotate with the axle.


In power stations the stator coils are in three sets and the rotor coils are inthree sets at 120 degrees to each other. This effectively produces three varyingsupplies that when superimposed provide a steadier power supply, which isknown as a three-phase supply.

Panel 1.2 AC/DC

Current describes the drift of electrons (and in some cases other charged parti-cles) under the influence of an electric field. For many of the electrical effectswe require, such as the heat and light produced by the current in a wire, thedirection of movement of the electrons is not important. The drift can be in onedirection, which is known as direct current (DC), and is produced, for exam-ple, by a battery in a circuit. However, electricity is more usually generatedand transmitted as an alternating current (AC). When necessary AC can be‘rectified’ to produce DC.

AC has at least three advantages over DC in a power-distribution grid:

• Large electrical generators generate AC naturally, so conversion to DCwould involve an extra step.

• Transformers must have alternating current to operate, and the power-distribution grid depends on transformers.

• It is easy to convert AC to DC but expensive to convert DC to AC, so, ifyou were going to pick one or the other, AC would be the better choice.

Panel 1.3 Transformers

A transformer changes an alternating voltage from one value to anotherusing the mutual-inductance principle. It can be used to increase (step up)or decrease (step down) the voltage and current. Electricity substations gen-erally house transformers that are stepping down the supply for domestic orcommercial use.

In a transformer two coils called the primary and secondary windings arewound around an iron core. When an alternating current passes through onecoil, known as the primary, it results in a fluctuating magnetic field, whichinduces an alternating current in the other, secondary, coil.

The amount of voltage induced in the secondary coil depends on the num-ber of turns in the two coils. If they have equal numbers of turns, the voltageinduced in the secondary coil is equal to that in the first. If the number of turns inthe secondary coil is twice that in the primary, then the voltage induced will be

Continues

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Panel 1.3 Continued

‘stepped up’ and will be double that in the primary coil. If the number of turnsin the secondary coil is half that in the primary coil the voltage induced in thesecondary coil will be ‘stepped down’ to half that of the primary coil.

Panel 1.4 Power units

How much work can you get done in a second? If you are a car, how far canyou drive? If you are an electric current, what kind of appliance could you run?For an engineer, power is defined as the energy available to get work done ineach second. Now we refer to it in watts (shortened to W), although it may havebeen easier to understand when it was referred to as horsepower.

For electricity, the power available depends on two characteristics: the ‘cur-rent’ through the wires, which measures how much electricity is flowing; andthe ‘voltage’, which measures how much ‘push’ it has. Compare it to the trafficon its way around the M25: the current is more or less the number of cars pass-ing at a single instant and the voltage is more or less their speed. To get an ideaof the amount of power available, you need to know both. Similarly, you cancalculate electrical power by multiplying the voltage and the current together.

A watt is a fairly small unit – there are around 750 W to the horsepower. Toget an idea of how much power you are using, consider the examples here.

The amount of power that can be provided by an electric generator varieshugely. The large power stations that dot British coalfields are each sendingseveral hundred million watts into the grid. Local renewable-energy projectsare often sized at a few thousand watts, while new wind turbines are up to amillion watts.

Another way of looking at power is not how much is being used at any onesecond, but how it adds up over time. This is also the ‘unit’ on your electric-ity bill – kWh, where k is just shorthand for 1 000. It’s a measure of the totalelectricity you have used – and how much you are paying, so it’s something toremember when you want to save energy. A low-energy light bulb doesn’t seemto draw much less power than an old-fashioned one. But multiply that by thenumber of hours it operates and you will see significant savings over a year.

1 W (calculator)40 W (light bulb)100 W (TV)1 000 W (iron)1 000 000 W (factory)80 000 000 W (UK capacity)


In scientific text there is a standard shorthand, accompanied by a standardsymbol, so that engineers and researchers from Moscow to Manchester can bequite confident that they are talking about the same size.

p pico trillionthn nano billionthµ micro millionthm milli thousandth0k kilo thousandM mega millionG giga billionT tera trillion

Once you start to pick it apart, it becomes fairly easy to work outthat 1 kg is 1 000 grams, 1 MW is 1 000 000 watts, and so on. And although teramay seem like a lot, the UK uses several hundred terawatt hours of electricityevery year and the USA uses nearly 3 500 TWh, so it is barely big enough.

Mega is the one representative of this group that has infiltrated nontechnicalspeak to any extent.

Chapter 2

The electricity system

2.1 Supplying and delivering power

The UK’s electricity supply system works in much the same way as the supply of anyother commodity. Electricity is ‘manufactured’ at power stations, and bulk suppliesare transported across the high-voltage transmission network. Retailers (‘suppliers’)buy the bulk power and sell it on to domestic and commercial customers, to whomit is supplied via a low-voltage local network operated by a distribution networkoperator (DNO).

The generators, high-voltage network operator (National Grid), DNOs andretailers are very different companies.

2.2 Generating power for the market

The generators and retailers operate in a competitive market, making contracts directlywith one another to buy and sell power. The amount of electricity that is required canvary markedly. Generally the highest demand is in the winter, when people tend tobe inside and it is dark for longer, so they are using more appliances. Although thereare heavy industries that require large amounts of power continuously, it is usuallydomestic use that governs the peak load. So the highest peak is on winter eveningsbetween 6 p.m. and 9 p.m., when most people are arriving home, making dinner andusing domestic appliances, and there is a smaller peak in the early morning.

The overall load in summer is lower than in winter but the increase in hot summersand the growing use of air conditioning have meant that the summer peak is increasing.This has important implications for the way the UK electricity system is managed. Inthe past, major repair and maintenance projects were planned for the summer months,when demand for electricity was traditionally low, so some plants could be out ofaction for weeks or months.

In July 2006, electricity demand increased dramatically in response to a weeks-long heat wave, as homes and businesses turned up existing air conditioning andstripped DIY stores of new air-conditioning units and electric fans. With avail-able capacity at its summer low, the National Grid had to warn that the systemwas dangerously close to its limit and appeal for demand reductions. In the longterm, this may require generating companies to alter their traditional maintenancestrategies.

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While the electricity being used varies dramatically, from up to 60 GW on awinter’s evening to around 30 GW at low-demand periods, the amount of electricitybeing supplied to the system is also changing.

2.3 Power-station characteristics

Different types of power station have different characteristics. This diversity is gen-erally regarded as a benefit, as it helps the system to meet the varying demand. It isalso an economic benefit, as it means the system as a whole does not rely on a singlefuel such as gas, and there is some protection from price rises of a single fuel.

So-called thermal power stations are those that rely on burning to turn a gas orsteam turbine.

2.3.1 Coal

Coal was for many years the most common thermal fuel and still provides up to athird of the UK’s power generation and around half of all the electricity generatedworldwide. It is attractive to power companies for several reasons. First, it is arelatively flexible form of generation, meaning that most plants can operate at lessthan their full capacity if required (at ‘part load’), and the amount of fuel burned andthe electricity output can be varied from hour to hour to follow changing demand.Fuel is fed in constantly during the operation.

A second attribute valuable for generating companies is that coal can be boughtfrom a wide variety of suppliers and transported by ship and rail. What is more, thecoal can be stockpiled so there is a reserve in case of need.

Coal, however, produces the most carbon dioxide emissions of all generatingtypes, along with other harmful emissions such as sulphur dioxide, nitrogen oxides,mercury and particulates. New coal plants will include additional systems to reducemost of those emissions, and similar cleanup systems have been ‘backfitted’ to exist-ing stations. However, they do affect the economics of running the plant, as theyreduce operating efficiency, meaning that more coal has to be burned to produce eachunit of electricity.

2.3.2 Gas

The UK generators began building gas-fired turbines in the 1990s, and gas now meetsnearly half of UK electricity demand. Gas and compressed air are combusted directlyinto a turbine, which works on the same principle as a steam turbine, connecteddirectly to a generator. The gas turbine is much more efficient than a steam turbine,both because it is operating at a much higher temperature and because there is no‘steam raising’ where energy can be lost. Gas turbines can be started up and shutdown, if necessary, over a period of several hours to less than an hour, so they can bebrought on line to meet peak loads, and in fact some are used specifically to meet peakloads, being started up and shut down twice each day. They have been less flexiblethan coal plants once in operation, although more recent versions are being designed

The electricity system 19

to operate more economically at part-load, but they can be sized at between one andseveral hundred megawatts, so they can allow mid-scale additions or removals ofcapacity from the system. They require constant fuel feed-in during operation.

In recent years so-called ‘combined cycle’ gas-fired plants have been used. Theseplants make use of the ‘waste’ heat from a gas turbine. Although it is referred to aswaste, because the conventional gas turbine burns gas at such a high temperature (theturbine inlet temperature is around 1 000 ◦C), the gas being expelled is hot enoughto produce steam that, in its turn, can be used in a steam turbine. This dramaticallyincreases the power available from the plant. There is some loss of flexibility in oper-ation as there are more processes to manage, so combined cycle plants are generallyused in constant operation (known as base load).

In recent years other fuels have been used to produce thermal power, includingbiomass (e.g. wood and straw), or methane gas produced from sewage or abstractedfrom landfill.

2.3.3 Nuclear

Nuclear stations vary in size but some are among the largest power stations on thegrid – Sizewell B, the largest, is rated at 1 400 MW – so they provide an enormous inputof power. What is more, they can provide that power over a long period, as fuel loadingis infrequent. They can operate for one or two years between shutdowns, depending onthe operating regime, and at very predictable cost as the fuel is a relatively minor partof their operating cost. But they are extremely inflexible in operation. Although it ispossible in some cases to vary their output slightly, it is technically and economicallyundesirable. It is a favourable option in countries where there are energy-intensiveindustries with continuous high demand, such as Sweden and Finland, or wherethere are neighbouring markets where oversupply can be exported, as happens withFrance’s large nuclear capacity. The UK has around 20 per cent nuclear on the system.Nuclear plants are also the slowest option to bring into operation, as they can takeseveral days to bring up to full power.

Thermal and nuclear generators include large rotating machinery (the turbine)that produces the electricity; in the context of the grid, this means they add stabilityto the operation. In theory, electricity flows through the grid at a steady frequency of50 Hz and maintains a constant voltage. In practice, these parameters are maintainedthanks to painstaking management and balancing actions, and by ensuring that, asfar as possible, all the generators and loads connected to the system tend to return tothat steady state after any disturbance. In practice, the flow of electricity is frequentlychanged, not just by new loads or generators connecting to or disconnecting fromthe grid but also by any number of disturbances on various scales. The result can besudden changes in frequency or voltage and they can affect large power equipmentas much as domestic-scale appliances such as PCs (computer shops sell sockets withbuilt-in protection against such ‘spikes’ and disturbances in the supply). This issueof ‘power quality’ is discussed in Chapter 8.

Power plants are often set up to detach automatically from the grid if there arelarge disturbances in the grid supply, as a self-protection measure. Disconnection, in

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turn, creates a new disturbance, so faults can propagate and the effect can spread.However, the heavy rotating machinery in thermal and nuclear plants has a certainamount of momentum that will carry them through grid disturbances (this is knownas fault ride-through) and this adds stability to the grid as a whole.

2.3.4 Hydropower

Hydropower has among the fastest responses in the system. There is no fuel to burn,so as long as there is water in the associated reservoir or river it is only a matterof opening the gates within the plant, so water passes through the turbines, andgeneration is available within seconds to minutes. This is the attribute employed bypumped-storage plants: water is pumped uphill to a reservoir at times when there isexcess power available on the grid, and released to generate at peak times. However,from a ‘fuel’ point of view, over the year there are periods when water levels are lowand this can force so-called run-of-river plants – those where there is no reservoir –out of operation. Operators of hydro plants with water stored in reservoirs have todecide whether to use their stored water to generate now, or save it for a later datewhen it may be needed more.

This is a mainly financial decision in a mixed system such as the UK’s, but far moreimportant in countries such as Norway that have a very high reliance on hydropower.Elsewhere it has led to accusations that hydro companies are ‘gaming’ the market –holding back water supplies unnecessarily to exacerbate a power shortage and forceup the price of electricity.

2.3.5 Wind power

Wind power now provides a small proportion of the UK’s power. Since it is availableonly when the wind is blowing, it is impossible to guarantee that power is availablewhen it is most needed (at peak times, for example). The power has to be accepted onto the grid whenever the wind blows, and other forms of generation have to be cycledup or down to adapt. In the UK this is easily accepted on to the grid, as wind penetrationis very low and wind forecasting is very good, not least because in the current marketdecisions on how much power is available and required are calculated within an hourof dispatch, and over such timetables short-term prediction is extremely reliable.

Wind farms can offer fast response in some circumstances: if a large wind farm isin operation and expected to be so for the next hour, it can provide an extremely fastresponse to changes in demand on the grid over the short term. In that case the windfarm would be gradually ‘turned down’ in advance of an expected peak by altering thepitch of the blades so less wind is ‘caught’, and then turned up quickly by returningthe blades to maximum pitch, then kept there as slower-response forms of generationsuch as coal stations are brought up to power.

However, predicting whether the wind farm will operate over days, weeks ormonths is progressively less reliable. Recent work has confirmed that there is almostnever a situation when there is no wind blowing anywhere in the UK, but there arefrequent periods when smaller regions have no wind. As a result, there is a limit


to how much conventional generation they can replace on the system and, althoughestimates vary depending on other grid characteristics, its value may begin to decreaseabove 10 to 20 per cent wind. In recent years the National Grid has estimated that,although the natural variability of wind power would eventually add to the cost ofoperating the UK system, the technical effect of the variability is insignificant up toat least 10 per cent wind penetration, as the variability is barely detectable withinthe natural variability of the mixed system as a whole. Grid stability may also beaffected at high wind penetration because wind is generally designed to disconnectin the event of a fault, although the ‘fault ride-through’ of conventional generationcan now be replicated using electronic systems.

2.3.6 Coping with grid variation

The UK’s power system is well placed to cope with all these different sources, andindeed their diversity gives system operators a useful set of different options to meetthe system’s varying needs.

Power plants do not operate continuously. As we have seen, some are designedto operate only during peak periods and are expected to shut down twice a day. Thereare other types of planned closure: they have to be shut down at regular intervals toallow maintenance work to be carried out, for example. Maintenance shutdowns varyin frequency and length depending on the type of plant involved, but can vary from afew days to a few weeks if there is major work to be done. Most of these maintenance‘outages’ are currently planned for the low-demand periods in the summer, whichalso means that the total amount of electricity available to the system at such timesis much lower. This can mean demand surges are difficult to meet, even though thesurge is still much lower than the winter peak: this was the case in summer 2006, whendemand for air conditioning during July’s hot weather meant the system operator hadto send out an emergency call for more power.

As well as planned outages, plants can suffer unplanned shutdowns for a number ofreasons. They may be shut down as a self-protection measure if there are disturbanceson the grid that could affect the power station. Alternatively, problems inside thepower station or in the switchyard (which connects the station to the power lines)could shut the plant down.

As well as plants coming in and out of service, they also have different operatingcharacteristics depending on local conditions. Wind is the most obviously affected: itdoes not generate if the wind does not blow. But it is not the only plant where weatherhas an important role to play. Gas turbines, for example, are greatly affected by theexternal temperature. They work by burning natural gas or a fuel oil with a fixedvolumetric rate of compressed air, so a turbine’s power output is directly proportionalto the mass rate of the compressed air that enters the system. When the weathergets hotter, the mass rate of the compressed air decreases because warmer air has alower density, so the turbine’s power output decreases. The effect is marked when thesurrounding air temperature is above 30 ◦C. If surrounding temperatures are above40 ◦C – unlikely in the UK but common in other countries – power supplied can dropby 35 per cent.

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This characteristic of combustion turbines is very unattractive for the powerproducers because they have less power to sell, just when the increase in outsidetemperature creates more power demand for air conditioning and the market price ofpower is also high.

The weather may also have indirect effects. Power stations that abstract waterfrom neighbouring water sources such as rivers to provide cooling are strictly limitedin the heat they can release to the river. In hot weather and especially at times of lowriver flow, when the river’s ambient temperature is high, it may not be possible toadd any heat at all without breaching the upper permissible limit. In 2004 and 2007several of France’s large power stations were unable to operate for this reason.

Similar temperature-dependent effects are felt throughout the system. In just twoexamples, the capacity of the transmission line alters depending on the temperaturebecause the high-tension cables expand and sag more at higher temperatures – a400 kV line currently has a capacity of 2 190 MVA in summer and 2 720 MVA inwinter.

Faults on the grid can also interrupt supply. Extreme weather events also placestresses on the system, and National Grid identifies high winds (in excess of 40 knots),high ice loads, low temperatures (and consequent fog and icing), heavy rain, lightningand salt pollution as likely to contribute to weather-related faults. Managing thesefaults requires investment in the high-voltage transmission system.

Lightning strikes are relatively frequent, and their effect can be partly designedout by using autoreclosers, which can trip and then reclose either automatically oron instructions from the control room. Some protection is built in. For example, thewest coast is subject to salt pollution from high winds. Protection takes the form of aspray that is released when the salt burden gets too big.

Electricity is bought and sold in the UK through a system known as the BritishElectricity Trading and Transmission Arrangements (BETTA). As National Gridexplains, the arrangements are based on bilateral trading among generators, suppliers,traders and customers, in any paired combination, across a series of markets operat-ing on a rolling half-hourly basis, which means that it is managed in half-hourly timeslots. Electricity can be bought and sold up to an hour before the start of the half-hourin question – known as gate closure. There are three stages to the wholesale market.

The bilateral-contract markets for firm delivery of electricity allow contracts tobe signed from a long time – a year or more – in advance of dispatch (i.e. the actualpoint in time at which electricity is generated and consumed) to as close as 24 hoursahead of real time. The markets provide the opportunity for a seller (generator) andbuyer (supplier) to enter into contracts to deliver or take delivery of, on a specifieddate, a given quantity of electricity at an agreed price.

This includes long-term contracts between the generators and the large users orretailers. These contracts may include special conditions that give generators flexibil-ity in return for a discount. Buyers that are willing to accept ‘interruptible’ contracts,for example, accept a risk that, if demand exceeds supply, they will stop receivingelectricity to reduce demand. Contracts may also take account of the time at whichelectricity is used: filling demand outside peak periods is much cheaper, so companieswho are able to draw most of their power at other times can negotiate a discount, in


much the same way as the Economy 7 domestic tariff offered cheaper electricity overthe nighttime period to encourage users to run washing machines, dishwashers, etc.during low load times when power was cheaper.

There is also a short-term market, sometimes known as the spot market, whichoperates through power exchanges. These are screen-based exchanges whereby par-ticipants trade a series of standardized blocks of electricity (e.g. the delivery of aspecified number of units over a specified period of the next day).

Power exchanges enable generators and buyers to fine-tune their rolling half-hour trade contract positions as their own demand and supply forecasts become moreaccurate as real time is approached. In theory they can operate over long timescalesof up to a year but in practice most trading is done in the last 24 hours before gateclosure as companies check their supply and demand positions.

The third timeframe operates from between gate closure and the second-by-seconddispatch of electricity on to the system. It is known as the balancing market and ismanaged by National Grid in its role as Great Britain System Operator (GBSO). Itexists to ensure that supply and demand can be continuously matched or balancedin real time. The mechanism is operated with the system operator acting as the solecounterparty to all transactions.

This market is required because demand and supply on the system are changingall the time, and certainly in timescales shorter than half an hour. Some of the biggestchanges happen when domestic consumers are all watching the same TV programmeand there are commercial breaks. This kind of ‘TV pickup’ typically means thatpeople leaving their sofas to turn on the kettle during the mid-programme break forCoronation Street can increase demand by 800 MW. The biggest TV pickup everrecorded was on 4 July 1990 following a semifinal World Cup football game betweenEngland and Germany. The game went to penalties, and, within minutes of theirfinishing, demand rose by 2 800 MW.

The high-voltage grid that National Grid manages reaches very few of the coun-try’s individual users. But that does not mean National Grid can leave questions ofload to the DNOs. Changes in consumption require the grid to bring extra power ontothe system and it can be very sensitive. On a summer’s day a shift from clear sky tothick cloud adds an additional 5 per cent demand – requiring power from, say, four500 MW gensets. An increase in wind adds 2 per cent to winter and 0.7 per cent tosummer demand.

That means that, although the DNOs each supply an area with around a twelfth ofthe UK users, National Grid has to know about the load in far more detail. To assessdemand it looks at the substation level and the individual grid supply points, whichmay supply a small town or half a larger city. That has a resolution of a 5–15-mileradius.

As local temperatures change and more extreme weather events occur, humanbehaviour changes and the electricity supply system has to be able to respond. Onebig effect in the long term will be from additional air-conditioning loads, which willadd to both peak and 24-hour demand.

National Grid saw growth of 5 per cent in air conditioning in the commercialsector in the five years to 2002 and expects to see a further 6 per cent in the period to

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2010. There is also likely to be a rise in the residential market. Often overlooked is thata 1 per cent rise in external temperatures increases the requirement for refrigeration –it increases cold-appliance consumption by 1.8 per cent, and some appliances doubletheir energy use when external temperatures increase from 18 ◦C to 26 ◦C.

2.4 The balancing market

As demand and supply fluctuate, National Grid manages the system through anothermarket known as the balancing market.

To this end, all market participants are required to inform National Grid of theirnet physical flows in all the forward markets in so-called initial physical notifications(IPNs), submitted at 11 a.m. at the day-ahead stage. These are continually updateduntil gate closure, when they become the final physical notifications (FPNs).

Power flows are metered in real time to determine the actual quantities of elec-tricity produced and consumed at each location. The magnitude of any imbalancebetween participants’ contractual positions (as notified at gate closure) and the actualphysical flow is then determined.

National Grid has offers to supply electricity into the balancing market that can bemade available at extremely short timescales. This may be hydropower, for example,from the pumped-storage plants at Dinorwig and Ffestiniogg in Wales, which takeadvantage of low electricity demand and low price period to pump water to a highreservoir, which can then be released to generate power when required. Such plantsare net energy users overall, but are an important tool in matching demand and supply.Other sources of short-notice power may be ‘spinning reserve’, essentially thermalstations operating in a similar way to a car in neutral. National Grid also has offers forshort-notice demand reduction, such as the interruptible contracts mentioned above.In some cases the system may have too much electricity available. In that case NationalGrid has offers in the balancing market from generators who will cut off their plant.

The cost of buying or laying off power, or paying for demand reductions, variesdepending on how far out of balance the system is, and on the cost of power duringthe half-hour timeslot concerned, and is known as the system buy price (SBP) orsystem sell price (SSP) depending whether the system needs to add or subtract power.The cost is charged back to suppliers whose physical supply was either more or lessthan they had contracted for and informed National Grid in their FPNs. This was animportant change from the previous market structure, and was designed specificallyto encourage participants to match closely their demand and supply. Since the marketstructure was introduced the amount of power bought and sold on the balancing markethas decreased, meeting one objective in the market design. However, in penalizinggenerators who do not match their supply and demand accurately, it takes in thosegenerators whose supply is partly beyond their control. This includes companiesoperating wind farms, whose ability to predict is limited, but it also includes CHPplant operators, for whom the electricity available to be sold may vary depending onhow much heat is sold. As the government wishes to encourage both wind and CHP, itsposition with regard to BETTA and the balancing market is under discussion. Partial


protection from the costs of being out of balance is most often gained at presentfrom joining other generators and acting as a single trader: this should mean theunpredictability of the group is less than that of each individual member. Companiesknown as consolidators offer this service.

The Balancing and Settlement Code (BSC) provides the framework within whichparticipants comply with the balancing mechanism and settlement process. The BSCis administered by a non-profit-making entity called Elexon.

2.5 Distribution network operators

The distribution companies (which may be a subsidiary of a utility with generatingand supply businesses) operate in defined areas (see Panel 2.1).

The companies hold separate licences for each area and are governed by theterms of their distribution licences. They are under a statutory duty to connect anycustomer requiring electricity within a defined area and to maintain that connec-tion and they have other statutory duties to facilitate competition in generation andsupply, to develop and maintain an efficient, coordinated and economical system ofdistribution and to be nondiscriminatory in all practices.

Embedded generation refers to the fact that these relatively small sources of powerare ‘embedded’ within the low-voltage network, rather than supplying power fromthe high-voltage grid through a grid supply point, or substation. It is at the DNOlevel that most of the network development must take place that will allow embeddedgeneration to become a significant component of the electricity supply network, andthese extensive changes will be required in both company structure and financing,and in the grid itself.

The structure of the DNOs is not very friendly towards embedded generationbecause they are ‘regulated’ businesses. Because they do not operate under com-petitive pressure, their costs and profits are examined by Ofgem to ensure that theirfinancial returns are reasonable. That has implications for the way the DNOs managetheir business. Since the DNOs are monopolies within their own area, the regulator(in this case Ofgem) tries to mimic the effect of competition on the business. EachDNO can manage its own operating methods and capital structure, and the regulatorprovides for a return on the capital invested and efficient operating costs, subject tocertain outputs being achieved.

The amount of income that DNOs are allowed to receive is set by the regulator, anddepends on how much work has to be done to maintain and extend the infrastructure,and how much profit is allowed by the regulator. The DNOs can make additionalprofit by reducing their costs, provided they meet their commitments to the regulatoron maintenance, network development and other ‘hardware’ operations, as well asa variety of targets on customer service. Reducing costs may mean an improvementin operations, or in some cases can be the result of introducing new technologiesthat make a step change in efficiency. In company and investor terms, the DNOs arelow-risk businesses. They have well-determined income and expenditure for severalyears, as work programmes and pricing are set on a five-yearly basis with Ofgem,

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so investors have a reliable return. But the returns are relatively low – high returnsaccompany high risk – and will continue to be limited by the regulator, so the DNOmust take a very cautious approach to new investment.

To encompass the changes that will be required to include significant embeddedgeneration, however, the nature of the DNOs’ networks must be completely changed.This is clearly a high-risk activity, as it is not clear where embedded generation maybe added to the system, what type of generation will be added, or how much will beused. No DNO wants to take the gamble of upgrading part of its network to acceptembedded generation under the current regulatory framework because, if the expectedgeneration does not appear as predicted, the investment will be wasted – and the DNOis unlikely to be allowed to charge the cost back to its customers.

The changes that must be made to the DNO’s local grid are extensive. As wehave seen, on the high-voltage network, National Grid balances varying input fromgenerators as their power plants start up and shut down, with demand from the buyersthat alters throughout the day and across the country. It is managed with constantfeedback from all parts of the system. The low-voltage network is much simpler. It isdesigned to accept power from the local substation and transmit it to domestic users.In some areas there are links between neighbouring areas, which allows flow to betransferred if, for example, work is required on the system. But the system is designedon the assumption that flow will be one way and will be sized for the likely load, sothat, while the supply along the high street will be through relatively high-capacitycomponents to provide power for commercial premises, residential street wires willbe smaller and the supply to remote, single premises smaller still.

The effect of this is twofold. First, day-to-day operation on the network is carriedout on the assumption that flow is one way, and this can be reflected in operations assimple as working on a single-network connection – once the connection is broken amaintenance technician assumes there is no possibility of power from the householdside. The other effect is on the network capacity. Remote areas are often the mostattractive as potential sites for embedded generation, but, if the existing connectionat that point has very low capacity, the cost of upgrading it may make the embeddedgeneration uneconomic.

2.6 Regulating the markets

Ofgem is the organization that regulates the UK’s energy markets and the companiesinvolved in them. The way in which it regulates varies depending on the type ofactivity involved and the market structure.

For functions where there is a competitive market, Ofgem has no role in settingprices: it is assumed that the effect of the market will be that customers can seek outthe most economic product. So, in the generation and retail market, Ofgem ensuresthat the market is operating effectively, licenses companies to trade within the marketand helps arbitrate disputes.

In areas where competition is not possible, such as the distribution and transmis-sion networks, Ofgem scrutinizes the monopoly suppliers and sets how much return


on their investment the companies are allowed to make, and how much they areallowed to charge to customers. As part of this process it examines what investmentis required to maintain or extend each network and what the operating costs are. Itthen sets a broad range of performance standards for companies. Provided the com-panies meet their performance standards and are within their price limits, they canmake efficiencies in operation and improve their level of profits, as an incentive.

The allowed prices and performance targets are set in five-yearly distributionprice control reviews and it is at this point that the operators and the regulator decideon likely major developments in the networks, such as developing them to acceptembedded generation, and how these developments should be funded at reasonablecost to users and retail customers. For example, the distribution price control reviewthat came into effect on 1 April 2005 included a specific incentive mechanism forthe connection of generation to distribution networks. There were two additionalincentive mechanisms – the Innovation Funding Incentive and Registered PowerZones – that encourage innovation in the connection and operation of distributedgeneration (DG). An additional development changed the basis on which generatorspay to connect and use the distribution system.

Ofgem also administers some of the government’s support and regulationschemes, including the Renewables Obligation and exemptions from the ClimateChange Levy.

Ofgem itself describes its first priority as ‘protecting consumers’, and its otherpriorities as helping secure Britain’s energy supplies by promoting competitive gasand electricity markets, and regulating so that there is adequate investment in thenetworks helping gas and electricity markets and industry achieve environmentalimprovements as efficiently as possible, taking account of the needs of vulnerablecustomers, particularly older people, those with disabilities and those on low incomes.

Ofgem is governed by an authority, consisting of a chief executive and manag-ing directors, along with nonexecutive members who bring various other types ofexperience to the authority.

The authority determines strategy, takes all major decisions and sets policypriorities.

Ofgem is funded by the energy companies who are licensed to run the gas andelectricity infrastructure.

Chapter 3

The heat connection and cogeneration

So-called ground-source heat allows heat from beneath the earth’s surface to beabstracted.

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So far we have discussed the UK’s electricity supply industry, how it works and itsmajor players, and how embedded generation fits into that system.

However, this refers entirely to the electricity we produce and use, and it shouldnot be overlooked that this is only part of the UK’s energy industry.

3.1 Energy use in the UK

When the UK’s Department for Business, Enterprise and Regulatory Reform(BERR) – formerly the Department of Trade and Industry (DTI) – publishes itsregular ‘Digest of UK Energy Statistics’ (‘DUKES’), it examines how much energyin the form of oil, gas, coal, etc. has been imported into the UK, and how much hasbeen produced here, again as gas or oil (from the North Sea) or coal, but also fromhome-grown sources such as wind power, hydropower, nuclear power and smallersources such as waste gases from landfill and energy crops.

DUKES figures also examine the fate of these primary energy sources. Some ofthe gas, oil and coal is used in generating stations to produce electricity, but even whenadded to the hydro, nuclear and wind power generated domestically this representsonly around 40 per cent of the total energy used. A large part of the oil import is usedas petroleum for transport, but oil, gas and coal are also used to provide heat, and thisis as important a part of the UK’s energy balance as is the electricity industry.

Gas is a very important heat provider, for example. The UK’s domestic gas net-work is not as extensive as that for electricity but nevertheless has been expandingsince the 1960s and now serves nearly 20 million domestic users – more than 80 percent of the whole. This network is almost entirely dedicated to heating and cookingand there is also a market in gas canisters for those who do not have access to thenetwork. A high-pressure gas network delivers gas to large-scale industrial users toprovide process heat to industrial customers, as well as to the gas-fired electricitygenerators.

The heat and electricity markets are intimately connected, because some fuels areused for both purposes and, equally, because electricity is also used to provide heat,although domestically electric space or water heating is often the most expensiveoption.

3.2 Support for heat and power

The heat factor has seldom received much notice from UK policymakers, despite itsimportance and the efforts of, for example, advocates of renewable energy and CHP,which often provide energy as heat. The largest support programmes for embedded orrenewable energy are in practice available only for renewable-sourced electricity. Thelargest, the Renewables Obligation, requires electricity suppliers to source a growingproportion of the electricity they sell (the ‘aspiration’ is to reach 20 per cent of theelectricity supplied by 2020) from renewable sources or pay a fine.

Efforts to persuade the government to introduce a similar ‘heat obligation’ havefallen on stony ground, as the government has argued that the market is too complex

The heat connection and cogeneration 31

and there is no small group of providers, similar to the electricity supply companies,on whom the obligation could be placed.

Why is heat an important issue for embedded generation? There are two rea-sons. Of more direct concern is that, as we have seen (Chapter 1), heat and powerare often produced together. Sometimes this is deliberately planned, with a use foreach product, in the CHP plants we have discussed, and sometimes the heat is sim-ply regarded as a waste product that must be dissipated in a way that does notcause problems elsewhere. The second, broader, reason is one of policy. Embed-ded generation is encouraged because it allows energy to be generated as close aspossible to where it is used, reducing the losses incurred in transporting it long dis-tances and giving customers a far better understanding of how much energy they useand why.

Together, this should greatly improve the efficiency of our energy use, bothbecause there are fewer losses in the system and because greater customer under-standing is seen as likely eventually to translate into lower consumption. This canhardly happen effectively if the energy being used for heat is left out of the equation.

Because policies on renewable and small-scale energy have focused almostentirely on electricity, huge opportunities to switch to different forms of energy pro-duction and, in the process, reduce the energy – and carbon dioxide – bill of thecountry as a whole have been lost.

3.3 Energy crops

Take for example the opportunities to plant and sell energy crops. These crops aregrown not for food, but to provide energy. There are a number of reasons why energycrops may be encouraged. They can be combusted to provide electricity or heat inpreference to fossil fuels such as coal and gas. Burning the energy crops does releasecarbon dioxide into the atmosphere, but it is carbon that was absorbed by the cropwhile it was growing. Over the cycle the carbon balance is not zero, as there aresome emissions from processing and transporting the crop and so forth, but the totalemissions are far smaller than they would be if coal, oil or gas were used. Energycrops are also interesting as a new opportunity for farmers and agriculture in general:it is a relatively small step from providing energy crops to using energy crops toprovide heat and/or power for local businesses.

The government has attempted to promote energy crops but was most interestedin using them to generate electricity, and at the turn of the century it invested millionsin an experimental power station that would use a new process called gasification asthe basis of a wood-fuelled power station. The National Farmers’ Union joined otherwood-energy organizations to argue that the project was too ambitious: the technologywas unproven, while the willow fuel would require farmers to take a seven-yeargamble on replacing arable land with coppice. Opponents argued that developingboth an energy-crop industry and a new generating plant together introduced toomany uncertainties and it would be better to use energy crops in wood-fuelled heatingboilers, replacing gas- or oil-fired boilers, until the industry was more developed.

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But there was a long-term support mechanism already in place for electricity fromrenewables, so the project went ahead but was halted within a year or two by technicalproblems, setting back development of embedded generation from energy crops byseveral years.

3.4 Domestic heating

Domestic heating is another example. Gas is currently regarded as one of the mostefficient ways of heating the average domestic property in the UK, but althoughthe gas network reaches more than 80 per cent of properties, that still leaves up to5 million properties without access to gas. Those properties may use oil or electricityto meet their heating needs – both expensive options. There are small heat-generatingtechnologies that can be used to fulfil the need for space heating or hot water, such asground-source heating and solar water heating. Neither provides electricity, but bothdisplace electricity or primary fuels such as oil, and they generate the heat directly onsite with no transport requirements. Although individual projects of both types canapply for partial grants, the funding available to support these and other heat projectsis very limited in extent and in the application window, being allocated every fewyears as part of the government departmental budget. The Renewables Obligation,which supports power projects, however, is expected to provide a subsidy for eachunit of electricity generated until at least 2027.

3.5 Combined heat and power

The disparity is revealed most clearly in projects designed as highly efficient CHPplants. Well-designed CHP where there is an adjacent heat requirement to make useof otherwise ‘waste’ heat can raise efficiencies dramatically, increasing the overallefficiency of a steam turbine from less than 40 per cent to nearer 90 per cent, forexample. This is clearly beneficial and policymakers have argued that CHP shouldbe much more widely employed, with a government target of 10 GW.

In practice, CHP is often employed where heat is the ‘premium product’. Industrialprocesses where there is a high and continuous requirement for heat, such as papermanufacturing, have generally installed their own boilers or turbines on site to provideheat directly and these projects can be as large as tens of megawatts. At a smaller scale,commercial or office buildings have a continuous demand for heat to warm buildingsin winter and to drive chillers or air coolers in summer, which can be provided by anon-site CHP at the kilowatt level. Public buildings such as sports centres, hospitalsand schools also clearly have a very large heat demand. In all these cases, heat wouldbe the major product of the CHP plant, with electricity produced as a by-producteither for use on site, or to be sold back to the local electricity company.

CHP clearly offers huge potential for improving energy efficiency, yet the gov-ernment’s 10 GW target has been receding. The policy focus on supporting embeddedgeneration of electricity is one reason, and so is a UK electricity market that penalizesgeneration that is unpredictable.


CHP operators face considerable burdens if they want to supply their electricity tothe grid. In most cases their output would be sold to an electricity retail company, sincesupplying electricity directly to customers requires the generator to meet stringentconditions to qualify for a licence and sign up to the BSC, the agreement underwhich electricity companies settle their contracts and reconcile them with the amountof electricity physically delivered. These administrative measures are generally toocostly for companies with relatively small amounts of electricity to sell, and this isusually the case for CHP plant operators, since for most CHP the heat is the mostimportant product and the amount of electricity produced is governed by the needsof the heat customer.

The supply of electricity can be variable and at times of very high heat demandthe electricity production may be very low. This means first that under the BETTAelectricity market structure CHP plant owners would be in danger of being ‘out ofbalance’ on contracts to supply electricity, supplying either too much or too little totheir customers, and would therefore be at risk of being charged balancing costs by theNational Grid. Selling to an electricity retailer means this risk is somewhat reduced,as the retailer will be trading electricity constantly and will have a variety of sourcesof power and demand reduction, so it can balance its own supply and demand andwill seldom be out of balance on its contracts. This makes the risk more manageablebut it does not remove it, and of course the electricity retail company has to bearthe costs of managing the risk. That is reflected in the price paid to the CHP plantowner for its exported electricity: slightly discounted if the potential exports are welldefined and largely guaranteed, but much lower if the export is less predictable.

The cost of exporting power into the market was recognized by the governmentwhen BETTA was introduced and in response it allowed for companies known asconsolidators, who would bring together supply from a number of smaller generators.Several such companies exist but they have found trading conditions difficult in amarket dominated by a few major electricity-generation and retail companies.

The result of this penalty on unpredictability is that it is difficult to obtain a goodprice for electricity being exported from CHP. There is an exception, if the CHPplant is fuelled by biomass and is therefore providing renewable energy. This meansthat it receives a subsidy via the Renewables Obligation for each unit of electricityproduced. Once again, however, this is not free of charge. Qualifying the CHP plantas a renewable generator and proving that the electricity qualifies for the RenewablesObligation again involve significant and continuing administration costs, which insome cases have been high enough to convince operators that the available subsidyfrom small export does not outweigh the cost of qualifying.

Calculating the cost and benefit of being able to export electricity, and the incomeavailable from doing so, more and more potential CHP operators seem to be decidingthat the scale falls on the cost side. The added expense of producing and exportingelectricity is not justified by the price available for the electricity, and operators aremore likely to use a very simple boiler with a relatively low capital cost but lowerpotential efficiency over its lifetime.

Heat advocates argue that this problem could be solved if the production of heat athigh-efficiency sources such as CHP or from renewable fuels received an additional

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subsidy. As it stands, many potential embedded generation projects that could begenerating heat and electricity at very high efficiency have been cancelled in favourof traditional boilers and electricity supplies that are much less efficient over theirlifetimes and offer the electricity system none of the benefits of DG, relying insteadon electricity from the grid.

3.6 Heat technologies

What are the heat technologies that could be used in the UK to reduce the requirementfor oil or cut electricity usage?

3.6.1 Biomass

Burning coal or oil to provide heat and electricity depletes a nonrenewable resourceand produces carbon dioxide. But other fuels can be substituted for these fossil fuelsthat are carbon-neutral over their life cycle. They are a renewable source of energy thatthe UK’s Department for Environment, Food and Rural Affairs (DEFRA) describesas ‘offering a new opportunity for rural areas’.

Five dedicated types of biomass are at various stages of development.Willow and miscanthus are at the stage of commercial availability and they are

being grown now, and there are now several thousand hectares of these crops undercultivation – mostly willow, but some miscanthus.

Willow (and sometimes poplar) is planted as short-rotation coppice (SRC) –densely planted, high-yielding varieties where the rootstock or stools remain in theground to produce new shoots after harvesting. Willow is cut back in the first yearand then harvested every three to four years. A plantation could be viable for up to 30years before replanting becomes necessary, although this depends on the productivityof the stools.

Miscanthus is a woody, perennial, rhizomatous grass. On most sites it will takearound two years to produce a stable crop. After that time it can be harvested annuallyfor at least 15 years. Miscanthus is not native to the UK – it comes from SouthEast Asia – and the current lines being planted in the UK are sterile hybrids, whichcannot seed.

Work on using willow and miscanthus has been under way for some time and thetwo crops are being promoted by DEFRA, with grants available both for planting andfor developing producer groups.

Reed canary grass may be next in line for development. It is native to the UK andit is already planted as game cover. In Scandinavia, reed canary grass is being usedboth as an energy crop and to produce fibre (for paper making, for example). So far,canary grass is a rather less attractive crop than willow or miscanthus. It has a loweryield and a shorter productive life, and there are potential problems in removing itbecause it is spread both by rhizome and through seed dispersal.

Switchgrass – also known as prairie grass – is a native of the USA, whereit is the most interesting energy grass. In the UK a R&D programme has beenstarted.


Described as ‘having potential, but still furthest from the market’, the finalenergy crop under investigation is Arundo donax – known variously as bamboo reed,Danubian reed, donax cane, giant reed, Italian reed, Spanish reed and Provence cane.Until now, this plant’s main claim to fame has been that it is the source of reeds forwoodwind instruments. It offers high yield, but there are mechanical and technicalproblems to be overcome.

All the new energy crops could be grown on set-aside land.Biomass may also refer to various types of wood waste, such as bark chippings,

or recycled wood from urban areas. This type of recycled wood, however, has to bevery carefully selected, as if it is contaminated it will come under EU directives onwaste incineration and must be burned in a dedicated and qualified incineration plant.

3.6.2 Solar water heating

Energy from the sun warms water left in a bucket on a sunny day. In fact, most ofthe extra warmth in the water does not come directly from the sun but via the bucketitself: the sun heats up the bucket, which in turn heats the water. A black bucketwill heat the water up faster because it is better at trapping the heat from the sun andpassing it on. This is a ‘passive’ system – it has no moving parts and does not requireelectricity or other external power.

The simplest solar hot-water systems, also known as solar thermal systems(and not to be confused with solar photovoltaic systems, which produce electric-ity directly – see Chapter 4) are pretty close to being black buckets. These ‘batch’collectors are black-coated containers or tanks that are housed in an insulated metalbox and covered with a solar glass or glazing material, and are larger than buckets.Usually batch collectors are filled with pressurized water.

Batch collectors operate without the need of ‘active’ pumps or controls, so theydon’t need much maintenance. Also, because they don’t have many parts, they canbe the cheapest system to purchase or build. But their effectiveness is limited, andthey are at risk of freezing, so during cold weather they may have to be drained.

The efficiency of the collectors was increased by using flat plates, usually madeout of a set of parallel copper pipes on a thin copper ‘fin’ that runs the length ofthe tubes. The ‘fins’ increase the heat absorption. Water, or one of various otherkinds of fluid that may have better heat-transfer characteristics or are not prone tofreezing, is circulated through the tubes. The solar absorber plate is then installed inan aluminium-framed box surrounded on the bottom and sides with insulation andcovered with tempered glass. Flat-plate solar panels require a constant flow of fluidthrough the panels.

There are two types of panel setup. Open-loop systems directly heat the water.Circulation of the fluid through the solar collector is accomplished via a small pumpmounted on a solar storage tank. The solar pump is activated by a differential ther-mostat controller that senses when heat is available in the solar collectors. The solarstorage tank connects to the existing hot-water heater and feeds the preheated solarwater into the gas or electric hot-water heater as hot water is used. The solar collectorsand feed lines are protected from freezing by automatic drain-down controls, which

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allow the water in the pipes and panels to fall safely back out of the solar collectorsand feed pipes. These types of system get the description ‘open-loop’ because theenergy-collection loop is not separate from the rest of the hot-water system – i.e. it is‘open’ to using the same water.

Active solar hot-water heating systems can also employ the use of heat exchangersthat circulate heat-exchange fluids through the panels and feed pipes. This type ofsystem is called a closed-loop system, because the solar exchange fluid is closed offfrom the external atmosphere or isolated from the potable water through utilization ofa heat exchanger. In a closed-loop system the heated solar fluid is pumped through thesolar collectors. The heated solar fluid flows through a copper or stainless-steel heatexchanger located near the solar storage tank. The heat from the solar fluid transfersto the potable water within the solar storage tank. Another small circulator pump maybe used to circulate the water through the potable side of the heat exchanger.

There are several advantages to these systems. One is that the anti-freeze heat-exchange fluids can withstand freezing temperatures, allowing the system to operateduring periods when there is the greatest temperature difference between cold incom-ing water, and temperatures reached in the solar collectors. The system can have thegreatest performance benefits at this time. Also, if maintained properly, these systemswill not corrode or scale the passageways in the solar collectors and pipes. Closed-loopsystems tend to have the lowest overall operating costs, other than passive systems,since they do not have to be drained and maintained, but they tend to have the high-est installation cost. They heat water slightly less efficiently than direct open-loopsystems, but can work more and longer when it is risky to operate open-loop systems.

Thermosiphon systems are a kind of ‘passive’ solar hot-water heating that employsflat-plate solar collectors. The solar panels are usually mounted at a lower elevationthan the storage water to be heated. Thermosiphon systems can circulate potablewater or utilize a heat exchanger and heat-exchange fluid.

For potable water systems, the cooler water at the bottom of the storage tank isthermally siphoned to the hotter water near the solar collector by the rising temperatureand volume of the warmer water, initiating a circulation of the storage water throughthe collector’s fluid passageways back into the top of the storage tank. The circulationcontinues until the temperature at the bottom of the storage tank is about the same asthe temperature of the outlet pipe at the top of the solar collector.

Since the early 1970s, the efficiency and reliability of solar heating systems andcollectors have increased greatly and costs have dropped. Low-iron, tempered glassis now used instead of conventional glass for glazing.

Improved insulation and durable selective coatings for absorbers have improvedefficiency and helped to reduce life-cycle costs.

3.6.3 Ground-source heat

In the winter, scraping ice off the car and seeing frost on the grass, it is hard to thinkof the ground as a source of heat. But in fact the earth is being bombarded with energyfrom the sun all day – even in winter – and it absorbs much of it. That energy is storedin the earth’s huge mass, so, while the surface may be frosty in winter or cracked and


dry in summer, even at depths of just a few feet the temperature is fairly constant allyear round. It varies, depending on where you are on the earth’s surface, between5 ◦C and 28 ◦C.

Ground-source heat takes advantage of this constant temperature – and very oftenit can be used all year round, so that it helps keep a building cool in summer andwarm in winter.

Ground-source heating has three main components. Within the building there isa heat-distribution system, which can be very similar to the radiators that distributehot water around the house in a conventional heating system. Air ducts that can beused for heating or cooling flows are another possibility.

Outside the building is the heat-exchange system. If this is a so-called ‘closed’system, it consists of loops of pipe in which water is circulated. Sometimes anotherfluid with better heat-transfer properties is used. Depending on the characteristics ofthe site and the requirements of the building, the pipework is buried horizontally orvertically, in wells bored for the purpose. In some cases horizontal tubes need be only2 m or so under the surface. Cold water in the tubes is warmed by the surroundingsand pumped back to the house. Horizontal tubes are cheaper to install, but verticaltubes are likely to have better performance because, at greater depth, the temperatureis more stable.

In some areas there is free water deep below the ground – known as an aquifer. Inthis case an ‘open’ system can be installed. Warm water from the aquifer is pumpedup through one tube, and cooled water is pumped back to the aquifer through a secondpipe.

The internal and external systems are joined by the third part of the system, theheat pump. This transfers the energy between the water pumped through the earthand the internal distribution system. The heat pump can ‘step up’ the heat that comesfrom the ground, concentrating the energy to increase the temperature. To do this,it uses a property of gases as they are compressed and vaporized. The principle issimilar to the systems used to extract heat from inside a refrigerator, turning it fromcold to icy inside and ‘dumping’ the energy as heat at the back of the fridge.

In the summer the system can work in reverse (and exactly like the fridge). Theheat inside the building is reduced and is ‘dumped’ through the underground pipes.

The system does require an energy input for pumping and the heat exchanger. Butgenerally the energy required to run the system is only a quarter of the energy thatcan be produced – and that may be supplied by PV cells or a turbine. Typically 1 kWof electricity used to drive the equipment will produce between 3 and 4 kW of heatoutput – very energy-efficient.

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Panel 3.1 Ground heat in Cornwall

When Penwith Housing Association (PHA) took over the housing stock ofPenwith District Council in 1994, it took on many homes in need of renovation,and had an energy policy aimed at providing affordable warmth for all itstenants. However, the association had still to deal with small groups of houseswith ageing heating systems, and, while affordable, low-carbon dioxide heatingcan be provided with gas-condensing boilers, mains gas is not always avail-able. Conventional electrical heating (e.g. storage heaters) does not provideaffordable warmth, and the large amount of mains electricity used is responsi-ble for quite high levels of carbon dioxide. Oil-fired heating is becoming moreexpensive as fuel costs rise, and recent legislation on fuel tanks has increasedinstallation costs. In any case, Cornwall had begun to build solid experience inrenewables projects and PHA wanted to build on this.

Trials of ground-source heating came about because it was a practical optionfor the Association’s pattern of small groups of housing.

PHA’s first experience with ground-source heating was in 1998 on a new-build project – four bungalows for elderly people. A more ambitious projectto fit the system to existing houses was initiated when the government’s ClearSkies grant programme started up in 2003 (see 16.6).

The site was carefully chosen. PHA has many existing homes in outlyingareas with no mains gas that require central-heating systems. Many of these,however, have quite high heating requirements. It was felt that it would be bet-ter to start with homes that have a lower heating requirement that would matchthe 3.5 kW or 5 kW output of the type of heat pump to be used in the project.

Some 14 homes at Chy An Gweal formed one of several sites that hadsmall, reasonably well-insulated bungalows that lacked efficient modern heat-ing. There were concerns about whether the technology could be installed inthese existing buildings. Of particular concern was installing geothermal bore-holes in the gardens. In part this was because on new-build sites drilling uses abig rig, and it is traditionally a messy operation.

A drilling rig around 2.5 m high drilled two holes in each garden that are200 mm wide and 40 m deep. Then a plumber took over to install Calorex heatpumps supplied by Powergen as part of its HeatPlant kits. These kits includeground loop components, a heat pump and a hot-water cylinder matched to suitthe heat pump.

The heat pump is similar in size to a small fridge. This sort of space canbe difficult to find in a small home, particularly because the position mustbe accessible to the ground loop pipes, so the heat pumps were installed in apurpose-built timber enclosure fixed to the external wall of the properties. Thisallowed easy connection to the ground loops and a simple connection of theheating pipes through the wall to the plumbing inside.


Inside the house there was also some work required. Geothermal heat is oftencombined with underfloor heating but that could not be installed in the existinghomes. By and large, it emerged that radiators were the best solution.

There are some changes in operation: a conventional boiler wants to deliverheat quickly and then turn off, and the latest components are designed for thatapproach, like radiators with low water content that heat quickly to providea ‘quick hit’. With a heat pump, temperatures are more like 60 ◦C instead of80 ◦C and it is better for it to run longer. So the new radiators had the highestpossible water content to provide thermal storage and there were fewer ther-mostatic valves because of the lower temperature.

The householders were delighted to get rid of their old coal-fired heating,which was fairly expensive and dusty.

The PHA project was made possible by the Clear Skies grant and addi-tional funding from the local authority. The total contract cost was £136 861, ofwhich the Clear Skies Community Programme provided £47 000 and PenwithDistrict Council £25 000.

Chapter 4

Wind power

Wind turbines are becoming a familiar sight, both as large wind farms and singly,as here.

So far, wind has been the most visible form of embedded generation, as small-scalewind farms have been developed across the UK in the last five years. But wind powerhas many other guises that make it fit a variety of embedded generation needs, fromsingle houses to large industrial users.

4.1 Wind-turbine components

The wind farms generally being installed share a three-bladed design that has becomethe standard offering from major suppliers. Thousands of turbines of this style have

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been installed worldwide, and it has undergone many refinements and been scaled upto as large as 5 MW. The main components are as follows:

• Tower. Made of cylindrical steel sections or open steel lattice, the tower can befrom 25 to 75 m high. In most cases the wind conditions improve with towerheight. At the top, a ‘yaw’ mechanism turns the tower head, along with the rotorand nacelle, so it faces the wind.

• Rotor. There are three rotor blades, or two or one – most often three – madeof fibreglass-reinforced polyester or wood epoxy. New designs are increasinglyusing blades reinforced with carbon fibre. The blades rotate around a horizontalhub that is connected to the electrical equipment in the nacelle (see below). Theamount of energy produced by the turbine depends on the length of the blade andthe area it ‘sweeps’ as it turns. Blades can be from 30 to 65 m long. The poweroutput from the turbine can be controlled by adjusting the angle of the blades asthe wind changes – this is called pitch control. More common is stall control,which relies on the aerodynamics of the blade. As the wind speed increases, sodoes the turbulence behind the blade, and this acts to slow the blade down.

• Nacelle. At the top of the tower, the nacelle contains the electrical components.Driven by the wind turning the blades, the rotor hub turns a low-speed shaft atabout 20–30 revolutions per minute. In most cases this is connected via a gearboxto a high-speed shaft, which turns at about 1 500 rpm. This drives an induction orasynchronous generator that produces the electrical power. Staff enter the nacelleto maintain these components.

• Anemometer. This instrument attached to the nacelle measures wind speed anddirection. This provides information to the computer controller, which starts theturbine operating when there is enough wind, operates the yaw mechanism andcontrols the electrical equipment.

Wind farms and industrial users will usually install larger turbines, on the 1 MWscale, so as to extract most power from a single site. Smaller turbines, sized at a fewhundred kilowatts, were more usual in the 1990s and are seen in their thousands inthe Netherlands and elsewhere in Europe. However, turbines are available in smallersizes aimed at the domestic and small commercial market. A long-lived UK supplier,Proven Energy, for example, supplies a range of turbines. The smallest, rated at600 W, is described by the company as being the same height as a telegraph pole,providing enough electricity to power lighting circuits in a standard three-bed house inthe UK. More commonly however, the 600 W is used by telecoms companies to feedpower into batteries for telecoms repeater/booster stations and has been used by theMOD (Ministry of Defence), BT, Orange and T-Mobile. Proven’s largest turbine, incontrast, is 1.5 kW and is aimed at light industrial, light commercial and agriculturaluse. With this sort of power you can power about six or seven typical three-bed housesin the UK.

The British Wind Energy Association (BWEA) notes that small wind turbineshave traditionally been used to generate electricity for charging batteries to run smallelectrical applications, often in remote locations where it is expensive or not physicallypossible to connect to a mains power supply. Such examples include rural farms, island

Wind power 43

communities, boats and caravans. Typical applications are electric livestock fencing,small electric pumps, lighting or any kind of small electronic system needed to controlor monitor remote equipment, including security systems.

4.2 Assessing the wind resource

The first stage of any wind-energy project is finding out the available wind resourcebase. Proven Energy, for example, assumes a wind resource averaging 5 metres persecond (m/s).

The ideal site would be on top of smoothly rising ground and away from treesor other obstructions – both characteristics will reduce wind turbulence and improveoutput. The effect of location can be dramatic, and sites just a quarter-mile apartmay have very different characteristics. Location is also important for the turbineconnection: it should be as close as possible either to the house, if connected directly,or to a point where it can be connected to the low-voltage grid.

To assess the average wind speed at a particular site, a general indication canbe established by using the UK wind-speed database (which can be accessed via theBWEA’s website at www.bwea.com/noabl). This returns an estimated annual meanspeed for a given Ordnance Survey grid reference. If the wind characteristics appearfavourable they must be assessed over as long a period as possible – several monthsat least, and ideally a year – by installing an anemometer, an instrument that recordswind speed mounted at the planned turbine height.

The BWEA notes that the electricity produced by a wind turbine over ayear depends critically on the annual mean wind speed at the site – higherwind speeds produce more energy. It says that, in general, small-scale wind tur-bines start to generate electricity in wind speeds of approximately 2.5–4 m/s andtheir rated optimum wind speed is 10–12 m/s. For instance, a 6 kW turbine ata wind speed of 5 m/s will generate an average of 11 000 units of electricitya year.

4.3 Installing a wind turbine

The BWEA’s guide, ‘Installing a Small Wind Turbine – in a nut shell’, can be foundon a web page called ‘Small Wind Technologies’ at http://www.bwea.com/small/technologies.html (accessed 21.10.07). This is how it summarizes the steps.

1 Get a reliable estimate of the wind speed at the proposed site. Turbine manufacturersshould be prepared to help. The generator must get acceptance for connection to theelectricity distribution network. (if applicable).

2 Mount the turbine on as high a tower as possible and well clear of obstructions, butdo not go to extremes. Easy access will be required for erection, and foundations forthe tower may be needed depending on the size and tower type. It is also important toensure that the wind turbine can be easily lowered for inspection and maintenance.

3 Try to have a clear, smooth fetch to the prevailing wind, e.g. over open water, smoothground or on a smooth hill.

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4 Use cable of adequate current carrying capacity (check with the turbine supplier. Thisis particularly important for low-voltage machines). Cable costs can be substantial.

5 Consult your local council as to whether you need planning permission. You should tryto minimize the environmental impact of the turbine, and it will be helpful to informyour neighbours of your plans at an early stage.

6 For larger machines you may have to pay rates. This can make a big difference to theeconomics of the installation, again you should find this out by consulting your localcouncil. Once the machine is under construction, ask your chosen supply companywhether they need you to be accredited for ROCs [Renewables Obligation Certificates],LECs [Levy Exemption Certificates], and REGOs [Renewable Energy Generation ofOrigin] and what type of onsite and/or export metering they require you to have (ifapplicable).

4.4 Rooftop turbines

Integrating wind turbines into the built environment poses some formidable chal-lenges. In urban areas generally, winds are slower, more turbulent and show greaterdirectional variation than in rural areas nearby. But these effects are smaller for thetops of buildings that are taller than their surroundings. Appropriately placed, windturbines can benefit from the ‘venturi’ or concentrator effect created by buildings,which produces higher wind speeds. Noise and flicker, considered a nuisance in ruralareas, will not be tolerated at all in towns, and vibration can threaten the integrity of abuilding if a turbine is placed inappropriately on a rooftop, which is usually the mostviable site for it.

London has a particularly low average wind speed of about 4 m/s, and is unlikelyto be the first-choice location for wind turbines, but some have already appearedand in the long term may contribute significantly to its energy needs. HammersmithCouncil recently shelved a project to build an Enercon E66 turbine on a site adjoiningWormwood Scrubs, because it was believed the scheme would fail at the planningstage. Undeterred, the council was, at the time of writing, pursuing a scheme to installsmall 6 kW wind turbines on the roof of a 22-storey residential block.

Tall buildings funnel wind, and architects have to keep this within acceptablelimits if people are present. But a building’s shape can be used to force the windthrough a turbine. Ambitious plans for another residential scheme in west Londonanticipated wind turbines installed not only on the roof of two lozenge-shaped towerblocks, but suspended between them. The project is along similar lines to an aero-dynamically shaped building called the WEB Twin Tower Building, which has three30-m-diameter integrated wind turbines suspended between kidney-shaped twin tow-ers designed by the University of Stuttgart in 2000 as part of the EU-funded WindEnergy in the Built Environment (WEB) project. Field tests conducted at RutherfordAppleton Laboratory showed that placing the wind turbines between the building’stwo towers, acting as a concentrator, produced considerably more power than mount-ing them conventionally at the same height on an open site. It increased wind speedby a significant 1 m/s. The kidney-shaped towers also directed wind into the fixedyawed turbine even when the wind was coming in at a 90-degree angle to the towers.The results suggested that a scaled-up version of the WEB design would produce a

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50 per cent increase in annual energy yield in a typically urban setting over a freelyyawing, stand-alone machine without the building.

In recent years new designs for small-scale turbines have been developed, intendedfor rooftop installation on domestic and commercial buildings. BT, for example,which consumes some 1.8 per cent of the non-domestic electricity generated in theUK and is struggling to reach its renewable-energy targets, is planning to installrooftop turbines on one of its telephone exchanges in Cornwall and, if the projectis successful, plans to replicate it at other sites. The insurance company CIS hasalso invested in roof-mounted turbines for its flagship CIS Tower in Manchester,complementing one of the largest PV installations in Europe. CIS is using smallWindsave turbines, which start to generate electricity at wind speeds of 4.0 m/s andreach the rated output of 1 kW at 12.5 m/s.

One of the main problems with installing propeller wind turbines on a rooftop hadbeen vibration, but now a new generation of turbines has been designed specificallyfor buildings. One of the most exciting designs is the 1.5 kW Swift Rooftop EnergySystem, from Edinburgh-based Renewable Devices.

The Swift’s design engineers, Charlie Silverton and David Anderson, claim itis the world’s first truly silent wind turbine. Research on the design began in 2002,on the back of a DTI Smart Award. Advanced aerodynamics make the rotor moreefficient, while reducing the noise emissions significantly, while a circular rim aroundthe outside of the blades holds on to the radial flow of air at the tip of each blade thatcreates a ripping noise with conventional turbines.

Renewable Devices has also developed an electronic control system that safe-guards the turbine in high winds and ensures efficient power extraction under normaloperating conditions

Renewable Devices won a Scottish Power Green Energy Trust Award to fit SwiftRooftop Wind Energy Systems to five primary schools in the Fife area to provideelectricity, hot water, lighting and computing equipment. The company also won theScottish Green Energy Award for Best New Business in 2003.

The Wind Dam system uses the inherent strength of a building to intercept andcollect wind energy using a vertical-axis turbine. The unit is caged for safety. It isthis design that BT has chosen to mount on its exchanges in Cornwall. The systemcan be incorporated into a large number of building types and also has considerableretrofit potential. The Wind Dam concept has completed a UK Smart feasibilitystudy.

The patented combined augmented technology turbine (CATT) from Stratford-upon-Avon-based FreeGEN is another British design that has been designedspecifically for use in the built environment.

Like the Swift, the CATT’s three rotors are enclosed, but in this instance with ashort aerodynamic duct, which works with an air-flow controller to boost the energypotential of wind speeds of less than 5 m/s.

There are other innovative designs. Developed by the University of Strathclydein 1999, the ducted-wind Windside is another vertical wind turbine based on sailingengineering, the wind rotor of which is rotated by two spiral-formed vanes. Developedin 1979 by Risto Joutsiniemi, Windside turbines have been made to order since 1982,

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mainly for use at sea. Their spiral construction makes them able to utilize windsof 1–3 m/s.

4.5 Making the connection

For a small or domestic installation, wind-turbine connection is relatively simple.Depending on the wind turbine’s size and the demand for power at the property, itmay be connected directly into the house’s main distribution board or connected viaa battery.

A battery-charging system provides you with a continuous power source for yourhouse via an inverter, which makes the power from the turbine usable.

The inverter converts the DC power provided by the turbine to the AC onwhich most household appliances and the domestic electricity system are designedto operate. Battery-charging wind turbines normally operate at low voltages suchas 12 or 24. Batteries are usually essential in off-grid systems, but are expensiveand will deteriorate over time. They store low-voltage DC electricity, and need tobe protected from over- and undercharging. Lead-acid batteries are the most cost-effective, although other types are available. For a renewable-energy system, ‘deepcycle’ batteries are used, which are designed to have up to 80 per cent of theircharge removed and repeatedly replaced over a period of 5–15 years (or 1 000 to2 000 times).

An inverter transforms the low-voltage DC power produced by a wind turbineinto high-voltage AC power that meets the quality requirements of the electricitynetwork.

To install a grid-connected system, you will need permission from the local DNO.This is the company that operates the distribution network in your area, and may notbe your electricity supplier.

DNOs have different policies when it comes to connecting small-scale renewable-generation systems to their networks. If you have an off-grid site, you wouldhave a diesel generator on standby to cover periods when you had no windat all for a few days (because batteries are typically sized to provide around2–3 days’ worth of storage). Grid-connected turbines do not operate when themains supply is interrupted: they are designed to shut down for electrical protectionreasons.

Panel 4.1 Off-grid turbines

The supermarket chain Waitrose is part of the John Lewis Partnership. Althoughthe Partnership produces few of its goods for itself, in rural Hampshire thefounder’s private estate is still part of the company’s portfolio. The estate alsohas working farms: two 200-cow production dairies, orchards, a mushroom

Wind power 47

farm, a milk-processing plant and a plant-propagation nursery as well as cerealproduction.

The farm also acts as a test bed for new methods, both in production and indeveloping the supply chain. The company put this into practice when it decidedthere was a market for chickens that were free-range, traditionally reared andmaize-fed.

The company produced a shed that opened at the sides, so that the chickenscould move freely in and out. The shed is on skids, so that it could be moved tofresh ground if necessary – to help avoid disease build-up, and allow the grassto recover. Then the issue of heat and light arose, and, although there was apower connection running down the field that would be suitable, that would notalways be the case, and the company wanted a demonstration project. Anotherfarmer might want to use a similar system in an area where there was no powerconnection.

The answer was to combine wind and solar power to run the sheds.The birds arrive as day-old chicks and for the first six weeks they are housed

in the shed. They have a 12-week life cycle and at six weeks, when they arefully feathered, they can move in and out of the shed during the day and areclosed up at night.

The energy requirement is fairly small. The shed is lit at low level for24 hours a day during the first six-week period, as the chicks tend to flockand can be crushed if they are in darkness. A small motor is required to trans-fer feed from an exterior hopper to feeding points in the shed. Each shedhouses 1 250 chickens and draws 26 A. As the birds grow they require lesslight, but more food, so the power requirement remains fairly stable over the12-week cycle.

The power supply is very simple. Each shed is supplied by a single turbineand solar panel combination, which feeds an array of six standard 12 V batter-ies. The turbines are around 10 m high and can be easily moved along with thesheds. Because they are portable, and the sheds are moveable, the company didnot need any kind of planning permission.

The 13 sheds were installed in mid-2001 and the first birds were installed inOctober of that year. The turbines and the solar panel trickle-feed the batteries,and the company found that it got power from the solar panels for about 15hours in midsummer and about 4 hours even in midwinter. The wind turbinesoperate more or less continuously, although at only 10 m above ground thewind is gusty and even within a single field the 13 turbines can be turning atdifferent speeds. The birds also require heat, but that is supplied from propaneburners.

The simple renewable-energy installations are a small proportion of the setupcost. The total cost of each shed was around £21 000, and, of that, the turbineand solar panel cost around £1 500 to buy and install.

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Panel 4.2 Wind across the Mersey

Mersey Docks and Harbour Company’s site had been identified in the early1990s as having a good wind resource, but the wind company that firstapproached the docks did not take up the option. Instead, Mersey Docks decidedto develop its own wind cluster.

Mersey Docks approached the wind cluster as it would any industrial project.To reduce the inevitable risks in any construction project the company chosewell-proven technology in the form of 600 kW Vestas turbines. Mersey Dockswas the project manager, as it is experienced in the project-management processand it felt the wind cluster was a small project by Mersey Docks standards. Itsprincipal risk at that time (before the Renewables Obligation was implemented)was the selling price, but it was eventually awarded a contract under the Non-Fossil Fuel Obligation (NFFO), which gave it a 15-year contract for electricitysales at an index-linked fixed price.

The company decided to go ahead with six turbines, Vestas-supplied V44-600s with a 50 m hub height and a blade diameter of 44 m.

The Mersey Docks is a 2 000-acre site and obtaining planning permission forthe centre of this highly industrial area might be thought relatively simple, butin fact feelings before the turbines were installed were very mixed. Objectionscame from a group of houses that are about three-quarters of a mile along thecoast, who were concerned over noise, dust, interference with TV receptionand bird strike on the turbines.

There was also a concern about local wildlife. The turbines are installed ona road along reclaimed land on the shore and reclaiming that land had createdartificial mud flats. The flats have become a nature reserve and more recentlya site of special scientific interest. But the issue was resolved by altering thespacing of the turbines either side of the flats.

As for the local councils, Wirral, on the opposite bank of the Mersey, senta letter of support as it thought the turbines would improve the environment.But the planning authority was Sefton Borough Council and it denied planningpermission when it was sought in 1995. Permission was granted on appeal, withthe conditions that turbine positioning and colour had to be approved. Uniquely,because Sefton feared the perceived risk of bird strike, each turbine had to standinoperative for two weeks. In practice, serial construction and commissioningtook up most of that time.

Construction began in late 1998 and – bird-education period notwithstand-ing – the turbines were in operation by March 1999. The company says theyhave operated with hardly any problems. External grid faults sometimes shutthem down – it is an automatic protection system – but the company’s ownelectrical engineer can reset them, so they can restart.

As Mersey Docks was managing the project itself, it used its own expertise inthe installation. The turbines are right on the sea wall and very exposed, as waves

Wind power 49

frequently break over the road. That called for some additional weatherprotection. Normally the transformers would be in a separate building, butMersey Docks sited them in the base of the tower. They are designed so that, ifa transformer needs replacing it can be removed through the access door. Thecontrol gear that would normally be at the base has been raised to a mezzaninelevel. It also needs extra protection against corrosion, so there is a marine-gradecoating on the outside and the inside is painted, where normally it would be leftunpainted.

The project cost around £2.5 million. That included £1.8 million for the tur-bines, £400 000 for civil works and £300 000 for electrical works. Connectingto the grid was relatively straightforward for a large user such as Mersey Docksas the local grid is sized for large industry and the company has electrical workson site and regular discussions with the local DNO. The connection was madesimpler, because it was entirely within the docks area, as Mersey Docks has itsown substation at the port entrance, which is connected to the DNO’s medium-voltage system.

Mersey Docks dealt with the maintenance risk by taking out a fixed-pricecontract with the manufacturer that includes performance guarantees. Thefixed-price contract is not for the life of the turbine, and Mersey Docks isalready considering what to do when it ends. Maintenance requirements areestimated at about a half-day each quarter for each turbine.

The company expects to get payback on the turbines in about ten years. ItsNFFO contract runs for 15 years. Although the delays in getting planning per-mission lost it about six months of the contract, the turbines generated slightlymore than expected.

The power the turbines have generated has varied a lot over the first twoyears. Mersey Docks estimated that during the first year they produced 10 percent more than was predicted and the second year produced 15 per cent less.But the prediction was slightly conservative. The dock as a whole has a goodsense of wind because it also affects shipping delays, downtime for the cranesand so on. The result is downtime in windy years – just the opposite to theturbines – and variability from year to year was anticipated.

The company was so pleased with its turbines that it is planning to installlarger ones in another part of the dock.

The turbines would be 1.8 MW or more but they must be optimized aroundthe site. They must get the spacing right. The manufacturers are concernedabout turbulence so they need to be away from buildings in an open area.

Mersey Docks is planning this next phase at a likely cost of around £7 millionwithout a long-term NFFO contract. The price of ROCs means the power fromthe turbines will be exported, not be used at the docks, which has a maximumpower demand of about 35 MW.

Chapter 5

Hydropower

Small hydropower plants use falling water to generate electricity.

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Water power has been a familiar sight for thousands of years. Most peoplein the UK probably know an old water mill – whether or not it still has itswater-wheel – that has been converted to another use. But the water that pow-ered a threshing machine or grindstones can be used equally well to generateelectricity.

5.1 Power from water

The power available from a hydro-turbine depends on two things: the distance thewater falls to the turbine (known as the head) and the amount of water flowing throughthe turbine.

The combination of these factors means that power can be generated from manytypes of river, from small but fast-flowing hill streams to large, slow-moving rivers.It also means that hydro-generation equipment has become far more varied than, forexample, wind turbines, as developers have tried to abstract power efficiently from avariety of watercourses.

High-head schemes generally use Pelton turbines (named after the Americanengineer L.A. Pelton). These bear some resemblance to water-wheels, in that thewater flows into a series of vessels (known as buckets). They are described as impulseturbines: the impulse is transferred directly from the falling water, turning the turbineand a central shaft that is attached to a generator.

Pelton turbines can range from several centimetres to several metres across,depending on head and flow, but they cannot be used for low-head schemes. Instead,a reaction turbine is used. In this system, the water is passed through a pipe con-taining a turbine shaped like a propeller. The water turns the propeller as it passesthrough it. Propeller-type schemes can be used for heads as low as 1 or 2 m ifthere is enough flow volume, making the UK’s many weirs and sluices potentialhydropower plants.

Between the Pelton turbine and the propeller, two other types of turbine knownas Francis and Turgo turbines allow mid-range head and flows to be used efficiently.The skill of the hydro engineer lies in assessing which type and size of turbine areappropriate for each site.

Small hydro schemes are unlikely to require a dam of any size to be built. Theymay have a storage or settling pond similar to a millpond, which evens out the flowrate at the plant intake, and protects the turbines from damage from solids in the waterby allowing them to settle out. Alternatively, they can operate as so-called ‘run ofriver’ with no storage at all.

Once installed, hydro plants are several times more efficient than solar or windpower and with regular maintenance some may operate for up to 100 years. What ismore, their operation can be predicted with some accuracy, because for some riversrecords of river levels are available over several decades or even longer, and this,combined with rainfall measurement in the river’s catchment area, allows drought orlow flows to be anticipated.

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5.2 The UK’s hydropower potential

How much small hydro can be developed in the UK? The general impression fromassessments of renewable options is that almost all the UK’s capacity has beenexploited. But there are new sites that can be considered and there are many millsites – some dating back a thousand years – in various stages of decay. There arealso existing weirs where it may be possible to install turbines to take advantage ofthe fall.

The most important factor affecting the economics is the head, or water drop,because it has the biggest effect on the amount of energy that can be produced.Halving the head means that just a third of the power output can be produced, forthe same capital cost. The total volume of water flow is also important, but, becauseof physical constraints and environmental requirements, the total flow may be verydifferent from the amount that can flow through the turbine. In a wide but shallowriver, for example, extensive works would be needed to divert flow through a narrowchannel.

Other issues that can greatly affect the economics are the cost of grid connec-tion and its distance, access to the site (for cranes, diggers and ready-mix lorries),fish-screening requirements and disposal of trash. These issues are all consideredin the design, and decisions on one area of the design will affect other areas. Forexample, spending more on the turbine may save the cost of civil works, as a siphonor submersible turbine would require less building work.

Low-head hydropower equipment in Europe generally falls into three cost bands.In general, the high-cost band can be attributed to large-hydro manufacturers scal-ing their sophisticated equipment down for small hydro, whereas the middle- andlow-cost bands tend to be companies whose major business is small hydro. Thereare also European manufacturers specializing in micro-hydro technology who havedeveloped simple and robust technologies that can bring down costs for small-scaleschemes.

The choice of design capacity (i.e. the power rating of the installation) is largelydictated by economics. The investment cost per kilowatt is generally lower for alarger installation, but sizing the turbine to the maximum may mean it cannot operateduring low-water periods. A smaller scheme will allow the turbines to run flat out formore of the time and so may lead to a quicker return on the investment.

Most small hydro schemes have lifetimes of more than 50 years. However, debtfunding generally requires a payback of 7–10 years.

A 1989 study – ‘Small Scale Hydroelectric Generation Potential in the UK’ –by the Energy Technology Support Unit (ETSU) illustrates how past hydro assess-ments have been made. It picked out 157 sites in the south-east, but rejectedall but 13 as uneconomic. Those 13 had a joint projected installed capacity of3.186 MWe.

The study rejected all sites under 2 m head and less than 25 kWe projectedinstalled capacity – even where an on-site demand existed. Its rejections includedsuch sites as Sonning Lock and Whitchurch Silk Mill, sites that later came underserious consideration for development.

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5.3 Assessing hydro sites

Estimates of the power that can be tapped vary enormously, largely because theresults depend very much on the assumptions made at the start. The south-east isa good example: studies of the potential capacity of the Thames have varied from5 MWe up to 25 MWe.

Thames Valley energy consultancy TV Energy examined the resource in moredetail, having decided that a more detailed understanding of the resource in the south-east was required if it was ever to be mobilized.

The group’s report illustrates the difficulties in harnessing the energy from water-courses. TV Energy considered the sites first as a technical resource – lookingpurely at the physical options and the machinery required – and then a practicalresource.

In the first stage, several hundreds of potential sites were identified from mapsand other information, but many of the sites were discounted. This was either due to alow head (in some cases weirs were only a few hundred millimetres high), or becauseit was obvious that there was insufficient flow – enough to turn a water-wheel anddrive a millstone or other slow-moving machinery, but not the faster flow requiredfor hydro-turbines. Access was often a problem on private land.

The remaining sites were assessed to consider: the degree to which silt from theriver bottom could become a problem; the flow likely to be available for power; theturbine/generator location; possible electricity consumers within 500 m; restrictionson flow; and other potential problems.

A lower cut-off point was defined at 1.0 m head (half that of the ETSU study)since anything less than this was likely to have a potential installed capacity of lessthan 3 kW and this was considered nonviable. Sites would need to have a potentialgrid connection within 500 m.

After visiting more than 100 of the sites and examining 50 in detail, then extrapo-lating the results across the region, TV Energy calculated that the technical potentialencompassed 400 sites totalling 9 088 kWe.

In addition, there are 45 weirs on the River Thames, of which 29 have ahead of 1.4 m or greater. Their technical potential was 4 118 kWe. Together, TVEnergy calculated a technical potential for low-head hydropower in the south-east of13.606 MWe.

The group then assessed the practical potential, considering environmentalmitigation, flood-control measures and planning issues.

In the south-east, almost all the low-head schemes are micro-hydro-sized (below500 kW and exploiting less than 3 m of available head). That means the tur-bine machinery will be relatively large and must have high flows to achieve areasonable power. Head is reduced during high-flow (flood) conditions. During oper-ation, there are high levels of trash in the water that could foul the turbine andmust therefore be collected and disposed of. But the biggest environmental con-straint is fish protection. Screens and barriers will be required and bypass routes(so-called fish ladders) may have to be built so migrating fish are not caught inthe turbine.

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Taking into account such factors as the effect of nontechnical constraints such assites where the environmental impact is likely to be an overriding issue, planning,poor economic potential and site access, TV Energy estimated that 120 sites hadeconomic potential, producing some 5 320 kWe. Of the Thames weirs, five had mostpotential, contributing 900 kWe.

A further estimate was made of the likely short-term realisable resourcethat might be mobilized to meet the 2010 regional renewables target. Expertopinion in the hydro industry says that only sites above 15 kWe are likely tobe developed. What is more, many potential sites belong to the EnvironmentAgency or private landowners who do not wish to develop them. On the otherhand, some mill owners appear motivated by a desire to rebuild and regener-ate old sites and may invest in sites that do not apparently meet the standardcriteria.

Taking these constraints into account, TV Energy calculated that the practicalaccessible resource in the short term may be 1.064 MWe, while a realistic view ofthe Thames weirs would be five of the schemes with the greatest economic potentialgiving an installed capacity of 900 kWe.

In addition to the general sites and Thames weirs, TV Energy examined millsites using records from historical societies. These sites also number in the hundredsbut the group considered that only around 10 per cent had technical potential andconsidered there may be a resource of some 276 kWe.

TV Energy concluded that there may be a short-term practical resource of2.024 MWe for low-head hydro in the south-east of England.

5.4 Environmental effects

Although the water used in a small hydro plant is returned to the river, the plant canaffect the river flow and flora and fauna, especially in the case of a plant that is on asmall river.

Each hydro station where water is diverted requires an abstraction licence fromthe Environment Agency – even if all the water that was taken from the river isreturned to it a few yards downstream. It is also likely to require a discharge licencefor the water return – a dual licence requirement.

Before it will grant an abstraction licence the Environment Agency also has tobe convinced that diverting part of the water will not change the character of theriver. The project may also be restricted in when it can operate, to ensure river flowlevels are maintained, which means some plants do not operate in summer. Even inrun-of-river plants where there is no storage or diversion, there may be potentiallycostly requirements, such as so-called ‘fish passageways’ to allow migrating fish topass by the turbine.

In the past, some hydro developers have found the requirements of the Environ-ment Agency to be onerous, and the feasibility studies and surveys required to assessthe impact of a project on the fish and smaller species, river plants and flow levels werelikely to represent a significant proportion of the project budget. The Environment

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Agency said it would ‘take a positive view of reasonable and well-designed proposalsfor hydro power schemes’.

Once in operation, hydro plants are welcome additions to the system because theyhave mostly predictable power generation and controllability. They are also extremelylong-lived – at least 50 years of reliable life is expected if the plant is well maintainedand some have had much longer lives.

5.5 Adding hydro to the system

Small hydro is not just about dedicated plants in remote areas. There are slots in ourextensive water supply network where a turbine would be a positive aid to the system.

The water source for our taps may be high upland areas that have high rainfall anda wide catchment area. The water is piped from its source to the water-treatment worksnear the users and that means that at the treatment works it is under high pressure –in hydro terms, the head may be hundreds of metres. At this point the water may beunder too much pressure and it has to pass through special pressure-reducing valves.

But head and flow are the components for hydropower and the effect of ahydropower turbine is to remove energy from the water and turn it into electricity.Why not replace the pressure-reducing valve with a hydro-turbine?

This idea is not new. For many years hydro engineers have looked at the energywasted in pressure-reducing valves and considered how best to extract it. Accordingto the British Hydropower Association (BHA), schemes already in operation in thewater system provide over 25 MW of electricity capacity and, overall, the BHA saysthe potential nationwide is likely to be around 100 MW.

5.6 Extracting the energy

Energy from the water system may seem like easy pickings. But there are prioritiesto be considered.

All electrical components in the water-supply system have to conform to verystrict, internationally agreed standards to ensure they do not adversely affect thewater. For example, they have to ensure that there is no possibility of contaminationby paint, oil or grease. The turbine is being added to an existing system, so there willusually be very tight physical constraints on the site, and in many cases the existingpipework is very old.

The treatment works have to run constantly so there can be no shutdown when theturbine is installed or maintained. Once it is in operation, the water flow must be tightlycontrolled so that water quality is maintained. This usually requires a sophisticatedcontrol system for the turbine and special control arrangements that allow water to beswitched to bypass the turbine when necessary. A bypass system will be used if theturbine needs to be shut down for maintenance, or during normal operation to ensurethat the flow is constant. Switching between the turbine and bypass route must be‘bumpless’, i.e. it must not create surges in the system.

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Elsewhere in the water system, water companies have installed turbines at reser-voir outlets and have examined the possibility of including them at the inlet towater-treatment works where gravity-fed wastewater arrives. That is a technical chal-lenge because solids in the wastewater can foul or degrade the turbine, and a newturbine design may be required.

Panel 5.1 Reviving old mills

Mill owners in Somerset combined with the district council to investigateelectricity generation. South Somerset District Council decided they wanted10 per cent of the energy used within the district to be generated from renew-able sources within the district.

That tall order was thought most likely to be met by wind turbines. But theregion also has many historic water mills that were now simply picturesquetourist features, or falling into disuse, that could be used to generate electricity,and bring the owners additional income.

The council began to investigate the mills at the beginning of 2001 and foundaround 15 potential sites, but owners were daunted by the planning process,and by dealing with the Environment Agency, researching the best technology,and all the other aspects.

The answer was to bring the mill owners together. Each pledged £100, andwith matching funding from the district council the next step was to carry out afeasibility study to look at the sites and the finances. The Energy Saving Trust(EST) stepped in with a grant for the feasibility study.

The study looked at the catchment area of each river, the flow, the potentialdesign output and the total energy capture that would be possible. With the helpof a further £2 000 from the EST, that led to the development of a business planfor each mill.

All the sites are different. The energy available from each site varied, and,although each has remnants of a mill building and some are in good condition,the amount of work required at each site was different. In some the leat (whichcarries water from the river to the mill wheel) was still in existence, while someneeded to be recut, for example.

The varied capital costs and energy available meant that payback time foreach mill was different. At one mill a 19-year payback period was likely andthat was too long for the owner, who dropped out of the project. Other mills,including two at Clapton, were also too expensive, while some produced lessthan a kilowatt of power and were thought to be too small to pursue. In the end,11 mills went forward to the implementation phase.

At this stage South Somerset District Council and the mill owners wentback to the EST for an implementation grant. The group won the maximumgrant from the Trust – some £88,000 – which will cover around 30 per cent of

Continues

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Panel 5.1 Continued

the project implementation. The rest will come from the owners themselves,whether in cash or in kind. Loan financing would be available from banks,but several project owners invested their own time and did some of the worksthemselves.

The group negotiated with several electricity companies to get the best pricefor the electricity that mill owners will feed onto the grid. There were veryfew embedded generators in the region, so they have not had to put in placea standard arrangement for export. At present they will either make an annualpayment based on an estimate of the kilowatt hours exported, or accept thegenerator privately installing their own meter.

The owner is expected to read the meter every six months and a six-monthlypayment for export will be made. The payment for the electricity exported willdepend on the size of the generator.

Eventually, the price on offer from the utilities was slightly higher than themill owners assumed in their calculations. That means most of the owners willbe moving into profit earlier than they had anticipated. While some had workto do to get their mills working again, by 2010 they should all be reaping therewards.

Panel 5.2 Hydropower in Snowdonia

Developing small hydro in a National Park called for sensitive design and con-struction. Ty Cerig is a small hydro plant built in the Snowdonia National Parkby Wales-based renewable-energy specialist Dulas Ltd.

The Ty Cerig scheme, sited near Dolgellau, took several years to come tofruition. Since it is sited in a national park, there were several powerful orga-nizations to convince, including the Snowdonia National Park. Consultationswere required with the RSPB and the Welsh archaeology service Cadw, as wellas planners. Finally there were the landowners: Forest Enterprise and a privatelandowner, in the case of Ty Cerig. But by the time Dulas got around to TyCerig several of the other projects were well under way and the company saysit had built up a good relationship with all the stakeholders.

Nevertheless, planning for this project required careful assessments in an areaso dependent on tourism. The main area of concern was the potential impactof the abstraction on populations of mosses, liverworts, fish and invertebrates.A detailed environmental assessment was carried out using experienced ecolo-gists, to demonstrate that there would be negligible impact. Luckily, the site wasmostly in a commercial conifer forestry area, so it is not a high-grade habitatand there was less conservation interest.

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Visual-impact issues are usually of less concern on small run-of-riverschemes such as these, where pipelines are buried, and weir and powerhousestructures are small and unobtrusive. A pipeline carries water from the river tothe powerhouse, where the turbine is housed and the electricity is generated.The pipeline runs down a forest track so it was fairly easy to bury it. Turf wascut by hand and replaced to ensure fast regeneration of the vegetation over theroute of the pipeline.

At the bottom, the powerhouse is in a slightly more sensitive area. The fieldat the bottom is a wildflower meadow and has significant conservation inter-est, so the powerhouse build was planned to allow the surroundings to recoverquickly. Similarly, the powerhouse had to be carefully designed to be as unob-trusive as possible. It has timber walls and the roof is turf – this blends in andnative species can grow on the roof.

The biggest problem was the abstraction regime. The maximum abstractionis 75 per cent of the river flow, so 25 per cent of the flow always remains inthe river and never less than a minimum threshold of 20 l/s. Furthermore, insummer, abstraction cannot commence until a high flow of 189 l/s is presentin the river, to give protection to the mosses and liverworts in times of highertemperatures and lower humidity. Due to these restrictions, and the fact thatlimit on turbine maximum flow means that it cannot make use of the high riverflows, the scheme will effectively abstract less than 30 per cent of the totalyearly flow volume. Technically, these limits are quite easy to work with, usingelectronic controls.

Electricity from the plant is being sold to the grid. The cost of connection ofsuch projects varies considerably, depending on how far the project is from theconnecting point – and a hydro plant cannot be relocated closer to the connec-tion. But at Ty Cerig the grid connection is only about 150m. The cables wereburied to reduce visual intrusion.

Chapter 6

Marine renewables

6.1 Wave and tidal power

So-called marine renewables encompass devices that tap the energy of either tides orwaves. The term is also used sometimes to refer to offshore wind as they share somedevelopment issues, such as making the equipment sufficiently robust to withstandthe marine environment or transporting the power from an offshore generation site tothe users on land. This chapter focuses on the wave and tidal sectors.

Although the possibility of generating power from these natural resources hasbeen recognized for decades, it is only in the last decade or so, with the growth ofinterest in renewables in general, that large-scale deployment has been regarded asmore than a remote possibility.

In the last few years, however, the view has changed. A large number of deviceshave been proposed that could abstract power from waves or from either the regularmovement of the tides or so-called tidal races, where the tide forces seawater througha narrow channel between two areas of sea.

6.2 How much energy is there?

The UK has been investing in this developing sector for several years, driven by thelarge energy resources that are almost certainly available to be tapped from areas inthe North Sea. The region has been an energy powerhouse for the UK for severaldecades, thanks to its extensive gas and oil reserves, but the end of production isalready in sight: in the next few years the majors will begin to abandon worked-outsources, and the remainder will be the preserve of minor companies able to makereturns on smaller or less accessible deposits.

As oil and gas production begins to taper off, the UK’s aim is to transfer theextensive offshore expertise to new energy industries, and especially those that willabstract power from the wave and tidal resources in the region. Wave and tidal streamshold tremendous energy potential – but abstracting the power and getting it to shorecall for significant engineering development. That means estimates of the usableenergy from these sources vary widely.

In Scotland, for example, Professor Ian Bryden, based at Robert GordonUniversity’s Centre for Environmental Engineering and Sustainable Energy, put somepreliminary estimates on the energy available from the North Sea. With the caution

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that estimates could vary widely depending on the assumptions made, he said hisown estimate put the North Sea’s annual potential at 18–25 TWh of power fromwave resources and 40–50 TWh from tidal currents, along with 60–400 TWh fromoffshore wind.

Around the UK, the North Sea is not the only potential source of power. TheAtlantic waves that beat along the south-west coasts are of interest to a number ofwave-energy developers, and, apart from the strong tides in the area, there are alsotidal races in some sites around Cornwall and Portland.

6.3 Distributed generation?

Is wave and tidal energy distributed generation (DG)? It is clear that in some casesthis type of energy is highly concentrated in widely separated areas – the tidal racesof the Pentland Firth, for example. If these areas were exploited fully, it is likely thatlarge devices or arrays would be required in the area, and would likely be linked to theelectricity grid through a single connection that could be rated at tens of megawatts.

At the moment we are far from that situation, and the number of such sites isrelatively small. In most cases, and for some time to come, the technologies beingproposed are composed of arrays of individual units each rated at less than 1 MW,and arrays of less than 20 MW.

If, as is hoped, the unit price of the technologies decreases as more are manufac-tured, they are likely also to be deployed in near-shore situations singly or in smallgroups.

Many or most projects will be ‘distributed generation’, not because they are spreadacross the country, but because they will be rated far below the average 50 MW levelat which projects will be directly linked to the transmission grid, so they will feed intothe distribution grid. And these technologies will be ‘local energy’ and potentiallyhave local ownership, when deployed in small numbers to serve coastal industries orcommunities.

6.4 The route from research to industry

UK industry has felt for many years that it ‘lost the lead’ on wind power: it was at theforefront of development in the 1950s, but it currently is only a component supplier.It is determined to remain at the forefront of wave and tidal exploitation, and the UKgovernment has been willing to help support new facilities that are intended to shifttechnology from the research phase to development and ultimately application.

The first centre is at Blyth on the coast of north-east England, close to the UK’s firstoffshore wind farm. It will house the UK’s most sophisticated wave simulation tank.

While onshore development takes place in north-east England, Scotland’s WesternIsles will be home to offshore work in seas that are ultimately likely to have waveand tidal generators in commercial operation.

The £5.65 million European Marine Energy Centre (EMEC) on Orkney is aone-stop facility for the industry to test wave-energy generators and other devices

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and measure their potential output in realistic conditions. Its aim is to stimulateand accelerate the development of marine-power devices in Scotland, providinghome-based companies with a head start in exploiting wave- and, later, tidal-energytechnologies.

EMEC is centred on two main sites on Orkney. One is a control and switchgearcentre at Billia Croo, which is connected to both the UK electricity grid and four off-shore testing berths, while EMEC’s main offices and data centre are situated in the OldAcademy, in Stromness. EMEC offered several offshore test berths for wave-energyconverters, along with connections to onshore laboratory and analysis facilities. Thewave test area is now being followed by an area to test tidal-energy devices off thenearby island of Eday.

The step from research to deployment of full-scale devices at near-commercialscale is a daunting one for any developer, but in the absence of new initiatives fromthe UK central government it was a local enterprise agency in the far south-west ofthe country that took the initiative. The South West Regional Development Agencyproposed to install an offshore connection for wave and tidal projects that wouldenable several arrays of different devices to be operated for a restricted period thatwould enable them to prove their commercial viability. Although it is far from thenorthern shores where wave and tidal projects were initially demonstrated, the south-west has some of the country’s most energetic tidal and wave areas, and the projectis consistent with an existing commitment in the region – one traditionally ill servedby the existing power network – to develop renewable energy expertise.

Wavehub, as the project is known, would enable developers to install demon-stration arrays at a much lower capital cost, because one of the major costs –connection between the array and the shore-based power offtaker – would be removed.Instead, the projects had only to make a connection to Wavehub. The proposal wouldalso greatly reduce other barriers to deployment, notably the requirement for time-consuming and costly environmental-impact reports, and the need to wrestle with theUK’s notoriously obstructive planning process. Instead, Wavehub would carry mostof the burden of these two processes, and the projects themselves would providelimited environmental-impact statements and would not require planning permissionfor any dedicated onshore facility.

Preliminary work began on Wavehub in 2007, and the government pledged to pro-vide a quarter of the necessary £20 million investment, subject to planning permission.It is expected to be in operation by 2010.

Here are some of the devices where work is most advanced.

6.4.1 Marine Current Turbines

The tidal-stream generators under development by Marine Current Turbines functionsimilarly to windmills. They will be installed in areas with high tidal current velocities,which the company notes have the advantage of being ‘as predictable as the tides thatcause them, unlike wind or wave energy’.

The technology under development consists of axial-flow rotors 15–20 m in diam-eter, each driving a generator via a gearbox. The power unit of each system is mounted

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on a tubular steel monopile some 3 m in diameter, which is set into a hole drilledinto the seabed from a jack-up barge. The company has dealt with the problem ofmaintaining undersea turbines by a hoist system: the turbines will be lifted clear ofthe water to enable maintenance to be carried out from surface vessels.

The submerged turbines, which will generally be rated at from 600 to 1 000 kW,will be grouped in arrays or ‘farms’ under the sea, at places with high currents.Compared with wind turbines, marine-current turbines of a given power rating aresmaller and can be packed closer together, so the company says they have little landuse or other environmental impact. The rotors turn slowly (10–20 rpm) – aroundone-tenth the speed of a ship’s rotors. The risk of impact from the rotor blades isextremely small.

Marine Current Turbines completed its first grid-connected marine-currentturbine, rated at 300 kW, in 2002 at Lynmouth off the North Devon coast. It benefitedfrom being adapted from well-known wind-turbine designs and from the ability toraise the turbine above the sea’s surface to carry out maintenance.

Marine Current Turbines has won support from Northern Ireland and from Walesfor Seagen, an undersea turbine rated at over 1 MW. In Northern Ireland, the companyis planning to install a 1 MW experimental turbine in Strangford Lough Narrows inthe spring of 2006. This is a research project involving a single-monopile-systemtidal turbine to be installed for a period of between two and five years; it will then beremoved.

The Northern Ireland government hopes that in the long term arrays of turbinescan eventually be deployed in the open sea off the coast of the province. Thecompany has also announced plans to investigate the potential for a commer-cial tidal-energy farm in waters off the Anglesey coastline. The project hasreceived £700 000 of grant support from the Welsh Assembly Government’s Objec-tive 1 programme. A seven-turbine energy farm in waters off Anglesey shouldproduce 10 MW.

The company also has plans for a 12 MW array off the North Devon coast.

6.4.2 PowerBuoy

Ocean Power Technologies plans to install a 5 MW project at Wavehub, based onits PowerBuoy wave-energy converter. The PowerBuoy system consists of a floatingbuoy-like device loosely moored to the seabed so that it can freely move up anddown in response to the rising and falling of the waves. The sealed unit also containsa power-takeoff device, an electrical generator, a power electronics system and acontrol system.

As the buoy’s float moves up and down on the central spar, the mechanical move-ment drives a hydraulic pump that forces hydraulic fluid through a rotary motorconnected to the electrical generator. The power-takeoff device converts the move-ment into rotational mechanical energy, which, in turn, drives the electrical generator.The 40 kW PowerBuoy system has a maximum diameter of a little under 4 m (12 feet)near the surface, and is around 16 m (52 feet) long, with approximately 4 m (13 feet) ofthe system protruding above the surface of the ocean. There will be larger PowerBuoy


systems. For example, a planned 500 kW system, once developed and manufactured,is expected to have a maximum diameter of 13 m (42 feet) and be approximately19 m (62 feet) long with approximately 5.5 m (18 feet) protruding above the oceansurface.

6.4.3 Pelamis

Ocean Power Delivery’s Pelamis system is described by the company as a semi-submerged, articulated structure composed of cylindrical sections linked by hingedjoints. The wave-induced motion of these joints is resisted by hydraulic rams, whichpump high-pressure oil through hydraulic motors via smoothing accumulators. Thehydraulic motors drive electrical generators to produce electricity. Power from allthe joints is fed down a single umbilical cable to a junction on the seabed. Severaldevices can be connected to shore through a single seabed cable.

A typical full-scale Pelamis machine would be 150 m long and 3.5 m in diameterand have an output of 750 kW.

OPD secured £6 million funding from an international consortium of venture-capital companies that included Norsk Hydro Technology Ventures, 3i and Zurich-based Sustainable Asset Management for its first full-scale preproduction prototype,tested at the UK Marine Energy Test Centre on Orkney (see below).

Ocean Prospect Ltd, a Bristol-based company and subsidiary of the Wind ProspectGroup, will trial up to ten Pelamis P750 devices developed by Ocean Power Deliveryof Edinburgh at Wavehub.

6.4.4 Fred Olsen

The third berth at Cornwall’s Wavehub will be taken up by Fred Olsen Ltd, whichwill install a multiple point-absorber system for energy extraction. The fourth will beOceanlinx, an Australian company. Oceanlinx has installed a prototype of its device,which uses an oscillating water column driven by the waves to generate power, atPort Kemble in Australia. The Wavehub connection will allow it to demonstrate thetechnology in UK waters.

A number of floating buoys attached to a light and stable floating platformmanufactured in composites convert the wave energy to electricity.

The UK’s biggest stumbling block is the support it provides for new technolo-gies making the jump from demonstration to commercial technologies. In theory, allrenewable-energy technologies are supported by the ‘technology-blind’ RenewablesObligation, which forces electricity suppliers to source a growing proportion of theirpower from renewable generators or pay a per-megawatt hour fine.

The Obligation was supported by tradable electronic Renewables Obligation Cer-tificates (ROCs) generated along with each megawatt hour of renewable electricity.But the Obligation was designed to bring the most developed technologies – in prac-tice, onshore wind – on stream as quickly as possible: there is no incentive to usenewer options that will be necessarily more expensive before they have achievedeconomies of scale and passed the uncertainties of new deployment.

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6.4.5 Limpet and Osprey

Two similar devices developed by Wavegen, known as Limpet and Osprey, use apartially submerged shell. As the water enters or leaves the shell, the level of waterin the chamber rises or falls in sympathy. A column of air, contained above the waterlevel, is alternately compressed and decompressed by this movement to generate analternating stream of high-velocity air. The air passes through a Wells turbine, whichturns in the same direction regardless of which way the air is flowing across theturbine blades.

The Limpet version of the technology is sited on the shoreline. A 75 kW demon-stration device was in successful operation for 10 years and is now decommissioned.A larger version using two 250 MWe generators – known as the Limpet 500 – wasinstalled in 2000.

The Osprey 2000 is Wavegen’s offshore version of the oscillating-water-columntechnology. It rests directly on the seabed and is designed to operate in the near-shoreenvironment in a nominal mean water depth of 15 m. Rated at 2 MW, it is expected tofeed into an existing grid or, with a standby support, be used as a prime power sourcefor remote island communities.

In May 2007, Wavegen won a £2.3 million grant from the UK’s DTI (now theDepartment for Business, Enterprise and Regulatory Reform) to support the devel-opment and demonstration of a series of three Osprey devices, which will be sited offthe Western Isles of Scotland, using the new test facilities on Orkney.

6.4.6 Stingray

Stingray was developed by the Engineering Business, a company that provides equip-ment and services to offshore businesses including submarine cabling, and the oil andgas industry.

Stingray consists of a hydroplane that moves in an approaching tidal waterstream. This causes the supporting arm to oscillate, which in turn forces hydrauliccylinders to extend and retract. The high pressures are used to drive a generator.Following a feasibility study on the design, which began in August 2001, the DTIawarded the company a £1.6 million grant to allow a demonstration project to becarried out.

The site chosen for the project was at Yell Sound, where a current meter installedon the seabed showed a peak spring-tide velocity in excess of 5 knots. At this site aStingray 24 m high, using a hydroplane some 15 m across, would be rated at 150 kW.

6.5 Development issues

Stingray is one tidal power design whose development has been halted. UK developerscomplained that, although the UK government has provided support for wave andtidal technologies at the research-and-development phase, its support in making theleap to a commercial technology was inadequate.


The UK initially offered limited capital grants and ROCs – the UK’s major supportprogramme for renewables – for all energy exported. Developers argued that this wasinadequate for this phase. One problem was that the ROC payment was simply nothigh enough to support these technologies. What is more, because of the structureof the Renewables Obligation the value of a ROC could vary considerably, makingfinancing more difficult. In addition, most technologies would provide relativelylow amounts of power from each single device. Achieving economies of scale, andtherefore lower prices, would not come in the first commercial deployments but whenthey were being installed in the hundreds or thousands.

In contrast to the UK, wind and wave technologies in Portugal receive a guaranteed‘feed-in’ tariff. It is an arrangement that is popular in several countries because itprovides the developer with a fixed and certain return – provided that the projectgenerates successfully. What is more, better performance means a better return.

Consistent lobbying for additional support in the UK was successful, but it isnot clear how effective the extra support will be. The UK government, followinga proposal taken forward by the Scottish Executive, will give additional ROCs foreach megawatt hour of electricity generated by the wave and tidal projects – doubleROCs if the Scottish Executive’s model is followed fully. This should double theamount of subsidy provided for generation, especially in the light of other changesplanned for the Obligation that would maintain ‘headroom’ between the amount ofrenewables available in the UK and the Obligation (target) that had to be met byelectricity suppliers. That change should maintain the value of a ROC. Developers,however, have argued that such a change, although welcome, may not be enough toconvince potential project developers, and it must be accompanied by higher capitalgrants.

Chapter 7

Solar photovoltaics

Solar power can be used both for water heating, as at this project, and to produceelectricity directly.

Solar power sometimes causes confusion because there are two ways of using thesun’s energy directly. If what you want is heat – for warm rooms or hot water – youneed solar thermal as described in Chapter 3. But if you want to generate electricityyou need photovoltaics – PV for short.

7.1 Photovoltaic power

PV panels turn sunlight directly into electricity, thanks to a property of their majorcomponent – silicon, the most abundant element on earth.

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Metals conduct electricity if the outer electrons on each atom are attached tothe atom so lightly that they can drift away under the influence of a magnetic field.This electron drift is the electric current. Silicon atoms hold on to the electrons thatsurround them, but some are held less tightly than others and the right-sized hit ofenergy can knock them loose. Sunlight provides that energy hit, so when light shineson it some electrons are freed.

Once the electrons are freed they can flow around a circuit – and that is an electriccurrent. Note that it is the light, not the heat, from the sun that enables the electricityto flow, so photovoltaics are just as effective in cold countries as in hot – providedthere are long hours of sunlight.

7.2 Assembling the PV panels

The principle is fairly simple, but turning a few stray electrons into usable electricityrequires some complex engineering.

First the silicon: although it is available almost everywhere in rock form, to takethe best advantage of silicon’s PV property it is best grown as a single crystal. Thecrystal is cut into very thin wafers, and each forms the basis of a PV cell. Usually thewafer is treated to improve its photovoltaic property (known as doping).

To extract the electricity, the wafer is printed with a fine metal grid and thencovered with an antireflection coating. It is sometimes placed on a second material– a substrate that improves its photovoltaic properties. The bottom is coated withaluminium and fired.

These assemblies are the ‘cells’, the characteristic circles seen inside many PVpanels. Between 36 and 72 cells are connected into a ‘mat’ and then embedded in aplastic material that protects the cells against damage from humidity and UV light.It is then laminated using a specially hardened, highly transparent glass in front ofthe cells and layers of foil behind the cells. The array is framed and connectors areattached.

PV cells have been described as an expensive technology reliant on very expensivematerials and clearly the manufacturing is a complex process. But they have manyadvantages.

All the indirect ways of turning the sun’s energy into electricity need turbines,generators and other equipment, whereas PV can be set up and connected directlyinto your supply. Once installed, it can last for decades and maintenance is almostnonexistent.

Development is moving very quickly, both to reduce the cost of familiar single-crystal panels, and to use the same principle in a variety of different forms. An earlystep was to use cheaper multicrystalline silicon instead of single crystals in some pan-els. Instead of the circular silicon wafers, multicrystalline panels are generally squareor rectangular, but close up it can be seen that the substrate is made of small piecesof silicon. Multicrystalline panels are much cheaper to produce, because ‘growing’large silicon crystals is energy-intensive.

Solar photovoltaics 71

Also of growing interest is thin-film PV. The process uses an automated productionline to apply a ‘thin solar coating’ to rolls of flexible foil, using amorphous silicon – farcheaper than the crystalline silicon now used – as the substrate. Unlike the rigid panels,thin-film PV can be used to coat curved or irregular surfaces. Both multicrystallineand thin-film PV are less efficient at converting light into electricity than single-crystalcells, but their lower cost and greater flexibility make them suitable for many differenttypes of installation. Obvious areas for their use are in atriums, on louvres and incladding.

The real opportunities for photovoltaics are beginning to arise now that newPV technologies are considered from the early stages of designing a building. Thisdramatically reduces the costs of installing PV because it can replace other materialssuch as cladding. What is more, when PV is retrofitted on an existing building,much of the cost arises from the installation – scaffolding, removing materials wherenecessary, fixing the PV, etc. This too is being addressed: Solarcentury, for example,has developed ‘solar tiles’, which can be used to replace standard roof tiles and canbe installed in an array of any size.

7.3 Off-grid applications

Because, once assembled, PV is so simple to connect and does not require the movingparts – turbines, generators, etc. – of traditional power generation, there are a hugevariety of small applications where it is extremely valuable. In this context, too,the fact that individual PV devices may provide very small amounts of power is apositive benefit, as devices can be sized to match the application. A short journeyreveals many devices in operation to illuminate signs, or provide street lighting orbus-shelter lights. More and more, small panels are used to power isolated items ofequipment by the roadside or along railway track, or in rural areas and sometimeswith small wind turbines to work alongside the panel.

The key to many of these applications is that they are off-grid – they are notconnected to the electricity-distribution system. This situation makes PV an economicchoice. Cabling an illuminated street sign to be powered from the electricity networkis an expensive business, and disruptive if cables need to be buried. Installing a PVpanel on the post, on the other hand, is very simple and easy to accomplish. What ismore, it can be moved if the occasion demands.

7.4 Street applications

Solar-powered street and transport infrastructure is making a real impact up anddown the country in the form of solar-powered bus stops, footpath lighting and trafficwarning systems. Many local authorities are experimenting with the installation ofone or two solar-powered footpath lights or traffic signs in areas where there is nomains connection and the cost and disruption of cabling to the nearest grid point

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would be prohibitive. Plymouth is currently rolling out some 300 solar-powered busshelters and 40 are on trial in London. Stoke, Manchester, Nottingham and Leicesterare soon to follow suit.

Plymouth’s is the biggest installation of its kind in the world. The shelters, suppliedby Solarcentury in partnership with the street furniture company JCDecaux and usingtechnology provided by Uni-Solar, total 300 and each takes only four weeks to build.

Some of the bolder designs on our streets are thanks to JCDecaux. The companyhas worked with the architect Norman Foster and the designer Philippe Starck tocome up with streamlined and user-friendly street furniture, and supplies around 33per cent of that in the UK.

A big issue in Plymouth is safety. Light is a great companion when one is standingat a bus stop at night, and the panel provides security and timetable lighting in avandalproof panel. The battery can be stored in the frame of the shelter or below thepanel. Solarcentury’s lighting controller drives 6 W LEDs, which give a better outputthan 11 W fluorescents.

Solarcentury had installed around 100 solar-powered bus shelters, including stops,until the Plymouth contract. The company has now installed a real-time solar bus stop,which includes a display that tells you when your next bus is coming.

The UK’s first solar-powered illuminated bus shelter was actually supplied bySepco, in November 1999. Sepco has gone on to install almost a thousand unitsnationwide. It is hard to dismiss the benefits of the Sepco Solarlite shelter, a ‘fit-and-forget’ system that requires no maintenance and incurs no costs until the batteryneeds replacing after five years:

• no excavation costs, saving around £50 a metre;• no cabling costs to run a line from the nearest grid point to the shelter, saving

£3–5 a metre;• no connection charges, saving between £300 and £800;• no electricity charges ever;• no waiting period for connection, which can take around six months in some

areas; and• no workmen digging up the road for weeks – a Sepco shelter goes up in a few hours.

No city suffers the misery of roadworks like London. For this reason the cityhas some 200 bus shelters that remain unlit because of the cost and disruption thatwould be caused by connecting them to the mains. This is all set to change. Morethan 40 bus stops in the capital are using solar power as part of a trial by Transportfor London (TfL). Each stop has a canopy fitted above the flag to gather sunlight.Power gathered during the day is stored in batteries and released during the hoursof darkness to illuminate the timetable and flag. This is all controlled by an energy-management system. The solar panels have been supplied by Solarcentury, Sepco anda Canadian company, Carmanah Technologies, and the shelters by the UK engineeringfirm Trueform.


In order to enhance passenger safety, TfL hopes to install lighting in the remaining200 bus shelters, as stated in the mayor’s transport strategy. Further stages of devel-opment could assess the possibilities of utilizing solar power for real-time passengerinformation and also for commercial advertising.

Other local authorities are experimenting with solar power on a smaller scale.SolarGen, based in Newport, South Wales, has provided solar-powered bus stops,footpath lighting and traffic warning lights to more than 100 public authoritiesthroughout the country.

Further west, Ceredigion County Council estimates that opting for a SolarGentraffic warning system saved it some 60 per cent in installation costs, plus the dis-ruption of digging up the road to put in cabling. By opting for solar traffic warningsystems there is no need for channelling cables, which will make the installation andmaintenance easier.

The company says that every light exchanged for a solar-powered light savesapproximately £20 a year in electrical costs. Ceredigion saves around four times thatamount with each solar-powered light it installs.

Newcastle has also installed its first solar-powered traffic signs. The signs, warn-ing motorists of traffic signals ahead, have a PV panel on the top to power up arechargeable battery. As the panel does not require direct sunlight to charge thebattery it can easily cope through overcast days in winter. And when night falls aphotoelectric cell switches on the 50 light-emitting diodes (LEDs) to illuminate thesign internally. The LEDs have a life expectancy of 100 000 hours, compared to the4 000 hours of a conventional lamp.

Newcastle plans to install similar signs on the central motorway and coast road,where the reduced installation costs should bring considerable cost benefits.

Western Isles Council is piloting two solar-powered street lamps provided bySolarGen. One is a stand-alone in the Lochs area of Lewis and the other is connectedto the grid, located in Stornoway town centre. It is the first grid-tied system in the UK.

Solar is also powering many of the pay-and-display machines that have come toreplace the antiquated parking meters installed in the 1950s.

Schlumberger Sema has installed around half of all the pay-and-display parkingmachines in the country, amounting to several thousands. The company is turningover half of its manufacturing capability to solar-powered machines, as it is seeinghuge growth in the area. It has just installed 456 solar-powered pay-and-displayterminals in Edinburgh, and has secured a further contract for solar terminals, againin Plymouth.

The only downside with solar-powered pay-and-display terminals is that theywon’t function in underground or poorly lit multistorey car parks. But the poten-tial market for the units is huge, as it encompasses not only local-authority parkingzones, but company car parks, airport car parks and so on. The Edinburgh machineswill be centrally monitored by a communications and database programme, whichwill provide staff with revenue data and alert engineers whenever a terminal needsattention.

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Panel 7.1 Sustainable Lambeth

The London Borough of Lambeth thinks councils play an important role ingetting renewables into all the UK’s streets. It spends around £50 million onconstruction every year, which means there is enormous potential to integraterenewables.

In Lambeth, the Housing Directorate has taken a lead on sustainability. Itfits with the council’s sustainable construction strategy and climate-changeagenda, and it promotes good practice in construction. Lambeth Housing hashad very positive publicity from sustainable construction and this was anotherbest-practice element to the programme.

Lambeth allocated £50 000 each year from the Lambeth capital fund – seedfunding that enabled the team to start planning projects and bid for a PV grant.

The first project to benefit from this approach was at a sheltered housingscheme with 45 dwellings, called Tomkyns House, owned by the council. PVwas installed along with solar thermal to reduce carbon emissions and energycosts. The housing department spent around £30 000 on the PV panels andinstallation and leveraged a further £20 000 to fund the solar thermal fromother sources. The PV panels, incorporated into the roof’s safety guardrail,now power communal areas, while the solar thermal will feed into a projectthat will give residents better and more controllable heating.

Lambeth Housing’s first integrated PV roof is a much larger project at War-wick House on the Angel Town Estate. This extensive regeneration project hasbeen under way for many years and residents support a sustainable agenda forthe project. Warwick House incorporates high insulation, passive stack venti-lation and condensing boilers.

Communal lighting within Warwick House will be powered from the PVarray on the building’s pitched roof. A local company, Solarcentury, is the pre-ferred PV supplier for the council. The array at Warwick House, supplied bySolarcentury, provides 11 775 kWh/year, roughly equivalent to the communallighting load. The PV has been partly funded by a £71 614 grant from the (for-mer) Department of Trade and Industry’s Major PV Demonstration Programme.

Lambeth’s third project is part of a £600 000 refurbishment at LangholmClose, a sheltered housing block with 43 dwellings. Once again, the projectaims to introduce sustainable construction techniques and the housing depart-ment plans to use solar shingles, provided by Solarcentury. This project hasan unusual design, with the conversion of seven flat roofs to pitched roofs.The system is likely to cost £160 000 and is likely to generate in the region of238 000 kWh/year.

Major solar PV schemes are being backed up by thermal projects under thecouncil’s Health and Housing scheme, where the energy strategy officer, ColinMonk, is expanding a scheme to install solar thermal as part of a project toprovide central heating for older residents. Feedback from residents has beengood and 25 further installations now have secured funding under the ClearSkies programme.


Panel 7.2 Experience in Grimsby

The DIY chain B&Q had been in discussions with BP about its solar cells. Butin 2002 the company did not see photovoltaics as financially viable for a longwhile. The company’s interest in DG was mainly in on-site microCHP.

But at Grimsby the planning department took the lead. During the planningapplication for a garden centre at B&Q, the local authority asked if the com-pany could install photovoltaics and rainwater harvesting. It had recently givenplanning permission to another garden centre with the same provisions, andasked the company to generate as much power as would be used to light theplants in the garden-centre area. The company was cautious, and not becauseof the store’s location in the north-east but because the building already existed,as B&Q had taken over a developer’s shell, and the garden centre was to be onits north side. The PV panels had to be on the south side of the building. But,as it happened, the building was perfectly lined up for it.

The panels installed at B&Q are single-crystal versions, 35 m long by 1.2 mhigh. BP had used the same technology on its filling stations, so B&Q knew itwould work, but had to think about how to install it and calculate the energybalance.

There were some practical issues. The panels can be seen from the A16 sothe company had to consider whether they would cause dazzle, but the angleis too steep for that to be a problem. The company was also worried aboutvandalism – bricks being thrown at the panels and so on. But it relied on anexisting security fence that was 4 m high, and thought there was little chancethat the panels would be hit.

At less than 5 kW, the panels are rated ‘domestic’, which made installationeasier. However, the company was already discussing its connection agreementwith the distribution network operator over a substation problem, and it did notwant to delay the opening of the store while negotiating the amendment to allowfor the PV.

B&Q said that it had to answer the DNO’s concern for the safety of itsown employees, who could be making repairs when the normal supply hasfailed, potentially suffering a back-feed from any small localized generation. Itinstalled an inverter that is synchronized with the grid. If the grid falls away itstops – it doesn’t operate in ‘island’ mode.

The question of metering the PV for export did not arise, because in prac-tice the company knew it would never export electricity. The store’s base-loaddemand is 40 kW and it peaks at 319 kW. The photovoltaics peak at 5 kW.

The PV panels cost about £20 000 to buy and install. The company describedit as a ‘considered experiment’ – it was expensive, but was a small addition tothe total cost of the development.

One benefit of the panels is that they incur hardly any operation and main-tenance costs. The rainwater-harvesting system, in comparison, uses threefiltration stages and an ultraviolet scrubber, and maintenance expenses aresignificant.

Chapter 8

Combined heat and power

A common method of generating electrical power involves a process known as theRankine cycle. A working fluid (often water) is placed in a system at high pressureand is passed through a boiler. The fluid is heated, but, because of the high pressure,it does not boil but instead becomes ‘superheated’. The superheated liquid is thenexpanded through a turbine, which it turns to produce electrical power. The resultinggas is then condensed into a liquid and returned to the circuit.

The process produces electricity, but most of the heat generated to drive theprocess is wasted – for power stations dispersing this waste, heat is a real problemand requires cooling towers or large heat sinks such as rivers or the sea.

But heat is a basic requirement for both industrial and domestic uses – in fact,some 40 per cent of the UK’s energy requirement is for heat. Using the heat from thepower station – for example, by piping hot water to local homes and businesses in adistrict heating scheme – makes very little difference to the operation of the powerstation but can increase the proportion of the fuel that is transformed into usableenergy from 30–40 per cent to upwards of 80 per cent.

8.1 The UK CHP programme

The idea of regarding both the potential heat and power outputs of a power station asuseful products is neither new nor unusual, but the potential has often been disregardedin the UK, even though there are plenty of existing projects that could take accountof its opportunity. Combined heat and power, or CHP, has been of most interestto industry that has a high heat demand (see Panel 8.1). It has huge potential forsmaller organizations in the industrial and commercial sectors, and equally in housingdevelopments.

The UK government’s strategy for CHP development is managed by theDepartment for Environment, Food and Rural Affairs, or DEFRA.

In 2004 the government published a target to achieve at least 10 000 MW of‘good-quality’ CHP by 2010. Progress has been extremely slow, partly because ofchanges in electricity-trading arrangements that did not favour CHP plants and madethem less attractive to commercial companies.

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Since 2000, the government has introduced a package of measures to supportCHP. These measures, as reported on in the CHP Strategy, included:

• exemption from the Climate Change Levy for all good-quality CHP fuel inputsand electricity outputs;

• Climate Change Agreements to provide an incentive for emissions reductions;• eligibility for Enhanced Capital Allowances (ECAs) to stimulate investment;• business-rates exception for CHP power generation plant and machinery; and• a reduction in VAT on certain domestic microCHP installations.

Grant support was available from the Community Energy programme to encour-age CHP in community heating schemes and the bioenergy capital grants scheme.Both are now closed to applicants.

DEFRA also lists a series of supporting easures in the regulator framework:

• changes to the licensing regime, benefiting smaller generators;• working with Ofgem, to ensure level playing field under the British Electric-

ity Trading and Transmission Arrangements (BETTA) for smaller generators,including CHP;

• emphasizing CHP benefits when planning or sustainable development guidanceis reviewed or introduced;

• reviewing procedures on power-station consents applications to ensure fullconsideration of CHP;

• exploring opportunities to incentivize CHP under any future Energy EfficiencyCommitment (EEC); and

• encouraging the take up of CHP through the building regulations.

Take-up was extremely low and the government decided to set an example bysetting a new target, to source 15 per cent of energy at government offices from CHP.

In 2006, the government also commissioned Cambridge Econometrics to assessthe potential for a CHP Obligation, and a number of other support schemes have alsobeen proposed.

8.2 EU Directive support

CHP received additional impetus after the EU passed the Directive on the Promotionof Cogeneration (Combined Heat and Power) in the EU.

The overall objective of the Directive is to create a framework to facilitate andsupport the installation and proper functioning of cogeneration where a useful heatdemand exists or is foreseen.

The main measures contained within the Directive are:

• a ‘guarantee of origin’ to be readily available for electricity produced fromcogeneration;

• obligations on member states to analyse national potentials for high-efficiencycogeneration and barriers to their realization;

Combined heat and power 79

• provisions for evaluating different support mechanisms for cogeneration used bymember states;

• provisions laying down the principles for the interaction between cogenerationproducers and the electricity grid; and

• provisions requiring member states to evaluate current administrative proce-dures with a view to reducing the administrative barriers to the developmentof cogeneration.

The Directive came into force on 21 February 2004. The government said its CHPQuality Assurance (CHPQA) strategy meant the UK was largely compliant with theDirective, but proposed further action in a consultation at the end of 2006.

The European Commission’s 1997 Cogeneration Strategy set an indicative targetof doubling the share of electricity production from CHP in total EU electricity pro-duction from 9 per cent in 1994 to 18 per cent by 2010. But in the time since thenthere has not been a significant increase in the share of CHP in the EU.

The need for policy action was reinforced in the European Commission’s 1997Cogeneration Strategy and its Communication on the implementation of the EuropeanClimate Change Programme.

The purpose of the Directive is to promote high-efficiency CHP wherever aneconomically justified potential is identified in order to save energy and reduce carbondioxide emissions. It does this by creating a framework that can support and facilitatethe installation and proper functioning of CHP where a useful heat demand (heatproduced in a CHP process to satisfy an economically justifiable demand for heat orcooling) exists or is foreseen.

8.3 Domestic CHP

The Rankine cycle is not the only available method of generating electricity from heat.Since 2000, the Stirling engine has attracted lots of attention as a potential method ofusing waste heat to generate electricity.

The Stirling engine was invented over a hundred years ago and for many yearshas been used in specialist applications. Stirling engines are efficient and quiet but inmost cases it is an unhurried technology, which takes a while to build up to full speedand almost as long to slow down without extensive braking systems.

Like all engines, the Stirling engine works because hot air expands. If you heat airin a rigid container the pressure inside increases as the hot gas tries to find more space,until it can find a way out (like steam from a whistling kettle) or burst the container.Similarly, hot gas shrinks as it cools and tries to pull the sides of its container inwards.

In a Stirling engine, gas is moved backwards and forwards in a sealed systembetween two cylinders with pistons in them, at different temperatures. The workinggas inside the engine (which may be air, helium or hydrogen) is moved by a mechanismfrom the hot side to the cold side. When the gas is on the hot side it expands andpushes up on a piston. When it moves back to the cold side it contracts, pulling thepiston on that side.

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Once the gas has expanded into the hot side it would stay put, except that thepiston is pushed back up by the crankshaft as it continues to turn. And it continues toturn because it is attached to a heavy ‘flywheel’. This is also the reason why Stirlingengines are slow to start up, as the flywheel is storing energy and it takes a fewrevolutions to get it started.

Some Stirling engines can run on very small temperature differences – AmericanStirling Company offers educational versions that can be run on a cup of coffee. Butthe company explains that, as the temperature difference becomes smaller, the size ofthe Stirling engine that would be needed to get them to do anything useful becomesunfeasibly large. So the best versions use high temperatures – such as gas burners –on the hot side.

8.4 Developing domestic technologies

Over the last few years companies such as BG Group have been investigating Stirlingengines as combined-heat-and-power plants for domestic and commercial uses. Twoproducts based on very different applications of the cycle were investigated.

The New Zealand company Whispertech began work on Stirling engines in 1989and released its first commercial DC units in 1998. Whispertech says its versioncombines four piston-cylinder sets in an axial arrangement, with the hot end of onecylinder attached to the cold end of the adjacent cylinder.

The company says that, if the power from the pistons was transferred to a rotarymotion by a traditional crank type of mechanism, it would put considerable sideloading on the pistons and cause rapid guide and seal wear – traditionally a life-limitingfactor in Stirling engines. Instead, it has developed a ‘wobble-yoke’ system to convertthe linear motion of the engine’s four pistons into the rotary motion necessary to drivea generator, while putting very little side load on the piston seals and guides. Thewobble-yoke mechanism connects the pistons to a single rotating shaft and alternator,which are sealed into the compact housing.

The Microgen microCHP was based on a design by US-based Sunpower andbased on a linear-free motor. The CHP unit is started up in synchronization with thegrid and a planar spring acts with the control system to maintain its frequency at 50Hz.

8.5 Development issues

Development of both microCHP units has been problematic. The target is a toughone: it is hoped the technology will replace conventional boilers, but that meansreducing its size to fit a standard kitchen spacing. It is unlikely that capital cost andinstallation charges will ever be as low as standard boilers, so customers will haveto be convinced that the benefit of lower electricity bills over time will outweigh theupfront cost.

The opportunity to export excess power to the grid could be a major sellingpoint for such products. But the grid structure in England and Wales is notoriouslyunprepared for such small-scale export.


As late as November 2001, for example, a framework document for design andplanning of low-voltage networks in greenfield housing estates referred to PV gen-eration as a possibility but said that domestic generation was unlikely in greenfieldestates – by then, BG Group already had nine microCHP prototype units in operationin UK houses.

As distributed generators of all sizes have found, connection requirements are notuniform across the UK. New generation coming onto the system usually has to applyto the local DNO, which operates as a regulated monopoly, for permission to connect,and the DNO sets the conditions. One significant victory has already been won: therequirement to pre-notify the DNO and obtain agreement for a microCHP installationwould be replaced by a ‘fit and notify’ arrangement. The original requirement wouldhave made it almost impossible to install microCHP ‘on the spot’ – for example toreplace a broken-down boiler – and removed a major opportunity.

A second issue is metering output from the microgenerator. Companies involvedin domestic generation have lobbied for bidirectional meters that would simply recordthe net import of generation, but the industry regulator Ofgem has consistentlyopposed this approach, and says that, since in every case a new meter would berequired, ‘there is merit in being able to measure import and export’.

In the past, Ofgem’s distributed-generation coordinator has pointed out, ‘If youdon’t export much, it doesn’t matter too much. But say you have a development ofthree or four hundred houses and a distributed CHP plant. You have a considerableamount of generation on the network and at certain times not much of it is being used.Then it is helpful to know the import/export profile.’

However one important development has been made in metering: microgener-ation has been exempted from the requirement for half-hourly metering normallymandatory for potential exporters.

Microgen pointed out that there are some users who may have significant exports,highlighting the old, who have constant heat demand throughout the winter and littlepower consumption. But in most cases the power available for export will be limited.The microCHPs would be generating power at times when they are producing hotwater and that also coincides with peak electricity consumption, when most domesticusers are consuming more than the kilowatt or so that they can generate.

If microCHP proved popular, its most significant effect is likely to be on thecountry’s load profile, rather than in providing large quantities of power for export. Upto 13 million homes in the UK could use gas-fuelled microCHP and, with all of themgenerating at peak times, the country’s winter peak demand would be significantlyreduced. That would mean lower peak prices and reduced requirements for reservecapacity.

But once again Ofgem has counselled caution, noting that when heating demanddisappears in the summer all those customers will once again need to meet theirdemand from the grid.

The units also offer greatly improved efficiency. Using gas to generate electricityin a power station and then transmitting the power overall has a fairly low efficiency.The best gas-fired generating stations convert around 60 per cent of the energy in thegas to electric power, and many are far less efficient. More of the power is dissipated

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as it is transmitted through the power network. But because all the heat producedby a microgenerator is used in the house, and electricity is a useful by-product,these small units can claim efficiency percentages in the high nineties. Even withoutallowing for the energy required to transmit the gas to the point of use, that is a hugeimprovement.

8.6 Who would buy?

The market potential is tempting. Since each year 6 per cent of boilers are replaced,there will be 8 million new installation opportunities by 2010. The big question iswhether domestic consumers – and installers – will accept microgeneration. So far,British domestic consumers have proved to be fairly resistant to new technology ofthis type. Condensing boilers, for example, have been very slow to penetrate thedomestic market – their higher capital cost weighing more with consumers than theirhigher efficiency.

Some observers have suggested that microCHP may be blocked by supply com-panies, but in fact other pressures on the UK market may mean that far-thinkingsuppliers become its best advocates.

The government’s increasing focus on energy efficiency and demand reductionmeans that supply companies are already under pressure to become more than sim-ple electricity suppliers, or look forward to competing in a shrinking market. Thatmeans acknowledging that the customer’s real need is seldom for electricity. Insteadit is for heat or for cooling, for example, and providing energy services rather thankilowatts.

MicroCHP suppliers see a potential market for their products anywhere there isa significant heating season, relatively expensive electricity and a good domestic gasnetwork. That makes Western Europe a core market (Microgen is also investigatingconnecting its system to a furnace for the US market, where forced-air heating ismore common than water-based heating systems).

In late 2006 it seemed that the potential for microCHP would remain just that,when BG Group, parent of the leading energy supplier Centrica, withdrew frommicroCHP development, citing problems with reducing the size of the unit, alongwith noise.

Development has not stopped: major boiler supplier Baxi has taken over devel-opment of Microgen and at the time of writing it was planning to bring a domesticproduct to market at the end of 2008. There are problems to be solved at the domesticscale, but larger versions of the technology are thought to be ready for deployment,and, indeed, Whispertech is selling its products at this scale.

The likely first market now is groups of apartments or houses that are served atthe moment by a single boiler. This would be replaced by a large microCHP unit,which would supply heat to all consumers and produce electricity as a by-product.This scale of technology is no longer constrained by domestic requirements and isgenerally housed in a dedicated room or a basement, so noise restrictions are not soonerous.


This type of arrangement is common in apartment blocks in many Europeancountries. In the UK it is a relatively rare arrangement but far from unique. In fact,around 1 per cent of Britain’s housing is served by joint heating and hot-water systems.Replacing these with CHP would make a real contribution to cutting energy use andtherefore carbon dioxide emissions.

Switching is not necessarily technically complicated, but it does require under-standing from those who own and manage properties. Once again, the capitalcost is almost certainly higher, but whole-life costing makes the CHP option moreattractive.

CHP is an option at the moment that is easy to ignore or dismiss in the commercialsector as not offering a return on investment. Two major policy changes may shiftthat perception. First is the work of local councils. Since 2000, upwards of halfthe UK’s 300 or so local councils have added new requirements to their planningstandards that make it mandatory for new developments to include energy-efficientor renewable-energy sources that would cut carbon emissions by up to 20 per cent(see Chapter 13). In that case CHP is a well-proven step on from boilers. The othernew policy, proposed in 2006, would see energy users in the smaller commercial,industrial and public sectors given carbon dioxide emissions allocations in a tradingscheme intended to parallel that used for large emitters across the EU (the EmissionsTrading Scheme, or ETS – see Chapter 19). That would also make CHP an attractiveoption because any additional cost for the CHP, compared with a standard boiler,would be balanced by the potential for extra income from reducing carbon dioxideemissions and selling excess allowances. At the start of the ETS several companies,notably in the pulp and paper industry, switched to CHP in exactly this fashion(see panel).

Panel 8.1 Good projects on paper

A new CHP plant at M-real’s Hallein mill in Austria will provide it with 21 MWof process heat in the form of steam, along with 5 MW of electricity to exportto the power grid at favourable rates.

The decision to build the new plant was an economic one, says man-ager Erich Feldbaumer, and it seems the carbon dioxide ETS tipped thebalance.

The mill currently uses a variety of sources for its heat and steam supply.The main boilers produce steam at 100 t/h using process liquor and these areaugmented by a dual-fuel plant, running on heavy fuel oil or gas, that suppliessteam at 75 t/h. Four additional fossil-fuelled steam blocks provide 30 t/h anda reheat boiler has 1.5 t/h available as backup.

The new CHP plant will replace the four steam blocks. It will be fuelled withsludge, bark and other residuals backed up by wood from local forests. Fuellingthe new plant will require the plant to process some 250 000 m3 of residuals

Continues

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Panel 8.1 Continued

and wood fuel each year, with the wood transported from as far away as 70 km,but Feldbaumer points out that the residuals would be handled on site in anycase, and the new unit will reduce the amount that has to go to landfill as waste.‘Our production is 2 million m3 a year in any case,’ he says, ‘so it is no big sitechange.’

Operation and maintenance will be performed by Hallein’s existing utili-ties department, whose 36 members already manage the existing steam unitsand other auxiliary processes, providing a round-the-clock service in five six-member shifts. Where the new CHP plant will change operating philosophiesis in the ranking of power units: the new plant will be ranked second and willbe used in preference to the dual-fuel unit to reduce fossil-fuel use.

As a major energy user, UPM wants to ensure that its mills are suppliedwith energy that has the least possible environmental load. In the spirit of thisprinciple, UPM has invested during the past few years in the utilization ofbiofuels. Now such fuels account for 60 per cent of the company’s total fuelconsumption.

At UPM most of the heat and power is consumed by its pulp and paper mills.Mills strive to utilize the by-products from the pulp and paper processes as

efficiently as possible. Reducing the amount of residues and increasing recov-ery are key targets at all UPM mills. Power plants at paper mills burn bark,forest residues, fibre residues and solids from de-inking and effluent-treatmentplants. Chemical pulp mills burn black liquor that forms during the pulpingprocess.

The new sludge boiler at Shotton Mill in the UK will combust all sludge pro-duced in the recovered-paper recycling process. To support the combustion ofmill sludge, biomass fuels will be co-combusted. The investment will increaseShotton’s self-sufficiency in heat by up to 90–95 per cent and in power by upto 25 per cent.

Meanwhile, in France, the latest investment is at Chapelle Darblay.Here a new power plant will annually combust 160 000 tonnes of energywood (branches, tops and stumps from logging operations) available in theregion and all the sludge produced in its recovered-paper recycling process.After this investment the production process at Chapelle Darblay will becarbon-dioxide-free.

In Finland the use of biofuels has increased and five new CHP plants havebeen built. At UPM’s Rauma paper mill on the west coast of Finland theplant will produce electricity, steam for the paper mill and district heat forRauma city.


Panel 8.2 London housing

The London Borough of Tower Hamlets says it has nearly alleviated fuelpoverty on the Barkantine housing estate thanks to the Barkantine CHP project,which it built and operates in partnership with London Electricity Services (partof EDF). The CHP unit provides hot water and electricity to 540 householdson the estate, as well as the local school and leisure centre.

The scheme received Private Finance Initiative (PFI) funding of more than£6 million and a grant of £12 500 from the Energy Saving Trust (EST) to inves-tigate legal issues, because the scheme is set up as an energy-services company(or ESCo – see Chapter 18).

The 1.4 MWe CHP unit, which has the potential to supply 1 000 houses, isin a refurbished substation on the estate.

The partnership will operate and manage the Barkantine project for 25 years.After the third year of operation, the council will receive a share of the profitsevery second year to invest in energy-saving measures on the estate.

Chapter 9

Biomass

Wood is one of the oldest biomass fuels and still has an important role to play.

9.1 Biomass fuels

Wood fuel can come from conifer forests, broadleaved woodlands, urban and roadsidetrees, clean by-products and offcuts from wood processing. It may be purpose-grownas short-rotation coppice (SRC), where high-yielding species such as willow andpoplar are planted at high density and harvested at three- to five-year intervals. A widevariety of forest products can be used: early thinnings, small-dimension roundwood,poor-quality crops, the side branches and tops of trees harvested for their stem wood.

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From an environmental point of view, burning wood from sustainably managedforests – that is, forests where harvested trees are replaced – has little net impacton carbon dioxide emissions. In Britain, a fuel market for currently unsaleablesmall roundwood could bring many small and derelict woodlands back into activemanagement with benefits for wildlife and rural employment.

Wood has provided heat for millennia, but only recently has modern technologyincreased efficiency and automation. In northern Europe and North America, wood-burning technology is widely used and markets are large and well developed. Innorthern Europe, medium-sized, automated central-heating systems underpinned bycapital-grant schemes were used to develop the markets, after which large-districtheating, combined heat and power (CHP) and power schemes were built.

Wood now accounts for up to 40 per cent of space heating in rural areas insome countries. Britain’s Forestry Commission exports timber for this purpose. TheCommission recently supplied 2 000 tonnes of timber via a merchant from its NorthYork Moors forests to Denmark for use in wood-burning power plants.

9.2 Heating programmes

In Britain there are comparatively few (perhaps a hundred) automated, wood-firedcentral-heating systems, mostly in businesses that produce considerable volumesof waste wood that they can use themselves, or on large rural estates. A handful ofwood-fired-power or CHP schemes were also in operation as of mid-2002. Indigenoussuppliers of both fuel and burners are small and few in number. Scotland, Wales, EastAnglia and the south-west of England are out in front, with the West Midlands closebehind.

The Forestry Commission is working with private forest owners, potential cus-tomers and government departments to identify opportunities for wood fuel. TheCommission has produced a draft wood-fuel policy, which looks at the obstaclesto developing a wood-energy industry and outlines ways to overcome them. Eng-land, Wales and Scotland are developing their own wood-fuel strategies to meet theirparticular pressures and conditions, but the Commission has also outlined a broadthree-phase framework strategy as a guide for moving forward.

In Phase 1, the Commission will seek to stimulate and promote markets for woodfuel by focusing on existing or low-risk technologies. It hopes that development ofmarkets for heat and co-firing with coal for electricity generation will demonstratethat a market for wood fuel exists and improve the knowledge base and operatingsystems, which will in turn lead to a reduction in costs and an increase in profitability.

Phase 2 will attempt to develop wood-fuelled production of CHP, evaluatenew technologies and systems (especially co-firing with gas, pyrolysis and ethanolproduction), and improve perceptions of wood fuel.

Finally, Phase 3 will build on pilot projects by introducing the most successfultechnologies and systems identified at the pilot stage. At the same time, the sustain-ability of various levels of wood-fuel removal will be monitored and, where levelsare unsustainable, practices adjusted to ensure sustainable forest management.

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9.3 Wood-energy strategies

Distinctive regional wood-fuel strategies are being developed across the UK.In England, the woodland resource is a valuable one of over 1 million hectares,

representing 8.4 per cent of the total land area.Marches Energy began the Marches Wood Energy Network (MWEN) in January

2002. The network has run workshops and built a network of at least 70 organizationsand individuals wanting to use wood heat. It is now ready to support installations andkeen to start an ESCo.

Herefordshire Sustain Project was started in February 2001 by the Small WoodsAssociation. It involves a broad partnership with local estates, Holme Lacy College,Bulmers and others and has plans to use wood from the estates to heat local build-ings, including the college, so acting as an educational resource on sustainabilitycourses.

Worcestershire County Council has installed a 700 kW wood-fired central-heatingsystem at County Hall, and another at Garibaldi School in Mansfield, with plans toreplicate on eight other sites. The council works via a contract with a private-sectorESCo and there is no public subsidy, although the total cost will be a little higherover the next ten years than an equivalent gas-fired system. The partnership hasestablished a not-for-profit renewable-energy company, Renewable NottinghamshireUtilities (ReNU).

ReNU has already secured DTI and New Opportunities Fund (Lottery) fundingto subsidize the installation of 4 MW of wood-fired boilers to operate under energy-services contracts. The initial tranche of boilers is being funded through the PublicSector Agreement Initiative and ReNU will secure fuel of sufficient quality andquantity under a fuel-supply agreement. These sources include wood from sustainablymanaged local forests and woodlands, clean recycled waste wood, new dedicatedenergy forestry, and potentially short-rotation coppice.

The Forest of Mercia, one of 12 community forests nationally, started in 1990 withlocal-authority and other partners and has trialled wood heating (pellets and logs),although fuel supply is seen as a key constraint. A school and the project officeshave been heated with wood and an action plan for extending wood-fuel use has beenproduced.

The potential supply of wood in the West Midlands much exceeds present demand.Foreseeable demand can be met from woodlands and clean waste from wood pro-cessing and manufacture. The creation of a national forest will provide a significantextra and growing resource, with around 500 ha of new woodland per year. Cost willbe a critical factor, but currently there is a surplus of low-grade material that could beused. Figures quoted for wood fuel have been in the region of £40.00–45.00/oven-dry tonne delivered (equal to £20.00–22.50/green tonne with a 50 per cent moisturecontent). A similar strategy is being developed in the south-west.

With an investment from the government of £100 million, DEFRA’s Energy CropsScheme encourages landowners in England to diversify their business by setting upproducer groups and planting energy crops. New energy-efficient schemes to heathomes, schools and other public buildings received more than £6 million in direct

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grants, adding to another tranche of £22 million already handed out to projects underthe government’s Community Energy Programme.

The investment has prompted plans for five large biomass power stations andseven small-scale biomass heating projects in England. These could produce enoughheat and electricity to meet the needs of more than 90 000 homes – equivalent to acity the size of Southampton.

9.4 Wood for Wales

Since it is facing a decline in the home-grown timber market, developing a domesticwood-fuel market is a key objective of the Welsh Assembly’s Strategy for Woods andTrees.

The Forestry Commission in Wales launched a Wood Energy Business Scheme(WEBS) to foster the development of a wood-fuel industry in Wales by providingcapital grants for wood-fuelled boilers and ancillary equipment.

WEBS is a support programme for businesses in the Objective 1 areas of WestWales and the Valleys, and the Objective 2 area of Powys. It has been establishedby Forestry Commission Wales on behalf of the Welsh Assembly Government, withEuropean funding through both Objective 1 and 2 mechanisms.

WEBS will provide appropriate projects with grant support to facilitate the instal-lation and operation of wood-fuel-powered heating and power generation plant, andequipment for the initial processing of roundwood into chip and pellet form. Bydoing so it will provide the pump-priming impetus for development of a viable supplyinfrastructure. This in turn provides a real incentive for landowners to bring woodlandback into management, with associated environmental benefits, and potential ruralemployment prospects.

The scheme will provide grants towards the initial capital cost of relevant plant andequipment, typically boiler systems, drying facilities and wood-chipping/pelletingmachinery, to businesses able to provide a detailed business case for a wood-fuelledsystem of between 80 kW and 2 MW capacity. This will typically be small to mediumpublic buildings, such as schools, hospitals and leisure centres. It will also supportdistrict heating or CHP installations that supply heat to a number of buildings andpower to the National Grid. The percentage grant available will depend on the strengthof the case for support and the actual location, but will be potentially as high as 50per cent.

In order to ensure that sufficient supplies of fuel are available before the private-sector supply comes on stream, Forestry Commission Wales has agreed to allocate100 000 tonnes of small roundwood from its own felling programme in the initialyears of the scheme.

Wales already has a community wood-heating project. In 2000 Powys EnergyAgency was consulted on replacing the boiler to heat a school and community centreat Ysgol Vyrnwy, Montgomeryshire.

After realizing that the school and community centre could be heated with locallysourced wood fuel, the local authority and the Forestry Commission explored the

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possibility for a community heating system. A feasibility study funded by the ESTshowed this to be viable. The idea was presented to the community through openmeetings and a questionnaire, the results of which showed interest from 30 localhouseholds.

Following two years of project development, the tender process and selectionof energy supply company took place between December 2002 and March 2003.The boiler was installed in August 2003 and commissioned in November 2003. Theschool and community centre now receive heat from the 520 kW Compte wood-chip, remote-automated boiler. The houses are connected to the boiler by a hot-water pipe referred to as a heat main. Hot water will continue to be available in thesummer, when there is little demand for space heating. There is a 350 kW backup oilboiler.

The project involves a number of partners including Ysgol Vyrnwy, LlanwddynCommunity Council, Antur Vyrnwy, Severn Trent Water, Powys County Council(legal, education, planning, community development, etc.), Forestry CommissionWales, Forest Research Board, Powys Energy Agency and Dulas Wood Energy.The system is owned by Powys County Council and Powys Energy Agency. It wasinstalled, and is now operated and maintained, by Dulas Wood Energy.

9.5 Wood-fuel research

As part of its broader nationwide strategy, the Forestry Commission has scientists atthe government-funded research body Forest Research working on a study to quantifythe volume of wood fuel available from woodlands, purpose-grown energy crops andother sources.

The programme has established a UK-wide network of more than 50 trial sitesand aims to produce definitive data on the SRC yield of more than 30 varieties ofenergy crop. The network of trial sites is funded in partnership with the predecessorsof BERR and DEFRA (the DTI and MAFF), the Department of Agriculture and RuralDevelopment in Northern Ireland and industrial members of British Biogen.

The study summarizes existing information to give temporary guidance on estab-lishment, indicative yields, harvesting operations and approximate costs to help theevaluation of these types of crop as sources of renewable biomass. Results from thetrial are posted on the Forest Research website.

The project is the largest field trial in the UK, and in Europe, of poplar and willowspecies grown as crops for the provision of biofuels. Its main aim is to develop modelsthat will forecast growth and yield performance in different climates and sites.

Fast-growing willow and poplar are among the most promising tree species forSRC, and the website shares the results of research trials. It also pulls together practicalinformation on cultivation and on grant support, intended to help existing and potentialgrowers as well as the policymakers.

At present, economic and logistical factors are the main constraints to the success-ful development of Britain’s wood-fuel industry. The costs of felling, transporting anddrying wood fuel mean that current prices for wood fuel do not offer much in the way

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of a profit margin to the producer. Moreover, the potential market for wood fuel isas yet undeveloped. Although some companies in a few locations have found nicheswhere they can operate at a profit, these developments are still at an early stage, andlarge-scale markets have not yet been proven.

Logistical constraints may be a larger obstacle to development. Britain does notcurrently have enough biomass to generate the expected proportion of the govern-ment’s renewable-energy targets (about 1 GW by 2010). In order to increase supply,new planting – either for wood fuel alone or for mixed objectives of wood fuel andtimber – is essential.

The regional availability of resources is also uncertain. National figures estimatethat by 2010 available wood-fuel resources will be around 4 million m3, but it ismore difficult to say what is available in a particular area and at a particular price. Adetailed breakdown of present and future resources is therefore needed to determinewhat is available within a realistic radius of a potential wood-fuel development point,and this will hopefully emerge from the trial results.

9.6 What is pyrolysis?

When biomass breaks down it does not transform directly from wood into carbondioxide. During the process a variety of smaller organic compounds are produced andthen broken down further. At some points in the process the intermediate productscan be abstracted, potentially in a more usable form than the initial biomass. Liquid,solid or gas forms are all potential products and share many characteristics with gasand liquid (e.g. oil or diesel) produced from fossil fuels. As a result, they may beavailable as replacements, or to mix with fossil equivalents.

In pyrolysis the first stage of the breakdown involves heat but no oxygen. In someaspects it is a process that has been known for hundreds of years, as when charcoalburners heated wood in insulated burners over a slow fire. The charcoal is light tocarry and has good clean-burning characteristics. What the charcoal burners did notknow was that the natural gases and oils produced during the process could also beburned, as we use fossil-sourced gas and oil.

Some process conditions, including low temperature, favour the production ofcharcoal. High temperature and longer residence time increase the biomass conversionto gas. Moderate temperature and short vapour-residence time produce liquid oils.In effect, pyrolysis converts biomass to products that can replace those used in ourconventional fossil-based processes.

Pyrolysis is always the first step in combustion and gasification processes, whereit produces a gas that can be used to operate gas turbines. Fast pyrolysis for liquidproduction is currently of particular interest, as the liquids are transportable andstorage is relatively simple. Fast pyrolysis occurs in a time of a few seconds or less.That means that developing it as an industrial process requires work not only on thechemical reaction but also on transporting the feedstock to the reaction process andon removing the heat produced. The reaction takes place at a temperature of around500 ◦C and residence times of typically less than 2 s.

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In fast pyrolysis, biomass decomposes to generate mostly vapours and aerosolsand some charcoal. After cooling and condensation, a dark-brown liquid is formedthat has a heating value about half that of conventional fuel oil. Bio-oil can substitutefor fuel oil or diesel in many static applications, including boilers, furnaces, enginesand turbines. There are a range of chemicals that can be extracted or derived, includingfood flavourings, specialities, resins, agrichemicals, fertilizers and emission-controlagents. Upgrading bio-oil to transportation fuels is not economic, although technicallyfeasible.

While it is related to the traditional pyrolysis processes for making charcoal, fastpyrolysis is an advanced process, with carefully controlled parameters to give highyields of liquid.

The main product, bio-oil, is obtained in yields of up to 75 per cent wt on a dry-feed basis, together with by-product char and gas, which are used within the processto provide the process heat requirements, so there are no waste streams other thanflue gas and ash.

A fast-pyrolysis process includes drying the feed to typically less than 10 percent water in order to minimize the water in the product liquid oil (although up to 15per cent can be acceptable), grinding the feed (to around 2 mm in the case of fluidbed reactors) to give sufficiently small particles to ensure rapid reaction, pyrolysisreaction, separation of solids (char), quenching and collection of the liquid product(bio-oil).

Virtually any form of biomass can be considered for fast pyrolysis. While mostwork has been carried out on wood due to its consistency, and comparability betweentests, nearly 100 different biomass types have been tested by many laboratories rang-ing from agricultural wastes such as straw, olive pits and nut shells to energy cropssuch as miscanthus and sorghum, forestry wastes such as bark and solid wastes suchas sewage sludge and leather wastes.

Chapter 10

Energy storage

Part of the reason why the electricity system requires such careful management is thatelectricity is not a storable commodity. If a peak in demand is on the way, or may beon the way, it is not possible to store up a pile of electricity and release it at the rightmoment.

This has important implications for managing the electricity grid. Electricitydemand is not constant. It tends to go up and down depending on the time of day andof year, as different groups’ electricity requirements begin and end. The biggest peakis generally on a winter evening, when domestic demand for heating, lighting andother uses is highest. A summer night has the lowest energy use.

Since it is not possible to store electricity, the aim for an electricity supply companyhas to be to invest in a diverse range of generation that will give it the best opportunityto match supply and demand.

10.1 Diverse energy in the network

A mixed system makes the best use of the different types of generation. Some formsof generation are slow to start up and have little flexibility in operation, but in con-tinuous generation they are cost-effective. These plants would typically be operatedcontinuously to supply ‘base load’ – the electricity required even on a summer’s night,maybe 30 per cent of the average load. Forms of generation that can be started upwithin minutes or hours and cycled up and down to provide more or less power wouldbe brought on to the system as load increases during the daytime and the industrialload increases. Finally, power would be added from very flexible generation to supplymorning or evening peaks.

Within this scenario different forms of renewables also have different character-istics. Wind energy is predictable in broad terms over a few days and in more detailover a few hours. Wave energy relies in part on the weather and so is affected byexpected weather patterns over days and hours, but is also a function of the physicallandscape. Tidal power is very predictable but not constant, as it will come on to thegrid in regular peaks whose timing varies in a predictable way with the tides.

The grid operator cannot predict demand in perfect detail, so ‘spinningreserve’ – effectively plants operating in neutral, or instantly available power suchas hydropower – has to be available to feed into the system at any moment. This isone reason why a large proportion of a single form of generation can be costly for the

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system. France, for example, has an extremely high proportion – some 77 per cent –of nuclear generation operating at base load. This has inconveniences for the Frenchgrid operator, which are alleviated by selling excess power at times of low Frenchdemand to its neighbouring countries. Countries with high proportions of wind powersometimes find that additional spinning reserve is used, either because more windthan expected results in additional wind generation, so other forms of generation aretaken out of supply, or to be ready for a potential loss of wind generation if windspeeds are forecast to drop in the next few hours.

Clearly, any form of energy storage is beneficial in managing such a system,and especially one where large amounts of renewable energy may become availableat times when the system cannot use it. Since the electricity cannot be stored, thealternative is to store a proxy – for example, by charging a battery. The biggest formof energy storage used worldwide is water.

10.2 Pumped storage

Hydropower plants, where water is stored behind a dam or, at smaller scale, in amillpond, are already offering an opportunity to store energy in the form of water. Ifit is not necessary to generate at full capacity, or at all, because other generators aremeeting the system needs, water can be allowed to collect in the reservoir or pooluntil the power is needed. In fact, in some countries this is an important feature of theprojects. In Norway, for example, reservoirs are filled during the spring by snowmeltand receive little additional water during the year. Similarly, in tropical countries,monsoon rains annually fill the reservoir.

Hydro-turbines can be brought into operation within seconds or minutes whennecessary, and water can be moved from one area to another by pumping. Thesecharacteristics have led to the development of pumped-storage plants.

On first glance, it may be difficult to see the benefit of a pumped-storage plant. Inthis type of plant there are two (or more) water reservoirs at different elevations andone (or more) generation/pumping station. Water is pumped up to the higher reservoirand released when necessary to flow down through the hydrogenerator to the bottomreservoir.

It is a net energy user: it always takes more energy to pump the water up to thetop reservoir than can be gained from generating on the way down. And it may beexpensive to build – requiring two sets of water-storage capacity and some very robusthydro pumps/turbines in between. But the pumped-storage system adds so much tothe overall efficiency of the electricity supply system that it is almost always worth theinvestment, and in a privatized industry there are plenty of opportunities to operatethe plant at a profit.

Pumping is done at times when there is excess power on the system and lowdemand, soaking up base-load power and the intermittent generation. Then, whendemand peaks, the stored water is released. It is immediate. One of hydro’s greatstrengths is that it starts up in seconds, reducing the spinning-reserve requirement.And, although it may have high capital costs, the avoided cost of generation is very

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low and it knocks carbon dioxide-producing gas, oil or diesel plants out of the rankingsat peak times.

The economic potential of pumped storage has been fully realized in deregulatedmarkets, where price differentials between times of low and peak demand are veryclear. The UK built two pumped-storage plants in Wales in the 1970s, expected topump and generate on a twice-daily cycle to meet peak demand. They fulfilled thatrole until privatization of the industry at the start of the 1990s, but now they pump andgenerate up to 100 times a day, and the reason is the new marketplace for electricity.The UK’s market, like many others, sees prices ten or a hundred times higher in peakhours than it does at low load, and electricity bought and sold in half-hourly slotsoffers many opportunities to buy or sell.

Similar possibilities have been picked up by Tasmania, which has hugehydropower and wind resources and a volatile privatized market across the BassStrait in mainland Australia. Hydro Tasmania now plans to install an undersea cableacross the strait so it can operate what will effectively be a pumped-storage systemwithout the pumping.

With some 2 260 MW of installed capacity and a peak load of only 1 600 MW,Tasmania has a more than comfortable reserve margin – the result of a long-term viewthat led to the creation of reservoirs far in excess of needs, an awareness that rainfallto feed the reservoirs could vary by 30 per cent from year to year, and a recognitionthat long-term storage may be required. It is also beginning to develop another ofits natural resources: the high wind speeds that arise because of its position in thelatitude of the so-called ‘roaring forties’. Hydro Tasmania estimates that wind speedson its west coast average 8–9 m/s – a ‘world-class wind resource’ – and it believesit has 1 000 MW of wind potential in the area. But the peak demand of the island’shalf-million population is growing fairly slowly and Hydro Tasmania is anticipatingderegulation and looking for new markets to grow its business. The answer is to shippower across the Bass Strait to the national electricity market to feed the growingneeds of Victoria and South Australia. In this market base prices are low, thanks tothe ready availability of coal, but summer peak prices are much higher and have beenknown to hit thousands of dollars for some short periods. Hydro Tasmania hopes toarbitrage this market.

The company will save its water reserve at times when prices are low, providingperhaps 600 MW and importing power from Australia to meet demand. At Aus-tralian peak times it will generate up to 2 000 MW to supply its own customers andthe Australian market. The wind turbines will feed into the grid whenever they aregenerating, allowing Hydro Tasmania to conserve its water so that it has maximumcapacity available when the price is high.

Roger Gill, general manager of Hydro Tasmania’s generation division, describedthe combination of the hydro reserve, the export link and the wind capacity as a‘quasi-pumped storage system’. It may not be classical pumped storage, but it usesthe concept in a way that allows the company to get all the energy management andeconomic benefits of pumped storage without having to invest in the real thing.

These are large-scale projects. But, as we have seen, small hydro offers many ofthe benefits of large hydro, and the same is true in pumped storage.

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As might be expected, water companies have made most of the running in this,because almost all the components for small-scale pumped storage are already on thesystem. Water companies have a large number of reservoirs where water is storedbefore it is sent out to users. Maintaining supplies often requires water to be pumpedfrom aquifers, rivers or other sources into the reservoirs. Meanwhile, water companiesare increasingly installing hydro-turbines in the outfall from reservoirs, where in thepast there would have been a pressure-reducing valve or settling pond to remove theenergy from the water.

These are the components of a pumped-storage system. It only remains for thewater companies to operate them as such for the benefit of the electricity system –something that water companies are increasingly taking on board.

10.3 Gas storage

A situation analogous to pumped-water storage also exists in the gas transmissionand distribution network. When fed into the network, gas has to be pressurized fortransport, and on arrival that pressure has largely to be released for delivery.

It has been proposed that turbines installed at decompression stations can recoversome of the energy from the system by generating electricity.

Once again, the compression and decompression process is a net energy user. Butit allows energy that would otherwise be lost to be at least partially recovered.

10.4 Batteries

In many cases simply using a battery storage system in conjunction with anintermittent electrical source may provide enough control.

Sustainable Energy Ireland (SEI) published the results of a feasibility study for theimplementation of a wind-energy storage facility at Sorne Hill Wind Farm, Buncrana,Donegal.

The study, which was jointly funded by SEI and Tapbury Management Limited,which oversees the management of Sorne Hill Wind Farm, examined the costs andbenefits of integrating a battery-based power storage system with a 6 MW wind farm.

The feasibility report provided an initial technical and economic validation for anumber of the key revenue streams that had previously been identified in relation tothe integration of wind power and storage.

The analysis of the feasibility of using an energy-storage system showed thatcombining the turbine with a battery system could support an uninterrupted sup-ply of wind-generated electricity to the National Grid and significantly improve theefficiency of the energy produced.

The purpose of the report was to determine the optimum size for such a systemin order to deliver an optimum return on investment, and to review the main benefitsthat this system would offer. The report concluded that the optimum battery is a2-MW-capacity battery delivering six hours of electricity storage.

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10.5 Centrifuges

At a medium-voltage scale, and more closely associated with the end-user thanpumped-storage projects, energy storage can be combined with power-quality man-agement. Urenco Power Technologies’ kinetic-energy storage system (KESS) is beingselected to resolve a range of power- and energy-management problems encounteredin applications such as wind farms, uninterruptible power supplies (UPSs), mining,heavy lifting gear and mass transit.

At the heart of the system is a patented high-speed composite flywheel, whichtakes advantage of the basic physical laws whereby kinetic energy is proportional tothe square of the speed. The design comprises a tubular rotor 900 mm long and withan external diameter of 330 mm, which is made up of carbon-fibre and glass-fibrecomposite weighing 110 kg. The bore of the rotor is lined with a patented magnetic-loaded composite, impulse magnetized, to produce the poles of the motor generatorand the passive magnetic bearing. The top speed is 630 Hz, with a surface speed equalto 1 400 mph.

It can also act as a power-levelling device, or as an energy sink. In its basic con-figuration, KESS offers an alternative to large battery banks used in UPS systems. Itoffers protection from a range of disturbances, including voltage dips, short blackoutsand brownouts. For users requiring continuous operation, it provides a bridge betweenmains power and backup generation. In this mode, the control system operates in sucha way as to maintain a constant voltage at the DC bus. The system is able to supplythe changes associated with varying loads while maintaining this constant voltage, incontrast to battery systems, where the output voltage decreases with increasing loadand as the battery discharges.

In Japan, the system has been used to improve operation at a wind farm at MountObu, Oki island. A single 200 kW unit has been fitted to a 600 kW wind turbine tosmooth the output. The overall variability of the turbine output (due to wind gustingand the pitching and yawing of the blades) has been significantly reduced.

Other applications include a 1 MW system installed on New York City Transit’stest track to support track voltage and save energy. The system consists of 10×100 kWmachines and has now been operational for 10 000 hours, reinforcing the voltage ofthe test track during testing of the new trains being supplied to New York City Transit,as well as of the adjacent revenue line during normal operation.

10.6 Moving to a hydrogen economy

An alternative method of energy storage is to use excess electricity at times of lowdemand to produce hydrogen. The hydrogen can be stored and used for fuel cells orother types of generation at times when demand is higher than generation.

This potential role for hydrogen has found much favour among policymakers,although work on developing systems has proceeded very slowly. The reason is thepossibility that hydrogen could eventually replace gas or petroleum products and beused in the transport industry.

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This proposal helps untie one of the biggest knots in plans to ‘decarbonize’ theworld’s economy. The aim of switching from fossil fuels to fuels that do not producecarbon dioxide has been driven by the need to reduce carbon dioxide emissions tohalt manmade climate change. But in the longer term there is another reason: thescarcity of fossil fuels, especially gas, means that a replacement will be needed inany case over the next several decades. Hydrogen is seen as the most likely source,as in theory it could be used in the same ways as gas.

Hydrogen has equally important potential for replacing gas in electricitygeneration.

It should be clear that in this context hydrogen is not an energy source. Its role isstorage and conversion of energy.

Producing hydrogen is expensive, not least in the energy cost required. It may beproduced by electrolysis (see above), or biological methods, and in each case energyis required to produce it. As with pumped storage, the idea is to use free or cheapenergy to produce the hydrogen – possibly renewable-energy-generating facilitiesthat are generating during low-demand periods. Hydrogen can then be pumped ortransported in another form to the point of use, where it may be used to generateelectricity or heat, or as transport fuel. Of course the transfer and reconversion of thehydrogen will require energy as well.

Hydrogen has already been used in demonstration projects as transport fuel or forheat and electricity production via fuel cells (see Panel 10.1). Whether it will ulti-mately replace fossil fuels as the energy carrier of choice depends partly on whethersimple and safe methods can be found to transport the hydrogen. Researchers haveexperimented with chemical storage systems, where hydrogen is held on a solid sub-strate in a different chemical form. This may be useful in the same way as rechargeablebatteries, with the hydrogen-storage modules refilled at local energy schemes wherehydrogen is, for example, being produced overnight by a wind turbine.

More ambitious projects to build a hydrogen infrastructure that would rival theexisting gas or electricity networks have also been proposed. Here, hydrogen could beproduced on an enormous scale – for example, using wind farms far offshore. Thereare technical issues to be overcome here in piping and transporting the hydrogen,which is less amenable than gas to a pipeline infrastructure. It also depends on howdirect electrical technologies such as batteries develop and whether the costs of thenew infrastructure would be justified. It is hard to see where investment in convertingelectricity to hydrogen and in a network to transport it would be financially viable ifdirect sales of the electricity were as successful for the end user.

Panel 10.1 Norway’s hydrogen experiment

In summer 2004 ten households on the island of Utsira, 20 km from the coastof Norway, became part of an experiment in new energy systems. In a pioneerproject, their electricity is supplied solely from two 600 kW wind turbinesand hydrogen. The hydrogen plant on Utsira started producing electricity inApril 2004.

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The rough weather at Utsira plays an important role in the process ofsupplying the island with power. The windy situation makes Utsira and its 240inhabitants a natural choice for wind-power production, and the wind turbinesinstalled will produce a significant excess of power under optimal conditions.

When there is too little or too much wind the turbines will not run. But onUtsira, excess power is being stored as chemical energy in the form of hydro-gen. On windy days electrolysers produce hydrogen for storage, and, when itis calm, a hydrogen engine and a fuel cell will convert the hydrogen back toelectricity. The hydrogen plant is dimensioned to produce enough electricity fortwo days with no wind at all – circumstances that are extremely rare on Utsira.

The Utsira project is outstanding in that ten households will receive all theirelectricity from renewable sources in a closed system. The power consump-tion of the islanders varies, but the stored hydrogen will ensure that sufficientrenewable power can be generated at any time – even when consumption ishigh and wind activity is minimal.

The hydrogen that will ensure stable power supply is produced from waterand the electricity from one of the wind turbines by means of an electrolyser.The excess power from the turbines is sold on the electricity market.

Norsk Hydro is leading the project. The German wind-turbine companyEnercon is also a partner in the project and the supplier of the wind turbines, net-stabilizing equipment and the control system. Hydro Electrolysers will deliverthe hydrogen plant, including electrolysers and the hydrogen-storage facility.Haugeland Kraft is the net owner for the ten households in the project, andhas signed an agreement with the project on the handling of electricity supplyfor customers and the use of the ordinary net. It has financial support fromEnova (a government body set up to promote environmentally friendly energyconsumption and production in Norway), the Norwegian Pollution ControlAuthority (SFT) and the Research Council of Norway.

The necessary infrastructure in the form of roads, water and electricity supplyand the foundations for the wind turbines was set up in 2003.

Hydro’s project organization, Hydro Technology and Projects, is responsiblefor the development, contracts and coordination of technical solutions. Hydro’spower production department will be responsible for day-to-day operationsof the whole plant. Enercon contributes both technology and a consider-able workload.

The most innovative aspect of this project is the way it puts it all togetherin a system. One of the challenges is the number of interfaces between theautonomous system and the rest of the net system. The demand for electricityvaries both through the year and through the day, and these variations have tobe met despite the fact that the wind is unpredictable.

Kraft also points out that the hydrogen engine and the fuel cell are the onlycomponents that the partners Hydro and Eneron have no experience of. One ofthe challenges in earlier hydrogen projects has been delays caused by problemswith fuel-cell deliveries.

Continues

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Panel 10.1 Continued

The island’s chief councillor, Robin Kirkhus, said that, in its first period ofoperation, the Utsira plant has already achieved production 97 per cent of thetime. He is hoping the project will become a permanent energy solution for theisland.

Panel 10.2 Hydrogen in Iceland

Commercial hydrogen filling stations in Reykjavík, Iceland, will be used to fuelthree DaimlerChrysler buses, which will be operated on a commercial basis inReykjavík by the municipal transport company Straeto. Private hydrogen vehi-cles are expected to follow in the future, and the Icelandic authorities havealready issued all the permits necessary for the station to operate on a commer-cial basis.

At present, the hydrogen is being supplied from geothermal and hydroelec-tric energy sources. Iceland has an abundant supply of geothermal energy, usedfor power production and heating, plus considerable hydroelectric resources.In addition, however, there are excellent opportunities for exploiting windenergy.

The Icelandic Allting committed itself to making Iceland the world’s firsthydrogen-based society, becoming fossil-fuel-free between 2030 and 2050.It set up a limited company, Icelandic New Energy (Islensk NyOrka, INE),in 1999 to spearhead the programme. The company is jointly owned bythe Icelandic VistOrka, with a stake of 51 per cent, plus DaimlerChrysler,Norsk Hydro and Shell Hydrogen. INE’s goal is to promote opportunities forthe production and use of hydrogen and fuel cells for different purposes inIceland.

As hydrogen is stored energy, there has been a discussion in Iceland regard-ing the possibility of producing hydrogen renewably for the European market.EURO-Hyport is a project pre-study looking into opportunities for large-scalehydrogen production, based on electrolysis and renewable power production,and how this can become a new, green export to Europe.

INE will also look into the possibility of the use of hydrogen by Iceland’sfishing fleet, as the fuel currently used by the fleet adds greatly to the coun-try’s carbon dioxide emissions. However, the technology has not yet advancedsufficiently to allow this.

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Panel 10.3 Battery powered

A hybrid PV (photovoltaic) and wind-power system on Bullerö, the main islandof a national park in the archipelago of Stockholm, uses Saft Sunica batteriesto provide a reliable supply of electricity.

Bullerö Island is remote from the nearest electricity grid and in 1986 the costof installing an undersea cable to provide power for the visitor facilities andthe park ranger, who lives on the island all year round, was estimated at aroundUS$100 000. Instead, in 1988, a low-cost combined PV and wind system wasinstalled. This was upgraded in 1996 with more PV modules and a new com-bined regulator and monitoring system.

The PV modules are mounted on an old air force tower and have an installedpeak power of 1.45 kW. The modules are connected by a 100-m cable to thebatteries in a battery room next to the park ranger’s house. A Rutland Furlmatic1800 wind generator with a nominal power of 0.25 kW is installed on a mast atthe back of the house. During the short periods when there is little sun or wind,a backup petrol generator with a nominal power of 0.75 kW is used to chargethe battery bank.

The battery bank comprises Saft Sunica rechargeable nickel-cadmium bat-teries with a nominal capacity of 571 Ah at 48 V. The system voltage of 48 VDC is converted to 12 V DC before being fed into the house. The electricitypowers lighting, a refrigerator and freezer, a radio, a television and a 1 kVAinverter for a few small appliances that need AC power. The Sunica batteriesare designed specifically for photovoltaic applications.

Photovoltaic systems require efficient batteries with a long cycle life anda potential for both shallow and deep cycling. The nickel-cadmium batteriesinstalled on Bullerö Island are designed specifically to meet key requirementsin this type of application, namely:

• constant charging efficiency over time;• continuous operation at any state of charge;• minimal self-discharge rates;• a high available performance even at very low states of charge; and• sustained efficiency even at high or low temperatures.

Chapter 11

Fuel cells

Fuel cells can provide heat and power, and a huge variety of fuel-cell devicescurrently being tested and demonstrated are likely to hit the market in the nextdecade.

11.1 How fuel cells work

Unlike other electricity generators discussed in this book, fuel cells produce theirpower as a result of a chemical reaction. Chemical reactions often involve the transferof electrons from one atom to another, leaving one positively charged and the othernegatively charged. If a carefully chosen reaction is made to take place in an electricalcircuit, with a source of electrons at one ‘pole’ and a substance that absorbs theelectrons to complete the reaction at the other ‘pole’, the electrons move around thecircuit.

A fuel cell operates a little like a battery. But a battery is a sealed unit containingits own fuel, in which the two poles are gradually consumed as a chemical processcreates electricity. As a result it ‘runs down’ as the constituents are consumed.

In contrast, a fuel cell provides the site for a chemical reaction that produceselectricity and water, but the fuel cell does not contain the chemicals that react: theyare fed in during the reaction so the fuel cell can continue to produce electricity andheat as long as fuel is supplied.

The principle of the fuel cell was discovered by the German scientist ChristianFriedrich Schönbein in 1838. Based on this work, the first fuel cell was developedby the Welsh scientist Sir William Robert Grove in 1843, using similar materialsto today’s phosphoric-acid fuel cell. It was in 1959 that the British engineer Fran-cis Thomas Bacon successfully developed a 5 kW stationary fuel cell. In 1959, ateam led by Harry Ihrig built a 15 kW fuel-cell tractor for Allis-Chalmers usingpotassium hydroxide as the electrolyte and compressed hydrogen and oxygen asthe reactants. Later in 1959, Bacon and his colleagues demonstrated a practical5 kW unit capable of powering a welding machine. In the 1960s, Pratt and Whit-ney licensed Bacon’s US patents for use in the space programme to supply electricityand drinking water (hydrogen and oxygen being readily available from the spacecrafttanks).

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11.2 Fuel-cell configuration

The reaction that generates the power in a fuel cell will happen whenever thecomponents are brought together: the key to producing useable power and heat fromthe cell is to manage the steps of the reaction so the products can be tapped at theright point.

There are relatively few components in a fuel cell. One of the most common typesuses a ‘proton exchange membrane’ (PEM).

• The anode, the negative post of the fuel cell, has several jobs. It conducts theelectrons that are freed from the hydrogen molecules so that they can be used inan external circuit. It has channels etched into it that disperse the hydrogen gasequally over the surface of the catalyst.

• The cathode, the positive post of the fuel cell, has channels etched into it thatdistribute the oxygen to the surface of the catalyst. It also conducts the electronsback from the external circuit to the catalyst, where they can recombine with thehydrogen ions and oxygen to form water.

• The electrolyte is the proton exchange membrane. This specially treated mate-rial conducts only positively charged ions. The membrane blocks electrons. Fora polymer electrolyte membrane fuel cell (PEMFC), the membrane must behydrated in order to function and remain stable.

• The catalyst is the material that helps the reaction of oxygen and hydrogen to takeplace. It may be made of platinum nanoparticles very thinly coated on to carbonpaper or cloth. The catalyst is rough and porous so that the maximum surface areaof the platinum can be exposed to the hydrogen or oxygen. The platinum-coatedside of the catalyst faces the PEM.

Hydrogen fuel diffuses to the anode catalyst, where it later dissociates into protonsand electrons. The protons are conducted through the membrane to the cathode, butthe electrons are forced to travel in an external circuit (supplying power) because themembrane is electrically insulating. On the cathode catalyst, oxygen molecules reactwith the electrons (which have travelled through the external circuit) and protons toform water. In this example, the only waste product is water.

The hydrogen/oxygen PEMFC used to be called a solid polymer electrolyte fuelcell (SPEFC) and is now known as a polymer electrolyte membrane fuel cell (PEFCor PEMFC, same as the short form for proton exchange membrane fuel cell).

In addition to pure hydrogen, there are hydrocarbon fuels for fuel cells, includingdiesel, methanol and chemical hydrides. The waste products with these types of fuelare carbon dioxide and water.

A typical fuel cell produces a small voltage. To create enough voltage, the cellsare layered and combined in series and parallel circuits to form a fuel-cell stack.

11.3 Solid-oxide fuel cells

A solid-oxide fuel cell (SOFC) is a fuel cell that generates electricity directly froma chemical reaction, yet, unlike normal fuel cells, an SOFC is composed entirely of

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solid-state materials, typically ceramics. Their composition also allows SOFCs tooperate at much higher temperatures than conventional fuel cells.

They are mainly used for stationary applications with an output between a few kilo-watts and 1 MW. They work at very high temperatures, typically between 700 and1 000 ◦C, so the gases produced can be used in a turbine to improve electricalefficiency.

In these cells, oxygen ions are transferred through a solid-oxide electrolytematerial at high temperature to react with hydrogen on the anode side.

The high operating temperature of SOFCs promotes the fuel-cell reaction so theyhave less need for catalysts (the platinum in the cell described above).

SOFCs have so far been operated on methane, propane, butane, fermentation gas,gasified biomass and paint fumes.

Thermal expansion demands a uniform and slow heating process at startup.Typically, eight hours or more are to be expected. Unlike with most other typesof fuel cell, which are stacked, the geometry of an SOFC can be more varied.

SOFCs can also be made in tubular geometries, where either air or fuel is passedthrough the inside of the tube and the other gas is passed along the outside ofthe tube.

An SOFC is made up of four layers. A single cell consisting of these four layersstacked together is typically only a few millimetres thick. Hundreds of these cells arethen stacked together in series to form what most people refer to as a ‘solid-oxide fuelcell’. The ceramics used in SOFCs do not become electrically and ionically activeuntil they reach very high temperature and as a consequence the stacks have to runat temperatures ranging from 700 to 1 200 ◦C.

The ceramic cathode layer must be porous, so that it allows air flow throughit and into the electrolyte. The electrolyte is the dense, gas-tight layer of each cellthat acts as a membrane separating the air on the cathode side from the fuel on theanode side. There are many ceramic materials that are being studied for use as anelectrolyte, but the most common are zirconium-oxide-based. Besides being air-tight,the electrolyte must also be electrically insulating so that the electrons resulting fromthe oxidation reaction on the anode side are forced to travel through an externalcircuit before reaching the cathode side. The most important requirement of theelectrolyte, however, is that it must be able to conduct oxygen ions from the cathode tothe anode.

The ceramic anode layer must also be very porous to allow the fuel to flowto the electrolyte. Like the cathode, it must conduct electricity. The most commonmaterial used is made of nickel mixed with the ceramic material that is used for theelectrolyte in that particular cell. The anode is commonly the thickest and strongestlayer in each individual cell, and is often the layer that provides the mechanicalsupport.

A metallic or ceramic layer sits between individual cells. Its purpose is to connecteach cell in series, so that the electricity each cell generates can be combined. Becausethe interconnect is exposed to both the oxidizing and reducing side of the cell at hightemperatures, it must be extremely stable. Ceramics are most useful but are extremelyexpensive. Research is focusing on lower-temperature SOFCs, which will allow metallayers to be used.

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11.4 Fuel-cell applications

As a route to generate electrical power at the point of use, fuel cells potentially havea huge number of applications. Among them are the following.

• Power generation. Portable power applications include small generators andbattery replacements. Fuel cells could be used in grid-connected locations foremergency backup and directly in the many areas where access to the electricitygrid is not available. In such areas they would offer alternatives to conventionalgenerators, such as diesel generators, that would allow power to be producedwithout noise or on-site pollutants. Domestic generator products are currentlynearing commercialization. Portable devices offer great potential as backup powersupplies.

• Battery replacement. Fuel-cell power sources are being developed for portableelectronic devices. In these applications, the fuel cell would provide a much longeroperating life than a battery would, in a package of lighter or equal weight per unitof power output. Fuel cells provide a higher power density, and are unlikely torequire the special disposal treatment required by many batteries. In any case thefuel cell itself would not require recharging or replacing, although its fuel supplywould need to be replenished.

Fuel-cell developers claim a higher efficiency than traditional combustion tech-nologies. The only drawback, as fuel-cell proponents concede, is that hydrogen isstill more expensive than other energy sources such as coal, oil and natural gas.

Three main methods are being investigated to provide inexpensive hydrogengeneration.

The first is known as reforming. Fuel cells generally run on hydrogen, but anyhydrogen-rich material can serve as a possible fuel source, including fossil fuels suchas methanol, ethanol, natural gas, petroleum distillates, liquid propane and gasifiedcoal. The hydrogen is produced from these materials by this reforming process. Thisis extremely useful where stored hydrogen is not available but must be used forpower, for example, on a fuel-cell-powered vehicle. One method is endothermicsteam reforming. This type of reforming combines the fuels with steam by vaporizingthem together at high temperatures. Hydrogen is then separated out using membranes.One drawback of steam reforming is that it requires energy input.

A second method uses bacteria and algae to generate hydrogen. The cyanobac-terium, an abundant single-celled organism, produces hydrogen through its normalmetabolic function. Cyanobacteria can grow in the air or water, and contain enzymesthat absorb sunlight for energy and split the molecules of water, thus producinghydrogen.

Finally, renewable energy, from solar or wind power, could be used to electrol-yse water into hydrogen and oxygen. In this manner, hydrogen becomes an energycarrier – able to transport the power from the generation site to another location foruse in a fuel cell. This process is particularly interesting for the renewable-energyindustry: it would answer objections that renewable energy is inefficient because the

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resource is not necessarily available when power is required, by using excess powerto produce hydrogen that can be used when, for example, wind power is becalmed.

Hydrogen can be extracted from novel feed stocks such as landfill gas or anaerobicdigester gas from wastewater treatment plants, from biomass technologies or fromhydrogen compounds containing no carbon, such as ammonia or borohydride.

11.5 Developing the industry

Fuel cells are unlikely to reduce overall energy consumption – the generation anddelivery of hydrogen fuel have their own energy requirement – but they do offer thepossibility of using that energy more efficiently. That is why both the US and EU areinvesting in developing fuel cells, as are potential users. The transport industry hasbeen particularly interested in the technology and has been backed by governmentfunding.

A total of 45 companies from across Europe have joined forces to push for thecreation of a Joint Technology Initiative (JTI) for fuel cells and hydrogen technology.The companies, which include Rolls-Royce Fuel Cell Systems from the UK andItaly’s SOFC Power, have formed an association called the JTI Industry Grouping asa first step to creating a JTI. The group is now pressing the European Commissionto accelerate plans to create the JTI (a public–private partnership) on fuel cells andhydrogen.

The European Commission has also launched a thematic call for proposals in thearea of component development and systems integration of hydrogen and fuel cells fortransport and other applications. The call covers fuel-cell and hybrid-vehicle devel-opment and the integration of fuel-cell systems and fuel processors for aeronautics,waterborne and other transport applications.

Elsewhere, European boiler manufacturers are developing fuel-cell units that canprovide heat and power on a near-domestic scale, offering on-site generation for anapartment block or small commercial or industrial units. Using both the heat andpower output makes such units extremely efficient. Demonstration units have beenin operation for several years, and manufacturers believe they will be commerciallyavailable in the next decade.

In Japan, Nuvera Fuel Cells and Takagi Industrial Co. have announced an agree-ment to develop commercial fuel-cell-based cogeneration systems for the Japanesemarket. Nuvera’s Avanti system uses natural gas to generate hot water and electricity.Takagi’s heat-management system will store the hot water and interface it with theend customer’s thermal demand.

America’s President George W. Bush announced that the US Department ofEnergy was investing more than $350 million in hydrogen research projects, alongwith $225 million in private-sector cost share, over the five years to 2010.

Chapter 12

Interacting with the electricity grid

Managing the electricity supply across the grid is not simply a case of generatingenough electricity to meet the needs of all the customers connected to it. Wherevercustomers tap into the power network it has to be able to supply power that has well-defined characteristics and that is supplied with minimal disturbances or interruptions.What is more, the quality of the grid supply has become still more important ascustomers at all scales from the domestic to heavy industry use electronic equipmentthat can be sensitive to disturbances in the supply that last a fraction of a second.

12.1 Voltage and frequency

The voltage and frequency of the network are the characteristics most often relevantfor domestic users. The UK system at the domestic level is maintained at a voltageof 230 V (originally 240 V, but the standard was changed to bring the UK into linewith mainland Europe). The supply frequency is 50 Hz.

The US system, in contrast, is maintained at 110 V and 60 Hz. All appliancesfor use in the UK are designed to operate at 230 V and 50 Hz, while US-marketedappliances require a 110 V, 60 Hz supply. Special converters are required to useUS appliances in the UK and vice versa. Similarly, power-generation equipment ismanufactured in different versions so that it can be used in grids that operate at 50 Hzor 60 Hz.

Whatever the function of an electrical appliance at whatever scale, it is convertingsome part of the power provided by the generator into other forms of energy – heat,light, sound, etc. This is known as a load.

12.2 Voltage

Voltage can be considered as the force that pushes electrons through an electricalcircuit. It measures the potential difference between two points, and in fact was onceknown as electromotive force (EMF). In some ways it is similar to the hydrostaticpressure in a water pipe that is higher at one end than the other. Gravity moves waterdown the pipe and enables it, for example, to turn a water-wheel.

The voltage is provided by a generator. The power provided by the generatormoves electrons that carry charge through a circuit but the charge encounters various

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levels of resistance. This is a very useful material property: the heat and light causedwhen a charge passes through a high-resistance material are the basis of the lightbulb, heating elements and so on. In such situations the electrical energy provided bythe generator is converted into usable heat and light. But no material is entirely freeof electrical resistance, and, as current flows along a wire or cable, some part of itsenergy is dissipated as the wire warms. This can be minimized by choosing the bestmaterial for the cables or wires, and by stepping up the voltage when transfer is overlong distances. This has the effect of reducing the current – a measure of the amountof current being moved – and the heating effect. The UK’s grid operates at 230 kV or450 kV for bulk transport of electricity across long distances and this reduces losses,but the supply is too large for most purposes except direct supply to some high-energyindustries. The circuits used to supply commercial and light-industrial premises mustbe of lower voltage and those at the domestic scale are at 230 V. Long circuits at thisvoltage can experience significant voltage drops along their length as users tap intothe supply.

12.3 Frequency

In an AC (alternating current) circuit the electrons are effectively being shunted backand forth, instead of being pushed steadily along the circuit as they would be by a DC(direct current) source such as a battery. Generators using rotating machinery producethis pattern and it means the voltage and current ‘cycle’ from zero to a maximum,back through zero to a minimum, and back to zero again. This provides a regular‘pulse’ 50 times per second. This is not ideal for large equipment such as motors, soa three-phase supply is used in which there are three supplies going up and down insequence to give a near-constant output.

‘Synchronous’ generators operate at a steady frequency locked into that ofthe grid, and because of that they help to maintain the frequency across thenetwork.

12.4 Reactive power

In an alternating current the voltage and current are constantly changing, reversingtheir flow (in the UK system) 50 times a second. As a current passes through acircuit component that has resistance, electric-field effects result. When the current isalternating, these fields are constantly changing and reversing along with the current.The consequence for the alternating current is that, instead of alternating in step,the voltage and current start to drift apart. This has important effects on the poweravailable in the circuit, because at any instant the power available is a product of thevoltage and the current. At some points the current and voltage are exactly out ofphase (i.e. the current is increasing to a maximum while the voltage is decreasing toa minimum) and the effect is that there is no net power flow – although energy isflowing backwards and forwards.

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This is reactive power and it must be carefully controlled in the circuit. Byconvention, inductive loads such as motors are said to ‘consume’ reactive power.In practice, most loads on the system are consumers of reactive power.

To compensate, reactive power has to be supplied to the system. The concept ofreactive power is a complex one but at bottom the effect of injecting reactive poweris to force the voltage and current parts of the alternating supply back into step.

This function may be performed by adding a generator to the system at a vulnerablepoint. But not all forms of generation are able to inject reactive power. Alternatively,dedicated equipment can be added to the system at vulnerable points.

In power transmission and distribution, significant effort is made to control thereactive power flow. During dispatch this is typically done automatically by switchinginductors or capacitor banks in and out, by adjusting generator excitation, and othermeans. There are also financial incentives on customers and suppliers to the system.Those that consume reactive power – for example, industrial sites with a large numberof motors, which are inductive – are penalized in their tariff. In the UK there is amarket for reactive power, which allows suppliers to offer reactive power to theNational Grid (or local distribution networks).

12.5 Maintaining the supply quality

The transmission system operator National Grid comments that power flows, bothactual and potential, must be carefully controlled for a power system to operate withinacceptable voltage limits. Reactive power flows can give rise to substantial voltagechanges across the system, which means that it is necessary to maintain reactive powerbalances between sources of generation and points of demand. System frequency isconsistent throughout an interconnected system, but the voltages experienced at pointsacross the system form a ‘voltage profile’ that is uniquely related to local generationand demand at that instant, and is also affected by the prevailing system networkarrangements.

National Grid is obliged to secure the transmission network to closely definedvoltage and stability criteria, and the operators of the low-voltage distribution networkhave the same responsibility for local networks.

The variation in demand over each 24-hour period has a basic pattern wherebydemand is lowest during the night and higher during the day, and increases to amorning and evening peak when domestic customers are at home. This is a cross-country aggregate and it varies with events where a significant proportion of thepopulation are involved. Soccer matches in which England are playing are a typicalexample: at half-time and full-time, there is an immediate demand surge as peopleput on kettles. This also happens when storylines in long-running soap operas reacha peak episode and in fact is a good way of assessing viewing figures.

Standby power is required for such events. But, as we have seen, the supply isaffected by more than just the demand: the nature of the demand is also important.An industrial site with a high demand to run motors, for example, will have a varyingrequirement for power and for reactive power.

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If the changes are planned or expected, such as the startup of an additional powerstation, or the regular demand of an industrial user, grid operators can ensure thetransition is smooth. In any system, for example, there is spinning reserve (see 10.1) –power generators operating ‘in neutral’ – that can be brought on to the system withinminutes or seconds, depending on their characteristics. These vary from large powerstations to small backup generators, often on industrial sites, that can provide power orreactive power at the medium voltage level. Similarly, some loads can be modulatedto compensate for a loss of generation.

12.6 Bringing on the reserve

In the UK there is a market for such services, in which the system operator NationalGrid periodically invites offers from companies who are able to operate flexibly. TheUK is not unique in this: in recent years interesting examples of demand and supplyresponse have been developing.

For example, wind power is often decried as an unpredictable and intermittentform of generation. It is certainly true that it becomes more difficult to predict windsupply over longer timescales. However, over a period of hours or minutes, operatorscan be pretty confident that, if there is a good supply of wind now, it will be therein an hour. This is particularly true in the offshore sector, where wind patterns canbe more easily predicted. That has allowed Denmark to use its offshore wind farmat Horns Rev for this type of ‘secondary regulation’. Denmark’s power supply islargely composed of CHP plants. Although these are very efficient, the importance oftheir heat loads and some regulations intended to support CHP mean that the systemoperator has very little control over the way they are operated, especially over thehours or minutes required to help balance the grid. The fastest response available onthe Danish system is the Horns Rev wind farm, because the power being produced atany time can be modulated by altering the angle of the turbine blades to catch moreor less wind – a matter of a few seconds. So, when the Danish operator expects asudden surge of power, the Horns Rev farm is held at an appropriate point below itsmaximum capacity. If demand surges the wind farm is modulated up and if demandstays at the higher level it continues operating at full power until, over several hours,other supplies can be brought to bear.

In the UK, companies with backup power supply have found the short-term reservemarket a useful one. Many different industries have to have backup generation imme-diately available. The ideal situation from one point of view would be if the backupgeneration never operated. But, nevertheless, power supply, generally in the form ofdiesel engines, has to be ready. The cost is more than simply the capital cost of theengine. It must also be maintained and started up on regular occasions to ensure thatit is available – with the resulting use of diesel fuel. Offering that generator in thereserve market means it may be called on a few times each year for periods up to a fewhours. That means test startups are no longer required; the income from the reservefunction may be enough to cover the maintenance costs of the engines, and it removesthe need for dedicated backup engines to be installed somewhere. Water companies


have found this particularly interesting and have the possibility of extending it andcombining it with management on the demand side. They have a large power demandspread across many sites, largely for pumping, with some power generated on theirsites using waste methane from sewage treatment. But in most cases water is pumpedfrom a source into a water-treatment plant, which generally includes water storage.That means that at most times water companies have flexibility about exactly whenwater is pumped into the water-treatment plant: anything from a continual, steadysupply to pumping all the water overnight, when there is little demand for powerand prices are low. Water companies can switch between using their power, usinggrid power and selling their own generation depending on payments available forload-shedding power generation, reserve power, etc.

12.7 Demand response

An interesting response on the demand side has been employed in several US cities.Energy-services companies take on power management of large, nonessential powerusers – in practice this has often been shopping malls, which have air conditioning,lighting, refrigeration, heating and many other mixed loads. The service companyacts as an intermediary between the shopping centre and the power company, buyingpower but also offering demand-reduction services at various levels. The incomefrom the demand reduction is shared between the shopping centre and the energy-services company. Experience so far has shown that a shopping centre can reduceits energy consumption by about 15 per cent effectively and continuously withoutcustomers being aware of any difference. Over short periods much bigger reductionsare possible: for example, chilling or heating loads can be cut for minutes or hours.

The demand response is small in comparison with the total load across the system,but such a system’s usefulness is far greater than it appears, not just for demandresponse but for the total system cost.

The generation system as a whole has to be sized to accommodate the highestlikely demand peak – plus a reserve in case a generator is unavailable or for anunforeseen extra peak. At peak times electricity is in short supply and the price – inthe half-hourly trading slot – can ramp up to many times the average price. This is thetime at which generators that are most expensive to operate have to be brought on tothe system. These may be the least efficient stations, or it may be that power stationsare built and connected to be used just a few times each year at peak times. Beingable to reduce demand reliably at peak times – known as peak lopping – reduces theneed for such plants.

12.8 Dealing with transients

When a new demand or load is added or subtracted from the system it affects thesupply: continuing our occasional water analogy, it causes ripples in the supply. Aswith water, the size of the ripples, how far they extend and their effect depend on thesize of the pebble and the size of the pool.

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Other disturbances can also produce transient or short-lived effects on thetransmission or distribution grid. A short circuit is one example caused by an impacton the cable or in the switchyard. This is unlikely in the case of transmission cables,since they are higher, but relatively common on the distribution network. There areregular examples of agricultural or industrial equipment striking overhead lines iftheir drivers misjudge their relative heights. Animals are also a frequent cause, espe-cially small climbing creatures such as squirrels, or trees and other vegetation canbe blown against the line. Lightning strikes are also frequently to blame – one effectthat is important for the transmission network. In many cases now, the network isequipped with automatic circuit breakers that switch in the event of a short circuitand automatically reclose a few seconds later to bring the line back into operation.In this case there is no loss of power (or a loss of only a few seconds) but the effectis to send more ripples across the network. In some cases it can cause a voltage orfrequency ‘collapse’.

Such transients have an effect. As computer operators know, power electron-ics systems are very vulnerable to them, so most computer shops sell socket setsthat include surge arrestors, which counter transient changes in the supply. Whichtransients have to be managed depends on how sensitive your computer is.

Similarly, equipment connected to the distribution or transmission networks hasto be protected against transients or faults in the grid supply, and the characteristicsof each type of generation determine how much protection is required and when,in certain circumstances, generators can help even out faults and add stability tothe grid.

Large disturbances in the grid can affect any generating plant and, beyond setlimits, most will automatically disconnect from the grid to limit the damage to theplant. But, as we have seen, the sudden removal of supply from the system can createits own fault: the result can be a domino effect that propagates faults far beyond theoriginal area and jeopardizes the running of the system.

Two such events happened within a few months of each other a few years ago. Inthe USA in August 2003 the loss of a transmission line in the north required power tobe switched to transport across another part of the network. The unanticipated extraload caused several power stations to ‘trip’, and faults quickly cascaded throughoutthe interconnected system in the north-east USA, eventually causing blackouts thatlasted several hours in New York and many of the surrounding states. Power cutsextended up to Canada. A few months later, similar effects caused blackouts in Italy.In both cases, the original event was a short circuit on one power line caused by atree striking the line.

For electricity-system operators, containing such an incident is easier if there aremore connections and an extensive grid: having a lot of transmission and distributionlines gives the operators different options for switching power around so that no onepart of the system becomes overloaded. Generators (and loads) also ideally havesome ability to ‘ride through’ faults, so they are less likely to disconnect and causethe problem to cascade. Some forms of conventional thermal and nuclear generationare valuable in this respect. Because they include heavy rotating machinery, the planthas huge mechanical momentum. A brief fault is not enough to interrupt the turning


generator and it will take several seconds before a fault develops that will cause it toseparate from the network.

Some other forms do not have this effect. Wind turbines, for example, havein the past been designed not to ride through faults but to disconnect immediately,because the turbine characteristics are such that the turbine risked being damaged bythe connection. This approach was taken because turbines were relatively small andseparated generators even in networks where they were widely used, and so the effectof disconnecting one small turbine from the network was very small. The situationchanged somewhat when wind started to be installed in much bigger quantities and inwind farms with a single connection that represented an important input to the grid,frequently in areas where the grid itself was spread thin and had little other capacityaround to share the burden. At this point, fault ride-through became an importantissue for wind. When a cyclist wobbles as he hits a pothole, it is not too important(except to the cyclist) whether he rides through it or falls off. But, if it happens in agroup of cyclists, the resulting pile-up could bring traffic to a halt for miles.

In practice, for large wind farms, electronic management systems can be incor-porated that allow the wind farm to mimic the ride-through ability of a generatorwith large rotating machinery, and this is likely to be cost-effective in a system wherefaults and unavailability are penalized.

12.9 Transmission/distribution interaction

In order to manage voltage, frequency and reactive power, and meet the other require-ments of supply, National Grid has a view of the electricity network that resolvesdown to around 8 km (5 miles). It has to take into effect not only the load and demandon its own network but, as we have seen, the cumulative effects of changes in thedistribution network.

This varies as load switches between consumer, industry and commercial users.Aggregate demand (the total from consumers in a region) is, of course, equallyvariable at the low-voltage level. The effects of the weather are well known, butare changing over time. DNOs know, for example, that, even if the temperature isrelatively pleasant, if there is rain and wind at the time people are travelling homefrom work they will tend to switch on additional heating when they arrive. If a sunnyday clouds over, lighting demand will rise because of apparent darkness, althoughthe ambient light levels are still high.

These changes are managed at the DNO level, where, of course, fault levels,voltage, frequency and reactive power have also to be managed. But, at the moment,the level of management is relatively light because the system is largely unidirectional– from the National Grid feed-in points from the transmission system through themedium voltage used by industry and commerce and then the low-voltage domesticnetwork. There are few points at which DG feeds in and no trading between differentparts of the network.

Elsewhere the situation has begun to develop somewhat differently, and a majorreason has been the introduction of DG. Thanks to the feed-in tariffs that guarantee

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export, German networks are required to accept all the power generated by windturbines, solar photovoltaics and other renewable-energy systems. Similarly, Danishnetworks are required to accept wind power and electricity from CHP plants.

This will ultimately make it necessary to operate distribution networks in a muchmore active way, more closely allied to the way in which the transmission network ismanaged. As this happens it will also require the interface between the distributionand transmission networks to be carefully managed. The assumptions previously usedby the transmission operator to track and predict demand and supply at the distributionnetwork may no longer be valid.

This is not an insoluble problem but in countries such as Germany and Denmarkit is one where the need to address it is moving rapidly up the agenda.

In November 2006 grid operators on the German border cut power to a transmis-sion line that passed over a river to allow a large ship to pass underneath on its wayfrom a shipyard to the sea. The transmission line was an interconnector – a line thatjoins the grids of two countries. The line had been depowered many times before forvery similar reasons, but in this case the result was a local blackout that triggeredblackouts centring on Germany and France and lasting only a couple of hours, butwhose effects were felt far further afield and for far longer.

The problem was traced to a lack of information passing between the grid oper-ators in the two countries and poor operating practices. It highlighted well-knowninadequacies in the extent of interconnection between European countries, especiallyin areas such as this, where there were large cross-border flows.

But, in its report on the incident, the Union for the Coordination of Transmission ofEnergy (UCTE) noted that lack of information between distribution and transmissionnetwork operators had made it more difficult for operators to bring the system backon line quickly.

The report said:

The requirements for disconnection of generation units connected to the distribution grid(especially wind generation and CHP) are usually less strict than for the units connectedto the transmission grid, i.e. they are disconnected at a smaller frequency deviation. Whenthe frequency deviation reaches the threshold values of the units’ protection, they areautomatically disconnected from the grid.

This was the case when the blackout happened: distribution units tripped whenthe frequency dropped below set limits. This worsened the situation in one of theblackout areas. The report adds,

Recovering the frequency to its nominal value required an increase of generation outputin the Western area and a decrease of generation output in the North-Eastern area. Aftera few minutes, wind farms were automatically reconnected to the grid, being out of theTSOs’ [transmission system operators’] control. This unexpected reconnection had a verynegative impact, preventing the dispatchers in both areas from managing the situation.

Additionally, certain TSOs in the North-Eastern area were not able to reduce the poweroutput from generation connected to the transmission and distribution grid in a sufficientlyshort time necessary for the frequency restoration.

These are examples of insufficient TSO control over the generation behavior. The TSOcontrol usually applies to generation connected to the transmission grid since traditionallythe generation connected to the distribution grids has not had a significant impact on the


power system as a whole. However, the recent rapid development of dispersed generation,mainly wind farms, has changed the situation dramatically. The wind generation in someareas significantly influences the operation of the power system due to its high share in thegeneration and intermittent behavior dependent on weather conditions.

In its recommendations, UCTE pointed out that

most TSOs do not have available real-time data on the power generated in the distributiongrids. In view of the rapidly growing share of such generation, this has multi-dimensionalconsequences:

• no real-time knowledge of the total national balance between supply and demand,• no real-time knowledge of the generation started in DSO [distribution system operator]

grids and possible tripping/reconnection in case of a frequency or voltage drop,• no real-time knowledge of generation started in DSO grids and possible impact on grid

congestion in the high voltage grid.

It also pointed out that at present the TSOs have no control over distribution-levelgeneration, and said this could lead to ‘serious power balance problems especially inover-frequency areas’. In response, it made three recommendations that would givetransmission system operators far more knowledge of, and control over, generationconnected to the distribution network.

• The regulatory or legal framework should be changed so that TSOs can assertcontrol over generation output (allowing them to change schedules, or to startand stop the units).

• TSOs should receive data on a per-minute basis on the generators connected tothe distribution system.

• Generation units connected to the distribution grid should have the same require-ments, in terms of behaviour during frequency and voltage variations, as unitsconnected to the transmission network.

Any such recommendation would likely impose requirements appropriate to thescale of differently sized DG. The effect of connecting or disconnecting a domesticsystem is very different from that of an industrial generator inputting tens of megawattsinto the grid. However, as we have seen on the demand side, the cumulative effect ofaggregating large numbers of similar systems should not be overlooked.

Developing control and oversight that provide enough management capabilityfor the distribution network, without overspecifying the generator and making itunnecessarily costly, is a balance that will have to be struck.

12.10 Adding microgeneration

What will be the effect on grid management of adding extensive microgenerationto the mix? Optimistic projections have suggested that domestic-scale generationcould meet up to 40 per cent of household electricity consumption. It may havean important role to play in reducing peak loads, but managing import and exportfrom the grid as millions of microgeneration units switch in and out presents its ownchallenges.

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The problem is that domestic demand varies, not just in aggregate but in individualhouses, as the Carbon Trust highlighted in a report on early field trials of domesticCHP.

The short-term export/import balance from buildings with any form of micro-generation is critical as electricity demand and supply must be balanced second bysecond. The Carbon Trust said that the amount of electricity exported from microgen-eration trial sites was considerably higher than forecast. ‘The reason for this appearsto be related to forecasting assumptions about electrical loads in homes during heatdemand periods.’

Modelling used for some purposes assumes that typical electrical demand inhomes during a half-hour is similar to the average demand in that half-hour. However,the Carbon Trust says that

trial data shows that for most of the time demand is much lower than the average and alsolower than typical microCHP output. Superimposed on this low demand are short periodsof very high demand. This is consistent with event-based modelling which builds up totalelectrical load from the predicted operation of electrical equipment. Typically a base-loadof 100 to 500 watts is present much of the time due to equipment including clocks, videos,televisions on standby, fridges and freezers. Added to this are intermittent, short durationpeak loads such as kettles (2 kW to 3 kW), electric showers (7 kW to 10 kW) and hair dryers(500 watts to 2 kW).

The Trust warns,

By averaging over a half-hour or longer these peaks are blurred into an average value ofaround 1 kW that ignores the significance of peaks and troughs. The reality of the situationis that low-voltage networks will have to be designed to cope with potentially high levels ofexport in addition to full load import when the units are not running and this needs carefulconsideration.

Chapter 13

Making progress on policy

The need to rethink the UK’s electricity network to accommodate local energyprojects was already exercising the minds of the industry at the start of the newcentury. In 2001 Callum McCarthy, then chief executive of the regulator, the Officeof Gas and Electricity Markets (Ofgem), said that government targets on renewablesand CHP would require the biggest revolution in the distribution network for 50 years.He told distribution network operators (DNOs) they must ‘bring these issues to the topof the senior management agenda’ and said that for Ofgem, too, it was ‘emphaticallynot business as usual’.

‘Today a DNO might have 300 embedded generators within its entire network. Ifthe government’s targets are to be met, by 2010 a DNO could have 300 generatorsconnected to every substation,’ McCarthy said.

Even then, he said, meeting the 2010 targets – 10 per cent renewable generationand 10 GW of CHP – would require 3 000 new renewable installations, 1 000 CHPplants and up to 3 million domestic CHP installations.

Technically, passive local networks would have to become active managers – and,financially, DNO investment planning would be more demanding and take on morecommercial dimensions.

13.1 Government strategy

In 2003 the government set out a strategy for developing the energy sector, in aWhite Paper titled Our Energy Future, that would give local energy projects andmicrogeneration an important role in the UK’s energy provision. It said,

We envisage the energy system in 2020 being much more diverse than today. At its heart willbe a much greater mix of energy, especially electricity sources and technologies, affectingboth the means of supply and the control and management of demand.

There will be much more local generation, in part from medium to smalllocal/community power plant, fuelled by locally grown biomass, from locally generatedwaste, from local wind sources, or possibly from local wave and tidal generators. Thesewill feed local distributed networks, which can sell excess capacity into the grid. Plant willalso increasingly generate heat for local use.

There will be much more microgeneration, for example from CHP plant, fuel cellsin buildings, or photovoltaics. This will also generate excess capacity from time to time,which will be sold back into the local distributed network.

New homes will be designed to need very little energy and will perhaps even achievezero carbon emissions. The existing building stock will increasingly adopt energy efficiency

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measures. Many buildings will have the capacity at least to reduce their demand on the grid,for example by using solar heating systems to provide some of their water heating needs, ifnot to generate electricity to sell back into the local network. Gas will form a large part ofthe energy mix as the savings from more efficient boiler technologies are offset by demandfor gas for CHP (which in turn displaces electricity demand).

In order to achieve that vision, the White Paper noted that

the nationwide and local electricity grids, metering systems and regulatory arrangementsthat were created for a world of large-scale, centralised power stations will need restructuringover the next 20 years to support the emergence of far more renewables and small-scale,distributed electricity generation; the future energy system will require greater involvementfrom English regions and from local communities, complemented by a planning system thatis more helpful to investment in infrastructure and new electricity generation, particularlyrenewables.

Over the last half-decade changes have been made that were intended to helppromote local energy projects. But progress has been mixed.

13.2 Planning progress

There has been progress on making it easier to get planning permission for renewable-energy projects, including local wind farms. Planning had been a huge barrier forprojects from domestic systems and up.

In 2004, Planning Policy Statement 22 (PPS22) for the first time set a positiveplanning framework for renewable energy. It said,

• Renewable-energy developments should be capable of being accommodatedthroughout England in locations where the technology is viable and environ-mental, economic and social impacts can be addressed satisfactorily.

• Regional spatial strategies and local development documents should containpolicies designed to promote and encourage the development of renewable-energy resources. Regional planning bodies and local planning authorities shouldrecognise the full range of renewable-energy sources.

• At the local level, planning authorities should set out the criteria that will beapplied in assessing applications for planning permission for renewable-energyprojects. Planning policies should not rule out or constrain the development ofrenewable-energy technologies.

• The wider environmental and economic benefits of all proposals for renewable-energy projects, whatever their scale, are material considerations that should begiven significant weight in planning decisions.

• Regional planning bodies and local planning authorities should not makeassumptions about the technical and commercial feasibility of renewable-energyprojects.

• Planning authorities should not reject planning applications for energy projectssimply because the level of output is small.

• Local planning authorities, regional stakeholders and local strategic partnershipsshould foster community involvement in renewable-energy projects.

Making progress on policy 123

For the first time, PPS22 insisted that the environmental benefits of renewablesand local energy projects were a good in themselves and should have a positive impacton the planning decision.

The guidance was helpful but local energy projects hit frequent barriers in gainingplanning permission. As a result, the government published additional guidance tounderpin and extend its support for local energy generation, making it a fundamentalrequirement for all new development in a revision of Planning Policy Statement 1(PPS1).

Published in 2007, PPS1 – on planning and climate change – took low-carbongeneration principles more fully into account, including not just renewable-energyprojects but all local energy generation that would reduce carbon emissions overall.

This PPS encourages regional planning bodies (RPBs), as part of their approachto managing performance on carbon emissions, to produce regional trajectories forthe expected carbon performance of new residential and commercial development,based on ‘average units/amounts of floor space’.

PPS1 said in its ‘Key Planning Guidance’ that all planning authorities shouldprepare and deliver spatial strategies that make a full contribution to delivering thegovernment’s climate-change programme and energy policies.

In preparing a regional spatial strategy, RPBs ‘should work with all stakeholdersin the region and alongside their constituent planning authorities to develop a realisticand responsible approach to addressing climate change’.

That would include ‘ensuring the spatial strategy is in line with applicable nationaltargets, in particular for cutting carbon emissions, and with regional targets on climatechange’. It would also require regional planning authorities to:

• ‘ensure opportunities for renewable and low-carbon sources of energy supply andsupporting infrastructure are maximised’; and

• ‘set regional targets for renewable energy in line with PPS22’.

What is more, local planning authorities ‘should assess their area’s potentialfor accommodating renewable and low-carbon technologies, including micro-renewables to be secured in new residential, commercial or industrial developmentand pay particular attention to opportunities for utilizing and expanding existingdecentralized energy supply systems, and fostering the development of new oppor-tunities for decentralized energy from renewable and low-carbon energy sources tosupply proposed and existing development’.

The planning authority should look favourably on proposals for renewable energy,and it should not require applicants to demonstrate either the overall need for renew-able energy or for a particular proposal for renewable energy to be sited in a particularlocation.

In an important development, PPS1 said that planning authorities should ‘ensurethat a significant proportion of the energy supply of substantial new development isgained on-site and renewably and/or from a decentralized, renewable or low-carbon,energy supply and should consider the potential for on-site renewable energy suppliesto meet wider needs’.

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This change arises from the pioneering work of the London Borough of Merton.Merton Council was first to introduce a new planning policy that required developersto build renewable energy or energy efficiency into the fabric of new factories, ware-houses and offices. If the proposed building is larger than 1 000 m2 and is not locatedin a conservation area, council planners will expect photovoltaic panels, solar waterheaters or other energy-producing equipment to be installed. The council will expectthis equipment to reduce the occupant’s carbon footprint by 10 per cent.

The policy emerged from the council’s review of its Unitary Development Plan.In spite of challenges from objectors who claimed that the policy would make ittoo costly for developers to construct commercial buildings in the borough, it wasstrongly supported by the appointed inspector. The idea quickly began to spread. TheMayor of London included a similar policy in his Plan for London, and several otherLondon boroughs redrafted their Unitary Development Plans to follow Merton’s lead.

The first building in Merton to be designed and built to comply with the policy wasa 3 000-m2 light-industrial and storage unit in Durnsford Road. But an early showcaseis a new office building planned for the site of the Odeon Cinema in WimbledonBroadway. Here the Chartered Institute of Personnel Development has been grantedpermission to develop 5 000 m2 of office space for its own use, provided that it installsrenewable-energy systems of sufficient capacity in the building. This will also givethe building engineers an incentive to minimize the energy use of the building.

The London Borough of Merton was applauded by Friends of the Earth for ‘mostinnovative action’ in its introduction of the policy. And, although developers initiallyargued that it was impossible and of dubious legality, the policy came successfullythrough all its challenges. Similar policies have already been adopted by upwards of50 councils and the provisions of PPS1 will require a similar provision by all planningauthorities.

13.3 Domestic changes

The support of PPS22 was useful at larger scale but of little help for the smallestprojects, especially at the domestic scale. For such projects the cost of applyingfor planning permission was enough to stop a potential purchase. B&Q, for example,which started selling domestic micro wind turbines that could be mounted on a house,reported that, although it had received several thousand enquiries, around one-thirdof all potential sales had been halted by the cost of planning permission – which itsaid had shown huge variation from £150 up to over £1 000 – or the opposition ofplanning committees.

In 2007 the government department now known simply as Communities and LocalGovernment (CLG), which has jurisdiction over planning policy, finally took forwardplans that would allow domestic energy projects to become ‘permitted development’,i.e. changes that can be made without requiring planning permission, so long as theinstallation meets building codes. The proposals covered solar, wind, CHP, biomassand heat pumps.


Solar: CLG suggested that there should be a general presumption in favour ofthe domestic installation of solar microgeneration equipment – photovoltaic or solarthermal. The principal restriction would relate to both solar on building and solarstand-alone technologies and reflect the potential visual impact that could occur in aconservation area or a World Heritage Site.

It recommended that solar technologies should be permitted, subject to their pro-jecting no more than 150 mm from the existing roof plane or standing off no morethan 150 mm from a wall. In addition, in order to ensure that the visual impact isminimized, no part of the installation should be higher than the highest part of theroof (which will generally be the ridge line). It also proposed there should be no limiton the roof area involved.

Wind turbines: Micro wind turbines would be permitted with blades 2 m in diam-eter at a height of 3 m above the roof or 11 m above ground level (for stand-aloneturbines). They would be subject to noise and vibration restrictions.

CHP and biomass: The CLG recognized that most biomass installation occursinside the property in the form of new boilers etc. It added a 1 m flue for such boilersto the permitted development scheme but did not extend the permit to a store forbiomass fuel.

Heat pumps: Ground- or water-source heat pumps would require assurance fromthe Environment Agency that no contamination of groundwater was possible. Allheat pumps would be subject to noise restrictions.

In 2006 the then Department of Trade and Industry and Ofgem jointly consultedon the barriers to DG that had still to be tackled.

13.4 Scotland and Wales approach

The devolved administrations in Scotland and Wales have planning responsibilitiesand both have produced planning policies to support renewables and local energygeneration.

Wales set out its approach to renewables in a planning Technical Advice Note(TAN8) published in 2005. TAN8 discussed all forms of renewable energy but focusedon wind farms, reflecting the contentious nature of such projects in Wales. TAN8 said,

the need for wind turbines is established through a global environmental imperative andinternational treaty, and is a key part of meeting the Assembly Government’s targets forrenewable electricity production. Therefore, the land use planning system should activelysteer developments to the most appropriate locations. Development of a few large scale(over 25 MW) wind farms in carefully located areas offers the best opportunity to meet thenational renewable energy target.

The Welsh Assembly identified areas in Wales that,

on the basis of substantial empirical research, are considered to be the most appropriatelocations for large scale wind farm development; these areas are referred to as StrategicSearch Areas (SSAs). Smaller (less than 5 MW), domestic or community-based wind tur-bine developments may be suitable within and without SSAs, subject to material planningconsiderations. On urban/industrial brownfield sites, small or medium sized (up to 25 MW)developments may be appropriate.

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It went on to say,

Local planning authorities should facilitate the development of all forms of renewableenergy and energy efficiency and conservation measures which fit within a sustainabledevelopment framework…. Local planning authorities should seek opportunities to inte-grate energy efficiency and conservation objectives into the planning and design of newdevelopment in their areas.

To back up TAN8, the Assembly’s Environment, Planning and Countryside Min-ister, Carwyn Jones, launched a new planning policy on climate change at the end of2006. It acknowledged that ‘there are a number of emerging policy issues related toclimate change that necessitate further advice for local planning authorities, landown-ers and developers and the community in Wales’. It said that new developments mustmaximize opportunities to reduce energy and water use, and to promote renewableenergy and efficient energy and water supplies.

It also adopted the approach pioneered by the London Borough of Merton,saying,

Local planning authorities should include within development plans a policy requiringmajor developments to reduce their predicted CO2 emissions by a minimum of 10 per cent(from the current baseline required by building regulations) through improvements to theenergy performance of buildings, efficient supply of heat, cooling and power and/or on siterenewable energy.

Scotland’s planning policy on renewable energy was published in March 2007. Ittakes the Merton policy further forward, saying that ‘development plans must includepolicies on the provision of low carbon and renewable sources of energy whichcomplement the increasingly high levels of energy efficiency required by buildingregulations’.

In local development plans, it says,

The expectation should be that all future applications proposing development with a totalcumulative floorspace of 500 sq metres or more should incorporate on-site zero and lowcarbon equipment contributing at least an extra 15 per cent reduction in CO2 emissionsbeyond the 2007 building regulations carbon dioxide emissions standard. The intention isfor national targets to increase through the Action Plan that will be prepared to implementthe Energy Efficiency and Microgeneration Strategy. In the meantime, the developmentplan process should be used to consider whether local circumstances justify going beyond15 per cent; below the 500 sq metres threshold; and whether higher standards can be securedfor particular developments, including the potential for decentralised energy supply systemsbased on renewable and low-carbon energy.

13.5 A microgeneration strategy

In March 2006 the then DTI (now called the Department for Business, Enterprise andRegulatory Reform, or BERR) released a strategy for microgeneration. It noted thatstudies had suggested that microgeneration could provide 30–40 per cent of domesticelectricity needs by 2050 and reduce household carbon emissions by 15 per cent.

But the DTI said that at that point there were only 82 000 microgeneration instal-lations in the UK. The objective of the strategy was to ‘create conditions under which


microgeneration becomes a realistic alternative or supplementary energy generationsource for the householder’. It could also help reduce fuel poverty for those withhard-to-heat homes that could not be insulated.

The government blamed cost constraints and the high price of microgenerationtechnologies, along with inadequate promotion, so that take-up even of the cheapesttechnologies had been slow. There were also technical issues, and the DTI cited arange of issues surrounding metering, connection to the distribution network andbalancing and settlement arrangements that could be preventing widespread take-up of electricity-generating technologies, and there were regulatory issues such asplanning.

The DTI pointed out that it had already supported the microgeneration sector byreducing the VAT level applicable to most microgeneration technologies to 5 per centand by its grant programmes (see Chapter 17). In 2007 it also reduced stamp duty forthe purchase of zero- or low-carbon housing.

The microgeneration strategy promised a range of additional measures.

• There will be research into consumer behaviour and what drives early-adopterpurchase decisions.

• DTI and Ofgem will produce a clear guidance document covering ROCs, LECsand REGOs, including the benefits of each and how to claim them.

• Energy suppliers will develop a scheme that will reward those microgeneratorsexporting excess electricity.

• DEFRA will consider whether electricity-generating technologies (other thanmicroCHP) could be included within the framework of the Energy EfficiencyCommitment.

• The department will develop an accreditation scheme for all microgenerationtechnologies.

• It will undertake a thorough review of existing activity in this area to assesseffectiveness and identify gaps.

• The department will actively investigate the possibilities for microgeneration onits own estate.

• It will work with CLG and planning officers to identify their informationneeds, assess whether these are being met adequately and, if not, develop acommunications pack.

• The department will lead work with other government departments and localauthorities to publish a report on measures that local authorities can take toimprove energy efficiency and levels of microgeneration installations.

• It will work in partnership with the energy-supply companies, distributednetwork operators and Ofgem to ensure that network and market sys-tems are able to cope with growing numbers of microgenerators exportingelectricity.

• It will continue to work with Ofgem, the distribution network operators, energysuppliers and the microgeneration industry to ensure that existing contractsbetween domestic customers and their electricity suppliers are not hindering thetake-up of microgeneration.

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• It will work with Ofgem, the distribution network operators, energy suppliersand the microgeneration industry to ensure that wiring regulations do not form anunnecessary barrier to take-up of microgeneration.

• It will investigate field trials that bring together smart meters and microgeneration.• The department and elements of the old DfES – the Department for Innova-

tion, Universities and Skills (DIUS) – will work with industry and other keystakeholders to develop a scheme for installing microgeneration technologies inschools.

13.6 Re-examining the remaining barriers

In late 2006 the regulator Ofgem and the then DTI jointly published a new call forevidence on the barriers still remaining for DG. The report said,

Some argue that Government should do more to promote DE primarily because of itspotential to reduce carbon emissions, but also on grounds of reliability and cost…. However,the Government has to ensure that the interests of electricity consumers are properly takeninto account. Cost implications of any changes will be a key consideration, as will preservingthe integrity of electricity networks.

In this document, DG was defined broadly, as:

• all plant connected to the distribution network rather than the transmissionnetwork;

• small-scale plant that supplies electricity to building, industrial site or community,potentially selling surplus electricity back through the local distribution network;

• microgeneration, i.e. small installations of solar photovoltaic panels or wind tur-bines that supply one building or small community, again potentially selling anysurplus;

• large CHP plants (where the electricity output feeds into the higher-voltagedistribution network or the transmission network, but the heat is used locally);

• building- or community-level CHP plants;• microCHP plants that effectively replace domestic boilers, generating both

electricity and heat for the home; and• non-gas heat sources such as biomass (particularly wood), solar thermal water

heaters, geothermal energy or heat pumps – which generate heat from renewablesources for use locally.

It was pointed out that this definition included many plants whose output was notused locally – for example, wind farms sited where wind conditions are favourable,rather than near demand. It also includes plants that are not necessarily low-carbon,such as CHP plants using fossil fuels. For such plants there may be diversity andefficiency benefits, the document says.

It cautions that

growth and investment in distributed electricity generation will not avoid the need forcontinued investment in the transmission system. The transmission system will continue toplay a role longer term. For example, investment will be needed for the foreseeable future


to ensure we have continued interconnection between the distribution networks to providebackup and security of supply. Moreover, many of the renewable projects that will be builtin the coming years will necessarily be sited in remote areas, away from centres of demand.

13.7 Licensing

Most electricity generators previously had to become licensed to operate in the UKelectricity supply industry. That meant they had to be party to the BSC and hadto enter into an agreement with the transmission system operator National GridElectricity Transmissions (NGET) for using the system. There are significant costsassociated with both. Small generators have been accommodated in this system bybecoming unlicensed generators. Some large distribution-connected sites have tomeet transmission standards, which is an unwarranted cost.

Unlicensed distributed generators also potentially have access to what are knownas embedded benefits. These reflect the fact that distributed generators have a shorterdelivery path to consumers. Under current arrangements, an unlicensed generator iseffectively treated as negative demand on the system and the electricity it generates isnot subject to NGET’s charges. By purchasing this output from a distributed generator,an energy supplier reduces the overall charges it faces from NGET. Energy supplierscan choose to pass back some of these savings to distributed generators or pass themon to consumers in the form of lower prices.

The then DTI noted in 2007 – in a programme taken on by BERR – claims thatthese embedded benefits are not sufficient to recognize the value of DG. Some arguethat exports should be valued close to the retail price and that suppliers should havean obligation to purchase. Others argue that the export value should be linked to thewholesale price of electricity.

13.8 Distribution and private wires

Redeveloping distribution networks so they can accommodate widespread localenergy projects is still ‘a real dilemma’, said the DTI. Expanding the network in areaswhere DG is expected could promote new projects; alternatively, it could become a‘stranded asset’ with no function that still has to be paid for by customers.

One option is to use so-called private wires – a local energy network with a singleunlicensed operator, supplied by unlicensed suppliers and with up to 2.5 MW ofdemand. The DTI asked whether this should continue unchanged, whether private-wire networks should have measures to encourage them, or whether a new regime isnecessary.

The DTI noted that the unlicensed operator is able to avoid a number of coststhat would usually apply to a licensed energy supplier, including the RenewablesObligation, the Climate Change Levy and the Energy Efficiency Commitment, as wellas some costs associated with the use of the transmission and distribution systems.Some of these savings can be used to help the financial viability of the often lower-carbon DG that connects into these private-wire networks and partly passed on to

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customers. But the DTI noted that ‘customers supplied by licensed energy suppliersare in effect subsidising the electricity costs of those linked into the private wirenetwork’.

The DTI added, ‘Some argue that by exploiting these exemptions and associatedfinancial benefits private wire networks could provide an important boost to thedevelopment of a larger base of distributed generation in the UK.’

But the department pointed out that there are countervailing arguments. Private-wire networks operate independently, but rely on the transmission grid for backuppower, and therefore they should pay charges that reflect this dependence. Patchworksof private networks may make it increasingly difficult to coordinate power flowsefficiently. In the longer term, there may be concerns about ensuring private networksare adequately maintained and about safety issues.

Also, the DTI pointed out that the licensing regime’s purpose is to protect theinterests of the consumer. Private-wire customers experiencing unreliable supply ora poor quality of service would have no route of redress and might not be able toswitch to another energy supplier.

Panel 13.1 How planning works

The planning system is central to the delivery of the government’s climatechange policy targets, including renewable energy projects. At the same time,it is there to ensure that development serves the public interest.

The system is in a state of flux. Scotland and Wales have, to all intents andpurposes, devolved planning systems.

The British planning system is ‘plan-led’. A development plan is preparedand, once adopted, its policies determine all planning applications. In two-tierlocal-authority areas a structure plan is prepared by the county council and alocal plan by the district, borough or city councils. The development plan con-stitutes the two documents taken together.

Development plans have to be prepared in accordance with the regional plan-ning guidance Regional Spatial Strategies (RSSs) within their region. RSSs areprepared by regional assemblies but, importantly, can be adopted only by thegovernment. Hence the government is ultimately responsible for setting theregional planning framework, which, in turn, guides the contents of develop-ment plans. Councils will be expected to cooperate in preparing subregionalspatial strategies, covering areas with common interest and straddling existinglocal-authority boundaries. Local plans will be replaced with local developmentdocuments.

Planning applications themselves are determined mainly by local planningauthorities (LPAs), usually the local council for the area concerned. Decisionsare made by elected council members of the council planning committee, takingadvice from planning officers, although some officers have delegated powers.


The system is administered by planning officers within the LPAs. In an attemptto speed up and make the development plan’s preparation process more certain,inspectors’ recommendations following local-plan inquiries will be binding onlocal planning authorities.

Applications for power plants over 50 MW are dealt with directly by thesecretary of state and are known as Section 36 applications.

Central government in each of the administrations of the UK (England, Scot-land, Wales and Northern Ireland) has retained for itself the ultimate power todetermine planning applications. Applications may be ‘called in’ for deter-mination by the relevant administration. Appeals against refusal of planningpermission are heard, and often decided by, inspectors or recorders appointedby the central administration.

The application

The construction of a new building or structure nearly always needs an appli-cation for planning permission. The development plan in force in an area willindicate whether a proposal is likely to be acceptable, so it is always worth talk-ing to a planning officer at the council before submitting an application. Tryto arrange a face-to-face meeting for this discussion. If there are difficulties,officers may be able to suggest ways to make your proposal more acceptable.

Planning applications are decided in line with the development plan unlessthere are very good reasons not to do so. Points that will be considered includethe number, size, layout and appearance of the proposed structures; access tothe development; landscaping and impact on the neighbourhood.

It is not necessary to make the application yourself. A planning consultantwill be aware of local land issues and can make the application for you.

The planning officer will tell you how many copies of the form you will needto send back and how much the application fee will be. Some councils are nowoperating an online applications service.

Decide what type of application you need to make. In most cases this willbe a full application but there are a few circumstances when you may wantto make an outline application – for example, you may wish to see what thecouncil thinks of the building work you intend to carry out before you go to thetrouble of making detailed drawings (but you will still need to submit detailsat a later stage). Outline applications may require a different form.

Consultations

Before making an application for a renewable-energy project, it is advisable toconsult any neighbours who might be affected by your proposal, and the localparish, town or community council. Provide information about predicted noiselevels, and images of what the development will look like. Be as open and

Continues

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informative as possible. The results of this consultation will be used in theplanning process.

You should also consult other bodies who might have an interest, such as theEnvironment Agency or the local water and sewerage company, to discuss anypotential sewerage, water or flooding problems, and/or the highway authority(usually the county council in non-metropolitan areas or the local council inmetropolitan areas) to discuss road safety and traffic issues (some wind-farmdevelopments have failed to get planning permission because they have beenconsidered a distraction to passing motorists).

How long does it take?

The council should decide your application within eight weeks. Large or com-plex applications may take longer. Your council should be able to give you anidea about the likely timetable. If it cannot decide your application within eightweeks, it should obtain your written consent to extend the period.

What does it cost?

The amount varies according to the type of development proposed. The revenuefrom fees contributes to the cost to the council of handling applications and thefee is not refundable unless the application is invalid.

Where the local planning authority fails to determine your application, orwhere you withdraw it before it has been determined, the fee will not be refund-able. However, if the local authority fails to determine your application, youcan appeal.

When a previous application has been granted, refused or withdrawn, onefurther application by the same applicant for the same type of development onthe same site can generally be made free of charge within 12 months.

Environmental-impact assessment

The local authority will let you know if an environmental-impact assessment(EIA) is needed for your proposal. It is usually required for renewable-energyprojects. The EIA is a study using scientific and other information about an areato be developed. It enables decisions to be taken with full knowledge of theenvironmental consequences that would result, in both rural and urban areas.

The planning process

Planning staff at the council should acknowledge your application within a fewdays. They will place it on the planning register at the council offices so that it


can be inspected by any interested member of the public. They will also eithernotify your neighbours or put up a notice on or near the site. In certain cases,applications are also advertised in a local newspaper. This gives the publicthe opportunity to express views. The parish, town or community council willusually be notified; other bodies such as the county council, the EnvironmentAgency and the ODPM may also need to be consulted.

Anyone can comment on your proposals. Your local council will assess therelevance of comments and, in the light of them, may suggest changes to theapplication to overcome any difficulties.

The planning department may prepare a report for the planning committee,which is made up of elected councillors. Or the council may give a senior offi-cer in the planning department the responsibility for deciding your applicationon its behalf.

You are entitled to see and have a copy of any report submitted to a localgovernment committee, along with any background papers used in its prepara-tion, which will generally include the comments of consultees, objectors andsupporters that are relevant to the determination of your application. Such mate-rial should normally be made available at least three working days before thecommittee meeting.

The council grants/refuses planning permission by sending you a letter noti-fying you of its decision.

Refusals and delays

If the council refuses permission or imposes conditions, it must give writtenreasons. If you are unhappy or unclear about the reasons for refusal or theconditions imposed, talk to the planning department.

As we saw above, if your application has been refused, you may be able tosubmit a modified application free of charge within 12 months. Alternatively,if you think the council’s decision is unreasonable, it is possible to considerappealing. The appeal route is also available if the council does not issue adecision within eight weeks.

Chapter 14

Embedded benefits

Generators and electricity suppliers (retailers) directly connected to the electricitytransmission grid pay a series of charges for using the network that can be avoidedby using local generation.

14.1 Costs

Transmission network use-of-system (TNUoS) charges are paid by generators andsuppliers directly connected to the electricity transmission grid. TNUoS charges relateto the costs of managing and maintaining the transmission network. The chargesvary for both generators and suppliers according to their geographic location and thedemand for grid usage at that location.

So, generator TNUoS charges vary by location and are based on the generator’scapacity. Supplier charges vary by location and are levied on the supplier’s peakdemand, measured at the three half-hours of highest system demand (known as thetriad).

There is also a charge for transmission losses. Up to 2 per cent of the electri-cal energy generated in England and Wales is lost in the transmission system. Thishappens because a proportion of the current flowing in transmission lines, cables andtransformer windings is dissipated through heating effects. These losses increase withthe distance the electricity has to travel. These costs are divided between generatorsand suppliers on a 45/55 split.

Generators and suppliers connected to the transmission network also have to signthe Balancing and Settlement Code (BSC), and this is costly, since it requires themto meet certain standards, which include financial reserves, and pay a proportionof the general costs of administering and managing the BSC, as well as their ownparticipatory costs. Signatories to BSC also incur other related charges includingBalancing Services Use of System (BSUoS) charges.

BSUoS charges are paid by suppliers and generators based on the energy takenfrom or supplied to the transmission network in each half-hour period. These chargesare paid to cover the costs of keeping the system in electrical balance and maintainingthe quality and security of supply.

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14.2 Embedded benefits

Smaller generators that are embedded in the distribution network are neither connectedto the transmission grid, nor signatories to the BSC, so they are not subject to thesecharges. The benefit they gain from this is known as embedded benefits.

When transmission-connected suppliers use power from distributed generators,the use of locally generated electricity reduces the extent to which the supplier hasto use the transmission system and the energy-balancing services offered by the grid.The result is a reduction both in TNUoS and BSUoS charges. Suppliers can pass onthese savings to distributed generators (subject to bilateral negotiation).

In addition, where a generator is embedded within the distribution system, boththe generator and the associated demand it supplies benefit from avoiding scaling fortransmission losses.

As with transmission network losses, there are also losses as power is transportedin the distribution network. In fact they are higher, as might be expected since thetransmission network is designed for bulk power transport. Around 7 per cent ofelectricity is lost in the distribution network. The extent to which embedded generatorshelp avoid distribution losses will vary according to their location. In some casesthere are savings but it is also possible that an embedded generator could increasedistribution losses, especially if there is already substantial embedded generation inthe area.

Embedded generation can be used to reduce a supplier’s triad demand (and thusits TNUoS charges), simply by reducing demand on the day in which triad costs aredetermined.

Triad benefit has been potentially the most substantial of the embedded bene-fits. Generators have normally expected to receive 70 per cent to 90 per cent ofthe total value. But the triad charge will be levied on the supplier’s demand onlynet of the embedded generation. Thus the benefit accrues to the supplier, and anembedded generator will have to claw it back through its energy contract with thesupplier.

There are other perceived benefits less easy to quantify. One would be an increasein the availability and security of supply due to the increased diversity of genera-tion sources. Another might be avoiding the cost of reinforcing the network, whereincreased demand would normally require increased flow down a part of the networkthat would therefore need the cables reinforcing. New generation near the demandcould mean bigger cables were not required. The electricity is also delivered eitherat or closer to the correct voltage for distribution. (Electrical output from central-ized generators has to be transformed up to a high voltage, transmitted, and thentransformed back down to the lower voltage).

However, DNOs argued that embedded benefits are small, if they exist at all,which is why payments for embedded benefits, where they have been offered, havealso been small. They point out that wrongly placed generation can actually increasetheir costs, as it may alter or even reverse the flows down their wires, sometimesrequiring replacement of equipment.

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Even where generation is placed in a location convenient to the DNO’s networkrequirements, they point out that they are obliged to provide 99.99 per cent availabilityof supply, whereas individual embedded generators are unlikely to exceed 95 per cent.DNOs may therefore feel obliged to reinforce the network regardless of embeddedgeneration.

Embedded generation brings most benefit where the transmission and distributiongrid is weak. This occurs in areas that are remote from centralized generation plants.

For many small local generators it is difficult to get a financial benefit from thefinancial and strategic benefits of embedded generation. Where it has been possibleto negotiate an increase in the price for electricity exported, on the strength of theembedded benefits, it may not mean the price paid is comparable to the retail oreven wholesale energy prices. This is because suppliers buying the exported powerare not obliged to buy it, and can offer low prices, arguing that the risk of over- orundersupply outweighs the embedded benefits. The smaller the likely export, the lessmarket power the generator is likely to have to negotiate a reasonable export price.

14.3 New incentives

As part of its 2005–10 Distribution Price Control Review, Ofgem introduced a newincentive mechanism for connecting DG intended to ‘encourage DNOs to investefficiently and economically in the provision of distributed generation connectionsand to be generally proactive in responding to connection requests’. In addition,Ofgem introduced two new incentive mechanisms: the innovation funding incentive(IFI) and registered power zones (RPZs).

The primary aim of these two incentives is to encourage the DNOs to applytechnical innovation in the way they pursue investment in and operation of theirnetworks.

14.3.1 Innovation funding incentive

The IFI is intended to provide funding for projects focused on the technical devel-opment of distribution networks to deliver value (whether financial, supply quality,environmental or safety) to end consumers. IFI projects can embrace any aspect ofdistribution-system asset management from design through to construction, commis-sioning, operation, maintenance and decommissioning. A DNO is allowed to spend upto 0.5 per cent of its combined distribution-network revenue on eligible IFI projects.DNOs will have to report their IFI activities openly on an annual basis.

14.3.2 Registered power zones

RPZs are intended to encourage DNOs to develop and demonstrate new, more cost-effective ways of connecting and operating generation that will deliver specificbenefits to new distributed generators and broader benefits to consumers generally.

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If a DNO employs genuine innovation in the way that it connects generation,it can seek to register the connection scheme with Ofgem as an RPZ. Ofgem willdecide whether the scheme qualifies as an RPZ. An incentive package of a maximumof £500 000 per year during the price-control period is allowed to each DNO for RPZprojects.

The RPZ incentive mechanism combines pass-through and capacity-related ele-ments. The capacity-related element allows a DNO to recover £1.50/kW/annumfor new generation connections for a 15-year period. This element is increased to£4.50/ kW/year in an RPZ for the first five years.

14.4 Small generators

The government recognized early on that the small generators were likely to findexport costly and difficult. Its solution was to invite companies to become consol-idators, who would allow groups of small generators to sell their electricity together.Aggregating suppliers, not necessarily in the same area, should reduce the variation insupply and offer larger amounts of power, so generators should have more opportunityto negotiate better prices.

Consolidation has been of very limited benefit so far, operated in the originalstand-alone model by only one company, SmartestEnergy, although some other com-panies in effect use a modified form of consolidation. Good Energy, for example,buys power generated from small generators and microgenerators, although its mainbusiness is power supply.

14.5 Consolidation

Generators have to sell their power. It is possible to sell directly – strike a contractwith an electricity user and sign up to the electricity market. But that incurs costs thatare generally too much for a small company to bear.

Getting access directly to the market is an expensive business. There are the costsof signing up to the BSC, interfacing with Elexon (the nonprofit entity that administersthe BSC), National Grid Co. and the counterparties to your supply contracts. Eventhe cost of employing regulatory specialists who understand the BSC is substantial.

Most small generators do not take on any of these issues. They simply sign acontract with a local electricity supplier, which agrees to take whatever power isgenerated for a fixed price. There is a certain amount of competition: in the same waydomestic consumers can choose their electricity supplier, a small generator can offerpower to different suppliers and compare prices. But there is another option. Powercan be sold to a consolidator – a specialist trading company that buys power from avariety of sources and sells it on.

The basis of consolidation is that you take on the risk of a portfolio of unpredictablegeneration. This would build to a chunk of power that is more predictable and couldbe sold on to the market. The consolidator can use its several sources of power tomanage the risk of not meeting its commitment.

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A consolidator may work by offering a fixed price for power supplied. But thatcan vary: it may be broken down into seasons, quarters, months, weeks or even timeof day. Some generators may decide that they have a very stable, predictable supplyto offer, and that they can take on some of the risk to get a better price.

The length of the contract can vary. It is typically 12 months, but in new projectsgenerators are looking for a contract of at least two to three years. Projects in devel-opment looking for finance in the form of bank loans may need a contract for five orten years.

SmartestEnergy says it will trade for sites with anything from 500 kW to 100 MW,but would seriously consider units as small as 200 kW or groups of five 100 kWgenerators. Once you get below that level the cost of entry is the physical connection,metering and so on. That may cost a few hundred pounds, for a return of just a coupleof hundred pounds. Very small suppliers are better off looking for a nearby customerthat can buy the power directly.

Chapter 15

Connecting and exporting power

How do you export power from your local energy installation to the electricity grid?Until recently, connection was a notoriously complex business, depending not only onyour installation and whether you hope to get some income from the export, but also onregulations that were intended for very different electricity generators and distributionnetwork operators (DNOs) whose procedures and attitudes vary widely. However, anew connection standard designed for the job has simplified matters considerably, ashave new regulations that determine the price paid for the connection and that willforce DNOs to offer export tariffs to new generators.

At bottom is a new attitude that acknowledges that, rather than being a nuisance ora sideshow, local energy projects can strengthen existing energy-supply arrangements,reduce the need to make expensive reinforcements to the grid when new demand inthe form of new housing or business arrives in the area, introduce efficiency andpersuade people to use energy with more care.

15.1 Connection standards

Connection standards are designed to achieve several things:

• the safety of electric appliances and people in the home;• the safety and reliability of the DNO’s network;• the safety of engineers working on the generator and the DNO network.

For DNOs, connecting large numbers of small generators to the network is verynew and it has a number of implications. For example, for engineers, the question ofsafety is paramount: staff working on electrical cabling need to be sure that, once themain supply is off, the cable is not ‘live’ due to power input from a small generator.Another issue is DNO income: they receive financial penalties if there are too many‘faults’ in supply and they argue that more generators on the system mean that faultsare more likely. Here are the steps you should take if you wish to connect yourgeneration system to the network.

15.1.1 Step 1: Decide on your system

Local energy depends on local resources. Are you planning a small hydro-turbine,photovoltaics, a wind turbine or a combination? Is biomass available and would it be

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best used to provide heat or power – or both? Consider the alternatives: if you are farfrom the gas network the cost of using biomass for heating may not be very differentfrom the cost of oil or electrical heating. Assess how much energy will be producedand whether it is required as heat or electricity, and look for other local users withwhom you could combine to have a more favourable profile of needs. Look carefullyat your demand to see whether, in practice, you are likely to have any electricity toexport to the grid.

15.1.2 Step 2: Get a connection agreement

If you are working towards a small project of less than 1 MW your system supplierwill probably be able to deal directly with the DNO on a connection agreement inexchange for a flat fee. Completion may take up to two months under the old G59/2standard but should be much swifter under the new G83/1 standard (see below).

15.1.3 Step 3: Install suitable metering

When you calculated how much electricity you would have to export, you may havefound only a few kilowatt hours. In that case, you may decide you would be payingout more in metering and administration than you can make from electricity sales,and in this case it may suit you to ‘dump’ those kilowatt hours on to the grid. In thiscase, since you won’t be exporting much energy and you do not want to be paid for ityou do not need a meter to record exported power. Your existing meter will continueto record imported units.

However, bear in mind that some meters have antifraud features and may assumethat electricity passing the ‘wrong way’ through the meter is an indication of attemptedmeter fraud. Meters vary in their reactions but in some cases may disconnect, so checkyour meter first, as you may need to get a new one installed.

Once the connection is complete you will continue to be billed for any power youimport and can change your electricity supplier in the normal way.

The next step is to install a meter that records imported and exported electricity.This can be obtained from your electricity supplier or their meter operator.

If you are exporting at a small power level (less than 16 A per phase, or 3.68 kW)you may use a so-called non-half-hourly (NHH) meter. This simply records the totalsfor export and import and will cost £50–100. It will have two meter identification num-bers (MPANs), for export and import registers, even if there is a single physical meter.

The alternative is to keep your existing import meter (and its MPAN number) andfit one new single-direction meter to count the export and get one new MPAN for it.

If you are exporting at a higher level, a half-hourly (HH) meter will be required,with substantial running costs. The renewables industry is currently lobbying to raisethe generator size limit for NHH metering, as the high cost of HH metering is aninsurmountable barrier to many small generators.

15.1.4 Step 4: Install a ROC meter

If you want to qualify for ROCs you will need to install a new meter to record thetotal output from your generator.

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15.1.5 Step 5: Arrange a tariff with your electricity supplier

Research electricity suppliers and choose the one that offers the best deal. Don’t forgetthat you may be offering ROCs and Climate Change Levy (CCL) exemption alongwith power.

15.2 The connection agreement

Written agreement is required from the DNO before the generator can be started upand connected. In the past, generators were connected under a standard known asG59/2. But this was written many years ago to connect large power stations (over5 MW) and it was designed mainly for plant with rotating turbines, not inverters.In practice, this means the standard does not fit well with small and renewablesources.

Previous applicants report that connecting small-scale projects often comes upagainst a similar lack of experience among DNO staff, as in the past the numbers ofsmall generators connecting to the network have been small.

It is up to the applicant to demonstrate that its scheme complies with G59/2 andwith the associated guidance document, known as ETR113, and to convince the DNOthat the operating conditions are safe. Each distribution network operator has its ownapplication form and its own format.

The applicant will have to provide scale drawings of earthing arrangements, anelectrical schematic and a description of operation under normal and network faultconditions. Some DNOs may insist on a site visit to witness tests (costs vary fromzero to several hundred pounds, depending on the DNO).

A new standard – G83/1 – was released in September 2003 and is designed tomake connection easier. It is valid for domestic CHP, photovoltaics and small hydro,but at present it is not valid for wind. This is because the upper size limit is set verylow, at 16 A (approx. 3.7 kW) per phase. This is too low for many small wind turbinesand the industry is protesting.

The Energy Networks Association indicates that DNOs will accept G83/1 as avalid connection standard for schemes that produce more than 16 A, but this is at itsdiscretion and it has not been tried yet.

G83/1’s main features are a simplified application form and appendices givingspecial requirements for the technologies mentioned above. It assumes that the inter-face between the grid and the generator (a grid connect inverter) has undergone ‘typetesting’ and passed.

Once the paperwork is complete, the DNO must be notified that the project isbeing installed – this can be as simple as a letter to the DNO. A third standard,designated G77, that was in place for PV arrays has now been withdrawn, as G83/1replaces it. Any devices that were type-approved under G77 are also approved underG83/1. Since G77 allowed up to a 5 kW connection, that level has been carried overto G83/1 and it allows PV installations up to 5 kW.

More recently, there has been particular focus on connecting domestic generation.This has been led by a surge in interest in such projects, grant programmes and the

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easy availability at least of photovoltaic panels or solar thermal panels and domesticwind turbines in DIY shops such as B&Q.

At one time these had also to be processed with the DNO by completing a con-nection agreement, but now the requirement is simply to inform the DNO that theinstallation has been made, so long as no exports are expected. Getting an agree-ment and tariff for the small amounts of electricity exported by such projects is moreproblematic and often will not be worth the trouble.

In February 2004, for the first time, a standard guide to connecting small gener-ating plants to the distribution network was published. The ‘Technical guide to theconnexion of generation to the distribution network’ does not describe in detail therequirements for individual projects, which are specified with the appropriate DNO.Instead, it provides background information and a ‘route map’ of the connectionprocess.

The new guide is just one result of work done by the then DTI’s DistributedGeneration Group to improve the position for small generators who want to connectto the low-voltage electricity system.

Describing the new guide to a Renewable Power Association (RPA) briefing onDG, Stephen Andrews of the consultants Ilex noted that, in the past, DNOs’ responseto requests for connection had been very different and there had been no consistentapproach. But now any potential generator could be sure the DNO should have a copyof the new guide and could work from the same document.

The document was created by just one of the technical work streams being under-taken under a joint process and a combined ‘Distribution code review panel’ withmembers from generation and distribution, who will work on developing connectionstandards.

15.3 Rethinking the network

The UK regulator has published proposals that should speed the deployment ofembedded generation.

Times are changing for the DNOs: increasingly, electricity is being generated bylocal schemes that supply power direct to the local network. Overall, the change isgenerally agreed to be a useful one: an extensive series of local power-generationprojects helps strengthen the network, and areas with their own generation are largelyprotected against the consequences of a failure in the grid. What is more, they increasethe overall efficiency of the network, as up to 3 per cent of the power generated atlarge remote stations can be lost during the long-distance transmission process.

But, while generation projects ‘embedded’ in their networks should ultimatelybe beneficial to DNOs, developing the networks to accept such projects is far fromstraightforward. The DNOs have a statutory duty to offer connection to new projects,but in most cases they also set the price of connection. For developers working onembedded generation projects, such as small onshore wind farms, some DNOs havein recent years gained a reputation for reluctance and obstruction in connecting theirprojects.


Because DNOs are local monopolies, their terms of business and financial rewardare laid down by the industry regulator Ofgem. In a five-yearly distribution pricereview, after consultation with the DNOs and others, Ofgem sets out the investmentto be made in the system and the costs that can be passed through to customers in theform of price rises. It also sets out a range of penalties for poor performance.

The DNOs argue that their difficulties with connecting DG arise because theirfinancial constraints are also not designed for the purpose. It may be that a localproject will benefit their network overall, but, because they cannot recover the cost ofgrid reinforcement from consumers, it has to be charged to the project. What is more,the DNOs say that the price involves more than just the cost of connecting a cable:there are practical implications to accepting generation on to the local network, frompotential faults elsewhere as electricity flow patterns change, to changed workingpractices for engineers working on the system.

As a result, DNOs previously imposed so-called ‘deep’-connection charges,where the new project bears all the network upgrade costs, rather than ‘shallow’-connection charges, which cover just the connection. The resulting capital costs havehalted many embedded generation projects. Part of the problem was that it was hardto predict how much reinforcement might be required to complete the connection.The most obvious aspects, such as the distance of the new project from the nearestconnection point, may mask other reinforcement required not only in cabling andsubstations on the immediate circuit but also at distances up to several miles. Also atstake were the other loads and generators already on the system or due to join, andwhether the new installation would be the point at which the circuit would have to bestepped up to a new supply-and-demand level.

Projects were expected not only to take on reinforcement costs but also to putaside financing at an early stage in the proceedings. And, thanks to the slow processof accepting new projects on to the grid, projects in the queue for connection couldeasily fail to proceed, changing the requirements for reinforcement elsewhere.

Ofgem and the DNOs began work on the charging structure for the operatingperiod 2005–10 with this in mind. The fourth distribution-price review (known asDPR4), which set financial terms for the DNOs from April 2005, contained pro-posals specifically designed to make connection of embedded generation simplerand cheaper, along with proposals intended to help begin developing more activenetworks.

Ofgem said in its proposals for DPR4 that there is ‘a general recognition thatinvestment to replace network assets and to improve network performance needs toincrease …[and] this will require investment in the distribution networks and changesto the regulatory regime’.

15.4 Shallowish connection

To respond to embedded generators, Ofgem proposed revised connection-chargingarrangements for connecting to the distribution network and incentives on DNOs torespond ‘proactively’ to requests from generators to connect to their network.

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‘Deep’-connection charging would be replaced by a ‘shallowish’ system. Here,the new project would still be required to pay the costs of upgrading the system butthe payment would be split: part would be paid as a capital sum before construction,but part would be paid as a toll on each unit of electricity exported. This appears asan addition to the distribution use-of-system charge paid by all users of the networkper unit of electricity transported.

The benefit to the project is that these payments are not made until the powerplant is operating. In addition, the new scheme would help reduce the costs of being a‘pioneer’ project. Previously, once one project had borne the cost of deep connection,later projects had a ‘free ride’, taking advantage of upgrades made to accommodatethe first project. New arrangements will allow some of the reinforcement charges tobe recouped from later projects that benefit from the strengthened network.

Embedded generators have long argued that, far from being a burden to DNOs,they offer benefits in operating the network. Their power input can help keep thesupply in order where the network is weak, maintaining frequency and voltage, forexample. In the bulk power system these benefits are quantified and rewarded. Ofgemsaid that, as the level of DG penetration increases and the management of the distri-bution networks becomes more active, there may be opportunities for the DNOs toutilize ancillary services from generation (as well as demand) to help operation of thenetwork. But it said that, to the extent to which these opportunities will arise over thenext period of DPR4 (i.e. until 2010), the effect is unlikely to be significant.

15.5 New charging regimes

The DNOs operated a temporary ‘shallowish’ charging regime from the DPR4 startdate in April 2005 but it was not intended to be permanent. Instead, DNOs wererequired to develop ‘enduring’ charging schemes that would be able to develop in apredictable and fair way as the distribution networks develop, as expected, into fullyactive networks.

Western Power Distribution, which owns and manages the networks in south-westEngland, was the first to develop a new charging methodology. Its methodology forhigher voltage networks on its system was implemented on 1 April 2007.

United Utilities, which operates networks in north-west England – Central Net-works, Scottish Power and Scottish and Southern Energy – expected to introduce newcharging methodologies in April 2008, while CE, which has networks in Yorkshireand the north-east, was aiming for April 2009. EDF Energy, with networks in Londonand eastern England, expected to make the change at some of its networks in April2008 and some in April 2009.

The networks were not expected to use the same methodology – Ofgem recognizedthat conditions in each area vary considerably and in any case the regulator’s aim isgenerally not to impose schemes on the DNOs but to enable them to be developed bythe operator. A Distribution Charging Methodologies Forum was set up in May 2007to enable the distribution companies to work together to deal with new problems asthey arise and as their networks change.


Among the early issues identified by Ofgem as likely to require discussion by thenew forum were the following:

• HV/LV generator charging. The new methodologies being developed havefocused on high-voltage levels in the distribution networks. Ofgem said the exist-ing charging models for HV and LV generators are simplistic and the new modelsdeveloped for EHV cannot readily be extended to cover the full HV or LV networkon the same basis. There is therefore a need to extend some of the concepts nowbeing developed to provide more cost- (and benefit-) reflective charging.

• Charging products and structures. The distribution companies recognized thatthere is scope to align definitions of the charging product (e.g. capacity) and theirapproaches to charging for reactive power. Ofgem said there was scope for betterreflection of costs of usage at different times and potentially for longer-term ormore flexible products. In the medium term, it might be valuable to developtariffs reflective of costs at voltage levels rather than by predetermined customerprofile/class.

• Methodology statements. A common format for each of the connections and use-of-system methodologies could be used by all electricity distributors. Work onthe connection methodology will be taken forward in consultation with Ofgem’sElectricity Connections Steering Group (ECSG).

• Existing generators: On 31 March 2005, when DNOs switched to interim charg-ing arrangements on a ‘shallowish’ basis for the first time, there was 12.9 GWof generation capacity connected to distribution networks. These generators con-nected under a ‘deep’-connection-charge regime and were not currently payinguse-of-system charges. But Ofgem said those generators’ decisions may have aneffect in future on network costs, including charges to prospective generators.Ofgem said it had explored various options for introducing charges for thesegenerators, with or without compensation, but had not taken the work forward.Existing generators expected, however, that Ofgem would return to the issue.

It is DNOs who are now responsible for proposing how to resolve all these issues.

15.6 Constraining connection?

One reason why connection costs have been so high is that grid rules say that newgenerators should be able to connect in an ‘unconstrained’ way, which means thatthe full theoretical output from the plant can be exported at any time. This has alsoresulted in extensive connection queues in areas where there is little or no capacityon the existing network.

But it has been argued strongly that ‘unconstrained’ connection is unnecessary,especially in the case of small or local projects. An alternative would see new projectsconnected on a ‘constrained’ basis. The DNO would be able to take the entire outputwhen it was possible, i.e. when there was capacity on the wires. On occasions whenthe capacity of the wires was fully utilized the generator would be unable to exportpower and would be paid an agreed fee by the DNO.

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It has been argued that experience from other countries – the system is used, forexample, in Norway – has shown that with some forms of generation the constraintis much less than might be expected. Wind is a useful example. A wind farm ratedat 1 000 kW would, under the UK system, have to pay for grid reinforcement thatwould enable it to export 1 000 kW at any time. But wind farms of course operateonly when there is wind, which may be anything from 60 to 90 per cent of the time.When the wind is not at the optimum speed the wind turbine generates a proportionof its rated power. Over an average year a turbine generates around 30 per cent of itstheoretical maximum over the year, and since it does this only when the wind blowsit is clear that it is hardly ever producing the maximum-rated capacity. Obviously, theoutcome depends on local circumstances, but experience from Norway has been thatthe constrained connection has been very beneficial. It has brought new capacity online much more quickly and has led to very few constraint payments.

This can be still more beneficial if it is operated in conjunction with a nearbydemand, where power can be used if it is not exported. So far, however, constrainedconnections have not found favour in the UK.

Chapter 16

Finance and local generation

Using the waste heat from the electricity-generation process, plants like this one atLudlow can convert fuel to power and heat at very high efficiencies.

The capital cost of local power and heat projects is often rather higher than providingpower or heat conventionally. There are a number of reasons for this: the equipment isrelatively new or supplied in small volumes, so it is more expensive; the technologymay be new to its location, so alterations are required in existing buildings to allow forit; it may simply have had a different cost structure from more conventional choices,with high capital costs eventually balanced by low operating or fuel costs.

The government response has been to try to pump-prime the market with subsidiesand grants that will eventually increase the market size to a point when unit costs beginto fall. That effort has been made more difficult because the options for distributed

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energy are so varied and apply at such different scales. Developing a volume marketfor the domestic scale is probably more achievable than it is at mid-scale, whereenergy will always have to be tailored both to the resources available and to theparticular needs of the customer.

One problem at mid-scale is that companies often require payback on new capitalinvestments within a few years. A switch to so-called ‘life-cycle’ costing, wherebythe purchasing and installation costs are assessed in conjunction with fuel and main-tenance – and often removal at the end of the plant’s lifetime – is more likely to favourdistributed energy.

16.1 Renewables Obligation

The government’s biggest support scheme for renewable energy is known as theRenewables Obligation (RO). The scheme was put in place in 2001. It places anobligation on all retailers of electricity to source a proportion of their electricity fromrenewable sources. The Obligation will remain in place until 2027 and the renewableproportion grows each year, from around 3 per cent in the first year to reach 20 per centof supply.

To prove that the retailer has complied with the obligation, a system of electronicROCs is employed. At the end of each financial year the amount of each retailer’sobligation is determined by Ofgem, which administers the RO. The retailers canthen discharge their obligation, either by presenting ROCs to prove that they haveused the required proportion of renewable power, or by paying a ‘buyout’ (fine) foreach megawatt hour where non-renewable (often called ‘brown’) power was suppliedinstead. The cash in the buyout fund is repaid, pro rata, to the retailers who presentedROCs.

The upshot is that each ROC has a value equal to at least the buyout fine, andpotentially considerably more if there is a shortfall in renewables generation, andmany retailers are forced to pay some buyout fees to fulfil their obligation. This hasbeen the case every year, and in fact is designed to be so: the Obligation level isincreased each year to ensure that there is a shortfall in the generation achieved, sothat renewables project developers can rely on receiving buying cash.

These three components provide the elevated power price required to make arenewables project financially viable. A renewables power project must first be certi-fied by providing information about the plant to Ofgem. Once it is accepted, the plantis awarded one ROC for each megawatt hour of power it produces. The generator cansell the power, the ROC and the likely benefit from the buyout fund.

The Renewables Obligation differs from many support schemes used in othercountries because it does not specify which renewables technologies should beemployed, nor exactly how much subsidy generators will receive. Many Europeancountries have favoured fixed tariffs (often known as feed-in tariffs), with a differenttariff set for each form of renewable energy and paid for each megawatt hour gen-erated for a specified number of years. But the UK favoured ‘market’ instruments,whereby the government’s role was not to distinguish between technologies but toallow the market to bring forward the most competitive.

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This was partly because of a general government preference for market instru-ments, and partly because the avowed intention of the Obligation was to bringrenewable energy on to the grid as quickly as possible, at the lowest possible price. Inthis it has been successful as well-developed technologies, particularly wind power,ramped up installation rates. The British Wind Energy Association, for example,notes that it took 14 years for the UK to install 1 000 MW of wind power, but just 20months to install the next 1 000 MW.

However, the structure of the subsidy means that it is far less useful in bringingnewer technologies forward, something developers of wave- and tidal-power projectshave highlighted. It also has very limited usefulness for small and distributed powergenerators, especially those whose business is not power generation but who havean interest in a local power project for other reasons – to provide on-site power,for example, as a community project, or who have a very small source such asPV panels.

What is the problem? First of all ROCs are cumbersome and costly to administer.Registering as a renewable power source is just the start: although Ofgem has sim-plified the forms required for this process for microgenerators, below 50 kW, theyare still 20 or more pages long and necessarily address technical issues that could bedifficult for this group – who are generally installing domestic systems – to get togrips with. Systems over 50 kW in size require still more information.

Once they are registered, it is necessary for generators to prove how much powerthey have generated and to make returns to Ofgem on a regular basis. For micro ordomestic users this will probably require new, more sophisticated, meters and the costcould outweigh any benefit from ROCs. It has been proposed that, instead, generatorsat the domestic level should have a ‘deemed’ figure for the average likely generationof their installation and receive ROC benefits on that basis, but so far this has notbeen implemented.

Companies are more likely to have half-hourly meters already in place, but willhave an additional administrative burden that could mean significant costs.

For this reason, many small generators will rely on an agreement with their elec-tricity retailer to manage their electricity production. This has its own disadvantage,which is mainly that the price offered is likely to be very low and if the installation isvery small no price may be on offer.

Companies argue that the contingent nature of the Renewables Obligation is thereason why they offer small generators low prices for the power they have available toexport. The base electricity price can vary considerably, as anyone with an electricitybill knows, and the value of the renewables certificate can also vary because, althoughthe buyout price is fixed in advance, the amount of buyout fund likely to be recycledis not known, so nor is the full value of the ROC. Some party has to bear the risk ofthis unknown price, so power retailers who offer fixed prices to distributed generatorswill pitch it very low. In practice, retailers have not been obliged to offer export dealsto small generators and often declined them, but, at the time of writing, this seemedlikely to change, with a new requirement on the horizon that would force retailersalso to offer export tariffs.

The cost and complexity of the export process have meant that small generatorswho may have had power available have sometimes decided not to export, as the costs

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are far greater than the benefits. And, although the RO always included an optionof selling ROCs to a consolidator, intended to provide a simpler route to market forsmall generators, this has never been successful.

An interesting variant of the RO that has been used in Australia for several yearscalculates an average lifetime generation for a small renewable energy source suchas domestic PV and calculates the number of ROCs that would be generated over thelife of the scheme. For domestic PV, in the Australian version, the lifetime ROCs areawarded to the PV supplier at the outset, who translates them by an agreed formulainto a discount on the purchase price. A similar system has been proposed in the UK.

Finally, a major problem with the RO for many local energy projects is that it isentirely focused on electricity production. No benefit or subsidy is available for heatproduction using this route. This clearly means that heat-only sources are excludedbut it also dramatically reduces the amount of subsidy available for mixed sources,which often offer greatly improved efficiency, such as combined heat and power.

CHP has huge potential in all kinds of projects, industrial, commercial and large-scale domestic, where both heat and power are required. CHP projects using fossilfuel would not be eligible for ROCs in any case, but some could use local biomassfor fuel and in theory many would be eligible as renewable-energy generators.

But in most projects heat is the most important product – for process heat inindustry, heating in commercial premises, etc. – whereas electricity is a by-product.The amount of electricity produced, even in a large product, may be relatively smalland production can vary dramatically depending on the heat needs of the site. Thatputs even large biomass CHP owners in a similar position to small generators: theyhave a few megawatt hours of power to generate, often unpredictably, so the pricethey can get for the power, even with ROCs, is low – and often not enough to justifyinvesting in an efficient CHP plant instead of a simple boiler that provides only heat.

An Act of Parliament on climate change passed in 2006 required the UK govern-ment to investigate the possibility of a renewable-heat obligation to run in parallelwith the RO. There was a precedent for this: the government had already decidedto introduce a renewable-transport-fuels obligation that would require transport-fuelsuppliers to mix a proportion of biomass-derived fuel with petrol and diesel.

The government had previously resisted the idea of a renewable-heat obligation,saying that, unlike for electricity and transport fuel, where there was a defined groupof retailers, it would be extremely difficult to identify a group of heat suppliers to becharged with the obligation.

16.2 Electricity trading arrangements

The system by which electricity is bought and sold by power-generation companiesand retailers also does not favour renewable energy. The current system was putin place across England and Wales in 2001, under the name New Electricity Trad-ing Arrangements (NETA), and it was renamed the British Electricity Transmissionand Trading Arrangements (BETTA) when it was extended to cover Scotland inApril 2005.


Before BETTA, electricity generators made offers of electricity supply at a certainprice for each half-hour of the day. The offers were known as the pool. As the half-hour arrived, the system operator would call on the cheapest offers first until demandwas met, and all those called on to generate would receive the price bid by the highestbid used. Generators have different amounts of flexibility over how they operate anddifferent constraints such as fuel price, so for some it was beneficial to bid a high priceand generate only when the price was high enough to cover fuel costs. For others,such as wind farms, it was more effective to bid a zero price and become a ‘pricetaker’: they would be called on whenever they had power to supply – i.e. when thewind was blowing – and, because the cost to run was minimal and there were no fuelcosts, they could accept even low prices.

However, it was thought that the pool allowed some electricity companies tomanipulate the market and produced electricity prices that were too high. Also, therewas no penalty if they were unable to supply for a period in which they had made abid, which was inefficient.

Under NETA and then BETTA, electricity generators and retailers made bilateralcontracts for whatever period suited them. The power was still dispatched by the sys-tem operator in half-hourly slots as it had been before, but the underlying assumptionwas that the sum of the contracts should mean the electricity supply and demand werein balance. In practice, there would always be minor balancing actions required (seeChapter 14), but this is managed by the system operator, who called on previouslyagreed demand and supply ‘top-ups’ or reductions, with appropriate payments. Thecost of balancing is charged back to generators or retailers who were ‘out of balance’.

The new arrangements were intended to ‘discover’ lower prices if they wereavailable and to penalize unpredictable generation. It was hugely successful at both.Prices dropped by more than 10 per cent and operators of unpredictable power suchas wind generators and CHP operators selling their excess power found that theywere paying balancing charges that in some cases outweighed the entire income fromtheir site.

Since the system went live the situation has eased somewhat. Companies havebecome more used to matching their supply and demand and the system as a wholehas seen much less balancing required. Forecasting of wind output has become muchmore exact, especially as ‘gate closure’ – the point at which final contracts have tobe made for each half-hourly dispatch slot – has moved to just one hour in advanceof dispatch. In most cases, forecasting is very reliable at this scale.

In practice now, what BETTA adds to the situation for distributed generators isanother layer of risk. That means that, in selling wholesale to a power company, theprice is likely to be discounted again because the power company is taking on themarket risk.

16.3 Climate Change Levy

A further subsidy available to most renewable-energy generators is via the ClimateChange Levy (CCL).

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The CCL has been in operation since 2001. It is a tax on the use of energy paid byindustry, commerce and the public sector, and its underlying aim is to reduce carbondioxide emissions. It was set up in response to the UK’s commitment, under theKyoto Protocol, to reduce carbon dioxide emissions by 12.5 per cent compared with1990 levels. The levy is intended to encourage efficient energy use and to provide anincentive for industry to move towards energy supply that has lower carbon dioxideemissions. That means that using gas or electricity attracts a lower rate of levy thanusing coal. No levy is paid if renewable energy is used.

In practice, because renewable energy is exempt from the CCL, generators canreceive a fixed CCL payment for each megawatt hour they generate. An importantdistinction between the CCL and RO, however, is that good-quality CHP, however itis fuelled, qualifies for the CCL.

Administration is relatively simple, especially for those generators who arealready qualifying as renewable-energy sources. The CCL is also administered byOfgem, which has worked hard to try to combine the paperwork for the two schemes.

16.4 Grants

As we have seen above, the support schemes by which the UK has attempted topromote the large-scale use of renewable energy, and persuade industry to switch tomore efficient and possibly site-based forms of generation, have been most successfulin persuading the existing power-generation industry to invest in renewables. Theyhave done little to help companies, groups or individuals who propose setting up localenergy schemes.

The nature of distributed energy supply does present problems for policymakers.Local energy is best served when local energy sources are used, and the energy is usedlocally. That means that a huge variety of energy sources have to be encompassedwithin a support scheme that may have very different investment and return profilesand be at very different stages of development. What is more, the support scheme mustbe usable by a wide range of potential suppliers and the benefits must be translatableto all the members of a group involved in a scheme.

The government has taken the view that eventually local energy will be a ‘volume’industry, where standard technologies can be simply connected – a far more extensiveversion of the current heating market, where a range of boilers is available off theshelf in domestic or industrial versions that can be fitted, at the domestic scale, bylocal tradespeople. That approach will always be complicated by the need to assessand make use of natural sources such as wind, but, alongside a volume industryfor equipment, a similar volume industry for services such as wind assessment anddesigning mixed systems should develop.

With sources as diverse as small hydro and microCHP to support, at scalesfrom domestic to major industry, the government has fallen back on grant pro-grammes intended to allow suppliers to build a volume business, on the assumptionthat the result should be price reductions, since ‘off-the-shelf’ technologies aremass-produced.


The diversity of the potential market has been a problem for the industry andgovernment because it means that responsibility extends across more than onegovernment department.

Support for heating schemes, for example, has come from the Department for theEnvironment, Food and Rural Affairs (DEFRA), which has also had responsibilityfor trying to support the growth of the biomass supply industry. Electricity supplysupport schemes have to come from the Department of Trade and Industry (DTI) –now the Department for Business, Enterprise and Regulatory Reform (BERR) – whileCommunities and Local Government (CLG) has some responsibility for buildings,and so, although it may not be involved in grant programmes, such programmes dohave to be designed with reference to CLG.

As a result, grant schemes have been slow to materialize, and are sometimesunwieldy and in danger of allowing important potential projects to fall betweenschemes. Similar problems have been encountered in dealing with organizationaland legal issues (see Chapter 13).

16.5 DEFRA support

DEFRA’s main area of support is the biomass industry. It has offered planting grantsfor biomass crops such as willow and miscanthus, and a further grant programme forproducer groups that aims to help farmers make the switch to these crops by helpingthem form cooperatives and companies that can jointly market their crop.

The largest grant scheme by far, however, has been the community-energy heatingscheme known as the Community Energy Programme. This provided grants for CHPprojects and ‘innovative’ heating, which often meant using biomass fuel instead ofgas or oil for heating purposes.

This was announced with a £50 million funding commitment in 2001, and DEFRAcommitted a further £10 million to the Community Energy Programme in 2004, butdecided that it would end in 2007. DEFRA said the decision to extend the programmewas based on initial strong demand and a number of larger schemes with significantoutputs. However, experience has shown that many larger schemes under the initialprogramme could not complete within the 31 March 2007 spend deadline and did notgo ahead. The smaller schemes that can complete tend to be expensive in relation totheir outputs. The high dropout rate for larger schemes is the main reason for the lim-ited estimate of spend. DEFRA added, ‘The situation would not improve appreciablyif we extended the spend deadline, as these larger schemes cannot complete within atimescale suitable for government funding, in some cases after 2010.’

The programme was said to have spent just £22.4 million of the funds available,and although it had brought around 28 MWe of CHP capacity online this was just 22per cent of the programme’s original target.

There was no direct replacement, although the Low Carbon Buildings Programme,administered by the Energy Saving Trust (EST), encompassed some similar projects.

Elsewhere, DEFRA is also responsible for the Energy Efficiency Commitment(EEC), which may eventually provide support for domestic generation. The EEC is

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a duty placed on electricity retailers to reduce carbon dioxide emissions by helpingtheir customers use energy more efficiently. There are a range of measures withinthe commitment, including loft and cavity wall insulation, more energy-efficientappliances such as fridges and boilers, low-energy lighting, etc. Retailers can choosehow they meet their commitment, by offering cheap low-energy lamps, or givinggrants for insulation, or reducing the price of efficient appliances.

It has been proposed that, in future phases of the EEC, microgeneration wouldbe a suitable addition to the range of measures available. Retailers could providegrants towards the cost, for example, of micro wind turbines or solar water heaters.The proposal is the subject of some debate: there is a question, for example, overhow beneficial it would be to install such technologies on uninsulated houses, wherelarge energy savings are available. There are also questions over the appropriatenessof including energy generation in the programme at all. At the time of writing, thatquestion had still to be resolved.

16.6 DTI grants

The former Department of Trade and Industry’s programme of support to small-scalerenewables began with the solar PV demonstration programme, which eventuallyprovided £31 million in grants to PV installations.

That programme was replaced by a broader-based scheme known as Clear Skies.This long-awaited capital-grant scheme to encourage UK homeowners, schools andcommunities to take the initiative in developing and installing their own renewable-energy schemes was launched by the then energy minister Brian Wilson at thebeginning of 2003 with an initial £10 million funding. The Scottish Executive put up£3.7 million to fund its own parallel scheme, with shared website and criteria.

For the first time the scheme encompassed projects that provided renewable-sourced heat as well as power and it included solar water heating, wind and smallhydro among the projects it supported.

The scheme focused on flagship and community projects, hoping that their highvisibility would act to promote renewables more generally, with a second stream thatprovided one-off grants for householders. At the time, the DTI said suggestions forlocal projects could include:

• a solar street, where water-heating panels are fitted to the roof of every house ina street;

• a small-scale hydropower project in a school;• a wind turbine to provide electricity to a hospital; and• energy crops, such as willow or poplar, to provide heat for a community farm.

Clear Skies was widely seen as a successful scheme, and it spent £12.5 millionbefore it was ended in 2006. It and the Major PV Demonstration programme werereplaced by a single scheme known as the Low Carbon Buildings Programme(LCBP).


Launched in May 2006, this programme had £30 million to spend and fourmain aims:

• to support a more holistic approach to reducing carbon emissions from build-ings by demonstrating combinations of both energy-efficiency measures andmicrogeneration products in a single development;

• to see demonstrated on a wider scale emerging microgeneration technologies(with a focus on building integrated technologies);

• to measure trends in costs of microgeneration technologies (it is expected thatthese costs should reduce over the lifetime of the programme against a 2005baseline); and

• to raise awareness by linking demonstration projects to a wider programme ofactivities including developing skills and communicating the potential of micro-generation to change the attitudes and behaviour of consumers (larger-scaleprojects will seek to engage the construction industry in project replication bydemonstrating the business case for developing low-carbon buildings).

Funding was offered in two streams. Stream 1 for householders, Stream 2 formedium and large microgeneration projects by public, not-for-profit and commercialorganizations.

The response to the LCBP from the household sector was immediate and fargreater than the government had anticipated. Grants were initially available in monthlytranches but take-up was so enthusiastic that funding ran out within minutes eachmonth. In March 2007 the government decided to provide a further £6 million forthat part of the scheme but also to suspend it temporarily so it could be ‘reshaped’.

The second stream, for community schemes, has been less problematic, not leastbecause of additional funding. In March 2006’s budget statement, it was announcedthat there would be a further £50 million for the programme. This became theLCBP Phase 2 – a £50 million capital-grant stream for the installation of microgen-eration technologies by organizations including local housing authorities, housingassociations, schools and other public-sector buildings and charitable bodies. It is notopen to private households or businesses. Under Phase 2, purchase and installationof technologies must be from a specific shortlist of suppliers, and of the follow-ing technologies: solar PV; solar hot water; wind; ground-source heat pumps; andbiomass.

The LCBP was due to end in 2008, by which time it was hoped that the industrycould ‘stand on its own feet’, but the industry was not confident that the programmeas it stood would do enough to pump-prime the market and called for more supportover a longer period.

Chapter 17

Changing the industry: ESCos andcooperative power ownership

At the moment, energy customers buy gas and electricity from their energy suppliers.But electricity and gas are not what they really want: in reality they want services suchas heat, lighting, refrigeration or entertainment. Energy-services companies (ESCos)can operate to take advantage of the mismatch between what customers are buyingnow and what they really want. In the process, it is hoped that providing servicesrather than energy could make it possible to make big energy savings – not leastbecause for most customers energy is an alien concept. That means it is perceived ascomplicated and of dubious benefit to make energy savings – customers want to besure they will have the services they want, and are not necessarily convinced that thatcan be achieved if less energy is used.

17.1 Energy-services companies

The ESCo business model is of great interest to traditional utilities, partly becausethey are customer-service companies whose business grows by offering new productsto their customers, especially services that distinguish them from their competitors.But they are also of interest because utilities also want to manage their power sup-plies better. For example, buying power at peak times is expensive and, if companiescan reduce that requirement, their costs will be reduced, and so will the risk thatthey will be forced to buy more power than expected at peak times and absorbthe cost.

17.2 The 28-day rule

Utilities have also been freed to operate in this way by the ending of the so-called28-day rule for domestic customers. This rule, applied from the start of the competitivemarket, meant that any domestic customer had to be able to terminate their supplycontract and switch suppliers at 28 days’ notice. The initial aim was to promote acompetitive market and make sure customers could switch in response to power-pricehikes. However, as the market has changed it has limited the abilities of companiesto develop new supply contracts that would benefit both company and customer.For example, many customers are still using extremely inefficient old boilers for

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heating. Replacing them would reduce energy costs and the capital cost might bepaid back after two or three years but nevertheless the capital cost might be too highfor the customer. Energy companies could offer to supply new boilers and, instead ofcharging an upfront fee, could recoup the cost over several years of energy bills. Thedifference between the old cost of heating and the new cost should mean bills wouldnot rise although the boiler was being paid off, and eventually the bills would drop.But no supplier could invest in a new boiler, or even in lower-cost measures suchas insulation, unless it knew the customer would stay with their energy supplier forlong enough for the cost to be recouped. There may have been customers who wouldwelcome such deals but, under the 28-day rule, they were illegal.

Now that has changed, the range of tariffs is likely to expand to something morelike the mortgage market. It is possible to remain on the mortgage company’s variablerate with complete freedom to switch lenders. Alternatively, the mortgage companyoffers various fixed-rate or fixed-period discount schemes, whereby customers haveto pay a penalty if they switch suppliers during the term of the deal.

The ending of the 28-day rule makes it possible for energy companies to act asESCos. It also makes it much easier for independent suppliers or local energy projectsto be set up. Most would not have had to follow the 28-day rule but the situation insome cases would have been ambiguous. Now it is clear that local energy projectcustomers, too, will not have to be free to switch suppliers on 28 days’ notice.

ESCos are also of interest for local energy generators, because they provide astructure for selling services such as heat, which may be the energy project’s mainproduct.

The 2003 White Paper Our Energy Future laid out government’s view of howESCos would work. In one form an ESCo would act as intermediary between energysuppliers and customers. Indeed many industrial companies use these types of servicecompany. The ESCos manage the electricity contract with the supplier, and, at thesame time, enter into a contract with customers to realize potential cost savings byreducing energy use, installing insulation, etc. The benefits are shared so that thecustomer pays less for energy services such as heating, lighting and power, while theESCo makes a profit.

Now that carbon dioxide emissions are a major cost for many businesses, ESCoscan tailor their offering to cut emissions as well.

Our Energy Future suggested several ways in which ESCos could work at thecommunity level.

• An ESCo either agrees energy-delivery partnerships with individual companiesor housing developers, or seeks ‘pools’ of buildings such as the collective stockof a local authority or perhaps a street or village.

• Once it has assessed a potential client’s needs, the ESCo offers an energy-deliverycontract with attractive terms for the delivery of low-emission heating, lighting,power, air conditioning and/or refrigeration, over a specified period of years.Once the terms have been agreed, the ESCo organizes and oversees all nec-essary works (which may include energy-efficiency measures) and the energysupply.

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• The client pays for the energy services, while the ESCo focuses on how to deliverthose services as efficiently as possible to maximize profits and/or environmentalbenefits.

• Energy costs to a property are thereby minimized, as are emissions to an extent,depending on the technologies used.

• The cost of providing an energy service is guaranteed by the ESCo, so the clientcannot lose out, and the financial risk to the ESCo ensures a focus on deliveringenergy by the most efficient and/or low-emissions means, depending on the termsof the contract.

It also suggested ways they could work at an individual level.

• The ESCo and the customer enter into a contract under which the customerundertakes to procure power and/or heat from the ESCo over a specified periodof time.

• The ESCo installs a microgenerator in the customer’s building, at no expense tothe customer. The microgenerator remains the property of the ESCo.

• The ESCo maintains, and if necessary replaces, the microgenerator and all otherequipment necessary to fulfil its obligations under the contract.

• By undertaking initial energy-efficiency measures in the building – improvinginsulation, for example – the ESCo can minimize the required output capacity ofthe supplied microgenerator, thus increasing its own profits.

Some ESCos are already operating at the community level, offering a range ofenergy-efficiency measures, advice, energy supply and access to grants and financing.From a social-housing perspective ESCos are set up in one of three formats: as anaffinity deal (one authority makes agreement with an energy supplier), a social housingclub, or as part of a CHP district heating system.

The basis of an ESCo (for non-CHP-related companies) is essentially for theauthority or club to buy electricity as a bulk purchase, or to sign over void propertiesto a specified provider, in exchange for commission payments. These payments canthen be used to offer discounts on energy-efficiency measures, even in the privatesector. Most commonly, these would be for cavity wall/loft insulation along with hot-water tank jackets, draught-proofing and so on. Some authorities are also offeringdiscounts or loans for solar water heating, fridges and other measures. The levelof involvement a local authority has varies greatly from part owning the ESCo andoperating a billing/metering service to a passive role with some verbal input.

Setting up an ESCo can help a local authority meet its responsibilities under theHome Energy Act, but there are a number of legal issues specific to local authoritiesthat affect their participation in the provision of energy services. In particular, localauthorities are prohibited from supplying gas or energy-efficiency measures to privatehouseholds. But this does not prevent some local authority involvement in a schemethat delivers full energy services.

A CHP-based ESCo offers heat and power at standard rates for all the customersin a particular area. This means that it can offer rates that are competitive, but alsohave a standard rate, no matter which payment option is being used.

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17.3 The affinity deal

Also known as preferred-supplier arrangements or marketing alliances, affinity dealsare a relatively simple concept. Following an evaluation process, a local authorityidentifies a licensed supplier of gas or electricity (or both) that it is willing to support.In return for the local authority’s support in promoting the supplier to its residents,the supplier may offer residents special services or other benefits (including targetedenergy-efficiency offers). The supplier may also offer payment to the local authorityfor every resident who signs up, which the local authority can use to fund energy-efficiency programmes.

Aberdeen City Council established preferred supplier arrangements withScottishPower for the supply of gas and electricity to empty council properties, forwhich it gained around £60 000 a year in commission.

17.4 The energy club

A social-housing energy club offers a competitive energy supply; a range of pay-ment options; access to full- or part-funded energy-efficiency measures; independentadvice on the use of existing heating systems; and access to low-interest finance fornew measures and appliances.

Black Country Energy Services Club was set up by Dudley Metropolitan BoroughCouncil plus six housing associations in 1999, with a grant of £50 000 from the EST.

The club offered fuel supply and discounted or grant-funded measures to themember tenants and service users, plus advice on the availability of social securitybenefits and a system of payment through the Post Office. Fuel was supplied byScottishPower, which also provided low-cost fluorescent light bulbs and insulationto users.

Black Country Energy Services Club had a partnership agreement with Scottish-Power that did not tie either party into long-term arrangements. ScottishPower paidthe club a commission for each new customer, and receives all the members’ voidproperties.

Income from commission payments of £40 000–50 000 a year is paid into acommunity fund, accessible to all partners, to fund energy-efficiency projects.

17.5 The CHP scheme

The Barkantine CHP project in the London Borough of Tower Hamlets was builtand operated in partnership with London Electricity Services (part of EDF Energy).The CHP unit provided hot water and electricity to 540 households on the Barkantinehousing estate, as well as the local school and leisure centre. The 1.4 MWe CHPunit, which has the potential to supply 1 000 households, is located in a refurbishedsubstation on the estate, which dates back to the turn of the twentieth century and wasused until the 1960s.


The partnership will operate and manage the Barkantine project for 25 years.After the third year of operation the council will receive a share of the profits everyother year to invest in energy-saving measures on the estate.

17.6 Thameswey

One of the largest community heating and cooling networks in the UK has beendeveloped by Woking Borough Council in an unregulated public–private joint ven-ture with the Danish energy company Esco International. Esco International ownsand operates a CHP plant and district energy network, while the council looks afterthe metering and billing of civic buildings. The organization formed by the part-nership, Thameswey Energy, provides customers with energy services at less costthan their previous supplier. Share of any profits is recycled into other energy andenvironmental-service projects under its articles of association.

Thameswey Energy’s projects are financed with shareholding capital and loanfinance. The public–private joint venture allows Thameswey Energy to escape cap-ital controls that would be imposed on a purely government company. This meansit can implement large-scale projects primarily with private finance, with the coun-cil’s initial capitalization shareholding coming from the council’s energy-efficiencyrecycle fund, which is recycled with every Thameswey project. The local authorityownership must be less than 20 per cent, otherwise Thameswey would be caught bycentral government’s capital controls. The council owns 19 per cent and the Danishcompany 81 per cent.

Thameswey Energy designs, finances, builds and operates sustainable-energyservices both within and outside the Borough of Woking. It has taken on the runningof the borough’s existing energy-efficiency schemes and plans to expand them onbehalf of the council.

Thameswey provides residential customers with sustainable-energy services atless cost than their previous energy suppliers, despite the higher cost of the energyplant, due to the payback from the plant by the sale of heating, cooling and particularlyelectricity to the customer. A nonresidential customer’s current electricity unit priceis normally matched and the energy-services costs are assimilated into the heat andchilled-water unit prices. The customer’s electricity consumption will be reducedsince electricity is no longer needed to generate cooling. The energy-services pricesagreed at the start of the long-term contract are index-linked annually so the customermaintains the benefits of the contract throughout its duration.

17.7 The legal framework

There are a number of legal issues that affect organizations wishing to establishan ESCo.

• Consumer-credit law requires drawing up credit agreements for sales involvingloans or deferred payments and a licence for issuing credit.

164 Local energy

• The Data Protection Act 1998 restricts the extent to which databases can be usedto identify and contact potential customers.

• People on whom data are to be collected have to give their consent in advance.

In addition to these general issues, there are a number of legal issues specific tolocal authorities. For instance, local authorities are empowered to supply electricityand heat generated by CHP schemes, and free energy-efficiency advice; but, as we sawin 17.2 above, they are specifically prohibited from supplying gas or energy-efficiencymeasures to private households.

The way round this restriction is to set up a partnership with an energy company.In the appointment of a private-sector partner, the Competition Act and Public SectorRegulations require an open and fair selection process. The appointing local authoritycannot require the charging of uniform or minimum prices for specified works. Localauthorities in England are restricted to 20 per cent of any joint venture company.

17.8 Community Interest Companies

Community development and investment in renewable energy projects to date havebeen slow. One obstacle has been the lack of a straightforward legal structure that willfoster the entrepreneurial spirit of a project, but keep the assets in the community.The government announced plans in 2003 for a new company structure for socialenterprises, the Community Interest Company (CIC), which will lock in the assetsof an enterprise so that they cannot be transferred out of the public interest. TheCIC fills a gap in the legal forms that are currently available for the development of acommunity renewables project, or indeed any social enterprise that wishes to reinvestits profits in the community.

The government defines a social enterprise as ‘a business with primarily socialobjectives whose surpluses are principally reinvested for that purpose in the businessor in the community, rather than being driven by the need to maximize profit for shareholders and owners’.

Existing social enterprises take on a variety of organizational forms that sharecommon values or ways of working such as cooperatives, development trusts orsocial firms. They also use a variety of legal structures under the Companies Actsand Industrial and Provident Society legislation.

17.9 Incorporation

Incorporating a renewable-energy project as a company limited by shares (CLS)or a company limited by guarantee (CLG) can be very simple, especially if youuse standard forms of Memorandum and Articles of Association. However, manyorganizations will want to use a bespoke Memorandum and Articles of Associationto ensure that their constitution reflects the governance structure and non-profit natureof the organization.


Once a constitution is agreed, an application to incorporate is submitted and isprocessed by Companies House within seven days.

The price payable for limited liability is public disclosure. The key disclosuresare an annual return, which has to be forwarded to the Registrar within 42 days ofthe annual general meeting, and audited accounts, which have to be filed with theRegistrar within ten months of the end of the financial year. If a company’s turnoveris less than £1 million per annum (or £250 000 for a charitable company), it does nothave to produce audited accounts. However, it may be desirable to have them auditedanyway to give assurance to external supporters, financiers, etc.

17.10 Not-for-profit

The image of a CLS rarely suits the spirit of a community venture, due to its associationwith the commercial world. A CLG is the type of incorporation used primarily fornot-for-profit organizations that require corporate status.

A guarantee company does not have a share capital, but has members who areguarantors instead of shareholders. The guarantors give an undertaking to contribute anominal amount towards the winding up of the company in the event of a shortfall uponcessation of business. However, the guarantee is nominal, normally being limited to£1. A company limited by guarantee can be established so that its Memorandumstates that it cannot distribute its profits to its members. In this case, if it has exclusivecharitable objects it will need to apply for charitable status.

CLGs are increasingly used in the not-for-profit world as a flexible and easy-to-establish model. But it should be remembered that, if the organization does nothave charitable status, its constitution can be changed to make it for-profit and theassets distributed to shareholders. It is for this reason that the CIC has been proposedas a way of setting up a company whose assets are locked into the public interest.

17.11 Full cooperation

If an organization wishes to be democratically controlled and avoid the requirementsof company law, and will not be affected by the lack of a charity number, it couldregister as a cooperative.

Legal forms that enshrine cooperative principles can be established either asIndustrial and Provident Societies (IPSs) or limited companies.

An IPS is a membership organization in which each member agrees to buy oneor more shares. Members’ liability is limited to the amount unpaid on the purchaseof the shares.

IPSs are governed by the Industrial and Provident Societies Acts 1965 to 1978,and administered by the Financial Services Authority (FSA), a section of the Treasury,which has absolute discretion in deciding which organizations are eligible to register.An applicant organization must be able to show why it should be registered as an IPSrather than a company limited by guarantee.

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The IPS structure is appropriate for voluntary organizations carrying on a business,trade or industry for the benefit of the community, and for bona fide cooperativesocieties. It must have a minimum of seven members and rules that forbid the dis-tribution of its assets among members. The IPS shares some features of a limitedcompany, namely the acquisition of a distinct legal identity and the consequent limiton liability of its management committee.

In general, the regulations and formalities governing an IPS are less onerous andcomplex and more flexible than those imposed by Companies House. But registrationas any type of IPS is slow and quite expensive.

A charitable IPS, unlike a charitable company, cannot register as a charity withthe Charity Commission (it registers with the Inland Revenue), although it can callitself a charity exempt from registration. As such, it does not have to comply withmost charity legislation and, although eligible for the tax advantages of charitablestatus, it is not subject to scrutiny by the Charity Commission. But the relative unfa-miliarity of IPSs may make it difficult to persuade official bodies, such as the InlandRevenue, banks, local authority officers and members of the public that the IPS ischaritable.

Panel 17.1 Baywind

Baywind Energy Cooperative is an Industrial and Provident Society formed in1996 on the lines of cooperative models pioneered in Scandinavia, the largest ofwhich is a 40 MW offshore wind farm, Middelgrunden, in Denmark, with 8 500members. The first two projects enabled a community in Cumbria to invest inlocal wind turbines. The original board of directors included seven membersof the community from Ulverston and Barrow.

Baywind’s first share offer in 1996–7 raised £1.2 million to buy two turbinesat the Harlock Hill wind farm. In 1998–9 the second share offer raised a further£670 000 to buy one turbine at the Haverigg II site. Preference is shown forlocal investors, and 43 per cent of existing Baywind shareholders live in eitherCumbria or Lancaster with a wider number from the north-west region.

Baywind has a minimum shareholding of £300 and a maximum (by law) of£20 000. The co-op currently has more than 1 300 shareholders throughout theUK and abroad.

The seven members who currently make up the board of directors draw on arange of skills and experience to conduct the business of the cooperative. Theboard is elected by the whole membership at an AGM and is supported by afull-time paid administrator, who is also a director.

All profits derived from electricity generation are paid back to the share-holders. Since the formation of Baywind in 1996 members have received acompetitive return on their investment: between 5.6 per cent and 6.6 per centgross. Under the government’s Enterprise Investment Scheme, most members


can claim back 20 per cent tax on their initial investment in the co-op, thusincreasing the return to between 7 per cent and 8.2 per cent. The co-op has aminimum shareholding of £300 and a maximum of £20 000.

Panel 17.2 Cooperative wind

The Centre for Alternative Technology (CAT) at Machynlleth in Wales ispowered by renewable energy but in 1998 it decided its 85 kW wind turbine,put up in 1985, had to be replaced – leaving a gap in its supply. The centredid not want to incur a capital cost at this point and it was considering pur-chasing electricity from the grid. But the community stepped in, seizing theopportunity to operate its own wind turbine and sell the power to CAT. Now theproject is seen as a model for community wind-power schemes for other parts ofthe UK. Project partners include Powys Energy Agency, Forest Enterprise andthe Baywind Energy Cooperative. The Dyfi Eco Valley Partnership (Ecodyfi)coordinated the whole scheme.

The area has a fair concentration of renewables companies, and at one ofthem, EcoDyfi, Andy Rowland had recently taken on an EU-funded project todevelop community renewable energy.

The proposal to build a turbine owned by the community was put to localpeople at a series of meetings. Following the meetings a steering group wasset up with around 90 members, each paying £10 to join. This provided somedevelopment funds and a strong core of support, useful both for planning theproject and in practical terms.

As the project solidified the group set up a company – structured as an Indus-trial and Provident Society on the Baywind model, called BroDyfi CommunityRenewables Ltd.

It was particularly important that the project got general agreement: as acommunity project, it depended on it for much of its funding.

Capital and setup costs to install the turbine totalled £85 000. That includedjust £15 000 for the 85 kW turbine because BroDyfi went to Denmark to buya turbine that had been operated for ten years. It enabled BroDyfi to buya turbine under 300 kW and one that met a size condition on the planningpermission.

Construction costs were £45 000 and future annual maintenance costs areestimated at £2 320.

The turbine was partly funded by grants. The European Regional Develop-ment Fund provided £19 000 via Ecodyfi, and ScottishPower’s Green EnergyTrust provided £10 000. The Energy Saving Trust invested £18 000, providingboth grant funding and buying shares.

Continues

168 Local energy


When shares were offered to the 90 members of the development group theoffer was oversubscribed. Those investors are hoping to average an 8 per centreturn on their investment over 15 years.

All the power from the turbine will be sold to CAT. The centre has signedan agreement to buy the power generated (around 163 MWh/year) for 15 yearsand will use 34 MWh/year to supply its site with electricity and hot water. Theremaining electricity will be exported to the local grid.

The 15-year agreement means the wind group has a fairly secure return on itsinvestment. Under this power purchase agreement the output from the turbineis split into three levels. The price for the lowest level is the highest, with theprice for the next two bands set progressively lower.

CAT takes on the rights to the renewables obligation certificates (ROCs)generated with the electricity.

Chapter 18

Output and generation

18.1 Load factors and variability

No form of generation will generate power or heat continuously. This variability ingeneration sources is of benefit to grid operators, because it means that there are anumber of options available to balance supply with demand as it varies during theday, the week and the year. A diverse electricity supply industry with a variety ofsources of electricity supplying the industry at different scales is the most robust.

Utilities use the term load factor to compare the different outputs of power-generation plants. Load factor is generally the amount of power produced by theplant compared with its theoretical maximum output, but this may also be referredto as ‘capacity factor’, implying that it measures how much of its total capacity theplant is supplying.

There are many reasons why a generator has a load factor of less than 100 percent. They stop generating in the case of renewable energy if there is no ‘fuel’ – itis dark (in the case of photovoltaics), say, or between tides (for tidal power). In thecase of rotating machinery, even if fuel is continuously fed into the power-generatingplant then regular stops are scheduled to allow the plant to be maintained.

Even devices with no moving parts and continuous supplies of fuel – such as afuel cell supplying heat and power – may be stopped, or the power output varied overtime, depending on the needs of the customer.

This is one reason why measurements of load factor have to be used cautiously:power stations that are operated at part load to meet the demands of the network willrecord a lower load factor, for example. In response, the industry sometimes uses an‘availability’ measure instead: this records what proportion of the time the plant is‘available to generate’. If a plant suffers an unexpected shutdown it will be reflectedin the availability, whereas if it is shut down to meet the demands of the grid it willnot affect the figures. Availability is, however, an ambiguous term as it is not clearlydefined. For photovoltaics and wind, for example, different definitions of availabilitydo or do not allow the equipment to be ‘available’ when there is no sun or wind.

Caution should also be used when comparing load factors or availability at dif-ferent times. The demands of the grid are very different at different times, so powerstations operate differently. A power station that shuts down unexpectedly in summermay stay out of operation for longer than necessary to complete outstanding mainte-nance work while demand – and hence prices – is low. In the winter an unexpectedshutdown would be kept to the minimum possible.

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Renewables sources have a very different profile of load factors.

• Wind-turbine load factors depend almost entirely on how much wind is available,with some short maintenance halts. A modern wind turbine produces electricity70–85 per cent of the time, according to the British Wind Energy Association,but it generates different outputs dependent on wind speed. Over the course of ayear, it will generate about 30 per cent of the theoretical maximum output, andthat is its load factor.

• Tidal power plants will generate on a cycle with two peaks as tides rise and fall,and two minima at ‘slack water’ as the tide turns.

• Photovoltaic plants should be available 100 per cent of the time that the sun shines,but they will generate the rated power only during so-called ‘peak solar hours’.In the UK this varies but may mean the PV array produces peak loads only for10–20 per cent of the time – although the array is generating at a lower level atother times. This is also moderated by the fact that high temperatures can reduceperformance by up to 20 per cent. The performance of the photovoltaic array istherefore partly determined by the siting of the PV panels to ensure they receivemaximum sunlight for the longest possible time.

• Wave-power plants will be affected by the wind that is forming the waves, and,depending on whether their site is near the coast, may also be affected by the tideas it interacts with the wind.

• Hydropower plants sited on a river can operate almost continuously while thewater level in the river is high enough. Strict restrictions placed on hydro stationsby the Environment Agency limit the use of plants if the host river has a low flowin summer. This depends entirely on the state of the river, and the effect can vary,from a situation where the plant stops generating during the summer entirely toone where the plant is halted at unpredictable intervals when flow drops. Hydroplants with storage in the form of a reservoir or millpond may have more controlover when they operate, but can be required to release water (and generate power)at times when river flow is low.

• Conventional thermal plants are halted for planned or unplanned maintenance atleast once per year and may be halted by unplanned maintenance at any time. Theamount of halted time is a function of the age of the plant, the condition of theequipment, how well it has been maintained and so on. Availability could be ashigh as 90 per cent for the best stations but much lower in those that are poorlymaintained. Since thermal plants can be operated at part load depending on griddemands and started up quickly, they may be used for load following, so loadfactors may be considerably lower than availability.

• For CHP plants both availability and load factor depend on how the plant is setup, and whether the major load is for the heat or power fraction of the output.

18.2 Micropower efficiency

The availability and load factors of power stations that export power to the grid atlarge or middle scales are fairly well understood. What is not clear is how much

Output and generation 171

electricity will be available for export from domestic-scale microgenerators. Thisgroup of devices, which include microCHP systems to replace household boilers, isexpected to be a major new influence in the market: government hopes that they willeventually be used by millions of homes.

A trial by the Carbon Trust investigated how much electricity was exported to thegrid as it examined field trials of microgeneration projects. It looked at the progressof devices with a range of electrical output up to about 25 kW and included Stir-ling engines, organic Rankine-cycle machines, fuel cells and internal-combustionengines.

The Carbon Trust points out that, while small-CHP is mature, and a few fuel-celldevices are emerging as ‘beta’ test units from several manufacturers, there is lessexperience in the microCHP area.

One of the most mature microCHP technologies is the WhisperGen Stirling engineunit, which has been sold as a low-voltage DC unit for remote heat and power onyachts and other off-grid installations for some years.

18.3 Progress of the field trial

The Carbon Trust initiated the trial in February 2003. By late autumn 2003, fivesuppliers of small and microCHP equipment had joined the trial but all the suppliersexperienced significant difficulty in supplying units for the trials. By August 2004,when 74 units had been contracted for installation, there were only 7 installed. TheCarbon Trust sought more widely and in the end carried out the trial with 40 units,31 microCHP and 9 small-CHP.

It compared the data with information from 40 homes with conventional boilers.The carbon-saving potential of small and microCHP depends on:

• overall thermodynamic efficiency;• the amount of electricity generated; and• the carbon intensity of the electricity displaced from the grid.

18.4 MicroCHP for homes

The findings from the trial indicate that the different technologies exhibit dif-ferent performance characteristics in different environments. Very early findingsfor microCHP indicate that its performance is not as encouraging as had beenhoped.

Data from trial units installed in representative homes in the UK suggest thatthe modelled predictions of carbon saving published to date are not being supported.There are several reasons for this, including the following:

• The actual, real-world efficiencies of the units are lower than assumed by existingtechnology modelling exercises.

• The amount of electricity generated is much lower than forecast. Electricityexported out of the building is considerably higher than expected.

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• In addition, a number of other concerns have been raised during the trial. Thisincludes notably high electricity consumption by the units during some phases ofoperation and the sensitivity of the units to poor installation.

The reasons for the poorer-than-expected efficiency appear to be related to thedesign and operation of the units at their current stage of development. A microCHPunit must reach a fairly high operating temperature before it can generate electricity.During its warm-up period it will provide some heat to the building, as heated water ispumped through the heating system, but at this stage no electricity is being generated.

However, warming up the mass of the unit to operating temperature absorbsenergy, most of which cannot be usefully recovered (this is especially true for unitsinstalled outside the living/working areas of a house/business). If the unit was startedonly once a day and then ran steadily for many hours, the impact of this would be verysmall, possibly negligible. However, in many properties heat demand is intermittentand is required for only short periods. In some sites units are called to start up as manyas five times a day. In such circumstances the repeated warm-ups absorb a significantamount of energy, which is not re-released in a useful way, thus resulting in reducedefficiency.

There is less electricity generated than expected simply because the data showthat running hours are lower than previously modelled. In addition, during warm-upperiods units do not generate electricity, as might have been assumed in modelling.This is particularly relevant for summer operation, when the units need to provideonly hot water. In this circumstance, little if any electricity is generated, as the watertank can reach the desired temperature before the microCHP has generated a materialamount of electricity.

Ideally, the microCHP industry needs to design units with the ability to modulateelectrical output much more widely than currently.

While it is still relatively early in the trial, at the current state of developmentof microCHP, the emerging trial data indicate there is unlikely to be a significantcarbon emissions reduction opportunity from wide deployment of the technology atthis stage in its evolution. From the results of the trial to date, carbon savings are inthe range of plus or minus 18 per cent. The reasons ‘appear to relate to the interactionof the devices with the heating system, building and occupancy’.

It is also instructive to note that these effects are also apparent to some degreein the findings relating to boilers and should be considered in any future support forefficient boilers.

‘If this trend continues for the full trial, there will be a material risk of anincrease in emissions if microCHP is deployed at scale without regard to the dif-ferent performance characteristics of specific technologies and the circumstances oftheir installation, maintenance and use.’

18.5 Small-CHP for business

The performance of small-CHP in businesses seems to be much stronger, where anumber of installations appear to offer material carbon savings. The technologies


being monitored in the Carbon Trust’s field trial appear to have better performancethan the microCHP units. Current data suggest that the electricity-generating efficien-cies are considerably higher and that overall thermodynamic efficiencies are good.Running hours are also longer than for microCHP and less intermittent and so startupand shutdown losses are much reduced. It should be noted that the sample size forsmall-CHP is small at this stage and therefore this picture may change as more unitscome on stream within the trial.

Overall it appears that worthwhile carbon emissions reductions can be foreseenfrom the range of internal-combustion engine devices monitored in the trial to date ifthey are installed and operated properly, based on current grid carbon emissions.

These results from the field trial support existing modelling results and there aretwo main factors that explain the enhanced performance compared with microCHP.

First, small-CHP units are installed in business premises on the basis of an eco-nomic business case. This tends to be based on a higher level of analysis than ina home and on long, continuous run hours with few or no starts during a 24-hourperiod. Under these conditions, which have been found in the trials, the units operatein steady-state and hence warm-up losses are negligible. In such circumstances theunits can be expected to exhibit high levels of thermodynamic efficiency throughgood design, which contributes to carbon-saving potential.

Second, the proportion of fuel input converted to electricity is found to be higherin the small-CHP units (20–25 per cent) than in microCHP (5–15 per cent) due totheir design at this electrical output. This is due to the efficiencies of the technologiesemployed in the units and the laws of physics governing their operation.

It is by virtue of electricity generated that any CHP saves carbon because the heatelement will be no more efficient than a boiler, and consequently the small-CHP unitswill tend to save more carbon than microCHP.

Evidence from the trial also demonstrates how carbon savings from small-CHPcan be very low due to poor installation, inadequate maintenance and poorly controlledoperation, together with additional electrical loads such as fans being added in boilerrooms when the CHP unit is installed

18.6 Replacing generation?

The Carbon Trust also raised some larger issues over how widespread microCHPmight affect grid operation and what that might mean for reducing carbon emissions.

If Micro-CHP units begin to operate early in the morning, ahead of the main rise in demand,then the effect may be to increase the rate of rise that occurs later. This may cause problemsfor managing the grid and, for example, a greater capacity of inefficient open cycle gasturbine plant may be called on to operate. If substantial numbers of Micro-CHP units areinstalled to deliver a capacity of over 1 000 MW then investors in new, efficient plant maydefer construction. The net result will be old, inefficient plant will continue to generate withhigh carbon emissions. Many of the plant operating at the margin are steam-raising coalplant. This is because they are the only plant capable of operating part-loaded to providefor the sudden changes in demand/supply balance seen due to, for example, sudden rises indemand when TV programmes end or the unplanned shut-down of a centralised generating

174 Local energy

station occurs. These may be the only plant available to provide this service and microCHPwill neither replace them nor reduce their output.

Published market predictions for Small and Micro-CHP suggest potentially 400,000per year (in a total market of around 1.1 million) might be installed from about 2010 onwards…The CHP units are intended to have a lifetime of 10 to 15 years and hence many will beoperating beyond 2020. By 2020, to meet climate-change obligations, it is likely that gridcarbon intensity will have reduced. Consequently, any potential carbon savings from smalland micro-CHP will reduce accordingly.

18.7 Saving carbon

As the problem of global climate change becomes more urgent, the life-cycle costof activities, in carbon dioxide emissions, has become a pressing issue. Take windpower. Although it has no carbon dioxide emissions at the point of generation, theconstruction and erection of the turbines do entail emissions. It is similar for all formsof generation: a lifetime measurement of carbon dioxide emissions from coal-firedgeneration includes not only the emissions from coal being burnt but from otheractivities such as the coal mining and transport and plant construction.

Concrete manufacture is highly energy-intensive and it is an important componentof most power-plant construction. As all forms of generation interact within theelectricity supply system, they also require carbon dioxide emissions in the form ofpeaking power, spinning reserve, etc.

The European Commission is one organization that has tried to quantify thecarbon emissions associated with each form of generation for its entire life cycle(see Table 18.1), including removal of the power station at the end of its lifetime.The question is not easy to answer, since judgements have to be made on where itis assumed that the activities end: if coal transport is included, for example, shouldthe emissions involved in constructing coal-transport ships also be included? Inter-ested parties will argue over where those lines should be drawn; nevertheless the ECestimate is one attempt to produce a basis for comparison.

What is clear is that combining biomass fuels with carbon capture and storageoffers the only opportunity to produce a negative carbon dioxide life-cycle balance –that is, to remove more carbon dioxide from the atmosphere than is emitted.

18.8 Changing energy patterns

Changes in the climate are likely to change electricity requirements over the longterm. The UK Climate Impact Programme estimates that ‘by the 2020s our annualaverage temperature would be between 0.2 ◦C and 0.8 ◦C higher’. But what thatmeans in practice is not a slightly warmer environment throughout the country, buta drier and hotter south-east and wetter northern areas, along with more extremeweather events. The basic message is that the changes are expected to accelerate. Bythe 2080s, the south-east could have summer temperatures as much as 6 ◦C higherthan we experience now – with perhaps 60 per cent less rain. Frost days have declined


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as temperatures have risen by 0.50 ◦C over the past century and we have seen lessrainfall in the summer but a higher proportion of heavy rain in the winter.’

The UK’s infrastructure was built for the weather pattern of the last 30 years andcompanies operating it have to prepare for change. The effects of extreme weather con-ditions were graphically demonstrated in 2002, when storm damage to the electricitynetwork left thousands without power – some for weeks.

Changes in the country’s weather patterns affect the electricity supply system intwo ways. First is the response of its equipment to more extreme weather patterns;second is the potential change in patterns of demand.

When it comes to hardware, the natural variation in the UK’s weather meansthat National Grid and the Distribution Network Operators (DNOs) have to dealwith all kinds of temperature and weather effects. There is an impact in day-to-daymanagement where equipment is affected by the temperature.

Transformer cables have different ratings in summer and winter, depending onthe external temperature. The operators start with a thermal rating based on ambienttemperatures for the last 10–20 years, which gives guidance, and then on a dailybasis a table is constructed for MVAr against temperature, which can be used toforecast performance. Similar temperature-dependent effects are felt throughout thesystem. In just two examples, the capacity of the transmission line alters dependingon the temperature, because the high-tension cables expand and sag more at highertemperatures – a 400 kV line currently has a capacity of 2 190 MVA in summer and2 720 MVA in winter. In the gas network, compressors sending the gas down thepipelines have to work harder at higher temperatures, drawing more power.

Temperature is not the only issue. Extreme weather events also place stresses onthe system, and National Grid identifies high winds (in excess of 40 knots), high iceloads, low temperatures (and consequent fog and icing), heavy rain, lightning andsalt pollution as likely to contribute to weather-related faults. Managing these faultsrequires investment in the high-voltage transmission system.

Some protection is built in. For example, the west coast is subject to salt pollutionfrom high winds and protection takes the form of a spray that is released when thesalt burden gets too big. Similar equipment is increasingly required at the distributionlevel, where the network is more extensive.

Changes in consumption require the grid to bring extra power on to the system andit can be very sensitive. On a summer’s day a shift from clear sky to thick cloud addsan additional 5 per cent demand – requiring power from, say, four 500 MW gensets.An increase in wind adds 2 per cent to winter and 0.7 per cent to summer demand.

That means that, although the DNOs each supply an area with around one-twelfthof the UK users, National Grid has to know about the load in far more detail.

As local temperatures change and more extreme weather events occur, humanbehaviour changes and the electricity supply system has to be able to respond. Onebig effect in the long term will be from additional air-conditioning loads, which willadd to both peak and 24-hour demand.

National Grid has already seen a growth of 5 per cent in air conditioning in thecommercial sector in five years to 2005 and it expects to see a further 6 per cent inthe period to 2010. There is also likely to be a rise in the residential market, although

178 Local energy

that is speculative at the moment, because it also depends on complex socioeconomicfactors.

Similarly, a 1 per cent rise in external temperatures increases the requirement forrefrigeration – it increases cold-appliance consumption by 1.8 per cent, and someappliances double their energy use when external temperatures increase from 18 ◦Cto 26 ◦C. That could be very much increased by the onset of a couple of hot summers,and a change in temperature is just one way in which climate change may have aneffect. If air quality deteriorates people tend not to use natural ventilation. Insteadthey close the window and put on the air conditioning.

Averages suggest that climate change will average just 1–2 ◦C over the country,and it is likely that the pattern of demand will stay broadly constant. But it is on thesmaller scale that large changes will take effect. With the south-east drier than thenorth, socioeconomic effects will be different in different parts of the country. Onthat scale, small perturbations affect the system and the grid suggests it may have touse the infrastructure differently. Most customers don’t take much account of theirconsumption. They use fans for cooling in the summer months – it’s a small item forone customer but for NGC it is a noticeable cooling load.

Chapter 19

Putting a price on carbon

The European Commission’s emissions-trading scheme should impose a cost onenergy generators that produce carbon dioxide, favouring renewable generation.

In July 2005 Greenpeace set out a list of changes that would have to be made tosupport and encourage DG in the UK. Among its proposals were changes to buildingregulations that would ensure that distributed energy was used in new homes andbusiness premises, changes in the rules on network access and export tariffs thatwould support the export of excess power from small generators, and tax changesthat would give a financial incentive for installing distributed energy. Progress insome of these areas has been significant, as is described elsewhere in this book.Many believe, however, that all progress on distributed energy must be underpinned,

180 Local energy

and will be given much more impetus, if the effect of carbon dioxide emissions isfully assessed and costed.

Greenpeace raises this possibility in its wish list as a tool to make visible the effectsof carbon dioxide emissions from large fossil-fuel-generating stations and impose afinancial penalty accordingly. But many believe that ‘discovering’ a price for carbondioxide emissions will be fundamental to shifting the balance of our energy industry.When the price of carbon dioxide emissions is factored into the energy price, it shouldreward companies and individuals who switch to the most efficient forms of energygeneration, as well as those who use sources that, like renewables, do not producecarbon dioxide emissions.

19.1 The EU Emissions Trading Scheme

The European Union has attempted to develop, and impose, a price for carbondioxide emissions with its Emissions Trading Scheme (ETS). In January 2005 theETS commenced operation as the largest multi-country, multi-sector greenhouse-gasemission-trading scheme worldwide. The scheme is based on Directive 2003/87/EC,which came into force on 25 October 2003. It is a cap-and-trade scheme that isintended to give incentives to all participating companies to reduce their emis-sions, but also to ensure there are ‘easy wins’ and that the easiest and cheapestemission-reduction activities are completed first.

The ETS requires each of the EU’s now 27 member states to set a so-calledNational Allocation Plan (NAP) – an annual ‘budget’ for carbon dioxide emissionsfrom the installations in sectors covered by the scheme. In each period, or phase, eachof the installations in each of the participating countries has its own annual emissionsallocation.

The scheme includes both heat- and power-based carbon dioxide emissions, basedas it was on all combustion installations that produced more than 20 MW of ther-mal energy, whether or not that was used to produce electric power. In the firstphase (2005–7), the ETS includes some 12 000 installations, representing approxi-mately 45 per cent of the EU’s carbon dioxide emissions. This phase encompassedenergy activities (combustion installations, mineral-oil refineries, coke ovens), pro-duction and processing of ferrous metals, mineral industry (cement clinker, glass andceramic bricks) and pulp, paper and board activities. Because it included combustioninstallations it took in industrial sites, but also heating and incineration plants suchas those used in large commercial buildings and even social organizations such ashospitals.

The emissions allocations granted to each installation were calculated in the UKby so-called ‘grandfathering’ – taking an average of emissions in previous years.

Once allocations were made, an electronic register of allocations was maintainedin each country. This made the trading part of the cap-and-trade approach possi-ble: companies or organizations that had emitted less carbon dioxide than had beenexpected would be rewarded, by being able to sell their extra allowances to companiesthat had emitted more carbon dioxide than their allocation allowed.

Putting a price on carbon 181

In the UK a reserve allocation was added to the NAP so that new plants starting upin the first phase would not have to buy their allowances. This approach was also takenelsewhere, although some environmental groups had argued that all new plants shouldbe required to buy allowances to ensure they had strong incentives to invest in themost efficient plant and reduce their emissions – indeed, many groups had argued thateven existing installations should have to buy all the necessary allowances, possiblythrough an auction method.

19.1.1 Results from Phase 1

The first phase of the EU TS had mixed success. The principle of the programme wasfirmly established: all countries presented NAPs, companies were given allowances,trading platforms were introduced and allowances were traded. However, it had beenargued from the start that the allowances granted in this phase had been too generous.The consultants Ecofys, for example, as early as 2004, were noting that the NAPswere not ambitious enough (in limiting emissions). The power-generation sector wasseen as most favoured by the NAPs. Ecofys suggested that the caps for Phase 1 werelenient. In most countries, the power sector would not need to reduce carbon dioxideemissions as much as the country as a whole. In other words, the other sectors mustmake more ambitious emission reductions than the power sector under the scheme.More strikingly, a few countries (such as the Netherlands) gave more allowances thanEcofys estimated to be needed under a business-as-usual scenario, implying that no‘real’ efforts to reduce emissions would be required.

When it became clear by 2006 that NAPs had indeed been too generous andthere would be an oversupply of carbon dioxide emission allowances, the priceof allowances fell dramatically, from around e30 per tonne of carbon dioxide inApril 2006 to e1–2.

In addition, the generous allowances given to power-generating stations cameunder fire. Power companies had passed on the supposed cost of participating in thescheme to their customers, but, as Ecofys – among others – had suggested, far frombeing short of allowances, had found themselves with allowances to sell.

Nevertheless, the fact that the ETS existed meant that emitting carbon dioxide hada price. And although that price had fallen dramatically in the course of the first phaseof the ETS it was clear that the European Commission would be more ambitious infuture about setting tight limits, so it was likely that the price of emitting could onlyincrease.

This has clearly influenced decisions on energy. Large pulp and paper suppliershave in some cases already switched to using biomass fuel instead of gas or oil (seeChapter 11) and major power generators, such as the UK’s largest coal-fired station atDrax, have pursued plans for co-firing with biomass and for efficiency improvementsthat would produce less carbon dioxide for each megawatt of power generated.

It could be argued that such switches were on the agenda for those plants anyway,and in some cases, far from bringing them forward, they could have been held back bythe ETS. Knowing the ETS would be implemented, holding back any improvementsuntil after ‘grandfathering’ had been used to calculate the site’s allowance would

182 Local energy

give it the maximum possible allowance which could then be traded when upgradeshad been completed after the ETS was in operation. That may be so. However, ETSsupporters can argue in response that there will be only one opportunity to benefitfrom the introduction of the ETS. The larger picture is that the ETS has indeed doneits job of altering the balance of the decision-making on how energy is produced, andits weight in the decision can only increase as the cost of carbon dioxide emissionsincreases. That will depend on how the second phase of the ETS is managed.

19.1.2 Setting up the ETS Phase 2

The second phase of the Emissions Trading Scheme is longer than the first, lastingfrom 2008 to 2012. The European Commission aims eventually to include all emittingsectors, including aviation, maritime and land-transport emissions, but early plans toinclude aviation in the second phase have been delayed.

Following the collapse in carbon prices in the first phase, the EC was determinedto impose stricter limits in Phase 2. It sent back almost all the National AllocationPlans submitted by the member states, requiring further cuts in the allocation.

Table 19.1 Suggested carbon dioxide emissions allowances by country for thesecond phase of the EU Emissions Trading Scheme

2005 verified Proposed cap Cap allowedMember state 1st period cap emissions 2008–12 2008–12

Austria 33.0 33.4 32.8 30.7Belgium 62.08 55.58 63.33 58.5Czech Republic 97.6 82.5 101.9 86.8France 156.5 131.3 132.8 132.8Germany 499 474 482 453.1Greece 74.4 71.3 75.5 69.1Ireland 22.3 22.4 22.6 21.15Latvia 4.6 2.9 7.7 3.3Lithuania 12.3 6.6 16.6 8.8Luxembourg 3.4 2.6 3.95 2.7Malta 2.9 1.98 2.96 2.1Netherlands 95.3 80.35 90.4 85.8Poland 239.1 203.1 284.6 208.5Slovakia 30.5 25.2 41.3 30.9Slovenia 8.8 8.7 8.3 8.3Spain 174.4 182.9 152.7 152.3Sweden 22.9 19.3 25.2 22.8United Kingdom 245.3 242.4 246.2 246.2

Source: EU press release IP/07/459: ‘Emissions trading: Commission adopts decision on Austria’s nationalallocation plan for 2008–2012’, 02/04/2007.


19.2 Trading outside Europe

In Phase 2 the ETS should also begin to trade with similar schemes outside theEuropean Union. Initially, this will be with European countries closely linked with,but not members of, the European Union – Norway (which began in 2007 to developits own NAP), Switzerland, Liechtenstein and Iceland. In this phase also, the ETSwill allow companies to take account of carbon reductions made outside Europe. Thisis accomplished through two mechanisms set up under the Kyoto Protocol, referredto as the Clean Development Mechanism (CDM) and the Joint Implementation (JI).

The CDM allows European companies to invest in emissions-reduction projectsoutside Europe that would not otherwise have taken place, or provide funding thatwill help replace a high-emissions project such as a new power plant with an optionthat produces lower emissions.

A JI project is similar to a CDM project, but the JI project must be in a so-calledAnnex 1 country that has signed up to limit its carbon dioxide emissions under theKyoto Protocol. In both cases the project and its emissions credits must be validatedby a third party.

Eventually, the ETS should also be able to trade with similar schemes elsewhere.One important target is the USA. Although the USA has not ratified the Kyoto Protocoland the Bush administration has not supported attempts to develop a global approachto reducing carbon dioxide emissions, the US picture as a whole reveals much moresupport for the enterprise than might be expected.

US states have considerable autonomy in setting taxes and developing their ownenvironmental policies and, for many, carbon dioxide emissions reductions have beena target. California, whose economy is comparable to that of any European country,has its own plans for emissions reductions, and a group of north-eastern states jointlydecided to set reductions targets in the mid-2000s. The cap-and-trade approach usedin the ETS was familiar to US regulators, as it had already been used to addressother pollutants, and the north-eastern states planned a cap-and-trade system of theirown for carbon dioxide. By 2007 both groups had taken a more than passing interestin the ETS and had raised the possibility of trades between the US and Europeanschemes. That is not likely in the near term, but Federal organizations have beenunder pressure to shift their position on carbon dioxide emissions. The Environmen-tal Protection Agency already runs cap-and-trade schemes to reduce sulphur dioxideand other pollutants, and under a long-running test case was being pushed to declarecarbon dioxide a similar pollutant, which would require it to be regulated and reducedin the same way. Meanwhile, the Bush administration was also under pressure fromindustry, which feared it would be subject to a variety of emission-reduction regu-lations set by tens of states. Instead, industry argued in favour of a single federalscheme.

It is unlikely that such an about-turn will be on the agenda for the Bush adminis-tration but an incoming Democrat or even Republican president would have supportfor taking some measures to fall closer into line with the global consensus onemissions.

184 Local energy

19.3 Carbon trading for commerce and industry

The European Union’s ETS is in its early days, but the system of cap and tradeto reduce emissions of pollutants has a longer history: it has been used to reducepollutant emissions including sulphur dioxide as well as more recently carbon dioxideemissions.

The UK government proposed in 2006 that this system should be used to limitand eventually force reductions in carbon emissions from businesses that fall outsidethe ETS. The ETS encompasses sites where carbon emissions are produced fromheat generators producing 20 MW or more. The UK also proposes to limit carbonemissions from less energy-intensive organizations.

Introducing the proposals, Secretary of State David Miliband noted that they‘would include large retail organizations, banks, large offices, universities, largehospitals, large local authorities and central government departments. Without newpolicies, emissions from these types of organization are set to increase over com-ing years but as explained in the Energy Review, this group of organizations havesignificant potential to achieve cost-effective carbon reductions.’

The new measure would be known as the Carbon Reduction Commitment(known briefly as the Energy Performance Commitment) and would apply to orga-nizations with electricity consumption higher than 3 000 MWh. At current energyprices, this would generally capture organizations with annual electricity bills above£250 000.

The government estimates that this sector comprises around 5 000 large non-energy-intensive organizations. It wants to provide ‘Policy instruments [that] canprovide an important framework to help organizations overcome the various barriersto investments in energy efficiency that remain.’ The Carbon Reduction Commit-ment (CRC) would be a mandatory cap-and-trade proposal covering energy-useemissions.

The proposal is for an auction-based cap-and-trade programme, in which partic-ipants would be required to purchase allowances corresponding to their emissionsfrom energy use (either at an auction or from each other) and then surrender them toa coordinator. Government would cap total energy-use emissions by deciding on thenumber of allowances issued for auction. The revenue raised by the auction wouldbe recycled to participants, so the proposal would be broadly revenue-neutral to theExchequer. In addition, the proposed system for recycling CRC auction revenueto participants overall would, to some extent, create individual winners and losers,so as to reinforce the business case for driving carbon savings and good energymanagement.

It would be accompanied by a system of voluntary benchmarking and reportingof energy use covering the sector. The government also plans to provide more infor-mation to the sector about how to reduce energy use and therefore emissions, andwork towards industry-led agreements to reduce emissions.

There would also be changes to building regulations, but, since they have recentlybeen revised, this is likely to be in the 2020 timeframe.


19.4 Making the case for local energy

The Carbon Reduction Commitment is intended to replicate the effect of the ETS forsmaller companies: that is, to put a price on carbon dioxide emissions that encouragescompanies to look for energy-efficient alternatives or to switch to renewables. Stillmore important, the cost of carbon-emission certificates should add weight to thefinancial argument for re-examining how energy is provided.

The cost of carbon dioxide may tip the scales for companies and organizationsconsidering whether they should invest in local generation for their heat and powerneeds. Other measures are working towards the same goal: planning documentsthat require new buildings to incorporate a proportion of on-site low-carbon energygeneration to meet their heat and power needs and an EU Directive that requires anenergy-efficiency certificate to be displayed in every public building.

There are a number of other changes that will act to help ease the developmentof local energy projects. These include changes in the method by which the cost ofconnecting a local energy project to the network is calculated and smart meters thatwill make it much easier for local energy producers to export their excess power acrossthe network. More broadly, there is a new opportunity for ESCos and private powernetworks to be set up, and to work with their customers to develop new approachesto energy supply and management.

There is still a long way to go before local energy schemes become a familiar sighton most new-build projects and are backfitted to help provide energy for existingbuildings, not least because the thousands of miles of existing wires and the networksthat feed the UK’s millions of buildings will all, eventually, have to be re-examinedand in many cases replaced by equipment that is much smarter and more flexible inoperation.

Nevertheless, it appears that much progress has been made since the turn of thecentury. As new measures begin to bite we can expect many more local energy projectsto be brought into operation using local energy resources. The result should be a muchmore diverse and reliable network.

186 Local energy

Panel 19.1 Greenpeace’s wish list

In a 2005 report Greenpeace set out a ‘top ten’ list of actions required to fosterthe development of DG. The actions were as follows:

1. The government to use the tax system to reward householders and busi-nesses that install distributed-energy technologies such as solar panels,micro-wind turbines or cogeneration systems.

2. All new buildings to be required to incorporate distributed-energytechnologies. This would steadily cut emissions from the building stockand enable the retirement of power stations, while also transformingthe economics of distributed energy by creating economies of scale andcutting installation costs.

3. Local sustainable electricity systems to be encouraged through theremoval of current limits on the development of private wires. Limitson the export of power from these sustainable local systems should beraised.

4. Local government to become a key player in moving to sustainable energysystems. There should be area-based carbon dioxide reduction targets,along with a statutory requirement for all councils to develop an energystrategy.

5. All electricity suppliers to be required to purchase surplus electricityfrom domestic power generators, at rates that will ensure the take-offof domestic generation.

6. Inefficient, centralized power stations to be heavily penalized to reflectthe damage they cause and to ensure that the most polluting are closed.One way to do this would be to tighten up the European ETS. In addition,supplementary fiscal measures could be enacted at UK level, such as atax on waste heat.

7. No new fossil-fuel generation to be permitted unless it includes cogene-ration.

8. A nationwide network of biomass or biogas cogeneration plants to bedeveloped, with Regional Development Agencies playing a leading role.

9. Energy regulation to be completely overhauled. Ofgem should be trans-formed into a sustainable energy regulator with its primary duty beingto deliver substantial emission reductions through the encouragement ofdistributed energy.

10. The publication of a Decentralized Energy White Paper.

Bibliography

Bowers B. History of Electric Light and Power, 2nd edn. London: Peter Peregrinus;1991

Carbon Trust. ‘The Carbon Trust’s Small-Scale CHP field trial update’. London:Carbon Trust; 2005

DEFRA. ‘Biomass Task Force Report to Government’. London: HMSO; 2005

DEFRA. ‘Consultation on measures to reduce carbon emissions in the large non-energy intensive business and public sectors’. London: HMSO; 2006

Department of Communities and Local Government. ‘Domestic Installation ofMicrogeneration Equipment, Final report from a Review of the related PermittedDevelopment Regulations’. London: HMSO; 2006

Department of Trade and Industry. ‘Our Energy Challenge: Power from the people’.London: HMSO; 2006

Department of Trade and Industry/Ofgem. ‘A call for evidence for the review ofbarriers and incentives to distributed electricity generation, including combined heatand power’. London: HMSO; 2006

Department of Trade and Industry. ‘The Energy Challenge: Energy Review Report’.London: HMSO; 2006

Department of Trade and Industry. Digest of UK Energy Statistics. London: HMSO;2006

ECOFYS. ‘Ecofys evaluation of Phase 1 NAPs’. Ecofys; 2004

Energy Saving Trust. ‘Potential for Microgeneration: Study and Analysis’. London:Energy Saving Trust: 2005

Greenpeace. Decentralising Power: An Energy Revolution for the 21st Century.London: Greenpeace; 2005

Jenkins N., Allan R., Crossley P., Kirschen D. and Strbac G. Embedded Generation.London: Institution of Electrical Engineers; 2000

Patterson W. ‘Electricity In Flux’. Presented at Uranium Institute 25th AnnualSymposium; London, 2000

188 Local energy

ReFresh (Recent Findings of Research in Economic & Social History), Networkindustries and the 19th and 20th century British economy, issue 19, Autumn1994

Union for the Coordination of Transmission of Electricity. ‘System Disturbance on 4November 2006’, final report. Brussels: UCTE; 2007

Index

AC/DC 13, 112affinity deals 162

B&Q, Grimsby, PV scheme 75backup generation 114Balancing and Settlement Code (BSC) 25,

33, 135balancing costs 33balancing market 23, 24Barkantine CHP project 162–3batteries, energy storage 46, 98Baywind Energy Cooperative 166–7biomass 87–93

life cycle costs 176planning consent 125projects 31–2, 89–92types 34–5

bio-oil 93Black Country Energy Services Club 162British Electricity Trading and Transmission

Arrangements (BETTA) 23–5, 152–3Bullerö Island, Sweden, scheme 103

capital costs 149–50carbon emissions 179–85

life cycle costs 174per MWh for different energy

sources 175–6small scale CHP 172–3

Carbon Reduction Commitment (CRC) 184–5carbon trading 180–4Carbon Trust, small scale CHP trials 171–4Central Electricity Generating Board 6–7, 8centrifuges, energy storage 99Clean Development Mechanism (CDM) 183Clear Skies 156climate change 174, 177–8Climate Change Levy (CCL) 143, 153–4coal-fired power generation

centralized power stations 5life cycle costs 175

operating characteristics 18combined cycle gas-fired plants 19combined-heat-and-power (CHP) 11, 32–3,

77–85Community Energy Programme 155domestic CHP 79–83economics 83, 152efficiency 171–3ESCo schemes 162–3EU support 78–9government support 77–8grid connection 81load factor 170, 171metering output 81potential markets 82–3projects 83–5supply management impact 120,

173–4system suppliers 82technology 77, 79–80wood-fuelled 88

Community Energy Programme 155Community Interest Companies (CIC) 164community projects

biomass 90–1ESCo schemes 160–1grants 155, 157wind power 166–8

company formationincorporation 164–5not-for-profit 165

competition 10–11connecting to the grid: see exporting power to

the gridconsolidators 25, 33, 152contracts

CHP operators 33consolidators 138–9ESCo’s 160–1wholesale 22–3, 24

cooperatives 165–6

190 Local energy

costscompared with conventional projects

149–50per MWh for different energy sources

175–6see also economics

DEFRA grant support 155–6demand response 115demand variation: see load variationderegulation 9diesel generators, life cycle costs 175distributed generation (DG)

benefits 10–11definition 128

distribution network operators (DNOs) 9,25–6, 143–4

distribution networksimpact of embedded generation 26,

119–20, 144–5private-wire networks 129–30

domestic CHP 79–83efficiency 171–2grid connection 81load factor 171metering output 81potential markets 82–3supply management impact 120system suppliers 82

domestic heating 32DTI grants 156

economics 149–50combined-heat-and-power (CHP) 83, 152hydoelectric power 53, 54–5

Electricity Council 7electricity demand: see load variationelectricity supply industry

competition 10–11before deregulation 2–3, 6–8deregulation 9

electricity supply system 17–27effect of climate change 174, 177–8supply management 23, 24, 113–15,

117–20embedded generation 25

benefits 136–7distribution system impacts 26, 119–20,

144–5see also exporting power to the grid

emissions trading 180–4Emissions Trading Scheme (ETS) 180–3energy clubs 162energy crops: see biomassenergy efficiency

combined-heat-and-power (CHP) 32energy-efficiency measures 160, 161–2gas-fired electricity generation 81–2ground-source heat 37heat and power 31transmission losses 3–4, 11

Energy Efficiency Commitment(EEC) 155–6

energy mix 95–6energy reserves 175–6Energy-services companies (ESCos) 159–64energy sources

life cycle costs 175–6UK energy use 30

energy storage 95–103EU Emissions Trading Scheme (ETS) 180–5exporting power to the grid

CHP 33, 80–1connection agreement 143–4connection charges 145–7connection standards 141, 143constraining connection 147–8distribution system impacts 26, 119–20,

144–5export value 33, 129, 136–7, 144, 146,

151–2grid connection 46, 80–3hydoelectric power 67steps by step guide 141–3supply management impact 117–20technical guide 144

fault ride-through 116–17finance, grant support 154–7Forestry Commission Wales 90–1forward prices 10frequency, standard 111, 112fuel cells

applications 108development projects 109types 106–7

fuel price sensitivity 175–6fuel reserves 175–6fuels: see energy sourcesfunding, grant support 154–7

Index 191

gas-fired electricity generation 11life cycle costs 175operating characteristics 18–19

gas storage 96–8gas turbines 18–19

operating characteristics 21–2gate closure 22generating companies 9, 10

effect of competition 11wholesale contracts 22–3, 24

generators 12–13government grants 154–7government strategy 121–2, 126–8grants 154–7grid connection: see exporting power to the

gridground-source heat 36–9

heat generation 29–39heat pumps 37, 125hydoelectric power 51–9

assessing hydro sites 53benefits to the water supply system 56economics 53, 54–5energy extraction 56environmental issues 55–6life cycle costs 176load factor 170location factors 5operating characteristics 20pumped storage 96–8short-term reserve market 114–15small scale 53turbine types 52UK’s hydropower potential 53

hydrogen economy 99–102projects 100–2, 109

hydrogen generation 108–9

Icelandic New Energy 102Industrial and Provident Societies (IPSs)

165–6

Joint Implementation (JI) 183

kinetic-energy storage system (KESS) 99Kyoto Protocol 183

licensing 129load factors 169–70

load variation 17–18, 23–4demand response 115effect of climate change 177–8standby power 113–14supply management 23–4

London Borough of Lambeth, PV schemes 74London Borough of Merton policies 124–6London Borough of Tower Hamlets, CHP

project 85Low Carbon Buildings Programme (LCBP)

156–7

maintenance shutdowns 21–2marketing alliances 26, 162market mechanisms 22–5, 152–3Mersey Docks and Harbour Company, wind

cluster 48–9metering 81, 142, 151microCHP 80–3

efficiency 171–2grid connection 81load factor 171potential markets 82–3supply management impact 120system suppliers 82

National Control Centre 6National Grid 3–4, 6, 9, 10

supergrid 7supply management 23, 24, 113–15

Norsk Hydro, hydrogen plant 100–2North of Scotland Hydro-Electric Board 8not-for-profit companies 165nuclear power generation

life cycle costs 176operating characteristics 19–20

Office of Gas and Electricity Markets(Ofgem) 25, 26–7

peak lopping 115Penwith Housing Association 38–9photovoltaic power 69–75

chemical reaction 106hybrid PV / wind-power system 103load factor 170panel types 71street applications 70–3

planning policies 122–4

192 Local energy

planning system 130–3power companies: see distribution network

operators (DNOs); generatingcompanies; retailers

power flows 112–13power stations

centralized 4–7generating characteristics 17–22life cycle costs 175–6load factor 170see also specific types

power units of measurement 14–15preferred-supplier arrangements 162private-wire networks 129–30proton exchange membrane fuel cells

(PEMFC) 106pumped storage 96–8pyrolysis 92–3

quality of supply 113–14

reactive power 112–13regulation 2–3, 27renewable-heat obligation 30–1, 152Renewables Obligation Certificates (ROCs)

67, 142–3, 150–1reserve power 114–15reserves of fuel 175–6retailers 9, 11retail market 22–3, 33, 152–3

Scotlandplanning policies 126power companies 8wave and tidal generation 62–3, 66

shutdown of plant 21, 169Snowdonia National Park, hydropower 58–9social enterprises 164solar power

life cycle costs 176planning consent 125see also photovoltaic power

solar water heating 35–6solid-oxide fuel cells (SOFC) 106–7South of Scotland Electricity Board 8South Somerset District Council, hydro

power 57–8spinning reserve 24, 114standards

connection 141

frequency 111, 112voltage 4

standby power 113–15supergrid 7supply companies: see retailerssupply management 23, 24, 113–15

for distributed generation 117–20supply quality 113–14

Thameswey Energy 163tidal power 61–7

load factor 170location factors 6potential resources 61–2project 66

trading arrangements 23–5, 152–3transformers 13–14transients 115–16transmission losses 3–4, 11transmission networks 6

energy dissipated 3–4seasonal variation in capacity 22see also National Grid

units of power 14–15Utsira, Norway, hydrogen plant 100–2

voltage 111–12standards 4, 111

Waitrose farm, wind and solarpower 46–7

Wales, planning policies 125–6waste heat 30–1watts 14–15wave power 61–7

government support 66–7load factor 170location factors 6marine current turbines 63–4plant scale 62potential resources 61–2projects 62–3, 64–6

weather effects 22, 174, 177–8wholesale contracts 22–3, 24wind power 41–9

assessing wind resource 43community projects 166–8constraining connection 148

Index 193

energy storage 46, 98, 100–3grid connection 46life cycle costs 176load factor 170location factors 5operating characteristics 20–1planning consent 125short-term reserve market 114turbines

design 41–2

installation 43–4regulation 114

rooftop 44–6small scale 42, 45–6

Wood Energy Business Scheme (WEBS) 90wood fuel 34, 35, 87–92

fuel supply 89–90, 91–2projects 31–2, 89–92

23423321 local energy distributed generation of heat and power

Documents

electrical power systems

power system protection

voltage systems

nuclear power

iet power

power system commissioning

power system equipmentr

high voltage engineering