IET POWER AND ENERGY SERIES 55
Distributed generation of heat and power
Other volumes in this series:
Volume 1 Volume 4 Volume 7 Volume 8 Volume 10 Volume 11 Volume 13 Volume 14 Volume 15 Volume 16 Volume 18 Volume 19 Volume 21 Volume 22 Volume 24 Volume 25 Volume 26 Volume 27 Volume 29 Volume 30 Volume 31 Volume 32 Volume 33 Volume 34 Volume 35 Volume 36 Volume 37 Volume 38 Volume 39 Volume 40 Volume 41 Volume 43 Volume 44 Volume 45 Volume 46 Volume 47 Volume 48 Volume 49 Volume 50 Volume 51 Volume 52 Volume 53 Volume 905 Power circuit breaker theory and design C.H. Flurscheim (Editor) Industrial microwave heating A.C. Metaxas and R.J. Meredith Insulators for high voltages J.S.T. Looms Variable frequency AC motor drive systems D. Finney SF6 switchgear H.M. Ryan and G.R. Jones Conduction and induction heating E.J. Davies Statistical techniques for high voltage engineering W. Hauschild and W. Mosch Uninterruptible power supplies J. Platts and J.D. St Aubyn (Editors) Digital protection for power systems A.T. Johns and S.K. Salman Electricity economics and planning T.W. Berrie Vacuum switchgear A. Greenwood Electrical safety: a guide to causes and prevention of hazards J. Maxwell Adams Electricity distribution network design, 2nd edition, E. Lakervi and E.J. Holmes Artiﬁcial intelligence techniques in power systems K. Warwick, A.O. Ekwue and R. Aggarwal (Editors) Power system commissioning and maintenance practice K. Harker Engineers’ handbook of industrial microwave heating R.J. Meredith Small electric motors H. Moczala et al. AC–DC power system analysis J. Arrillaga and B.C. Smith High voltage direct current transmission, 2nd edition J. Arrillaga Flexible AC Transmission Systems (FACTS) Y-H. Song (Editor) Embedded generation N. Jenkins et al. High voltage engineering and testing, 2nd edition H.M. Ryan (Editor) Overvoltage protection of low-voltage systems, revised edition P. Hasse The lightning ﬂash V. Cooray Control techniques drives and controls handbook W. Drury (Editor) Voltage quality in electrical power systems J. Schlabbach et al. Electrical steels for rotating machines P. Beckley The electric car: development and future of battery, hybrid and fuel-cell cars M. Westbrook Power systems electromagnetic transients simulation J. Arrillaga and N. Watson Advances in high voltage engineering M. Haddad and D. Warne Electrical operation of electrostatic precipitators K. Parker Thermal power plant simulation and control D. Flynn Economic evaluation of projects in the electricity supply industry H. Khatib Propulsion systems for hybrid vehicles J. Miller Distribution switchgear S. Stewart Protection of electricity distribution networks, 2nd edition J. Gers and E. Holmes Wood pole overhead lines B. Wareing Electric fuses, 3rd edition A. Wright and G. Newbery Wind power integration: connection and system operational aspects B. Fox et al. Short circuit currents J. Schlabbach Nuclear power J. Wood Condition assessment of high voltage insulation in power system equipment R.E. James and Q. Su Power system protection, 4 volumes
Distributed generation of heat and power
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 Copyright Convention. All rights reserved. Apart from any fair dealing for the purposes of research or private study, or criticism or review, as permitted under the Copyright, Designs and Patents Act, 1988, this publication may be reproduced, stored or transmitted, in any form or by any means, only with the prior permission in writing of the publishers, or in the case of reprographic reproduction in accordance with the terms of licences issued by the Copyright Licensing Agency. Enquiries concerning reproduction outside those terms should be sent to the publishers at the undermentioned address: The Institution of Engineering and Technology Michael Faraday House Six Hills Way, Stevenage Herts, SG1 2AY, United Kingdom www.theiet.org While the author and the publishers believe that the information and guidance given in this work are correct, all parties must rely upon their own skill and judgement when making use of them. Neither the author nor the publishers assume any liability to anyone for any loss or damage caused by any error or omission in the work, whether such error or omission is the result of negligence or any other cause. Any and all such liability is disclaimed. The moral rights of the author to be identiﬁed as author of this work have been asserted by her in accordance with the Copyright, Designs and Patents Act 1988.
British Library Cataloguing in Publication Data A 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, Chennai Printed in the UK by Athenaeum Press Ltd, Gateshead, Tyne & Wear
Developing the UK’s energy infrastructure 1.1 The development of electric power 1.2 Regulating the industry 1.3 Coordinating the supply 1.4 Centralizing power stations 1.5 Managing the expansion 1.6 The Central Electricity Generating Board 1.7 Monopolies and private companies 1.8 Breaking up the monopoly 1.9 The effect of competition Panel 1.1 Generators Panel 1.2 AC/DC Panel 1.3 Transformers Panel 1.4 Power units The electricity system 2.1 Supplying and delivering power 2.2 Generating power for the market 2.3 Power-station characteristics 2.3.1 Coal 2.3.2 Gas 2.3.3 Nuclear 2.3.4 Hydropower 2.3.5 Wind power 2.3.6 Coping with grid variation 2.4 The balancing market 2.5 Distribution network operators 2.6 Regulating the markets The heat connection and cogeneration 3.1 Energy use in the UK 3.2 Support for heat and power 3.3 Energy crops 3.4 Domestic heating 3.5 Combined heat and power
1 1 2 3 4 6 6 7 9 10 12 13 13 14 17 17 17 18 18 18 19 20 20 21 24 25 26 29 30 30 31 32 32
Local energy 3.6 Heat technologies 3.6.1 Biomass 3.6.2 Solar water heating 3.6.3 Ground-source heat Panel 3.1 Ground heat in Cornwall 34 34 35 36 38 41 41 43 43 44 46 46 48 51 52 53 54 55 56 56 57 58 61 61 61 62 62 63 64 65 65 66 66 66 69 69 70 71 71 74 75
Wind power 4.1 Wind-turbine components 4.2 Assessing the wind resource 4.3 Installing a wind turbine 4.4 Rooftop turbines 4.5 Making the connection Panel 4.1 Off-grid turbines Panel 4.2 Wind across the Mersey Hydropower 5.1 Power from water 5.2 The UK’s hydropower potential 5.3 Assessing hydro sites 5.4 Environmental effects 5.5 Adding hydro to the system 5.6 Extracting the energy Panel 5.1 Reviving old mills Panel 5.2 Hydropower in Snowdonia Marine renewables 6.1 Wave and tidal power 6.2 How much energy is there? 6.3 Distributed generation? 6.4 The route from research to industry 6.4.1 Marine Current Turbines 6.4.2 PowerBuoy 6.4.3 Pelamis 6.4.4 Fred Olsen 6.4.5 Limpet and Osprey 6.4.6 Stingray 6.5 Development issues Solar photovoltaics 7.1 Photovoltaic power 7.2 Assembling the PV panels 7.3 Off-grid applications 7.4 Street applications Panel 7.1 Sustainable Lambeth Panel 7.2 Experience in Grimsby
List of contents 8 Combined heat and power 8.1 The UK CHP programme 8.2 EU Directive support 8.3 Domestic CHP 8.4 Developing domestic technologies 8.5 Development issues 8.6 Who would buy? Panel 8.1 Good projects on paper Panel 8.2 London housing Biomass 9.1 Biomass fuels 9.2 Heating programmes 9.3 Wood-energy strategies 9.4 Wood for Wales 9.5 Wood-fuel research 9.6 What is pyrolysis? Energy storage 10.1 Diverse energy in the network 10.2 Pumped storage 10.3 Gas storage 10.4 Batteries 10.5 Centrifuges 10.6 Moving to a hydrogen economy Panel 10.1 Norway’s hydrogen experiment Panel 10.2 Hydrogen in Iceland Panel 10.3 Battery powered Fuel cells 11.1 How fuel cells work 11.2 Fuel-cell configuration 11.3 Solid-oxide fuel cells 11.4 Fuel-cell applications 11.5 Developing the industry Interacting with the electricity grid 12.1 Voltage and frequency 12.2 Voltage 12.3 Frequency 12.4 Reactive power 12.5 Maintaining the supply quality 12.6 Bringing on the reserve 12.7 Demand response 12.8 Dealing with transients
vii 77 77 78 79 80 80 82 83 85 87 87 88 89 90 91 92 95 95 96 98 98 99 99 100 102 103 105 105 106 106 108 109 111 111 111 112 112 113 114 115 115
Local energy 12.9 Transmission/distribution interaction 12.10 Adding microgeneration 117 119 121 121 122 124 125 126 128 129 129 130 135 135 136 137 137 137 138 138 141 141 141 142 142 142 143 143 144 145 146 147 149 150 152 153 154 155 156
Making progress on policy 13.1 Government strategy 13.2 Planning progress 13.3 Domestic changes 13.4 Scotland and Wales approach 13.5 A microgeneration strategy 13.6 Re-examining the remaining barriers 13.7 Licensing 13.8 Distribution and private wires Panel 13.1 How planning works Embedded benefits 14.1 Costs 14.2 Embedded benefits 14.3 New incentives 14.3.1 Innovation funding incentive 14.3.2 Registered power zones 14.4 Small generators 14.5 Consolidation Connecting and exporting power 15.1 Connection standards 15.1.1 Step 1: Decide on your system 15.1.2 Step 2: Get a connection agreement 15.1.3 Step 3: Install suitable metering 15.1.4 Step 4: Install a ROC meter 15.1.5 Step 5: Arrange a tariff with your electricity supplier 15.2 The connection agreement 15.3 Rethinking the network 15.4 Shallowish connection 15.5 New charging regimes 15.6 Constraining connection? Finance and local generation 16.1 Renewables Obligation 16.2 Electricity trading arrangements 16.3 Climate Change Levy 16.4 Grants 16.5 DEFRA support 16.6 DTI grants
List of contents 17 Changing the industry: ESCos and cooperative power ownership 17.1 Energy-services companies 17.2 The 28-day rule 17.3 The affinity deal 17.4 The energy club 17.5 The CHP scheme 17.6 Thameswey 17.7 The legal framework 17.8 Community Interest Companies 17.9 Incorporation 17.10 Not-for-profit 17.11 Full cooperation Panel 17.1 Baywind Panel 17.2 Cooperative wind Output and generation 18.1 Load factors and variability 18.2 Micropower efficiency 18.3 Progress of the field trial 18.4 MicroCHP for homes 18.5 Small-CHP for business 18.6 Replacing generation? 18.7 Saving carbon 18.8 Changing energy patterns Putting a price on carbon 19.1 The EU Emissions Trading Scheme 19.1.1 Results from Phase 1 19.1.2 Setting up the ETS Phase 2 19.2 Trading outside Europe 19.3 Carbon trading for commerce and industry 19.4 Making the case for local energy Panel 19.1 Greenpeace’s wish list
ix 159 159 159 162 162 162 163 163 164 164 165 165 166 167 169 169 170 171 171 172 173 174 174 179 180 181 182 183 184 185 186 187 189
Developing the UK’s energy infrastructure
The development of electric power
Scientists first began to understand fully and make use of electricity generation in the late nineteenth century. Experimenters had been investigating the phenomena of static electricity and magnetism for more than 200 years up to that point and had reported on a variety of interesting results. Their names are commemorated in some of 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, who explored electromagnetic induction during a series of experiments begun in 1831. He found that, if he moved a magnet through a loop of wire, an electric current flowed in 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 a magnetic field, an electric current and movement. Any two of these components together will produce the third, so that moving a conductor in a magnetic field will produce a current, and, equally, passing an electric current through a conductor in a magnetic field will make the conductor move – the principle by which an electric motor works. With these three components electricity can be generated – or an electric motor set up – using very simple apparatus and at small or large scale. As a result, once it was clear that electric current was a useful tool and could be employed in an electric circuit to produce light or heat, first experimenters and then industry quickly began to make use of it and, in its very early days, it was produced domestically, in sheds or cellars. Of course, to generate electricity in a reliable way it was necessary to find a force to move the conductor within the magnetic field. One way would be to attach the conductor 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 used for centuries to move grindstones for milling flour. In fact, there are mills still in existence with nineteenth-century electricity-generation apparatus. Using a mill was particularly valuable because many had millponds in place, allowing water to be conserved so that it was available at times when the river would otherwise have too little water to allow the water-wheel to operate. Dams, ponds and adjustable gates or sluices, used to direct the water and provide a reliable supply for grindstones, could be equally effective at ensuring electricity generation was reliable. Alternative motive
forces for electricity generators could include wind (‘harvested’ by windmills). But for industry, which wanted a 100 per cent reliable source if it was to use electric power, the most attractive motive force to use to generate electricity was steam. The steam engine had been invented and developed by Thomas Newcomen and James Watt, and was already used by many industries. Almost any kind of fuel, but mainly coal or wood, could be used to boil water and produce steam under high pressure, which was originally, in Newcomen’s and Watt’s engines, used to drive pistons. But in 1884 Charles Parsons proposed a steam turbine in which vanes rather like those of a windmill (the turbine blades) are connected to a central shaft. The steam turns the blades as it expands through them, turning the centre shaft. This arrangement can be very efficient, because additional sets of turbine blades can be added, with each set sized according to how far the steam has expanded. The entire steam turbine is in a cylindrical casing. The steam turbine was far more useful for the fledgling electric-power industry than the earlier steam engines because the result is a rotating shaft ideal for using in a stationary magnet to produce an electric current. In fact, Parsons’s first model was connected to a dynamo that generated 7.5 kW of electricity. That first turbine was soon scaled up, and within Parsons’s lifetime turbines were built with generating capacity thousands of times bigger. Steam turbines are still by 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 nuclear stations, where the steam is produced using the heat from nuclear fission. In some cases they are used in conjunction with a gas turbine – known as a combined-cycle plant, or in configurations where waste steam is captured at some point in the process and used for direct heat in a so-called combined-heat-and-power plant. The names of Parsons and his US competitor George Westinghouse are still to be seen in the companies active in the power industry. The relative simplicity of the electricity-generation process and the use of the steam turbine meant they were quickly employed in both industrial and domestic applications. Most were dedicated for use by a single industrial concern, or domestically were used for a few customers of a single site. Initially there was no consistency between the different generators: each operated at its chosen current and voltage. Measured in amps, current describes the amount of electric charge moving in the electric circuit, while the voltage (measured in volts) describes how much energy each unit of charge has – similar to the difference between the number of cars travelling along a road (current) and the speed at which each is travelling (voltage).
Regulating the industry
Generation began to come under legislative regulation in the 1880s and 1900s. The first Electricity Act in 1882 allowed the setting up of supply systems by persons, companies or local authorities, and amendments in 1888 made such new enterprises easier to set up. A further Act in 1909 regulated planning consent for new power stations, but by 1914 there were hundreds of independent undertakings, private and
Developing the UK’s energy infrastructure
public, in operation. They sold electricity for power and for lighting, meeting demand of 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 production of munitions and machinery. At this stage there were few connections between local undertakings, and many technical differences. Although there were 600 or so generators, they were unable to be fully effective because they were not interconnected. Generators that for one reason or another had to stop producing power were unable to make up the shortfall by importing power from other suppliers, and at the same time companies who were producing more than required by their customers could not export the power. The lack of connecting wires was not the only problem: the different companies still provided their power to different specifications and used different technical standards. London alone had 50 electricity supply systems, 24 different voltages and 10 different frequencies. Power stations remained unlinked, however, and it was not until 1919 that legislation was passed aimed, among other things, at correcting this. A government committee set up by the Board of Trade and chaired by Sir Archibald Williamson had recommended that the electricity supply companies be nationalized. The government rejected this proposal, but went ahead with other proposals to set up an Electricity Commission under the Ministry of Transport and a series of regional Joint Electricity Boards. The Commissioners regulated the industry but the joint boards, which were intended to coordinate development, were ineffective. By 1926 total sales of electricity were 5.8 TWh, generated by 478 power stations with a total capacity of 4 422 MW. Local authorities owned 264 stations and companies owned 215, the biggest of which had more than 100 MW of plant installed. Some generators were producing alternating current, while others produced direct current.
Coordinating the supply
In 1926 the new Electricity Act not only provided for existing undertakings to maintain control of distribution, but also provided for the coordination of new power-station planning and the control of power stations. It established a public body, the Central Electricity Board, which had a remit to standardize electricity supply across the country. 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 steadily being replaced by larger, more efficient power stations that served hundreds or thousands of users. This allowed for economies of scale, but transmitting electricity along electric wires can mean that much of the energy is dissipated – depending on the type of wire, energy can be lost as heat, for example; this is the principle by which the traditional incandescent light operates. However, the rate at which energy is dissipated varies depending on the voltage and current measured in the wire. A high current, when lots of charge is moving in the wire, has a much greater heating effect than a high voltage. The total energy is a product of the voltage and the current. Another result of this relationship is that, if
the energy remains the same, a higher voltage must result in a lower current, and vice versa. At lower current, less energy is dissipated and there is potential to transport much more power. Power designers took advantage of this relationship in designing electricity transport networks, along with another well-known property of electricity: the fact that a changing electric current passing through a coil of wire that generates a magnetic field could 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 the voltage 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 transformer could be used to reduce the voltage and increase the current to the levels used to power appliances. The result was the complex ‘grid’ that began to take shape after the 1926 report and has been expanding ever since. Now there is a national grid with some long-distance lines operating at 440 000 V (440 kV) and others at 275 000 V (275 kV) that is used to transfer ‘bulk’ supplies from major power plants to the major load centres, and a network 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-down transformers are used to reduce the voltage to a level suitable for domestic users. Domestic power supply was standardized at 240 V for many years, although recently the UK voltage has been standardized at 230 V to be consistent with the rest of the European power network. Large industrial energy users may take power from the network at higher voltage levels depending on their requirements.
Centralizing power stations
Why was it necessary to develop the high-voltage grid? Even back in 1926 it was clear that, as the electricity industry was developing, the need to transmit power longer distances was growing. This was not just to allow power to be transferred between neighbouring companies among the 400 or so selling electricity: it also enabled the network as a whole to take advantage of economies of scale. Steam turbines could be made to work more efficiently as the size of the boiler and turbine increased, so the cost of a unit of electricity produced decreased. At the same time, economies of scale 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 from the areas where electricity was used (the ‘load’ centres). For steam turbines, one reason for the shift was the need to transport huge amounts of fuel to the big new stations. 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 financial and environmental costs in transporting coal from the mine to the power station. If the power station owner is willing to link the plant closely to a single mine, it is much more efficient to build so-called ‘mine mouth’ power stations to minimize the distance that
Developing the UK’s energy infrastructure
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 the coal, which can vary considerably from deposit to deposit. China has come up against this issue recently, during its rapid growth in the last two decades and resulting need to supply power to its burgeoning industries. While most of the country’s coal deposits are in the north and west of the country, the major load centres were, and still are, the fast-growing industrial centres and cities of the southwest. Instead of choking the country’s train system by transporting millions of tonnes of coal each day, the country announced a ‘coal-by-wire’ policy to site power generation closer to the mines and build high-voltage transmission lines instead. The recognition that power stations can cause local environmental degradation and emit pollutants that affect its immediate surroundings has also tended to aid the shift towards using sites far away from centres of population and hence areas where the power load is highest. While for coal-fired power stations choice of site is a balance between transporting power and transporting fuel, other types of power-generating plant may have less 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 water to be diverted or stored. What is more, the amount of electricity that can be generated depends on the amount of energy available from the moving water, which usually requires either a significant drop, or a large volume of water moving through the turbines. Mountainous terrain is where suitable hydropower sites are most often found, which are seldom the areas where major load centres are found. That can lead to significant power-management requirements in countries that are heavily reliant on water power. Norway, for example, which meets upwards of 90 per cent of its electricity needs from hydropower plants, has to transport most of its electricity from the north of the country to the major cities in the south. The UK is a windy country, and average wind speeds are favourable for building wind farms in many areas of the country. But good winds ‘on average’ are not necessarily good enough for a wind farm to make economic sense. Instead, powergenerating companies have to search out the sites that offer the best possible wind speeds 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 fewer people live and where farming or other low-density activities are more common than industry, so the electricity system in these areas tends to be on a relatively small scale and low in capacity – built to serve a few small users. The Western Isles of Scotland and the island of Lewis are a good example. These areas have among the UK’s best wind resources but have in the past been home to farming and fishing communities. It is thought that Lewis alone could host several hundred wind turbines providing electricity equivalent to a couple of the UK’s largest power stations. But transmitting the electricity to places where it will be used in England requires some new high-capacity transmission lines to be built – ‘wind by wire’.
New types of water power will also have the problem of location, to a varying extent. Some devices rely on a so-called ‘tidal race’, which is typically a channel between two areas of sea where the effect of the tide is very pronounced, so that the water moves much faster through the channel. These are of course entirely restricted on their location. However, some other tidal devices will have much broader application and could be used to abstract some energy from less dramatic tides along the coast and in river estuaries. Wave-powered devices will also be less constrained. For these power sources it will be a matter of finding the best possible sites and costing the transport of power back to shore; the chosen sites will be an economic balance between the two.
Managing the expansion
Building ever-larger and more complex networks to subdivide and deliver the electricity output to users did carry significant cost, and still does. What is more, it requires transmission lines to be installed across both public and private property. Building new lines is always contentious. But the overall effect of the increasing scale of electricity generation and interconnected systems steadily reduced the cost of electric light and motive power. The National Grid was developed rapidly after the 1926 recommendations. By 1933 some 4 000 miles of transmission lines had been completed and by 1935 the grid was regarded as complete. Rated at 110 kV, it was much smaller and operated at a lower voltage than the grid in operation today. But it signalled a radical shift in managing the electricity supply. The fact of the grid’s existence meant that all electricity generators and electricity users were connected. For it to work successfully, power generators had to supply (‘export’) power to the network within strictly controlled current and voltage limits. What is more, the power stations could no longer operate entirely independently. Part of the intention of the grid was to allow electricity to be moved around the network to meet users’ needs and to provide backup, for example for power stations 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 diverted to other parts of the network as required, and, what was more, they had to be willing to accept a measure of control from the grid. In 1939 this was formalized when the grid became a nationally integrated network with a National Control Centre under the CEB’s direction. The savings arising from the grid were large and demand grew rapidly. In 1914 electricity sales per head of population had been 77 kWh. By 1939 it was 486 kWh. At that time the installed capacity of power stations was 9 712 MW, most new generators being 30 or 50 MW capacity.
The Central Electricity Generating Board
In April 1948 the entire industry in Great Britain (except the North of Scotland HydroElectric Board, already a public board) was nationalized when the assets of 200
Developing the UK’s energy infrastructure
companies, 369 local authority undertakings and the Central Electricity Generating Board (CEGB) were brought together under the British Electricity Authority (BEA) – which was known as the Central Electricity Authority (CEA) after 1954 – and 14 area distribution boards. At this time work started on building the 275 kV high-voltage grid (known as the supergrid) that operates today. The area distribution boards accepted bulk supply from the supergrid and stepped it down to provide power to domestic properties. The power stations and transmission network were run by a central authority within the BEA. In January 1958, following examination of the industry by the Herbert Committee and legislation, the CEA was replaced by an Electricity Council, whose function was to act as a central policy-making body for the whole of England and Wales; and a Central Electricity Generating Board, which was to be responsible for generation and main transmission in England and Wales, owning such assets as the power stations and the grid. The CEGB inherited 262 power stations with a capacity of 24.34 GW, and annual sales 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 programme of power-station and transmission-line construction. By 1971 the CEGB owned 187 power 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 largest coal-fired and nuclear stations came on line. Within each power station there may be several ‘generating sets’ or units, each producing several hundred megawatts of power. The largest power station of all was Drax, a coal-fired station in the north-east with a total rating of 2 000 MW from its six units, but there were several sites pumping over 1 000 MW into the grid. In the 1970s the increasing demand and the larger power stations 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.
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 was both a cause and effect of the industry’s development. Economies of scale meant that building large power stations was more cost-efficient for the electricity generator. But bigger power stations meant more customers were required, with ever-greater costs for installing and maintaining an extensive fixed network of wires. The industry was capital-intensive: building the generating stations and the network was relatively expensive, while producing and delivering the product once the infrastructure was in place were relatively cheap. A power-generating company had
to be able to rely on customers over terms of many years to make a return on the capital invested – and, in any case, electricity supply was quickly seen as a ‘public good’, and a requirement almost as basic as a water supply. The result was that it was assumed that power companies should be awarded monopoly supply rights within their 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 other monopoly suppliers in Scotland: the South of Scotland Electricity Board and the North of Scotland Hydro-Electric Board. Within these power monopolies were generating stations, a high-voltage transmission network and local ‘area boards’ that operated the low-voltage network and supplied power to domestic customers. This industry structure was largely replicated worldwide. Local or national monopolies generated and supplied electricity within a defined area and many were owned by the national or local government corresponding to their service area. Since they were monopolies, their investments and customer pricing were overseen by the government. In some cases – notably in the USA – power companies were privately owned, but their ability to decide investment and set customer prices was limited by independent Public Utility Boards, who scrutinized utilities’ work and investment programmes and agreed what prices were allowable. The monopoly structure helped determine the industry’s development. It worked extremely well and customers – especially domestic customers – could assume that a reliable and unlimited supply of electricity was available at all times. Once a reliable supply of electricity could be assumed to exist in every house, appliances could be developed to make use of it. From fridges and irons, to PlayStations and home cinemas, there was no restriction on domestic electricity use. Demand could grow ever higher, while suppliers with large service areas tended to invest in everlarger power-generating stations, to meet their customer needs, and build them at the most economic site, generally near the fuel source and away from population centres. A similar development had been under way in the supply of gas. A network of pipes had been installed, supplied at first by local ‘gas works’ and later direct from North Sea and other reserves. As with the electricity network, a state-owned monopoly – British Gas – was set up to procure gas and supply it to domestic and industrial customers. The UK’s gas network is still less extensive than the electricity network, thanks partly to the high cost of burying pipes to serve small groups of isolated customers, but also partly because once an electricity supply is in place it can provide the heat that the gas would supply, both for space heating and for cooking, while also powering all kinds of other appliances. With an electricity supply in 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 electricity decentralization. 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.
Developing the UK’s energy infrastructure
Breaking up the monopoly
As well as privatizing the CEGB, the Conservative government under Prime Minister Margaret Thatcher also wanted to shake up its monopoly supply function, on the grounds that competition would be more efficient, would lower prices and encourage innovation. Clearly, there would be limited areas where competition was possible: building new wires alongside those already existing and inviting customers to switch between them was no efficiency improvement. Nor could the government achieve its aims by simply splitting the CEGB geographically: that would result in a patchwork of monopoly suppliers instead of just one. Instead, the government split the industry by function. Electricity generation and supply to customers were two areas where competition could be introduced. Operating the high- and low-voltage networks constituted monopoly activities and would remain so. The result was a split into generation, transmission, distribution and supply that has been widely copied among other countries that have also been changing the operating model of their power industries. This model conceives the industry not as unique, but as very similar to other industries where manufacturers sell their products wholesale to retailers who supply individual customers. In this model, products are transferred 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 generating companies build and operate electricity-generating plants to manufacture electricity. They sell their electricity in bulk to supply companies with thousands or millions of small customers (or sometimes direct to very large users such as heavy industry). The supply companies, or electricity retailers, are the industry face that domestic users see, and customers can switch between them without needing to make physical changes to their supply. The electricity networks play the role of, say, the road network. Bulk power is transmitted 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 network. These local, low-voltage networks are owned and operated by so-called distribution network operators (DNOs), which step down the power still further and distribute it to individual premises and houses. The National Grid and the DNOs are monopolies, whose income is from ‘tolls’ paid by the generating and supply companies and who supply various other services to keep the network running. The result is that what were parts of the same industry now have very different functions and operate in very different ways. The companies that retail electricity are more like other major consumer companies such as banks, focused on providing services for thousands or millions of customers. Among their major functions as companies are managing their customer information, billing and collecting payment. In the 1990s this reinvention as ‘home service’ companies led them to expand into other services, such as providing vehicle-breakdown cover or financial services. At that time the strategy was not very successful, except in closely related industries so
that most energy retailers supplied both gas and electricity. Now, however, the model has been revived, as other consumer companies such as supermarkets have begun to offer electricity supply deals. The transmission and distribution companies remain superficially similar as businesses. They maintain, and where appropriate expand, a fixed network and are paid via tolling fees that are governed by an independent regulator, the Office of Gas and Electricity Markets (Ofgem). The transmission operator National Grid has additional roles in balancing supply and demand and managing an active network, whereas the local networks are passive, as we will see (Chapter 5). Both are seen as relatively stable industries with low risk and relatively low returns on investment. The generation companies have operations that are still rather similar to those of the corresponding section of the CEGB, but the market in which they operate is very different. Building generating plants under a monopoly supplier was a low-risk activity, centrally planned and with assured customers for the life of the plant. Now generators compete on price to sell their supplies to retailers, and their investment is driven by a market that may provide very little information about trading conditions over the life of any new plant built. So-called ‘forward prices’ give some indication of whether the electricity price is likely to rise (responding to a shortage of power stations) or fall (in response to overcapacity). But this indication extends only a few years ahead, whereas power stations are immense capital investments that require customers over two to four decades to provide their owners with a return on investment. Since a number of companies are making investment decisions in response to similar market conditions, the industry tends to swing from boom to bust and back again. The UK generating market was described as ‘bust’ by one generating company in 2002, for example, but by the winter of 2005–6 generating capacity was very near demand, leaving little margin for emergencies, and prices had risen to record levels. Although companies are required to keep activities in the different parts of the industry separate, many large utility companies now have interests in both retail and generating sectors. A stake in the generating sector ensures that companies will have sufficient electricity to meet their customers’ needs even in times of shortage, and the peaks and troughs of retail and generating businesses will be different, giving companies more surety over their long-term return.
The effect of competition
The industry privatization was successfully completed in the early 1990s, and competition did, as planned, take effect in the generating and retailing of electricity. What it did not do was open the industry to different forms of generation and models of electricity supply – in fact, the reverse happened. With a customer base of millions and guaranteed income in perpetuity, the CEGB had an enormous research budget and could – in theory – invest in new forms of generation that might not provide an economic return for many years. One continuing complaint against the company,
Developing the UK’s energy infrastructure
however, was that public-sector inertia and an institutional belief in the existing model of ever-larger central power stations combined to stifle innovation. But when the private electricity generators took over, the basis on which they could compete for customers among the retail companies was mainly the price of the electricity they supplied. This drove down electricity prices for the whole of the late 1990s and the early years after 2000, partly because efficiency improvements meant there were savings to be made, but also because oversupply drove prices down further. Investment decisions were driven not by the possibility of changing the power system but by the need to build any new power-generating capacity as fast as possible, and at as low a capital cost as possible, so it could start earning income for the company immediately. The result was a so-called ‘dash for gas’ during the 1990s. Gas-fired electricity generation was very well understood, but had never been favoured – in fact was under a moratorium – under the CEGB, which considered that gas was far too expensive and useful in direct supply to be converted to electricity. But for private electricity generators gas was ideal. The gas-turbine stations could be built extremely quickly – within 18 months, once planning permission 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. What was more, gas was a ‘clean’ fuel: it did not produce the emissions associated with coal-fired plants, including sulphur dioxide and particulates, that were the subject of increasingly stringent regulations, requiring ‘cleanup’ technologies to be fitted to the plant and both incurring new capital costs and reducing the plant efficiency. It was true that running costs of gas plant could be high, and it was very vulnerable to high gas prices, but the plants could be started up and switched off fairly quickly, so it was possible to stop operating them at times of oversupply when electricity prices were 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 or understanding of how or where their electricity was generated. The retailers were unlikely to find much take-up for different supplies, and this was borne out by the experience of so-called ‘green’ tariffs, which offered customers access to electricity produced from renewable sources – but at a higher price. The proportion of customers taking up the option was vanishingly small. Elsewhere, an alternative model for electricity generation was being explored that went right back to the UK’s early electricity industry. Countries where there was no electricity infrastructure already existing were developing one that looked rather like the UK’s early industry, with local electricity generation for local use, and gradual linkages forming between local areas to exchange supply and supply backup where necessary. This ‘distributed’ model was somewhat different from the early days in the UK. First, with standards in place across the developed world, electricity systems tended to be able to link. Second, new forms of electricity generation were being developed, and old ones updated, that could be employed at very small scale and without the drawbacks of previous technologies. Solar photovoltaic panels and battery storage, for example, offered clean generation and minimal running costs, compared with using a diesel generator.
There was a second benefit to generating and using electricity locally: transmission, at high or low voltage, necessarily involves significant energy loss through the wires. Using the electricity at or near the generation point could balance out the economies 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 dissipated via a cooling tower or other ‘heat sink’ could be used. It was available for industrial processes, if some were or could be sited near the power plant, or it could be used to supply heat to local buildings. This type of combined-heat-and-power (CHP) plant was overall much more efficient. Neither the UK’s privatized system nor its power market supported this type of local generation. By 2000 it was clear that government intervention would be needed to change the market structure to force it to invest not only in new types of generation such as renewables, but also to shift the balance in the UK away from a centralized system so that electricity could be generated at whatever scale and site it was most efficient. That would mean that, as well as central power stations, there would be electricity fed into the system from a huge variety of local projects ‘embedded’ into the lower-voltage parts of the network. It could make the network more efficient, more reliable and cheaper to operate – but it would clearly require government intervention and financial incentives to make the shift.
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 materials, so they are known as electrical conductors. They conduct electricity. The moving electrons transmit electrical energy from one point to another. Electricity needs a conductor in order to move. There also has to be something to 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 rotated between the poles of a magnet. Because the coil is rotating, it produces an electric current that varies regularly, known as an alternating current. As the coil makes one revolution, one cycle is produced, so that the frequency of the current equals the number of revolutions per second made by the coil. In practice the coils are wound in a soft iron cylinder known as an armature. In a power station the armature containing the coils remains stationary and is known as the stator, and instead the magnetic field is rotated around it and is referred to as the rotor. A turbine turned by steam pressure, falling water, wind, etc. is used to provide the rotation, which in large power stations can be at 50 turns per second, the same as the grid supply (‘synchronized’). In an AC generator the current is supplied to the external circuit by two so-called ‘brushes’, spring-loaded graphite blocks that press against two copper ‘slip rings’, which rotate with the axle.
Developing the UK’s energy infrastructure In power stations the stator coils are in three sets and the rotor coils are in three sets at 120 degrees to each other. This effectively produces three varying supplies that when superimposed provide a steadier power supply, which is known as a three-phase supply.
Current describes the drift of electrons (and in some cases other charged particles) under the influence of an electric field. For many of the electrical effects we require, such as the heat and light produced by the current in a wire, the direction of movement of the electrons is not important. The drift can be in one direction, which is known as direct current (DC), and is produced, for example, by a battery in a circuit. However, electricity is more usually generated and 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 DC would involve an extra step. • Transformers must have alternating current to operate, and the powerdistribution grid depends on transformers. • It is easy to convert AC to DC but expensive to convert DC to AC, so, if you were going to pick one or the other, AC would be the better choice.
A transformer changes an alternating voltage from one value to another using the mutual-inductance principle. It can be used to increase (step up) or decrease (step down) the voltage and current. Electricity substations generally house transformers that are stepping down the supply for domestic or commercial use. In a transformer two coils called the primary and secondary windings are wound around an iron core. When an alternating current passes through one coil, known as the primary, it results in a fluctuating magnetic field, which induces an alternating current in the other, secondary, coil. The amount of voltage induced in the secondary coil depends on the number of turns in the two coils. If they have equal numbers of turns, the voltage induced in the secondary coil is equal to that in the first. If the number of turns in the secondary coil is twice that in the primary, then the voltage induced will be Continues
‘stepped up’ and will be double that in the primary coil. If the number of turns in the secondary coil is half that in the primary coil the voltage induced in the secondary coil will be ‘stepped down’ to half that of the primary coil.
How much work can you get done in a second? If you are a car, how far can you 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 in each second. Now we refer to it in watts (shortened to W), although it may have been easier to understand when it was referred to as horsepower. For electricity, the power available depends on two characteristics: the ‘current’ through the wires, which measures how much electricity is flowing; and the ‘voltage’, which measures how much ‘push’ it has. Compare it to the traffic on its way around the M25: the current is more or less the number of cars passing at a single instant and the voltage is more or less their speed. To get an idea of the amount of power available, you need to know both. Similarly, you can calculate 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. To get 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 varies hugely. The large power stations that dot British coalfields are each sending several hundred million watts into the grid. Local renewable-energy projects are often sized at a few thousand watts, while new wind turbines are up to a million watts. Another way of looking at power is not how much is being used at any one second, but how it adds up over time. This is also the ‘unit’ on your electricity bill – kWh, where k is just shorthand for 1 000. It’s a measure of the total electricity you have used – and how much you are paying, so it’s something to remember when you want to save energy. A low-energy light bulb doesn’t seem to draw much less power than an old-fashioned one. But multiply that by the number 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)
Developing the UK’s energy infrastructure In scientific text there is a standard shorthand, accompanied by a standard symbol, so that engineers and researchers from Moscow to Manchester can be quite confident that they are talking about the same size. p n µ m 0 k M G T pico nano micro milli kilo mega giga tera trillionth billionth millionth thousandth thousand million billion trillion
Once you start to pick it apart, it becomes fairly easy to work out that 1 kg is 1 000 grams, 1 MW is 1 000 000 watts, and so on. And although tera may seem like a lot, the UK uses several hundred terawatt hours of electricity every 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 nontechnical speak to any extent.
The electricity system
Supplying and delivering power
The UK’s electricity supply system works in much the same way as the supply of any other commodity. Electricity is ‘manufactured’ at power stations, and bulk supplies are transported across the high-voltage transmission network. Retailers (‘suppliers’) buy the bulk power and sell it on to domestic and commercial customers, to whom it is supplied via a low-voltage local network operated by a distribution network operator (DNO). The generators, high-voltage network operator (National Grid), DNOs and retailers are very different companies.
Generating power for the market
The generators and retailers operate in a competitive market, making contracts directly with one another to buy and sell power. The amount of electricity that is required can vary markedly. Generally the highest demand is in the winter, when people tend to be inside and it is dark for longer, so they are using more appliances. Although there are heavy industries that require large amounts of power continuously, it is usually domestic use that governs the peak load. So the highest peak is on winter evenings between 6 p.m. and 9 p.m., when most people are arriving home, making dinner and using 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 summers and 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. In the 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 of action for weeks or months. In July 2006, electricity demand increased dramatically in response to a weekslong heat wave, as homes and businesses turned up existing air conditioning and stripped DIY stores of new air-conditioning units and electric fans. With available capacity at its summer low, the National Grid had to warn that the system was dangerously close to its limit and appeal for demand reductions. In the long term, this may require generating companies to alter their traditional maintenance strategies.
While the electricity being used varies dramatically, from up to 60 GW on a winter’s evening to around 30 GW at low-demand periods, the amount of electricity being supplied to the system is also changing.
Different types of power station have different characteristics. This diversity is generally regarded as a benefit, as it helps the system to meet the varying demand. It is also an economic benefit, as it means the system as a whole does not rely on a single fuel 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 or steam turbine.
Coal was for many years the most common thermal fuel and still provides up to a third of the UK’s power generation and around half of all the electricity generated worldwide. It is attractive to power companies for several reasons. First, it is a relatively flexible form of generation, meaning that most plants can operate at less than their full capacity if required (at ‘part load’), and the amount of fuel burned and the 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 bought from a wide variety of suppliers and transported by ship and rail. What is more, the coal can be stockpiled so there is a reserve in case of need. Coal, however, produces the most carbon dioxide emissions of all generating types, along with other harmful emissions such as sulphur dioxide, nitrogen oxides, mercury and particulates. New coal plants will include additional systems to reduce most of those emissions, and similar cleanup systems have been ‘backfitted’ to existing stations. However, they do affect the economics of running the plant, as they reduce operating efficiency, meaning that more coal has to be burned to produce each unit of electricity.
The UK generators began building gas-fired turbines in the 1990s, and gas now meets nearly half of UK electricity demand. Gas and compressed air are combusted directly into a turbine, which works on the same principle as a steam turbine, connected directly 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 shut down, if necessary, over a period of several hours to less than an hour, so they can be brought on line to meet peak loads, and in fact some are used specifically to meet peak loads, being started up and shut down twice each day. They have been less flexible than coal plants once in operation, although more recent versions are being designed
The electricity system
to operate more economically at part-load, but they can be sized at between one and several hundred megawatts, so they can allow mid-scale additions or removals of capacity from the system. They require constant fuel feed-in during operation. In recent years so-called ‘combined cycle’ gas-fired plants have been used. These plants make use of the ‘waste’ heat from a gas turbine. Although it is referred to as waste, because the conventional gas turbine burns gas at such a high temperature (the turbine inlet temperature is around 1 000 ◦ C), the gas being expelled is hot enough to produce steam that, in its turn, can be used in a steam turbine. This dramatically increases the power available from the plant. There is some loss of flexibility in operation as there are more processes to manage, so combined cycle plants are generally used in constant operation (known as base load). In recent years other fuels have been used to produce thermal power, including biomass (e.g. wood and straw), or methane gas produced from sewage or abstracted from landfill.
Nuclear stations vary in size but some are among the largest power stations on the grid – Sizewell B, the largest, is rated at 1 400 MW – so they provide an enormous input of power. What is more, they can provide that power over a long period, as fuel loading is infrequent. They can operate for one or two years between shutdowns, depending on the operating regime, and at very predictable cost as the fuel is a relatively minor part of their operating cost. But they are extremely inflexible in operation. Although it is possible in some cases to vary their output slightly, it is technically and economically undesirable. It is a favourable option in countries where there are energy-intensive industries with continuous high demand, such as Sweden and Finland, or where there are neighbouring markets where oversupply can be exported, as happens with France’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 take several 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 stability to the operation. In theory, electricity flows through the grid at a steady frequency of 50 Hz and maintains a constant voltage. In practice, these parameters are maintained thanks to painstaking management and balancing actions, and by ensuring that, as far as possible, all the generators and loads connected to the system tend to return to that steady state after any disturbance. In practice, the flow of electricity is frequently changed, not just by new loads or generators connecting to or disconnecting from the grid but also by any number of disturbances on various scales. The result can be sudden changes in frequency or voltage and they can affect large power equipment as much as domestic-scale appliances such as PCs (computer shops sell sockets with built-in protection against such ‘spikes’ and disturbances in the supply). This issue of ‘power quality’ is discussed in Chapter 8. Power plants are often set up to detach automatically from the grid if there are large disturbances in the grid supply, as a self-protection measure. Disconnection, in
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 certain amount of momentum that will carry them through grid disturbances (this is known as fault ride-through) and this adds stability to the grid as a whole.
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 matter of opening the gates within the plant, so water passes through the turbines, and generation is available within seconds to minutes. This is the attribute employed by pumped-storage plants: water is pumped uphill to a reservoir at times when there is excess 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 low and 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 to decide whether to use their stored water to generate now, or save it for a later date when it may be needed more. This is a mainly financial decision in a mixed system such as the UK’s, but far more important 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 force up the price of electricity.
Wind power now provides a small proportion of the UK’s power. Since it is available only when the wind is blowing, it is impossible to guarantee that power is available when it is most needed (at peak times, for example). The power has to be accepted on to the grid whenever the wind blows, and other forms of generation have to be cycled up or down to adapt. In the UK this is easily accepted on to the grid, as wind penetration is very low and wind forecasting is very good, not least because in the current market decisions on how much power is available and required are calculated within an hour of 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 is in operation and expected to be so for the next hour, it can provide an extremely fast response to changes in demand on the grid over the short term. In that case the wind farm would be gradually ‘turned down’ in advance of an expected peak by altering the pitch of the blades so less wind is ‘caught’, and then turned up quickly by returning the blades to maximum pitch, then kept there as slower-response forms of generation such as coal stations are brought up to power. However, predicting whether the wind farm will operate over days, weeks or months is progressively less reliable. Recent work has confirmed that there is almost never a situation when there is no wind blowing anywhere in the UK, but there are frequent periods when smaller regions have no wind. As a result, there is a limit
The electricity system
to how much conventional generation they can replace on the system and, although estimates vary depending on other grid characteristics, its value may begin to decrease above 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 of operating the UK system, the technical effect of the variability is insignificant up to at least 10 per cent wind penetration, as the variability is barely detectable within the natural variability of the mixed system as a whole. Grid stability may also be affected at high wind penetration because wind is generally designed to disconnect in the event of a fault, although the ‘fault ride-through’ of conventional generation can now be replicated using electronic systems.
Coping with grid variation
The UK’s power system is well placed to cope with all these different sources, and indeed their diversity gives system operators a useful set of different options to meet the system’s varying needs. Power plants do not operate continuously. As we have seen, some are designed to operate only during peak periods and are expected to shut down twice a day. There are other types of planned closure: they have to be shut down at regular intervals to allow maintenance work to be carried out, for example. Maintenance shutdowns vary in frequency and length depending on the type of plant involved, but can vary from a few 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, which also means that the total amount of electricity available to the system at such times is much lower. This can mean demand surges are difficult to meet, even though the surge is still much lower than the winter peak: this was the case in summer 2006, when demand for air conditioning during July’s hot weather meant the system operator had to send out an emergency call for more power. As well as planned outages, plants can suffer unplanned shutdowns for a number of reasons. They may be shut down as a self-protection measure if there are disturbances on the grid that could affect the power station. Alternatively, problems inside the power 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 operating characteristics depending on local conditions. Wind is the most obviously affected: it does not generate if the wind does not blow. But it is not the only plant where weather has an important role to play. Gas turbines, for example, are greatly affected by the external temperature. They work by burning natural gas or a fuel oil with a fixed volumetric rate of compressed air, so a turbine’s power output is directly proportional to the mass rate of the compressed air that enters the system. When the weather gets hotter, the mass rate of the compressed air decreases because warmer air has a lower density, so the turbine’s power output decreases. The effect is marked when the surrounding air temperature is above 30 ◦ C. If surrounding temperatures are above 40 ◦ C – unlikely in the UK but common in other countries – power supplied can drop by 35 per cent.
This characteristic of combustion turbines is very unattractive for the power producers because they have less power to sell, just when the increase in outside temperature creates more power demand for air conditioning and the market price of power is also high. The weather may also have indirect effects. Power stations that abstract water from neighbouring water sources such as rivers to provide cooling are strictly limited in the heat they can release to the river. In hot weather and especially at times of low river flow, when the river’s ambient temperature is high, it may not be possible to add any heat at all without breaching the upper permissible limit. In 2004 and 2007 several of France’s large power stations were unable to operate for this reason. Similar temperature-dependent effects are felt throughout the system. In just two examples, the capacity of the transmission line alters depending on the temperature because the high-tension cables expand and sag more at higher temperatures – a 400 kV line currently has a capacity of 2 190 MVA in summer and 2 720 MVA in winter. Faults on the grid can also interrupt supply. Extreme weather events also place stresses 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, lightning and salt pollution as likely to contribute to weather-related faults. Managing these faults requires investment in the high-voltage transmission system. Lightning strikes are relatively frequent, and their effect can be partly designed out by using autoreclosers, which can trip and then reclose either automatically or on instructions from the control room. Some protection is built in. For example, the west coast is subject to salt pollution from high winds. Protection takes the form of a spray that is released when the salt burden gets too big. Electricity is bought and sold in the UK through a system known as the British Electricity Trading and Transmission Arrangements (BETTA). As National Grid explains, the arrangements are based on bilateral trading among generators, suppliers, traders and customers, in any paired combination, across a series of markets operating on a rolling half-hourly basis, which means that it is managed in half-hourly time slots. Electricity can be bought and sold up to an hour before the start of the half-hour in question – known as gate closure. There are three stages to the wholesale market. The bilateral-contract markets for firm delivery of electricity allow contracts to be signed from a long time – a year or more – in advance of dispatch (i.e. the actual point in time at which electricity is generated and consumed) to as close as 24 hours ahead of real time. The markets provide the opportunity for a seller (generator) and buyer (supplier) to enter into contracts to deliver or take delivery of, on a specified date, a given quantity of electricity at an agreed price. This includes long-term contracts between the generators and the large users or retailers. These contracts may include special conditions that give generators flexibility 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 receiving electricity to reduce demand. Contracts may also take account of the time at which electricity is used: filling demand outside peak periods is much cheaper, so companies who are able to draw most of their power at other times can negotiate a discount, in
The electricity system
much the same way as the Economy 7 domestic tariff offered cheaper electricity over the 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, which operates through power exchanges. These are screen-based exchanges whereby participants trade a series of standardized blocks of electricity (e.g. the delivery of a specified number of units over a specified period of the next day). Power exchanges enable generators and buyers to fine-tune their rolling halfhour trade contract positions as their own demand and supply forecasts become more accurate as real time is approached. In theory they can operate over long timescales of up to a year but in practice most trading is done in the last 24 hours before gate closure as companies check their supply and demand positions. The third timeframe operates from between gate closure and the second-by-second dispatch of electricity on to the system. It is known as the balancing market and is managed by National Grid in its role as Great Britain System Operator (GBSO). It exists to ensure that supply and demand can be continuously matched or balanced in real time. The mechanism is operated with the system operator acting as the sole counterparty to all transactions. This market is required because demand and supply on the system are changing all the time, and certainly in timescales shorter than half an hour. Some of the biggest changes happen when domestic consumers are all watching the same TV programme and there are commercial breaks. This kind of ‘TV pickup’ typically means that people leaving their sofas to turn on the kettle during the mid-programme break for Coronation Street can increase demand by 800 MW. The biggest TV pickup ever recorded was on 4 July 1990 following a semifinal World Cup football game between England and Germany. The game went to penalties, and, within minutes of their finishing, demand rose by 2 800 MW. The high-voltage grid that National Grid manages reaches very few of the country’s individual users. But that does not mean National Grid can leave questions of load to the DNOs. Changes in consumption require the grid to bring extra power onto the system and it can be very sensitive. On a summer’s day a shift from clear sky to thick cloud adds an 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 a twelfth of the UK users, National Grid has to know about the load in far more detail. To assess demand it looks at the substation level and the individual grid supply points, which may supply a small town or half a larger city. That has a resolution of a 5–15-mile radius. As local temperatures change and more extreme weather events occur, human behaviour changes and the electricity supply system has to be able to respond. One big effect in the long term will be from additional air-conditioning loads, which will add to both peak and 24-hour demand. National Grid saw growth of 5 per cent in air conditioning in the commercial sector in the five years to 2002 and expects to see a further 6 per cent in the period to
2010. There is also likely to be a rise in the residential market. Often overlooked is that a 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 double their energy use when external temperatures increase from 18 ◦ C to 26 ◦ C.
The balancing market
As demand and supply fluctuate, National Grid manages the system through another market known as the balancing market. To this end, all market participants are required to inform National Grid of their net 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 updated until gate closure, when they become the final physical notifications (FPNs). Power flows are metered in real time to determine the actual quantities of electricity produced and consumed at each location. The magnitude of any imbalance between participants’ contractual positions (as notified at gate closure) and the actual physical flow is then determined. National Grid has offers to supply electricity into the balancing market that can be made available at extremely short timescales. This may be hydropower, for example, from the pumped-storage plants at Dinorwig and Ffestiniogg in Wales, which take advantage of low electricity demand and low price period to pump water to a high reservoir, which can then be released to generate power when required. Such plants are 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 thermal stations operating in a similar way to a car in neutral. National Grid also has offers for short-notice demand reduction, such as the interruptible contracts mentioned above. In some cases the system may have too much electricity available. In that case National Grid 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, varies depending on how far out of balance the system is, and on the cost of power during the half-hour timeslot concerned, and is known as the system buy price (SBP) or system 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 less than they had contracted for and informed National Grid in their FPNs. This was an important change from the previous market structure, and was designed specifically to encourage participants to match closely their demand and supply. Since the market structure was introduced the amount of power bought and sold on the balancing market has decreased, meeting one objective in the market design. However, in penalizing generators who do not match their supply and demand accurately, it takes in those generators whose supply is partly beyond their control. This includes companies operating wind farms, whose ability to predict is limited, but it also includes CHP plant operators, for whom the electricity available to be sold may vary depending on how much heat is sold. As the government wishes to encourage both wind and CHP, its position with regard to BETTA and the balancing market is under discussion. Partial
The electricity system
protection from the costs of being out of balance is most often gained at present from joining other generators and acting as a single trader: this should mean the unpredictability of the group is less than that of each individual member. Companies known as consolidators offer this service. The Balancing and Settlement Code (BSC) provides the framework within which participants comply with the balancing mechanism and settlement process. The BSC is administered by a non-profit-making entity called Elexon.
Distribution network operators
The distribution companies (which may be a subsidiary of a utility with generating and supply businesses) operate in defined areas (see Panel 2.1). The companies hold separate licences for each area and are governed by the terms of their distribution licences. They are under a statutory duty to connect any customer requiring electricity within a defined area and to maintain that connection and they have other statutory duties to facilitate competition in generation and supply, to develop and maintain an efficient, coordinated and economical system of distribution and to be nondiscriminatory in all practices. Embedded generation refers to the fact that these relatively small sources of power are ‘embedded’ within the low-voltage network, rather than supplying power from the high-voltage grid through a grid supply point, or substation. It is at the DNO level that most of the network development must take place that will allow embedded generation to become a significant component of the electricity supply network, and these 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 generation because they are ‘regulated’ businesses. Because they do not operate under competitive pressure, their costs and profits are examined by Ofgem to ensure that their financial returns are reasonable. That has implications for the way the DNOs manage their 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. Each DNO can manage its own operating methods and capital structure, and the regulator provides for a return on the capital invested and efficient operating costs, subject to certain outputs being achieved. The amount of income that DNOs are allowed to receive is set by the regulator, and depends 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 additional profit by reducing their costs, provided they meet their commitments to the regulator on maintenance, network development and other ‘hardware’ operations, as well as a variety of targets on customer service. Reducing costs may mean an improvement in operations, or in some cases can be the result of introducing new technologies that make a step change in efficiency. In company and investor terms, the DNOs are low-risk businesses. They have well-determined income and expenditure for several years, as work programmes and pricing are set on a five-yearly basis with Ofgem,
so investors have a reliable return. But the returns are relatively low – high returns accompany high risk – and will continue to be limited by the regulator, so the DNO must take a very cautious approach to new investment. To encompass the changes that will be required to include significant embedded generation, 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 may be added to the system, what type of generation will be added, or how much will be used. No DNO wants to take the gamble of upgrading part of its network to accept embedded generation under the current regulatory framework because, if the expected generation does not appear as predicted, the investment will be wasted – and the DNO is 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 we have seen, on the high-voltage network, National Grid balances varying input from generators as their power plants start up and shut down, with demand from the buyers that alters throughout the day and across the country. It is managed with constant feedback from all parts of the system. The low-voltage network is much simpler. It is designed 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 be transferred if, for example, work is required on the system. But the system is designed on the assumption that flow will be one way and will be sized for the likely load, so that, while the supply along the high street will be through relatively high-capacity components to provide power for commercial premises, residential street wires will be 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 carried out on the assumption that flow is one way, and this can be reflected in operations as simple as working on a single-network connection – once the connection is broken a maintenance technician assumes there is no possibility of power from the household side. The other effect is on the network capacity. Remote areas are often the most attractive as potential sites for embedded generation, but, if the existing connection at that point has very low capacity, the cost of upgrading it may make the embedded generation uneconomic.
Regulating the markets
Ofgem is the organization that regulates the UK’s energy markets and the companies involved in them. The way in which it regulates varies depending on the type of activity involved and the market structure. For functions where there is a competitive market, Ofgem has no role in setting prices: it is assumed that the effect of the market will be that customers can seek out the most economic product. So, in the generation and retail market, Ofgem ensures that the market is operating effectively, licenses companies to trade within the market and helps arbitrate disputes. In areas where competition is not possible, such as the distribution and transmission networks, Ofgem scrutinizes the monopoly suppliers and sets how much return
The electricity system
on their investment the companies are allowed to make, and how much they are allowed to charge to customers. As part of this process it examines what investment is required to maintain or extend each network and what the operating costs are. It then sets a broad range of performance standards for companies. Provided the companies meet their performance standards and are within their price limits, they can make efficiencies in operation and improve their level of profits, as an incentive. The allowed prices and performance targets are set in five-yearly distribution price control reviews and it is at this point that the operators and the regulator decide on likely major developments in the networks, such as developing them to accept embedded generation, and how these developments should be funded at reasonable cost to users and retail customers. For example, the distribution price control review that came into effect on 1 April 2005 included a specific incentive mechanism for the connection of generation to distribution networks. There were two additional incentive mechanisms – the Innovation Funding Incentive and Registered Power Zones – that encourage innovation in the connection and operation of distributed generation (DG). An additional development changed the basis on which generators pay to connect and use the distribution system. Ofgem also administers some of the government’s support and regulation schemes, including the Renewables Obligation and exemptions from the Climate Change Levy. Ofgem itself describes its first priority as ‘protecting consumers’, and its other priorities as helping secure Britain’s energy supplies by promoting competitive gas and electricity markets, and regulating so that there is adequate investment in the networks helping gas and electricity markets and industry achieve environmental improvements as efficiently as possible, taking account of the needs of vulnerable customers, particularly older people, those with disabilities and those on low incomes. Ofgem is governed by an authority, consisting of a chief executive and managing directors, along with nonexecutive members who bring various other types of experience to the authority. The authority determines strategy, takes all major decisions and sets policy priorities. Ofgem is funded by the energy companies who are licensed to run the gas and electricity infrastructure.
The heat connection and cogeneration
So-called ground-source heat allows heat from beneath the earth’s surface to be abstracted.
So far we have discussed the UK’s electricity supply industry, how it works and its major players, and how embedded generation fits into that system. However, this refers entirely to the electricity we produce and use, and it should not be overlooked that this is only part of the UK’s energy industry.
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 its regular ‘Digest of UK Energy Statistics’ (‘DUKES’), it examines how much energy in the form of oil, gas, coal, etc. has been imported into the UK, and how much has been produced here, again as gas or oil (from the North Sea) or coal, but also from home-grown sources such as wind power, hydropower, nuclear power and smaller sources such as waste gases from landfill and energy crops. DUKES figures also examine the fate of these primary energy sources. Some of the gas, oil and coal is used in generating stations to produce electricity, but even when added to the hydro, nuclear and wind power generated domestically this represents only around 40 per cent of the total energy used. A large part of the oil import is used as petroleum for transport, but oil, gas and coal are also used to provide heat, and this is 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 network is not as extensive as that for electricity but nevertheless has been expanding since the 1960s and now serves nearly 20 million domestic users – more than 80 per cent of the whole. This network is almost entirely dedicated to heating and cooking and there is also a market in gas canisters for those who do not have access to the network. A high-pressure gas network delivers gas to large-scale industrial users to provide process heat to industrial customers, as well as to the gas-fired electricity generators. The heat and electricity markets are intimately connected, because some fuels are used for both purposes and, equally, because electricity is also used to provide heat, although domestically electric space or water heating is often the most expensive option.
Support for heat and power
The heat factor has seldom received much notice from UK policymakers, despite its importance and the efforts of, for example, advocates of renewable energy and CHP, which often provide energy as heat. The largest support programmes for embedded or renewable energy are in practice available only for renewable-sourced electricity. The largest, the Renewables Obligation, requires electricity suppliers to source a growing proportion of the electricity they sell (the ‘aspiration’ is to reach 20 per cent of the electricity supplied by 2020) from renewable sources or pay a fine. Efforts to persuade the government to introduce a similar ‘heat obligation’ have fallen on stony ground, as the government has argued that the market is too complex
The heat connection and cogeneration
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 reasons. Of more direct concern is that, as we have seen (Chapter 1), heat and power are often produced together. Sometimes this is deliberately planned, with a use for each product, in the CHP plants we have discussed, and sometimes the heat is simply regarded as a waste product that must be dissipated in a way that does not cause problems elsewhere. The second, broader, reason is one of policy. Embedded generation is encouraged because it allows energy to be generated as close as possible to where it is used, reducing the losses incurred in transporting it long distances and giving customers a far better understanding of how much energy they use and why. Together, this should greatly improve the efficiency of our energy use, both because there are fewer losses in the system and because greater customer understanding is seen as likely eventually to translate into lower consumption. This can hardly 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 almost entirely on electricity, huge opportunities to switch to different forms of energy production and, in the process, reduce the energy – and carbon dioxide – bill of the country as a whole have been lost.
Take for example the opportunities to plant and sell energy crops. These crops are grown not for food, but to provide energy. There are a number of reasons why energy crops may be encouraged. They can be combusted to provide electricity or heat in preference to fossil fuels such as coal and gas. Burning the energy crops does release carbon dioxide into the atmosphere, but it is carbon that was absorbed by the crop while it was growing. Over the cycle the carbon balance is not zero, as there are some emissions from processing and transporting the crop and so forth, but the total emissions are far smaller than they would be if coal, oil or gas were used. Energy crops 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 to provide heat and/or power for local businesses. The government has attempted to promote energy crops but was most interested in using them to generate electricity, and at the turn of the century it invested millions in an experimental power station that would use a new process called gasification as the basis of a wood-fuelled power station. The National Farmers’ Union joined other wood-energy organizations to argue that the project was too ambitious: the technology was unproven, while the willow fuel would require farmers to take a seven-year gamble on replacing arable land with coppice. Opponents argued that developing both an energy-crop industry and a new generating plant together introduced too many uncertainties and it would be better to use energy crops in wood-fuelled heating boilers, replacing gas- or oil-fired boilers, until the industry was more developed.
But there was a long-term support mechanism already in place for electricity from renewables, so the project went ahead but was halted within a year or two by technical problems, setting back development of embedded generation from energy crops by several years.
Domestic heating is another example. Gas is currently regarded as one of the most efficient ways of heating the average domestic property in the UK, but although the gas network reaches more than 80 per cent of properties, that still leaves up to 5 million properties without access to gas. Those properties may use oil or electricity to meet their heating needs – both expensive options. There are small heat-generating technologies that can be used to fulfil the need for space heating or hot water, such as ground-source heating and solar water heating. Neither provides electricity, but both displace electricity or primary fuels such as oil, and they generate the heat directly on site with no transport requirements. Although individual projects of both types can apply for partial grants, the funding available to support these and other heat projects is very limited in extent and in the application window, being allocated every few years as part of the government departmental budget. The Renewables Obligation, which supports power projects, however, is expected to provide a subsidy for each unit of electricity generated until at least 2027.
Combined heat and power
The disparity is revealed most clearly in projects designed as highly efficient CHP plants. Well-designed CHP where there is an adjacent heat requirement to make use of otherwise ‘waste’ heat can raise efficiencies dramatically, increasing the overall efficiency of a steam turbine from less than 40 per cent to nearer 90 per cent, for example. This is clearly beneficial and policymakers have argued that CHP should be much more widely employed, with a government target of 10 GW. In practice, CHP is often employed where heat is the ‘premium product’. Industrial processes where there is a high and continuous requirement for heat, such as paper manufacturing, have generally installed their own boilers or turbines on site to provide heat 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 buildings in winter and to drive chillers or air coolers in summer, which can be provided by an on-site CHP at the kilowatt level. Public buildings such as sports centres, hospitals and schools also clearly have a very large heat demand. In all these cases, heat would be the major product of the CHP plant, with electricity produced as a by-product either 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 government’s 10 GW target has been receding. The policy focus on supporting embedded generation of electricity is one reason, and so is a UK electricity market that penalizes generation that is unpredictable.
The heat connection and cogeneration
CHP operators face considerable burdens if they want to supply their electricity to the grid. In most cases their output would be sold to an electricity retail company, since supplying electricity directly to customers requires the generator to meet stringent conditions to qualify for a licence and sign up to the BSC, the agreement under which electricity companies settle their contracts and reconcile them with the amount of electricity physically delivered. These administrative measures are generally too costly for companies with relatively small amounts of electricity to sell, and this is usually the case for CHP plant operators, since for most CHP the heat is the most important product and the amount of electricity produced is governed by the needs of the heat customer. The supply of electricity can be variable and at times of very high heat demand the electricity production may be very low. This means first that under the BETTA electricity market structure CHP plant owners would be in danger of being ‘out of balance’ on contracts to supply electricity, supplying either too much or too little to their customers, and would therefore be at risk of being charged balancing costs by the National 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 sources of power and demand reduction, so it can balance its own supply and demand and will seldom be out of balance on its contracts. This makes the risk more manageable but it does not remove it, and of course the electricity retail company has to bear the costs of managing the risk. That is reflected in the price paid to the CHP plant owner for its exported electricity: slightly discounted if the potential exports are well defined and largely guaranteed, but much lower if the export is less predictable. The cost of exporting power into the market was recognized by the government when BETTA was introduced and in response it allowed for companies known as consolidators, who would bring together supply from a number of smaller generators. Several such companies exist but they have found trading conditions difficult in a market 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 good price for electricity being exported from CHP. There is an exception, if the CHP plant is fuelled by biomass and is therefore providing renewable energy. This means that it receives a subsidy via the Renewables Obligation for each unit of electricity produced. Once again, however, this is not free of charge. Qualifying the CHP plant as a renewable generator and proving that the electricity qualifies for the Renewables Obligation again involve significant and continuing administration costs, which in some cases have been high enough to convince operators that the available subsidy from small export does not outweigh the cost of qualifying. Calculating the cost and benefit of being able to export electricity, and the income available from doing so, more and more potential CHP operators seem to be deciding that the scale falls on the cost side. The added expense of producing and exporting electricity is not justified by the price available for the electricity, and operators are more likely to use a very simple boiler with a relatively low capital cost but lower potential efficiency over its lifetime. Heat advocates argue that this problem could be solved if the production of heat at high-efficiency sources such as CHP or from renewable fuels received an additional
subsidy. As it stands, many potential embedded generation projects that could be generating heat and electricity at very high efficiency have been cancelled in favour of traditional boilers and electricity supplies that are much less efficient over their lifetimes and offer the electricity system none of the benefits of DG, relying instead on electricity from the grid.
What are the heat technologies that could be used in the UK to reduce the requirement for oil or cut electricity usage?
Burning coal or oil to provide heat and electricity depletes a nonrenewable resource and produces carbon dioxide. But other fuels can be substituted for these fossil fuels that are carbon-neutral over their life cycle. They are a renewable source of energy that the UK’s Department for Environment, Food and Rural Affairs (DEFRA) describes as ‘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 under cultivation – 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 the ground to produce new shoots after harvesting. Willow is cut back in the first year and then harvested every three to four years. A plantation could be viable for up to 30 years before replanting becomes necessary, although this depends on the productivity of the stools. Miscanthus is a woody, perennial, rhizomatous grass. On most sites it will take around two years to produce a stable crop. After that time it can be harvested annually for at least 15 years. Miscanthus is not native to the UK – it comes from South East Asia – and the current lines being planted in the UK are sterile hybrids, which cannot seed. Work on using willow and miscanthus has been under way for some time and the two crops are being promoted by DEFRA, with grants available both for planting and for developing producer groups. Reed canary grass may be next in line for development. It is native to the UK and it is already planted as game cover. In Scandinavia, reed canary grass is being used both 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 lower yield and a shorter productive life, and there are potential problems in removing it because it is spread both by rhizome and through seed dispersal. Switchgrass – also known as prairie grass – is a native of the USA, where it is the most interesting energy grass. In the UK a R&D programme has been started.
The heat connection and cogeneration
Described as ‘having potential, but still furthest from the market’, the final energy 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 for woodwind instruments. It offers high yield, but there are mechanical and technical problems 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 be very carefully selected, as if it is contaminated it will come under EU directives on waste incineration and must be burned in a dedicated and qualified incineration plant.
Solar water heating
Energy from the sun warms water left in a bucket on a sunny day. In fact, most of the extra warmth in the water does not come directly from the sun but via the bucket itself: the sun heats up the bucket, which in turn heats the water. A black bucket will heat the water up faster because it is better at trapping the heat from the sun and passing it on. This is a ‘passive’ system – it has no moving parts and does not require electricity 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 electricity 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 metal box 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 they don’t need much maintenance. Also, because they don’t have many parts, they can be the cheapest system to purchase or build. But their effectiveness is limited, and they 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 made out of a set of parallel copper pipes on a thin copper ‘fin’ that runs the length of the tubes. The ‘fins’ increase the heat absorption. Water, or one of various other kinds of fluid that may have better heat-transfer characteristics or are not prone to freezing, is circulated through the tubes. The solar absorber plate is then installed in an aluminium-framed box surrounded on the bottom and sides with insulation and covered with tempered glass. Flat-plate solar panels require a constant flow of fluid through 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 pump mounted on a solar storage tank. The solar pump is activated by a differential thermostat controller that senses when heat is available in the solar collectors. The solar storage tank connects to the existing hot-water heater and feeds the preheated solar water into the gas or electric hot-water heater as hot water is used. The solar collectors and feed lines are protected from freezing by automatic drain-down controls, which
allow the water in the pipes and panels to fall safely back out of the solar collectors and feed pipes. These types of system get the description ‘open-loop’ because the energy-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 exchangers that circulate heat-exchange fluids through the panels and feed pipes. This type of system is called a closed-loop system, because the solar exchange fluid is closed off from the external atmosphere or isolated from the potable water through utilization of a heat exchanger. In a closed-loop system the heated solar fluid is pumped through the solar collectors. The heated solar fluid flows through a copper or stainless-steel heat exchanger located near the solar storage tank. The heat from the solar fluid transfers to the potable water within the solar storage tank. Another small circulator pump may be 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 heatexchange fluids can withstand freezing temperatures, allowing the system to operate during periods when there is the greatest temperature difference between cold incoming water, and temperatures reached in the solar collectors. The system can have the greatest performance benefits at this time. Also, if maintained properly, these systems will not corrode or scale the passageways in the solar collectors and pipes. Closed-loop systems 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 highest installation cost. They heat water slightly less efficiently than direct open-loop systems, 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 employs flat-plate solar collectors. The solar panels are usually mounted at a lower elevation than the storage water to be heated. Thermosiphon systems can circulate potable water or utilize a heat exchanger and heat-exchange fluid. For potable water systems, the cooler water at the bottom of the storage tank is thermally siphoned to the hotter water near the solar collector by the rising temperature and volume of the warmer water, initiating a circulation of the storage water through the collector’s fluid passageways back into the top of the storage tank. The circulation continues until the temperature at the bottom of the storage tank is about the same as the temperature of the outlet pipe at the top of the solar collector. Since the early 1970s, the efficiency and reliability of solar heating systems and collectors have increased greatly and costs have dropped. Low-iron, tempered glass is now used instead of conventional glass for glazing. Improved insulation and durable selective coatings for absorbers have improved efficiency and helped to reduce life-cycle costs.
In the winter, scraping ice off the car and seeing frost on the grass, it is hard to think of the ground as a source of heat. But in fact the earth is being bombarded with energy from the sun all day – even in winter – and it absorbs much of it. That energy is stored in the earth’s huge mass, so, while the surface may be frosty in winter or cracked and
The heat connection and cogeneration
dry in summer, even at depths of just a few feet the temperature is fairly constant all year round. It varies, depending on where you are on the earth’s surface, between 5 ◦ C and 28 ◦ C. Ground-source heat takes advantage of this constant temperature – and very often it can be used all year round, so that it helps keep a building cool in summer and warm in winter. Ground-source heating has three main components. Within the building there is a heat-distribution system, which can be very similar to the radiators that distribute hot water around the house in a conventional heating system. Air ducts that can be used 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 another fluid with better heat-transfer properties is used. Depending on the characteristics of the site and the requirements of the building, the pipework is buried horizontally or vertically, in wells bored for the purpose. In some cases horizontal tubes need be only 2 m or so under the surface. Cold water in the tubes is warmed by the surroundings and pumped back to the house. Horizontal tubes are cheaper to install, but vertical tubes are likely to have better performance because, at greater depth, the temperature is more stable. In some areas there is free water deep below the ground – known as an aquifer. In this case an ‘open’ system can be installed. Warm water from the aquifer is pumped up through one tube, and cooled water is pumped back to the aquifer through a second pipe. The internal and external systems are joined by the third part of the system, the heat pump. This transfers the energy between the water pumped through the earth and the internal distribution system. The heat pump can ‘step up’ the heat that comes from 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 is similar to the systems used to extract heat from inside a refrigerator, turning it from cold 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). The heat 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. But generally the energy required to run the system is only a quarter of the energy that can be produced – and that may be supplied by PV cells or a turbine. Typically 1 kW of electricity used to drive the equipment will produce between 3 and 4 kW of heat output – very energy-efficient.
Ground heat in Cornwall
When Penwith Housing Association (PHA) took over the housing stock of Penwith 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 its tenants. However, the association had still to deal with small groups of houses with ageing heating systems, and, while affordable, low-carbon dioxide heating can be provided with gas-condensing boilers, mains gas is not always available. Conventional electrical heating (e.g. storage heaters) does not provide affordable warmth, and the large amount of mains electricity used is responsible for quite high levels of carbon dioxide. Oil-fired heating is becoming more expensive as fuel costs rise, and recent legislation on fuel tanks has increased installation costs. In any case, Cornwall had begun to build solid experience in renewables projects and PHA wanted to build on this. Trials of ground-source heating came about because it was a practical option for the Association’s pattern of small groups of housing. PHA’s first experience with ground-source heating was in 1998 on a newbuild project – four bungalows for elderly people. A more ambitious project to fit the system to existing houses was initiated when the government’s Clear Skies grant programme started up in 2003 (see 16.6). The site was carefully chosen. PHA has many existing homes in outlying areas 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 better to start with homes that have a lower heating requirement that would match the 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 had small, reasonably well-insulated bungalows that lacked efficient modern heating. There were concerns about whether the technology could be installed in these existing buildings. Of particular concern was installing geothermal boreholes in the gardens. In part this was because on new-build sites drilling uses a big rig, and it is traditionally a messy operation. A drilling rig around 2.5 m high drilled two holes in each garden that are 200 mm wide and 40 m deep. Then a plumber took over to install Calorex heat pumps supplied by Powergen as part of its HeatPlant kits. These kits include ground loop components, a heat pump and a hot-water cylinder matched to suit the heat pump. The heat pump is similar in size to a small fridge. This sort of space can be difficult to find in a small home, particularly because the position must be accessible to the ground loop pipes, so the heat pumps were installed in a purpose-built timber enclosure fixed to the external wall of the properties. This allowed easy connection to the ground loops and a simple connection of the heating pipes through the wall to the plumbing inside.
The heat connection and cogeneration Inside the house there was also some work required. Geothermal heat is often combined with underfloor heating but that could not be installed in the existing homes. By and large, it emerged that radiators were the best solution. There are some changes in operation: a conventional boiler wants to deliver heat quickly and then turn off, and the latest components are designed for that approach, like radiators with low water content that heat quickly to provide a ‘quick hit’. With a heat pump, temperatures are more like 60 ◦ C instead of 80 ◦ C and it is better for it to run longer. So the new radiators had the highest possible water content to provide thermal storage and there were fewer thermostatic 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 additional funding from the local authority. The total contract cost was £136 861, of which the Clear Skies Community Programme provided £47 000 and Penwith District Council £25 000.
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-scale wind farms have been developed across the UK in the last five years. But wind power has many other guises that make it fit a variety of embedded generation needs, from single houses to large industrial users.
The wind farms generally being installed share a three-bladed design that has become the standard offering from major suppliers. Thousands of turbines of this style have
been installed worldwide, and it has undergone many refinements and been scaled up to as large as 5 MW. The main components are as follows: • Tower. Made of cylindrical steel sections or open steel lattice, the tower can be from 25 to 75 m high. In most cases the wind conditions improve with tower height. At the top, a ‘yaw’ mechanism turns the tower head, along with the rotor and nacelle, so it faces the wind. Rotor. There are three rotor blades, or two or one – most often three – made of fibreglass-reinforced polyester or wood epoxy. New designs are increasingly using blades reinforced with carbon fibre. The blades rotate around a horizontal hub that is connected to the electrical equipment in the nacelle (see below). The amount of energy produced by the turbine depends on the length of the blade and the area it ‘sweeps’ as it turns. Blades can be from 30 to 65 m long. The power output from the turbine can be controlled by adjusting the angle of the blades as the 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, so does 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 at about 20–30 revolutions per minute. In most cases this is connected via a gearbox to a high-speed shaft, which turns at about 1 500 rpm. This drives an induction or asynchronous generator that produces the electrical power. Staff enter the nacelle to maintain these components. Anemometer. This instrument attached to the nacelle measures wind speed and direction. This provides information to the computer controller, which starts the turbine operating when there is enough wind, operates the yaw mechanism and controls the electrical equipment.
Wind farms and industrial users will usually install larger turbines, on the 1 MW scale, so as to extract most power from a single site. Smaller turbines, sized at a few hundred kilowatts, were more usual in the 1990s and are seen in their thousands in the Netherlands and elsewhere in Europe. However, turbines are available in smaller sizes 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 at 600 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 in the UK. More commonly however, the 600 W is used by telecoms companies to feed power into batteries for telecoms repeater/booster stations and has been used by the MOD (Ministry of Defence), BT, Orange and T-Mobile. Proven’s largest turbine, in contrast, is 1.5 kW and is aimed at light industrial, light commercial and agricultural use. With this sort of power you can power about six or seven typical three-bed houses in the UK. The British Wind Energy Association (BWEA) notes that small wind turbines have traditionally been used to generate electricity for charging batteries to run small electrical applications, often in remote locations where it is expensive or not physically possible to connect to a mains power supply. Such examples include rural farms, island
communities, boats and caravans. Typical applications are electric livestock fencing, small electric pumps, lighting or any kind of small electronic system needed to control or monitor remote equipment, including security systems.
Assessing the wind resource
The first stage of any wind-energy project is finding out the available wind resource base. Proven Energy, for example, assumes a wind resource averaging 5 metres per second (m/s). The ideal site would be on top of smoothly rising ground and away from trees or other obstructions – both characteristics will reduce wind turbulence and improve output. The effect of location can be dramatic, and sites just a quarter-mile apart may have very different characteristics. Location is also important for the turbine connection: 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 can be established by using the UK wind-speed database (which can be accessed via the BWEA’s website at www.bwea.com/noabl). This returns an estimated annual mean speed for a given Ordnance Survey grid reference. If the wind characteristics appear favourable they must be assessed over as long a period as possible – several months at least, and ideally a year – by installing an anemometer, an instrument that records wind speed mounted at the planned turbine height. The BWEA notes that the electricity produced by a wind turbine over a year depends critically on the annual mean wind speed at the site – higher wind speeds produce more energy. It says that, in general, small-scale wind turbines start to generate electricity in wind speeds of approximately 2.5–4 m/s and their rated optimum wind speed is 10–12 m/s. For instance, a 6 kW turbine at a wind speed of 5 m/s will generate an average of 11 000 units of electricity a year.
Installing a wind turbine
The BWEA’s guide, ‘Installing a Small Wind Turbine – in a nut shell’, can be found on 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 manufacturers should be prepared to help. The generator must get acceptance for connection to the electricity distribution network. (if applicable). 2 Mount the turbine on as high a tower as possible and well clear of obstructions, but do not go to extremes. Easy access will be required for erection, and foundations for the tower may be needed depending on the size and tower type. It is also important to ensure 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, smooth ground or on a smooth hill.
4 Use cable of adequate current carrying capacity (check with the turbine supplier. This is 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 try to minimize the environmental impact of the turbine, and it will be helpful to inform your 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 the economics of the installation, again you should find this out by consulting your local council. Once the machine is under construction, ask your chosen supply company whether they need you to be accredited for ROCs [Renewables Obligation Certificates], LECs [Levy Exemption Certificates], and REGOs [Renewable Energy Generation of Origin] and what type of onsite and/or export metering they require you to have (if applicable).
Integrating wind turbines into the built environment poses some formidable challenges. In urban areas generally, winds are slower, more turbulent and show greater directional variation than in rural areas nearby. But these effects are smaller for the tops of buildings that are taller than their surroundings. Appropriately placed, wind turbines can benefit from the ‘venturi’ or concentrator effect created by buildings, which produces higher wind speeds. Noise and flicker, considered a nuisance in rural areas, will not be tolerated at all in towns, and vibration can threaten the integrity of a building if a turbine is placed inappropriately on a rooftop, which is usually the most viable site for it. London has a particularly low average wind speed of about 4 m/s, and is unlikely to be the first-choice location for wind turbines, but some have already appeared and in the long term may contribute significantly to its energy needs. Hammersmith Council recently shelved a project to build an Enercon E66 turbine on a site adjoining Wormwood Scrubs, because it was believed the scheme would fail at the planning stage. Undeterred, the council was, at the time of writing, pursuing a scheme to install small 6 kW wind turbines on the roof of a 22-storey residential block. Tall buildings funnel wind, and architects have to keep this within acceptable limits if people are present. But a building’s shape can be used to force the wind through a turbine. Ambitious plans for another residential scheme in west London anticipated wind turbines installed not only on the roof of two lozenge-shaped tower blocks, but suspended between them. The project is along similar lines to an aerodynamically shaped building called the WEB Twin Tower Building, which has three 30-m-diameter integrated wind turbines suspended between kidney-shaped twin towers designed by the University of Stuttgart in 2000 as part of the EU-funded Wind Energy in the Built Environment (WEB) project. Field tests conducted at Rutherford Appleton Laboratory showed that placing the wind turbines between the building’s two towers, acting as a concentrator, produced considerably more power than mounting them conventionally at the same height on an open site. It increased wind speed by a significant 1 m/s. The kidney-shaped towers also directed wind into the fixed yawed 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
50 per cent increase in annual energy yield in a typically urban setting over a freely yawing, stand-alone machine without the building. In recent years new designs for small-scale turbines have been developed, intended for rooftop installation on domestic and commercial buildings. BT, for example, which consumes some 1.8 per cent of the non-domestic electricity generated in the UK and is struggling to reach its renewable-energy targets, is planning to install rooftop turbines on one of its telephone exchanges in Cornwall and, if the project is successful, plans to replicate it at other sites. The insurance company CIS has also invested in roof-mounted turbines for its flagship CIS Tower in Manchester, complementing one of the largest PV installations in Europe. CIS is using small Windsave turbines, which start to generate electricity at wind speeds of 4.0 m/s and reach the rated output of 1 kW at 12.5 m/s. One of the main problems with installing propeller wind turbines on a rooftop had been vibration, but now a new generation of turbines has been designed specifically for buildings. One of the most exciting designs is the 1.5 kW Swift Rooftop Energy System, from Edinburgh-based Renewable Devices. The Swift’s design engineers, Charlie Silverton and David Anderson, claim it is 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 more efficient, while reducing the noise emissions significantly, while a circular rim around the outside of the blades holds on to the radial flow of air at the tip of each blade that creates a ripping noise with conventional turbines. Renewable Devices has also developed an electronic control system that safeguards the turbine in high winds and ensures efficient power extraction under normal operating conditions Renewable Devices won a Scottish Power Green Energy Trust Award to fit Swift Rooftop Wind Energy Systems to five primary schools in the Fife area to provide electricity, hot water, lighting and computing equipment. The company also won the Scottish Green Energy Award for Best New Business in 2003. The Wind Dam system uses the inherent strength of a building to intercept and collect wind energy using a vertical-axis turbine. The unit is caged for safety. It is this design that BT has chosen to mount on its exchanges in Cornwall. The system can be incorporated into a large number of building types and also has considerable retrofit potential. The Wind Dam concept has completed a UK Smart feasibility study. The patented combined augmented technology turbine (CATT) from Stratfordupon-Avon-based FreeGEN is another British design that has been designed specifically for use in the built environment. Like the Swift, the CATT’s three rotors are enclosed, but in this instance with a short aerodynamic duct, which works with an air-flow controller to boost the energy potential of wind speeds of less than 5 m/s. There are other innovative designs. Developed by the University of Strathclyde in 1999, the ducted-wind Windside is another vertical wind turbine based on sailing engineering, the wind rotor of which is rotated by two spiral-formed vanes. Developed in 1979 by Risto Joutsiniemi, Windside turbines have been made to order since 1982,
mainly for use at sea. Their spiral construction makes them able to utilize winds of 1–3 m/s.
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, it may be connected directly into the house’s main distribution board or connected via a battery. A battery-charging system provides you with a continuous power source for your house via an inverter, which makes the power from the turbine usable. The inverter converts the DC power provided by the turbine to the AC on which most household appliances and the domestic electricity system are designed to operate. Battery-charging wind turbines normally operate at low voltages such as 12 or 24. Batteries are usually essential in off-grid systems, but are expensive and will deteriorate over time. They store low-voltage DC electricity, and need to be protected from over- and undercharging. Lead-acid batteries are the most costeffective, although other types are available. For a renewable-energy system, ‘deep cycle’ batteries are used, which are designed to have up to 80 per cent of their charge removed and repeatedly replaced over a period of 5–15 years (or 1 000 to 2 000 times). An inverter transforms the low-voltage DC power produced by a wind turbine into high-voltage AC power that meets the quality requirements of the electricity network. 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 not be your electricity supplier. DNOs have different policies when it comes to connecting small-scale renewablegeneration systems to their networks. If you have an off-grid site, you would have a diesel generator on standby to cover periods when you had no wind at all for a few days (because batteries are typically sized to provide around 2–3 days’ worth of storage). Grid-connected turbines do not operate when the mains supply is interrupted: they are designed to shut down for electrical protection reasons.
The supermarket chain Waitrose is part of the John Lewis Partnership. Although the Partnership produces few of its goods for itself, in rural Hampshire the founder’s private estate is still part of the company’s portfolio. The estate also has working farms: two 200-cow production dairies, orchards, a mushroom
Wind power farm, a milk-processing plant and a plant-propagation nursery as well as cereal production. The farm also acts as a test bed for new methods, both in production and in developing the supply chain. The company put this into practice when it decided there was a market for chickens that were free-range, traditionally reared and maize-fed. The company produced a shed that opened at the sides, so that the chickens could move freely in and out. The shed is on skids, so that it could be moved to fresh ground if necessary – to help avoid disease build-up, and allow the grass to recover. Then the issue of heat and light arose, and, although there was a power connection running down the field that would be suitable, that would not always be the case, and the company wanted a demonstration project. Another farmer might want to use a similar system in an area where there was no power connection. 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 are fully feathered, they can move in and out of the shed during the day and are closed up at night. The energy requirement is fairly small. The shed is lit at low level for 24 hours a day during the first six-week period, as the chicks tend to flock and can be crushed if they are in darkness. A small motor is required to transfer feed from an exterior hopper to feeding points in the shed. Each shed houses 1 250 chickens and draws 26 A. As the birds grow they require less light, but more food, so the power requirement remains fairly stable over the 12-week cycle. The power supply is very simple. Each shed is supplied by a single turbine and solar panel combination, which feeds an array of six standard 12 V batteries. The turbines are around 10 m high and can be easily moved along with the sheds. Because they are portable, and the sheds are moveable, the company did not need any kind of planning permission. The 13 sheds were installed in mid-2001 and the first birds were installed in October 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 15 hours in midsummer and about 4 hours even in midwinter. The wind turbines operate more or less continuously, although at only 10 m above ground the wind is gusty and even within a single field the 13 turbines can be turning at different speeds. The birds also require heat, but that is supplied from propane burners. The simple renewable-energy installations are a small proportion of the setup cost. The total cost of each shed was around £21 000, and, of that, the turbine and solar panel cost around £1 500 to buy and install.
Wind across the Mersey
Mersey Docks and Harbour Company’s site had been identified in the early 1990s as having a good wind resource, but the wind company that first approached the docks did not take up the option. Instead, Mersey Docks decided to 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 chose well-proven technology in the form of 600 kW Vestas turbines. Mersey Docks was the project manager, as it is experienced in the project-management process and it felt the wind cluster was a small project by Mersey Docks standards. Its principal risk at that time (before the Renewables Obligation was implemented) was the selling price, but it was eventually awarded a contract under the NonFossil Fuel Obligation (NFFO), which gave it a 15-year contract for electricity sales at an index-linked fixed price. The company decided to go ahead with six turbines, Vestas-supplied V44600s 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 for the centre of this highly industrial area might be thought relatively simple, but in fact feelings before the turbines were installed were very mixed. Objections came from a group of houses that are about three-quarters of a mile along the coast, who were concerned over noise, dust, interference with TV reception and bird strike on the turbines. There was also a concern about local wildlife. The turbines are installed on a road along reclaimed land on the shore and reclaiming that land had created artificial mud flats. The flats have become a nature reserve and more recently a site of special scientific interest. But the issue was resolved by altering the spacing of the turbines either side of the flats. As for the local councils, Wirral, on the opposite bank of the Mersey, sent a letter of support as it thought the turbines would improve the environment. But the planning authority was Sefton Borough Council and it denied planning permission when it was sought in 1995. Permission was granted on appeal, with the conditions that turbine positioning and colour had to be approved. Uniquely, because Sefton feared the perceived risk of bird strike, each turbine had to stand inoperative for two weeks. In practice, serial construction and commissioning took up most of that time. Construction began in late 1998 and – bird-education period notwithstanding – the turbines were in operation by March 1999. The company says they have operated with hardly any problems. External grid faults sometimes shut them down – it is an automatic protection system – but the company’s own electrical engineer can reset them, so they can restart. As Mersey Docks was managing the project itself, it used its own expertise in the installation. The turbines are right on the sea wall and very exposed, as waves
Wind power frequently break over the road. That called for some additional weather protection. Normally the transformers would be in a separate building, but Mersey Docks sited them in the base of the tower. They are designed so that, if a transformer needs replacing it can be removed through the access door. The control gear that would normally be at the base has been raised to a mezzanine level. It also needs extra protection against corrosion, so there is a marine-grade coating on the outside and the inside is painted, where normally it would be left unpainted. The project cost around £2.5 million. That included £1.8 million for the turbines, £400 000 for civil works and £300 000 for electrical works. Connecting to the grid was relatively straightforward for a large user such as Mersey Docks as the local grid is sized for large industry and the company has electrical works on site and regular discussions with the local DNO. The connection was made simpler, because it was entirely within the docks area, as Mersey Docks has its own substation at the port entrance, which is connected to the DNO’s mediumvoltage system. Mersey Docks dealt with the maintenance risk by taking out a fixed-price contract with the manufacturer that includes performance guarantees. The fixed-price contract is not for the life of the turbine, and Mersey Docks is already considering what to do when it ends. Maintenance requirements are estimated at about a half-day each quarter for each turbine. The company expects to get payback on the turbines in about ten years. Its NFFO contract runs for 15 years. Although the delays in getting planning permission lost it about six months of the contract, the turbines generated slightly more than expected. The power the turbines have generated has varied a lot over the first two years. Mersey Docks estimated that during the first year they produced 10 per cent 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 good sense of wind because it also affects shipping delays, downtime for the cranes and so on. The result is downtime in windy years – just the opposite to the turbines – and variability from year to year was anticipated. The company was so pleased with its turbines that it is planning to install larger ones in another part of the dock. The turbines would be 1.8 MW or more but they must be optimized around the site. They must get the spacing right. The manufacturers are concerned about 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 million without a long-term NFFO contract. The price of ROCs means the power from the turbines will be exported, not be used at the docks, which has a maximum power demand of about 35 MW.
Small hydropower plants use falling water to generate electricity.
Water power has been a familiar sight for thousands of years. Most people in the UK probably know an old water mill – whether or not it still has its water-wheel – that has been converted to another use. But the water that powered a threshing machine or grindstones can be used equally well to generate electricity.
Power from water
The power available from a hydro-turbine depends on two things: the distance the water falls to the turbine (known as the head) and the amount of water flowing through the turbine. The combination of these factors means that power can be generated from many types 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, for example, wind turbines, as developers have tried to abstract power efficiently from a variety of watercourses. High-head schemes generally use Pelton turbines (named after the American engineer L.A. Pelton). These bear some resemblance to water-wheels, in that the water flows into a series of vessels (known as buckets). They are described as impulse turbines: the impulse is transferred directly from the falling water, turning the turbine and 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 containing a turbine shaped like a propeller. The water turns the propeller as it passes through it. Propeller-type schemes can be used for heads as low as 1 or 2 m if there is enough flow volume, making the UK’s many weirs and sluices potential hydropower plants. Between the Pelton turbine and the propeller, two other types of turbine known as 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 are appropriate for each site. Small hydro schemes are unlikely to require a dam of any size to be built. They may have a storage or settling pond similar to a millpond, which evens out the flow rate at the plant intake, and protects the turbines from damage from solids in the water by allowing them to settle out. Alternatively, they can operate as so-called ‘run of river’ with no storage at all. Once installed, hydro plants are several times more efficient than solar or wind power and with regular maintenance some may operate for up to 100 years. What is more, their operation can be predicted with some accuracy, because for some rivers records 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 or low flows to be anticipated.
The UK’s hydropower potential
How much small hydro can be developed in the UK? The general impression from assessments of renewable options is that almost all the UK’s capacity has been exploited. But there are new sites that can be considered and there are many mill sites – some dating back a thousand years – in various stages of decay. There are also existing weirs where it may be possible to install turbines to take advantage of the 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, for the same capital cost. The total volume of water flow is also important, but, because of physical constraints and environmental requirements, the total flow may be very different from the amount that can flow through the turbine. In a wide but shallow river, for example, extensive works would be needed to divert flow through a narrow channel. Other issues that can greatly affect the economics are the cost of grid connection 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 considered in the design, and decisions on one area of the design will affect other areas. For example, spending more on the turbine may save the cost of civil works, as a siphon or 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 scaling their sophisticated equipment down for small hydro, whereas the middle- and low-cost bands tend to be companies whose major business is small hydro. There are also European manufacturers specializing in micro-hydro technology who have developed simple and robust technologies that can bring down costs for small-scale schemes. The choice of design capacity (i.e. the power rating of the installation) is largely dictated by economics. The investment cost per kilowatt is generally lower for a larger installation, but sizing the turbine to the maximum may mean it cannot operate during low-water periods. A smaller scheme will allow the turbines to run flat out for more 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, debt funding 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 assessments have been made. It picked out 157 sites in the south-east, but rejected all but 13 as uneconomic. Those 13 had a joint projected installed capacity of 3.186 MWe. The study rejected all sites under 2 m head and less than 25 kWe projected installed capacity – even where an on-site demand existed. Its rejections included such sites as Sonning Lock and Whitchurch Silk Mill, sites that later came under serious consideration for development.
Assessing hydro sites
Estimates of the power that can be tapped vary enormously, largely because the results depend very much on the assumptions made at the start. The south-east is a good example: studies of the potential capacity of the Thames have varied from 5 MWe up to 25 MWe. Thames Valley energy consultancy TV Energy examined the resource in more detail, having decided that a more detailed understanding of the resource in the southeast was required if it was ever to be mobilized. The group’s report illustrates the difficulties in harnessing the energy from watercourses. TV Energy considered the sites first as a technical resource – looking purely at the physical options and the machinery required – and then a practical resource. In the first stage, several hundreds of potential sites were identified from maps and other information, but many of the sites were discounted. This was either due to a low head (in some cases weirs were only a few hundred millimetres high), or because it was obvious that there was insufficient flow – enough to turn a water-wheel and drive a millstone or other slow-moving machinery, but not the faster flow required for hydro-turbines. Access was often a problem on private land. The remaining sites were assessed to consider: the degree to which silt from the river bottom could become a problem; the flow likely to be available for power; the turbine/generator location; possible electricity consumers within 500 m; restrictions on 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 less than 3 kW and this was considered nonviable. Sites would need to have a potential grid connection within 500 m. After visiting more than 100 of the sites and examining 50 in detail, then extrapolating the results across the region, TV Energy calculated that the technical potential encompassed 400 sites totalling 9 088 kWe. In addition, there are 45 weirs on the River Thames, of which 29 have a head of 1.4 m or greater. Their technical potential was 4 118 kWe. Together, TV Energy calculated a technical potential for low-head hydropower in the south-east of 13.606 MWe. The group then assessed the practical potential, considering environmental mitigation, flood-control measures and planning issues. In the south-east, almost all the low-head schemes are micro-hydro-sized (below 500 kW and exploiting less than 3 m of available head). That means the turbine machinery will be relatively large and must have high flows to achieve a reasonable power. Head is reduced during high-flow (flood) conditions. During operation, there are high levels of trash in the water that could foul the turbine and must therefore be collected and disposed of. But the biggest environmental constraint 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 in the turbine.
Taking into account such factors as the effect of nontechnical constraints such as sites where the environmental impact is likely to be an overriding issue, planning, poor economic potential and site access, TV Energy estimated that 120 sites had economic potential, producing some 5 320 kWe. Of the Thames weirs, five had most potential, contributing 900 kWe. A further estimate was made of the likely short-term realisable resource that might be mobilized to meet the 2010 regional renewables target. Expert opinion in the hydro industry says that only sites above 15 kWe are likely to be developed. What is more, many potential sites belong to the Environment Agency or private landowners who do not wish to develop them. On the other hand, some mill owners appear motivated by a desire to rebuild and regenerate old sites and may invest in sites that do not apparently meet the standard criteria. Taking these constraints into account, TV Energy calculated that the practical accessible resource in the short term may be 1.064 MWe, while a realistic view of the Thames weirs would be five of the schemes with the greatest economic potential giving an installed capacity of 900 kWe. In addition to the general sites and Thames weirs, TV Energy examined mill sites using records from historical societies. These sites also number in the hundreds but the group considered that only around 10 per cent had technical potential and considered there may be a resource of some 276 kWe. TV Energy concluded that there may be a short-term practical resource of 2.024 MWe for low-head hydro in the south-east of England.
Although the water used in a small hydro plant is returned to the river, the plant can affect the river flow and flora and fauna, especially in the case of a plant that is on a small river. Each hydro station where water is diverted requires an abstraction licence from the Environment Agency – even if all the water that was taken from the river is returned to it a few yards downstream. It is also likely to require a discharge licence for the water return – a dual licence requirement. Before it will grant an abstraction licence the Environment Agency also has to be convinced that diverting part of the water will not change the character of the river. The project may also be restricted in when it can operate, to ensure river flow levels are maintained, which means some plants do not operate in summer. Even in run-of-river plants where there is no storage or diversion, there may be potentially costly requirements, such as so-called ‘fish passageways’ to allow migrating fish to pass by the turbine. In the past, some hydro developers have found the requirements of the Environment Agency to be onerous, and the feasibility studies and surveys required to assess the impact of a project on the fish and smaller species, river plants and flow levels were likely to represent a significant proportion of the project budget. The Environment
Agency said it would ‘take a positive view of reasonable and well-designed proposals for hydro power schemes’. Once in operation, hydro plants are welcome additions to the system because they have mostly predictable power generation and controllability. They are also extremely long-lived – at least 50 years of reliable life is expected if the plant is well maintained and some have had much longer lives.
Adding hydro to the system
Small hydro is not just about dedicated plants in remote areas. There are slots in our extensive 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 and a wide catchment area. The water is piped from its source to the water-treatment works near 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 be under 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 a hydropower 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 energy wasted in pressure-reducing valves and considered how best to extract it. According to the British Hydropower Association (BHA), schemes already in operation in the water system provide over 25 MW of electricity capacity and, overall, the BHA says the potential nationwide is likely to be around 100 MW.
Extracting the energy
Energy from the water system may seem like easy pickings. But there are priorities to be considered. All electrical components in the water-supply system have to conform to very strict, internationally agreed standards to ensure they do not adversely affect the water. For example, they have to ensure that there is no possibility of contamination by paint, oil or grease. The turbine is being added to an existing system, so there will usually be very tight physical constraints on the site, and in many cases the existing pipework is very old. The treatment works have to run constantly so there can be no shutdown when the turbine is installed or maintained. Once it is in operation, the water flow must be tightly controlled so that water quality is maintained. This usually requires a sophisticated control system for the turbine and special control arrangements that allow water to be switched to bypass the turbine when necessary. A bypass system will be used if the turbine needs to be shut down for maintenance, or during normal operation to ensure that the flow is constant. Switching between the turbine and bypass route must be ‘bumpless’, i.e. it must not create surges in the system.
Elsewhere in the water system, water companies have installed turbines at reservoir outlets and have examined the possibility of including them at the inlet to water-treatment works where gravity-fed wastewater arrives. That is a technical challenge because solids in the wastewater can foul or degrade the turbine, and a new turbine design may be required.
Reviving old mills
Mill owners in Somerset combined with the district council to investigate electricity generation. South Somerset District Council decided they wanted 10 per cent of the energy used within the district to be generated from renewable sources within the district. That tall order was thought most likely to be met by wind turbines. But the region also has many historic water mills that were now simply picturesque tourist 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 found around 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, and with matching funding from the district council the next step was to carry out a feasibility 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 potential design output and the total energy capture that would be possible. With the help of a further £2 000 from the EST, that led to the development of a business plan for 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 (which carries water from the river to the mill wheel) was still in existence, while some needed to be recut, for example. The varied capital costs and energy available meant that payback time for each mill was different. At one mill a 19-year payback period was likely and that 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 less than 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 went back to the EST for an implementation grant. The group won the maximum grant from the Trust – some £88,000 – which will cover around 30 per cent of Continues
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 works themselves. The group negotiated with several electricity companies to get the best price for the electricity that mill owners will feed onto the grid. There were very few embedded generators in the region, so they have not had to put in place a standard arrangement for export. At present they will either make an annual payment based on an estimate of the kilowatt hours exported, or accept the generator privately installing their own meter. The owner is expected to read the meter every six months and a six-monthly payment for export will be made. The payment for the electricity exported will depend on the size of the generator. Eventually, the price on offer from the utilities was slightly higher than the mill owners assumed in their calculations. That means most of the owners will be moving into profit earlier than they had anticipated. While some had work to do to get their mills working again, by 2010 they should all be reaping the rewards.
Hydropower in Snowdonia
Developing small hydro in a National Park called for sensitive design and construction. Ty Cerig is a small hydro plant built in the Snowdonia National Park by Wales-based renewable-energy specialist Dulas Ltd. The Ty Cerig scheme, sited near Dolgellau, took several years to come to fruition. Since it is sited in a national park, there were several powerful organizations to convince, including the Snowdonia National Park. Consultations were required with the RSPB and the Welsh archaeology service Cadw, as well as planners. Finally there were the landowners: Forest Enterprise and a private landowner, in the case of Ty Cerig. But by the time Dulas got around to Ty Cerig several of the other projects were well under way and the company says it had built up a good relationship with all the stakeholders. Nevertheless, planning for this project required careful assessments in an area so dependent on tourism. The main area of concern was the potential impact of the abstraction on populations of mosses, liverworts, fish and invertebrates. A detailed environmental assessment was carried out using experienced ecologists, to demonstrate that there would be negligible impact. Luckily, the site was mostly in a commercial conifer forestry area, so it is not a high-grade habitat and there was less conservation interest.
Hydropower Visual-impact issues are usually of less concern on small run-of-river schemes such as these, where pipelines are buried, and weir and powerhouse structures are small and unobtrusive. A pipeline carries water from the river to the 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 was cut by hand and replaced to ensure fast regeneration of the vegetation over the route of the pipeline. At the bottom, the powerhouse is in a slightly more sensitive area. The field at the bottom is a wildflower meadow and has significant conservation interest, so the powerhouse build was planned to allow the surroundings to recover quickly. Similarly, the powerhouse had to be carefully designed to be as unobtrusive as possible. It has timber walls and the roof is turf – this blends in and native species can grow on the roof. The biggest problem was the abstraction regime. The maximum abstraction is 75 per cent of the river flow, so 25 per cent of the flow always remains in the river and never less than a minimum threshold of 20 l/s. Furthermore, in summer, abstraction cannot commence until a high flow of 189 l/s is present in the river, to give protection to the mosses and liverworts in times of higher temperatures and lower humidity. Due to these restrictions, and the fact that limit on turbine maximum flow means that it cannot make use of the high river flows, the scheme will effectively abstract less than 30 per cent of the total yearly flow volume. Technically, these limits are quite easy to work with, using electronic controls. Electricity from the plant is being sold to the grid. The cost of connection of such projects varies considerably, depending on how far the project is from the connecting point – and a hydro plant cannot be relocated closer to the connection. But at Ty Cerig the grid connection is only about 150m. The cables were buried to reduce visual intrusion.
Wave and tidal power
So-called marine renewables encompass devices that tap the energy of either tides or waves. The term is also used sometimes to refer to offshore wind as they share some development issues, such as making the equipment sufficiently robust to withstand the marine environment or transporting the power from an offshore generation site to the users on land. This chapter focuses on the wave and tidal sectors. Although the possibility of generating power from these natural resources has been recognized for decades, it is only in the last decade or so, with the growth of interest in renewables in general, that large-scale deployment has been regarded as more than a remote possibility. In the last few years, however, the view has changed. A large number of devices have been proposed that could abstract power from waves or from either the regular movement of the tides or so-called tidal races, where the tide forces seawater through a narrow channel between two areas of sea.
How much energy is there?
The UK has been investing in this developing sector for several years, driven by the large energy resources that are almost certainly available to be tapped from areas in the North Sea. The region has been an energy powerhouse for the UK for several decades, thanks to its extensive gas and oil reserves, but the end of production is already in sight: in the next few years the majors will begin to abandon worked-out sources, and the remainder will be the preserve of minor companies able to make returns on smaller or less accessible deposits. As oil and gas production begins to taper off, the UK’s aim is to transfer the extensive offshore expertise to new energy industries, and especially those that will abstract power from the wave and tidal resources in the region. Wave and tidal streams hold tremendous energy potential – but abstracting the power and getting it to shore call for significant engineering development. That means estimates of the usable energy from these sources vary widely. In Scotland, for example, Professor Ian Bryden, based at Robert Gordon University’s Centre for Environmental Engineering and Sustainable Energy, put some preliminary estimates on the energy available from the North Sea. With the caution
that estimates could vary widely depending on the assumptions made, he said his own estimate put the North Sea’s annual potential at 18–25 TWh of power from wave resources and 40–50 TWh from tidal currents, along with 60–400 TWh from offshore wind. Around the UK, the North Sea is not the only potential source of power. The Atlantic waves that beat along the south-west coasts are of interest to a number of wave-energy developers, and, apart from the strong tides in the area, there are also tidal races in some sites around Cornwall and Portland.
Is wave and tidal energy distributed generation (DG)? It is clear that in some cases this type of energy is highly concentrated in widely separated areas – the tidal races of the Pentland Firth, for example. If these areas were exploited fully, it is likely that large devices or arrays would be required in the area, and would likely be linked to the electricity 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 is relatively small. In most cases, and for some time to come, the technologies being proposed 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 manufactured, they are likely also to be deployed in near-shore situations singly or in small groups. Many or most projects will be ‘distributed generation’, not because they are spread across the country, but because they will be rated far below the average 50 MW level at which projects will be directly linked to the transmission grid, so they will feed into the distribution grid. And these technologies will be ‘local energy’ and potentially have local ownership, when deployed in small numbers to serve coastal industries or communities.
The route from research to industry
UK industry has felt for many years that it ‘lost the lead’ on wind power: it was at the forefront 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 UK government has been willing to help support new facilities that are intended to shift technology 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 first offshore wind farm. It will house the UK’s most sophisticated wave simulation tank. While onshore development takes place in north-east England, Scotland’s Western Isles will be home to offshore work in seas that are ultimately likely to have wave and tidal generators in commercial operation. The £5.65 million European Marine Energy Centre (EMEC) on Orkney is a one-stop facility for the industry to test wave-energy generators and other devices
and measure their potential output in realistic conditions. Its aim is to stimulate and accelerate the development of marine-power devices in Scotland, providing home-based companies with a head start in exploiting wave- and, later, tidal-energy technologies. EMEC is centred on two main sites on Orkney. One is a control and switchgear centre at Billia Croo, which is connected to both the UK electricity grid and four offshore testing berths, while EMEC’s main offices and data centre are situated in the Old Academy, in Stromness. EMEC offered several offshore test berths for wave-energy converters, along with connections to onshore laboratory and analysis facilities. The wave test area is now being followed by an area to test tidal-energy devices off the nearby island of Eday. The step from research to deployment of full-scale devices at near-commercial scale is a daunting one for any developer, but in the absence of new initiatives from the UK central government it was a local enterprise agency in the far south-west of the country that took the initiative. The South West Regional Development Agency proposed to install an offshore connection for wave and tidal projects that would enable several arrays of different devices to be operated for a restricted period that would enable them to prove their commercial viability. Although it is far from the northern shores where wave and tidal projects were initially demonstrated, the southwest has some of the country’s most energetic tidal and wave areas, and the project is consistent with an existing commitment in the region – one traditionally ill served by the existing power network – to develop renewable energy expertise. Wavehub, as the project is known, would enable developers to install demonstration 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 would also greatly reduce other barriers to deployment, notably the requirement for timeconsuming and costly environmental-impact reports, and the need to wrestle with the UK’s notoriously obstructive planning process. Instead, Wavehub would carry most of the burden of these two processes, and the projects themselves would provide limited environmental-impact statements and would not require planning permission for any dedicated onshore facility. Preliminary work began on Wavehub in 2007, and the government pledged to provide 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.
Marine Current Turbines
The tidal-stream generators under development by Marine Current Turbines function similarly 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 that cause them, unlike wind or wave energy’. The technology under development consists of axial-flow rotors 15–20 m in diameter, each driving a generator via a gearbox. The power unit of each system is mounted
on a tubular steel monopile some 3 m in diameter, which is set into a hole drilled into the seabed from a jack-up barge. The company has dealt with the problem of maintaining undersea turbines by a hoist system: the turbines will be lifted clear of the 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 are smaller and can be packed closer together, so the company says they have little land use or other environmental impact. The rotors turn slowly (10–20 rpm) – around one-tenth the speed of a ship’s rotors. The risk of impact from the rotor blades is extremely small. Marine Current Turbines completed its first grid-connected marine-current turbine, rated at 300 kW, in 2002 at Lynmouth off the North Devon coast. It benefited from being adapted from well-known wind-turbine designs and from the ability to raise the turbine above the sea’s surface to carry out maintenance. Marine Current Turbines has won support from Northern Ireland and from Wales for Seagen, an undersea turbine rated at over 1 MW. In Northern Ireland, the company is planning to install a 1 MW experimental turbine in Strangford Lough Narrows in the spring of 2006. This is a research project involving a single-monopile-system tidal turbine to be installed for a period of between two and five years; it will then be removed. The Northern Ireland government hopes that in the long term arrays of turbines can eventually be deployed in the open sea off the coast of the province. The company has also announced plans to investigate the potential for a commercial tidal-energy farm in waters off the Anglesey coastline. The project has received £700 000 of grant support from the Welsh Assembly Government’s Objective 1 programme. A seven-turbine energy farm in waters off Anglesey should produce 10 MW. The company also has plans for a 12 MW array off the North Devon coast.
Ocean Power Technologies plans to install a 5 MW project at Wavehub, based on its PowerBuoy wave-energy converter. The PowerBuoy system consists of a floating buoy-like device loosely moored to the seabed so that it can freely move up and down in response to the rising and falling of the waves. The sealed unit also contains a power-takeoff device, an electrical generator, a power electronics system and a control system. As the buoy’s float moves up and down on the central spar, the mechanical movement drives a hydraulic pump that forces hydraulic fluid through a rotary motor connected to the electrical generator. The power-takeoff device converts the movement 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) of the 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 approximately 19 m (62 feet) long with approximately 5.5 m (18 feet) protruding above the ocean surface.
Ocean Power Delivery’s Pelamis system is described by the company as a semisubmerged, articulated structure composed of cylindrical sections linked by hinged joints. The wave-induced motion of these joints is resisted by hydraulic rams, which pump high-pressure oil through hydraulic motors via smoothing accumulators. The hydraulic motors drive electrical generators to produce electricity. Power from all the joints is fed down a single umbilical cable to a junction on the seabed. Several devices 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 diameter and have an output of 750 kW. OPD secured £6 million funding from an international consortium of venturecapital companies that included Norsk Hydro Technology Ventures, 3i and Zurichbased 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 Prospect Group, will trial up to ten Pelamis P750 devices developed by Ocean Power Delivery of Edinburgh at Wavehub.
The third berth at Cornwall’s Wavehub will be taken up by Fred Olsen Ltd, which will install a multiple point-absorber system for energy extraction. The fourth will be Oceanlinx, an Australian company. Oceanlinx has installed a prototype of its device, which uses an oscillating water column driven by the waves to generate power, at Port Kemble in Australia. The Wavehub connection will allow it to demonstrate the technology in UK waters. A number of floating buoys attached to a light and stable floating platform manufactured in composites convert the wave energy to electricity. The UK’s biggest stumbling block is the support it provides for new technologies making the jump from demonstration to commercial technologies. In theory, all renewable-energy technologies are supported by the ‘technology-blind’ Renewables Obligation, which forces electricity suppliers to source a growing proportion of their power from renewable generators or pay a per-megawatt hour fine. The Obligation was supported by tradable electronic Renewables Obligation Certificates (ROCs) generated along with each megawatt hour of renewable electricity. But the Obligation was designed to bring the most developed technologies – in practice, onshore wind – on stream as quickly as possible: there is no incentive to use newer options that will be necessarily more expensive before they have achieved economies of scale and passed the uncertainties of new deployment.
Limpet and Osprey
Two similar devices developed by Wavegen, known as Limpet and Osprey, use a partially submerged shell. As the water enters or leaves the shell, the level of water in the chamber rises or falls in sympathy. A column of air, contained above the water level, is alternately compressed and decompressed by this movement to generate an alternating stream of high-velocity air. The air passes through a Wells turbine, which turns in the same direction regardless of which way the air is flowing across the turbine blades. The Limpet version of the technology is sited on the shoreline. A 75 kW demonstration 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 – was installed in 2000. The Osprey 2000 is Wavegen’s offshore version of the oscillating-water-column technology. It rests directly on the seabed and is designed to operate in the near-shore environment in a nominal mean water depth of 15 m. Rated at 2 MW, it is expected to feed into an existing grid or, with a standby support, be used as a prime power source for remote island communities. In May 2007, Wavegen won a £2.3 million grant from the UK’s DTI (now the Department for Business, Enterprise and Regulatory Reform) to support the development and demonstration of a series of three Osprey devices, which will be sited off the Western Isles of Scotland, using the new test facilities on Orkney.
Stingray was developed by the Engineering Business, a company that provides equipment and services to offshore businesses including submarine cabling, and the oil and gas industry. Stingray consists of a hydroplane that moves in an approaching tidal water stream. This causes the supporting arm to oscillate, which in turn forces hydraulic cylinders 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 DTI awarded the company a £1.6 million grant to allow a demonstration project to be carried out. The site chosen for the project was at Yell Sound, where a current meter installed on the seabed showed a peak spring-tide velocity in excess of 5 knots. At this site a Stingray 24 m high, using a hydroplane some 15 m across, would be rated at 150 kW.
Stingray is one tidal power design whose development has been halted. UK developers complained that, although the UK government has provided support for wave and tidal technologies at the research-and-development phase, its support in making the leap to a commercial technology was inadequate.
The UK initially offered limited capital grants and ROCs – the UK’s major support programme for renewables – for all energy exported. Developers argued that this was inadequate for this phase. One problem was that the ROC payment was simply not high enough to support these technologies. What is more, because of the structure of the Renewables Obligation the value of a ROC could vary considerably, making financing more difficult. In addition, most technologies would provide relatively low amounts of power from each single device. Achieving economies of scale, and therefore lower prices, would not come in the first commercial deployments but when they 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 it provides the developer with a fixed and certain return – provided that the project generates successfully. What is more, better performance means a better return. Consistent lobbying for additional support in the UK was successful, but it is not clear how effective the extra support will be. The UK government, following a proposal taken forward by the Scottish Executive, will give additional ROCs for each megawatt hour of electricity generated by the wave and tidal projects – double ROCs if the Scottish Executive’s model is followed fully. This should double the amount of subsidy provided for generation, especially in the light of other changes planned for the Obligation that would maintain ‘headroom’ between the amount of renewables available in the UK and the Obligation (target) that had to be met by electricity suppliers. That change should maintain the value of a ROC. Developers, however, have argued that such a change, although welcome, may not be enough to convince potential project developers, and it must be accompanied by higher capital grants.
Solar power can be used both for water heating, as at this project, and to produce electricity directly. Solar power sometimes causes confusion because there are two ways of using the sun’s energy directly. If what you want is heat – for warm rooms or hot water – you need solar thermal as described in Chapter 3. But if you want to generate electricity you need photovoltaics – PV for short.
PV panels turn sunlight directly into electricity, thanks to a property of their major component – silicon, the most abundant element on earth.
Metals conduct electricity if the outer electrons on each atom are attached to the 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 that surround them, but some are held less tightly than others and the right-sized hit of energy can knock them loose. Sunlight provides that energy hit, so when light shines on it some electrons are freed. Once the electrons are freed they can flow around a circuit – and that is an electric current. Note that it is the light, not the heat, from the sun that enables the electricity to flow, so photovoltaics are just as effective in cold countries as in hot – provided there are long hours of sunlight.
Assembling the PV panels
The principle is fairly simple, but turning a few stray electrons into usable electricity requires some complex engineering. First the silicon: although it is available almost everywhere in rock form, to take the best advantage of silicon’s PV property it is best grown as a single crystal. The crystal is cut into very thin wafers, and each forms the basis of a PV cell. Usually the wafer is treated to improve its photovoltaic property (known as doping). To extract the electricity, the wafer is printed with a fine metal grid and then covered with an antireflection coating. It is sometimes placed on a second material – a substrate that improves its photovoltaic properties. The bottom is coated with aluminium and fired. These assemblies are the ‘cells’, the characteristic circles seen inside many PV panels. Between 36 and 72 cells are connected into a ‘mat’ and then embedded in a plastic 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 of the cells and layers of foil behind the cells. The array is framed and connectors are attached. PV cells have been described as an expensive technology reliant on very expensive materials and clearly the manufacturing is a complex process. But they have many advantages. 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 directly into your supply. Once installed, it can last for decades and maintenance is almost nonexistent. Development is moving very quickly, both to reduce the cost of familiar singlecrystal panels, and to use the same principle in a variety of different forms. An early step was to use cheaper multicrystalline silicon instead of single crystals in some panels. Instead of the circular silicon wafers, multicrystalline panels are generally square or rectangular, but close up it can be seen that the substrate is made of small pieces of silicon. Multicrystalline panels are much cheaper to produce, because ‘growing’ large silicon crystals is energy-intensive.
Also of growing interest is thin-film PV. The process uses an automated production line to apply a ‘thin solar coating’ to rolls of flexible foil, using amorphous silicon – far cheaper 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 multicrystalline and thin-film PV are less efficient at converting light into electricity than single-crystal cells, but their lower cost and greater flexibility make them suitable for many different types of installation. Obvious areas for their use are in atriums, on louvres and in cladding. The real opportunities for photovoltaics are beginning to arise now that new PV technologies are considered from the early stages of designing a building. This dramatically reduces the costs of installing PV because it can replace other materials such as cladding. What is more, when PV is retrofitted on an existing building, much of the cost arises from the installation – scaffolding, removing materials where necessary, 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 can be installed in an array of any size.
Because, once assembled, PV is so simple to connect and does not require the moving parts – turbines, generators, etc. – of traditional power generation, there are a huge variety 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 a positive benefit, as devices can be sized to match the application. A short journey reveals many devices in operation to illuminate signs, or provide street lighting or bus-shelter lights. More and more, small panels are used to power isolated items of equipment by the roadside or along railway track, or in rural areas and sometimes with small wind turbines to work alongside the panel. The key to many of these applications is that they are off-grid – they are not connected to the electricity-distribution system. This situation makes PV an economic choice. Cabling an illuminated street sign to be powered from the electricity network is an expensive business, and disruptive if cables need to be buried. Installing a PV panel on the post, on the other hand, is very simple and easy to accomplish. What is more, it can be moved if the occasion demands.
Solar-powered street and transport infrastructure is making a real impact up and down the country in the form of solar-powered bus stops, footpath lighting and traffic warning systems. Many local authorities are experimenting with the installation of one or two solar-powered footpath lights or traffic signs in areas where there is no mains connection and the cost and disruption of cabling to the nearest grid point
would be prohibitive. Plymouth is currently rolling out some 300 solar-powered bus shelters and 40 are on trial in London. Stoke, Manchester, Nottingham and Leicester are soon to follow suit. Plymouth’s is the biggest installation of its kind in the world. The shelters, supplied by Solarcentury in partnership with the street furniture company JCDecaux and using technology 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 company has worked with the architect Norman Foster and the designer Philippe Starck to come up with streamlined and user-friendly street furniture, and supplies around 33 per cent of that in the UK. A big issue in Plymouth is safety. Light is a great companion when one is standing at a bus stop at night, and the panel provides security and timetable lighting in a vandalproof panel. The battery can be stored in the frame of the shelter or below the panel. Solarcentury’s lighting controller drives 6 W LEDs, which give a better output than 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 by Sepco, in November 1999. Sepco has gone on to install almost a thousand units nationwide. It is hard to dismiss the benefits of the Sepco Solarlite shelter, a ‘fitand-forget’ system that requires no maintenance and incurs no costs until the battery needs 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 city has some 200 bus shelters that remain unlit because of the cost and disruption that would be caused by connecting them to the mains. This is all set to change. More than 40 bus stops in the capital are using solar power as part of a trial by Transport for 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 hours of darkness to illuminate the timetable and flag. This is all controlled by an energymanagement system. The solar panels have been supplied by Solarcentury, Sepco and a Canadian company, Carmanah Technologies, and the shelters by the UK engineering firm Trueform.
In order to enhance passenger safety, TfL hopes to install lighting in the remaining 200 bus shelters, as stated in the mayor’s transport strategy. Further stages of development could assess the possibilities of utilizing solar power for real-time passenger information 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 authorities throughout the country. Further west, Ceredigion County Council estimates that opting for a SolarGen traffic warning system saved it some 60 per cent in installation costs, plus the disruption of digging up the road to put in cabling. By opting for solar traffic warning systems there is no need for channelling cables, which will make the installation and maintenance easier. The company says that every light exchanged for a solar-powered light saves approximately £20 a year in electrical costs. Ceredigion saves around four times that amount with each solar-powered light it installs. Newcastle has also installed its first solar-powered traffic signs. The signs, warning motorists of traffic signals ahead, have a PV panel on the top to power up a rechargeable battery. As the panel does not require direct sunlight to charge the battery it can easily cope through overcast days in winter. And when night falls a photoelectric cell switches on the 50 light-emitting diodes (LEDs) to illuminate the sign internally. The LEDs have a life expectancy of 100 000 hours, compared to the 4 000 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 by SolarGen. One is a stand-alone in the Lochs area of Lewis and the other is connected to 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 to replace the antiquated parking meters installed in the 1950s. Schlumberger Sema has installed around half of all the pay-and-display parking machines in the country, amounting to several thousands. The company is turning over half of its manufacturing capability to solar-powered machines, as it is seeing huge growth in the area. It has just installed 456 solar-powered pay-and-display terminals in Edinburgh, and has secured a further contract for solar terminals, again in Plymouth. The only downside with solar-powered pay-and-display terminals is that they won’t function in underground or poorly lit multistorey car parks. But the potential market for the units is huge, as it encompasses not only local-authority parking zones, but company car parks, airport car parks and so on. The Edinburgh machines will be centrally monitored by a communications and database programme, which will provide staff with revenue data and alert engineers whenever a terminal needs attention.
The London Borough of Lambeth thinks councils play an important role in getting renewables into all the UK’s streets. It spends around £50 million on construction every year, which means there is enormous potential to integrate renewables. In Lambeth, the Housing Directorate has taken a lead on sustainability. It fits with the council’s sustainable construction strategy and climate-change agenda, and it promotes good practice in construction. Lambeth Housing has had very positive publicity from sustainable construction and this was another best-practice element to the programme. Lambeth allocated £50 000 each year from the Lambeth capital fund – seed funding 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 housing scheme with 45 dwellings, called Tomkyns House, owned by the council. PV was installed along with solar thermal to reduce carbon emissions and energy costs. The housing department spent around £30 000 on the PV panels and installation and leveraged a further £20 000 to fund the solar thermal from other sources. The PV panels, incorporated into the roof’s safety guardrail, now power communal areas, while the solar thermal will feed into a project that will give residents better and more controllable heating. Lambeth Housing’s first integrated PV roof is a much larger project at Warwick House on the Angel Town Estate. This extensive regeneration project has been under way for many years and residents support a sustainable agenda for the project. Warwick House incorporates high insulation, passive stack ventilation and condensing boilers. Communal lighting within Warwick House will be powered from the PV array on the building’s pitched roof. A local company, Solarcentury, is the preferred PV supplier for the council. The array at Warwick House, supplied by Solarcentury, provides 11 775 kWh/year, roughly equivalent to the communal lighting load. The PV has been partly funded by a £71 614 grant from the (former) Department of Trade and Industry’s Major PV Demonstration Programme. Lambeth’s third project is part of a £600 000 refurbishment at Langholm Close, a sheltered housing block with 43 dwellings. Once again, the project aims to introduce sustainable construction techniques and the housing department plans to use solar shingles, provided by Solarcentury. This project has an 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 of 238 000 kWh/year. Major solar PV schemes are being backed up by thermal projects under the council’s Health and Housing scheme, where the energy strategy officer, Colin Monk, is expanding a scheme to install solar thermal as part of a project to provide central heating for older residents. Feedback from residents has been good and 25 further installations now have secured funding under the Clear Skies programme.
Experience in Grimsby
The DIY chain B&Q had been in discussions with BP about its solar cells. But in 2002 the company did not see photovoltaics as financially viable for a long while. The company’s interest in DG was mainly in on-site microCHP. But at Grimsby the planning department took the lead. During the planning application for a garden centre at B&Q, the local authority asked if the company could install photovoltaics and rainwater harvesting. It had recently given planning permission to another garden centre with the same provisions, and asked the company to generate as much power as would be used to light the plants in the garden-centre area. The company was cautious, and not because of 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 on its 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 m high. BP had used the same technology on its filling stations, so B&Q knew it would work, but had to think about how to install it and calculate the energy balance. There were some practical issues. The panels can be seen from the A16 so the company had to consider whether they would cause dazzle, but the angle is too steep for that to be a problem. The company was also worried about vandalism – bricks being thrown at the panels and so on. But it relied on an existing security fence that was 4 m high, and thought there was little chance that the panels would be hit. At less than 5 kW, the panels are rated ‘domestic’, which made installation easier. However, the company was already discussing its connection agreement with the distribution network operator over a substation problem, and it did not want to delay the opening of the store while negotiating the amendment to allow for the PV. B&Q said that it had to answer the DNO’s concern for the safety of its own employees, who could be making repairs when the normal supply has failed, potentially suffering a back-feed from any small localized generation. It installed an inverter that is synchronized with the grid. If the grid falls away it stops – it doesn’t operate in ‘island’ mode. The question of metering the PV for export did not arise, because in practice the company knew it would never export electricity. The store’s base-load demand 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 described it as a ‘considered experiment’ – it was expensive, but was a small addition to the total cost of the development. One benefit of the panels is that they incur hardly any operation and maintenance costs. The rainwater-harvesting system, in comparison, uses three filtration stages and an ultraviolet scrubber, and maintenance expenses are significant.
Combined heat and power
A common method of generating electrical power involves a process known as the Rankine cycle. A working fluid (often water) is placed in a system at high pressure and 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 then expanded through a turbine, which it turns to produce electrical power. The resulting gas is then condensed into a liquid and returned to the circuit. The process produces electricity, but most of the heat generated to drive the process is wasted – for power stations dispersing this waste, heat is a real problem and 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 the power station – for example, by piping hot water to local homes and businesses in a district heating scheme – makes very little difference to the operation of the power station but can increase the proportion of the fuel that is transformed into usable energy from 30–40 per cent to upwards of 80 per cent.
The UK CHP programme
The idea of regarding both the potential heat and power outputs of a power station as useful products is neither new nor unusual, but the potential has often been disregarded in the UK, even though there are plenty of existing projects that could take account of its opportunity. Combined heat and power, or CHP, has been of most interest to industry that has a high heat demand (see Panel 8.1). It has huge potential for smaller organizations in the industrial and commercial sectors, and equally in housing developments. The UK government’s strategy for CHP development is managed by the Department 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 of changes in electricity-trading arrangements that did not favour CHP plants and made them less attractive to commercial companies.
Since 2000, the government has introduced a package of measures to support CHP. These measures, as reported on in the CHP Strategy, included: • • • • • exemption from the Climate Change Levy for all good-quality CHP fuel inputs and 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 encourage 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 Electricity Trading and Transmission Arrangements (BETTA) for smaller generators, including CHP; emphasizing CHP benefits when planning or sustainable development guidance is reviewed or introduced; reviewing procedures on power-station consents applications to ensure full consideration of CHP; exploring opportunities to incentivize CHP under any future Energy Efficiency Commitment (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 by setting a new target, to source 15 per cent of energy at government offices from CHP. In 2006, the government also commissioned Cambridge Econometrics to assess the potential for a CHP Obligation, and a number of other support schemes have also been proposed.
EU Directive support
CHP received additional impetus after the EU passed the Directive on the Promotion of Cogeneration (Combined Heat and Power) in the EU. The overall objective of the Directive is to create a framework to facilitate and support the installation and proper functioning of cogeneration where a useful heat demand exists or is foreseen. The main measures contained within the Directive are: • • a ‘guarantee of origin’ to be readily available for electricity produced from cogeneration; obligations on member states to analyse national potentials for high-efficiency cogeneration and barriers to their realization;
Combined heat and power • • •
provisions for evaluating different support mechanisms for cogeneration used by member states; provisions laying down the principles for the interaction between cogeneration producers and the electricity grid; and provisions requiring member states to evaluate current administrative procedures with a view to reducing the administrative barriers to the development of cogeneration.
The Directive came into force on 21 February 2004. The government said its CHP Quality Assurance (CHPQA) strategy meant the UK was largely compliant with the Directive, but proposed further action in a consultation at the end of 2006. The European Commission’s 1997 Cogeneration Strategy set an indicative target of doubling the share of electricity production from CHP in total EU electricity production from 9 per cent in 1994 to 18 per cent by 2010. But in the time since then there 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 1997 Cogeneration Strategy and its Communication on the implementation of the European Climate Change Programme. The purpose of the Directive is to promote high-efficiency CHP wherever an economically justified potential is identified in order to save energy and reduce carbon dioxide emissions. It does this by creating a framework that can support and facilitate the installation and proper functioning of CHP where a useful heat demand (heat produced in a CHP process to satisfy an economically justifiable demand for heat or cooling) exists or is foreseen.
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 of using waste heat to generate electricity. The Stirling engine was invented over a hundred years ago and for many years has been used in specialist applications. Stirling engines are efficient and quiet but in most cases it is an unhurried technology, which takes a while to build up to full speed and almost as long to slow down without extensive braking systems. Like all engines, the Stirling engine works because hot air expands. If you heat air in 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 system between two cylinders with pistons in them, at different temperatures. The working gas inside the engine (which may be air, helium or hydrogen) is moved by a mechanism from the hot side to the cold side. When the gas is on the hot side it expands and pushes up on a piston. When it moves back to the cold side it contracts, pulling the piston on that side.
Once the gas has expanded into the hot side it would stay put, except that the piston is pushed back up by the crankshaft as it continues to turn. And it continues to turn because it is attached to a heavy ‘flywheel’. This is also the reason why Stirling engines are slow to start up, as the flywheel is storing energy and it takes a few revolutions to get it started. Some Stirling engines can run on very small temperature differences – American Stirling Company offers educational versions that can be run on a cup of coffee. But the company explains that, as the temperature difference becomes smaller, the size of the Stirling engine that would be needed to get them to do anything useful becomes unfeasibly large. So the best versions use high temperatures – such as gas burners – on the hot side.
Developing domestic technologies
Over the last few years companies such as BG Group have been investigating Stirling engines as combined-heat-and-power plants for domestic and commercial uses. Two products based on very different applications of the cycle were investigated. The New Zealand company Whispertech began work on Stirling engines in 1989 and released its first commercial DC units in 1998. Whispertech says its version combines four piston-cylinder sets in an axial arrangement, with the hot end of one cylinder attached to the cold end of the adjacent cylinder. The company says that, if the power from the pistons was transferred to a rotary motion by a traditional crank type of mechanism, it would put considerable side loading on the pistons and cause rapid guide and seal wear – traditionally a life-limiting factor in Stirling engines. Instead, it has developed a ‘wobble-yoke’ system to convert the linear motion of the engine’s four pistons into the rotary motion necessary to drive a generator, while putting very little side load on the piston seals and guides. The wobble-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 and based on a linear-free motor. The CHP unit is started up in synchronization with the grid and a planar spring acts with the control system to maintain its frequency at 50Hz.
Development of both microCHP units has been problematic. The target is a tough one: it is hoped the technology will replace conventional boilers, but that means reducing its size to fit a standard kitchen spacing. It is unlikely that capital cost and installation charges will ever be as low as standard boilers, so customers will have to be convinced that the benefit of lower electricity bills over time will outweigh the upfront cost. The opportunity to export excess power to the grid could be a major selling point for such products. But the grid structure in England and Wales is notoriously unprepared for such small-scale export.
Combined heat and power
As late as November 2001, for example, a framework document for design and planning of low-voltage networks in greenfield housing estates referred to PV generation as a possibility but said that domestic generation was unlikely in greenfield estates – by then, BG Group already had nine microCHP prototype units in operation in UK houses. As distributed generators of all sizes have found, connection requirements are not uniform across the UK. New generation coming onto the system usually has to apply to 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: the requirement to pre-notify the DNO and obtain agreement for a microCHP installation would be replaced by a ‘fit and notify’ arrangement. The original requirement would have made it almost impossible to install microCHP ‘on the spot’ – for example to replace a broken-down boiler – and removed a major opportunity. A second issue is metering output from the microgenerator. Companies involved in domestic generation have lobbied for bidirectional meters that would simply record the net import of generation, but the industry regulator Ofgem has consistently opposed this approach, and says that, since in every case a new meter would be required, ‘there is merit in being able to measure import and export’. In the past, Ofgem’s distributed-generation coordinator has pointed out, ‘If you don’t export much, it doesn’t matter too much. But say you have a development of three or four hundred houses and a distributed CHP plant. You have a considerable amount 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: microgeneration has been exempted from the requirement for half-hourly metering normally mandatory 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 little power 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 hot water and that also coincides with peak electricity consumption, when most domestic users 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 the country’s load profile, rather than in providing large quantities of power for export. Up to 13 million homes in the UK could use gas-fuelled microCHP and, with all of them generating at peak times, the country’s winter peak demand would be significantly reduced. That would mean lower peak prices and reduced requirements for reserve capacity. But once again Ofgem has counselled caution, noting that when heating demand disappears in the summer all those customers will once again need to meet their demand from the grid. The units also offer greatly improved efficiency. Using gas to generate electricity in 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 the gas to electric power, and many are far less efficient. More of the power is dissipated
as it is transmitted through the power network. But because all the heat produced by 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 without allowing for the energy required to transmit the gas to the point of use, that is a huge improvement.
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 is whether domestic consumers – and installers – will accept microgeneration. So far, British domestic consumers have proved to be fairly resistant to new technology of this type. Condensing boilers, for example, have been very slow to penetrate the domestic market – their higher capital cost weighing more with consumers than their higher efficiency. Some observers have suggested that microCHP may be blocked by supply companies, but in fact other pressures on the UK market may mean that far-thinking suppliers become its best advocates. The government’s increasing focus on energy efficiency and demand reduction means that supply companies are already under pressure to become more than simple electricity suppliers, or look forward to competing in a shrinking market. That means acknowledging that the customer’s real need is seldom for electricity. Instead it is for heat or for cooling, for example, and providing energy services rather than kilowatts. MicroCHP suppliers see a potential market for their products anywhere there is a significant heating season, relatively expensive electricity and a good domestic gas network. That makes Western Europe a core market (Microgen is also investigating connecting its system to a furnace for the US market, where forced-air heating is more 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 from microCHP development, citing problems with reducing the size of the unit, along with noise. Development has not stopped: major boiler supplier Baxi has taken over development of Microgen and at the time of writing it was planning to bring a domestic product to market at the end of 2008. There are problems to be solved at the domestic scale, 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 at the 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 is generally housed in a dedicated room or a basement, so noise restrictions are not so onerous.
Combined heat and power
This type of arrangement is common in apartment blocks in many European countries. 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 and therefore carbon dioxide emissions. Switching is not necessarily technically complicated, but it does require understanding from those who own and manage properties. Once again, the capital cost is almost certainly higher, but whole-life costing makes the CHP option more attractive. CHP is an option at the moment that is easy to ignore or dismiss in the commercial sector as not offering a return on investment. Two major policy changes may shift that perception. First is the work of local councils. Since 2000, upwards of half the UK’s 300 or so local councils have added new requirements to their planning standards that make it mandatory for new developments to include energy-efficient or 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 other new policy, proposed in 2006, would see energy users in the smaller commercial, industrial and public sectors given carbon dioxide emissions allocations in a trading scheme intended to parallel that used for large emitters across the EU (the Emissions Trading Scheme, or ETS – see Chapter 19). That would also make CHP an attractive option because any additional cost for the CHP, compared with a standard boiler, would be balanced by the potential for extra income from reducing carbon dioxide emissions 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).
Good projects on paper
A new CHP plant at M-real’s Hallein mill in Austria will provide it with 21 MW of process heat in the form of steam, along with 5 MW of electricity to export to the power grid at favourable rates. The decision to build the new plant was an economic one, says manager Erich Feldbaumer, and it seems the carbon dioxide ETS tipped the balance. 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 are augmented by a dual-fuel plant, running on heavy fuel oil or gas, that supplies steam at 75 t/h. Four additional fossil-fuelled steam blocks provide 30 t/h and a reheat boiler has 1.5 t/h available as backup. The new CHP plant will replace the four steam blocks. It will be fuelled with sludge, bark and other residuals backed up by wood from local forests. Fuelling the new plant will require the plant to process some 250 000 m3 of residuals Continues
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 any case, 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 site change.’ Operation and maintenance will be performed by Hallein’s existing utilities department, whose 36 members already manage the existing steam units and other auxiliary processes, providing a round-the-clock service in five sixmember shifts. Where the new CHP plant will change operating philosophies is in the ranking of power units: the new plant will be ranked second and will be 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 supplied with energy that has the least possible environmental load. In the spirit of this principle, UPM has invested during the past few years in the utilization of biofuels. Now such fuels account for 60 per cent of the company’s total fuel consumption. 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 recovery 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-treatment plants. Chemical pulp mills burn black liquor that forms during the pulping process. The new sludge boiler at Shotton Mill in the UK will combust all sludge produced in the recovered-paper recycling process. To support the combustion of mill sludge, biomass fuels will be co-combusted. The investment will increase Shotton’s self-sufficiency in heat by up to 90–95 per cent and in power by up to 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 energy wood (branches, tops and stumps from logging operations) available in the region and all the sludge produced in its recovered-paper recycling process. After this investment the production process at Chapelle Darblay will be carbon-dioxide-free. In Finland the use of biofuels has increased and five new CHP plants have been built. At UPM’s Rauma paper mill on the west coast of Finland the plant will produce electricity, steam for the paper mill and district heat for Rauma city.
Combined heat and power
The London Borough of Tower Hamlets says it has nearly alleviated fuel poverty on the Barkantine housing estate thanks to the Barkantine CHP project, which it built and operates in partnership with London Electricity Services (part of EDF). The CHP unit provides hot water and electricity to 540 households on 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 investigate 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, is in 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 profits every second year to invest in energy-saving measures on the estate.
Wood is one of the oldest biomass fuels and still has an important role to play.
Wood fuel can come from conifer forests, broadleaved woodlands, urban and roadside trees, clean by-products and offcuts from wood processing. It may be purpose-grown as short-rotation coppice (SRC), where high-yielding species such as willow and poplar are planted at high density and harvested at three- to five-year intervals. A wide variety 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.
From an environmental point of view, burning wood from sustainably managed forests – that is, forests where harvested trees are replaced – has little net impact on carbon dioxide emissions. In Britain, a fuel market for currently unsaleable small roundwood could bring many small and derelict woodlands back into active management with benefits for wildlife and rural employment. Wood has provided heat for millennia, but only recently has modern technology increased efficiency and automation. In northern Europe and North America, woodburning technology is widely used and markets are large and well developed. In northern Europe, medium-sized, automated central-heating systems underpinned by capital-grant schemes were used to develop the markets, after which large-district heating, 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 in some countries. Britain’s Forestry Commission exports timber for this purpose. The Commission recently supplied 2 000 tonnes of timber via a merchant from its North York Moors forests to Denmark for use in wood-burning power plants.
In Britain there are comparatively few (perhaps a hundred) automated, wood-fired central-heating systems, mostly in businesses that produce considerable volumes of waste wood that they can use themselves, or on large rural estates. A handful of wood-fired-power or CHP schemes were also in operation as of mid-2002. Indigenous suppliers of both fuel and burners are small and few in number. Scotland, Wales, East Anglia and the south-west of England are out in front, with the West Midlands close behind. The Forestry Commission is working with private forest owners, potential customers and government departments to identify opportunities for wood fuel. The Commission has produced a draft wood-fuel policy, which looks at the obstacles to developing a wood-energy industry and outlines ways to overcome them. England, Wales and Scotland are developing their own wood-fuel strategies to meet their particular pressures and conditions, but the Commission has also outlined a broad three-phase framework strategy as a guide for moving forward. In Phase 1, the Commission will seek to stimulate and promote markets for wood fuel by focusing on existing or low-risk technologies. It hopes that development of markets for heat and co-firing with coal for electricity generation will demonstrate that a market for wood fuel exists and improve the knowledge base and operating systems, 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, evaluate new technologies and systems (especially co-firing with gas, pyrolysis and ethanol production), and improve perceptions of wood fuel. Finally, Phase 3 will build on pilot projects by introducing the most successful technologies and systems identified at the pilot stage. At the same time, the sustainability of various levels of wood-fuel removal will be monitored and, where levels are unsustainable, practices adjusted to ensure sustainable forest management.
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 organizations and individuals wanting to use wood heat. It is now ready to support installations and keen to start an ESCo. Herefordshire Sustain Project was started in February 2001 by the Small Woods Association. 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 buildings, including the college, so acting as an educational resource on sustainability courses. Worcestershire County Council has installed a 700 kW wood-fired central-heating system at County Hall, and another at Garibaldi School in Mansfield, with plans to replicate on eight other sites. The council works via a contract with a private-sector ESCo and there is no public subsidy, although the total cost will be a little higher over the next ten years than an equivalent gas-fired system. The partnership has established a not-for-profit renewable-energy company, Renewable Nottinghamshire Utilities (ReNU). ReNU has already secured DTI and New Opportunities Fund (Lottery) funding to subsidize the installation of 4 MW of wood-fired boilers to operate under energyservices contracts. The initial tranche of boilers is being funded through the Public Sector Agreement Initiative and ReNU will secure fuel of sufficient quality and quantity under a fuel-supply agreement. These sources include wood from sustainably managed local forests and woodlands, clean recycled waste wood, new dedicated energy forestry, and potentially short-rotation coppice. The Forest of Mercia, one of 12 community forests nationally, started in 1990 with local-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 offices have been heated with wood and an action plan for extending wood-fuel use has been produced. 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 processing and manufacture. The creation of a national forest will provide a significant extra and growing resource, with around 500 ha of new woodland per year. Cost will be a critical factor, but currently there is a surplus of low-grade material that could be used. Figures quoted for wood fuel have been in the region of £40.00–45.00/ovendry tonne delivered (equal to £20.00–22.50/green tonne with a 50 per cent moisture content). A similar strategy is being developed in the south-west. With an investment from the government of £100 million, DEFRA’s Energy Crops Scheme encourages landowners in England to diversify their business by setting up producer groups and planting energy crops. New energy-efficient schemes to heat homes, schools and other public buildings received more than £6 million in direct
grants, adding to another tranche of £22 million already handed out to projects under the government’s Community Energy Programme. The investment has prompted plans for five large biomass power stations and seven small-scale biomass heating projects in England. These could produce enough heat and electricity to meet the needs of more than 90 000 homes – equivalent to a city the size of Southampton.
Wood for Wales
Since it is facing a decline in the home-grown timber market, developing a domestic wood-fuel market is a key objective of the Welsh Assembly’s Strategy for Woods and Trees. The Forestry Commission in Wales launched a Wood Energy Business Scheme (WEBS) to foster the development of a wood-fuel industry in Wales by providing capital grants for wood-fuelled boilers and ancillary equipment. WEBS is a support programme for businesses in the Objective 1 areas of West Wales and the Valleys, and the Objective 2 area of Powys. It has been established by Forestry Commission Wales on behalf of the Welsh Assembly Government, with European funding through both Objective 1 and 2 mechanisms. WEBS will provide appropriate projects with grant support to facilitate the installation and operation of wood-fuel-powered heating and power generation plant, and equipment for the initial processing of roundwood into chip and pellet form. By doing so it will provide the pump-priming impetus for development of a viable supply infrastructure. This in turn provides a real incentive for landowners to bring woodland back into management, with associated environmental benefits, and potential rural employment prospects. The scheme will provide grants towards the initial capital cost of relevant plant and equipment, typically boiler systems, drying facilities and wood-chipping/pelleting machinery, to businesses able to provide a detailed business case for a wood-fuelled system of between 80 kW and 2 MW capacity. This will typically be small to medium public buildings, such as schools, hospitals and leisure centres. It will also support district heating or CHP installations that supply heat to a number of buildings and power to the National Grid. The percentage grant available will depend on the strength of the case for support and the actual location, but will be potentially as high as 50 per cent. In order to ensure that sufficient supplies of fuel are available before the privatesector supply comes on stream, Forestry Commission Wales has agreed to allocate 100 000 tonnes of small roundwood from its own felling programme in the initial years of the scheme. Wales already has a community wood-heating project. In 2000 Powys Energy Agency was consulted on replacing the boiler to heat a school and community centre at Ysgol Vyrnwy, Montgomeryshire. After realizing that the school and community centre could be heated with locally sourced wood fuel, the local authority and the Forestry Commission explored the
possibility for a community heating system. A feasibility study funded by the EST showed this to be viable. The idea was presented to the community through open meetings and a questionnaire, the results of which showed interest from 30 local households. Following two years of project development, the tender process and selection of energy supply company took place between December 2002 and March 2003. The boiler was installed in August 2003 and commissioned in November 2003. The school and community centre now receive heat from the 520 kW Compte woodchip, remote-automated boiler. The houses are connected to the boiler by a hotwater pipe referred to as a heat main. Hot water will continue to be available in the summer, when there is little demand for space heating. There is a 350 kW backup oil boiler. The project involves a number of partners including Ysgol Vyrnwy, Llanwddyn Community Council, Antur Vyrnwy, Severn Trent Water, Powys County Council (legal, education, planning, community development, etc.), Forestry Commission Wales, Forest Research Board, Powys Energy Agency and Dulas Wood Energy. The system is owned by Powys County Council and Powys Energy Agency. It was installed, and is now operated and maintained, by Dulas Wood Energy.
As part of its broader nationwide strategy, the Forestry Commission has scientists at the government-funded research body Forest Research working on a study to quantify the volume of wood fuel available from woodlands, purpose-grown energy crops and other sources. The programme has established a UK-wide network of more than 50 trial sites and aims to produce definitive data on the SRC yield of more than 30 varieties of energy crop. The network of trial sites is funded in partnership with the predecessors of BERR and DEFRA (the DTI and MAFF), the Department of Agriculture and Rural Development in Northern Ireland and industrial members of British Biogen. The study summarizes existing information to give temporary guidance on establishment, indicative yields, harvesting operations and approximate costs to help the evaluation of these types of crop as sources of renewable biomass. Results from the trial are posted on the Forest Research website. The project is the largest field trial in the UK, and in Europe, of poplar and willow species grown as crops for the provision of biofuels. Its main aim is to develop models that will forecast growth and yield performance in different climates and sites. Fast-growing willow and poplar are among the most promising tree species for SRC, and the website shares the results of research trials. It also pulls together practical information on cultivation and on grant support, intended to help existing and potential growers as well as the policymakers. At present, economic and logistical factors are the main constraints to the successful development of Britain’s wood-fuel industry. The costs of felling, transporting and drying wood fuel mean that current prices for wood fuel do not offer much in the way
of a profit margin to the producer. Moreover, the potential market for wood fuel is as yet undeveloped. Although some companies in a few locations have found niches where they can operate at a profit, these developments are still at an early stage, and large-scale markets have not yet been proven. Logistical constraints may be a larger obstacle to development. Britain does not currently have enough biomass to generate the expected proportion of the government’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 and timber – is essential. The regional availability of resources is also uncertain. National figures estimate that by 2010 available wood-fuel resources will be around 4 million m3 , but it is more difficult to say what is available in a particular area and at a particular price. A detailed breakdown of present and future resources is therefore needed to determine what is available within a realistic radius of a potential wood-fuel development point, and this will hopefully emerge from the trial results.
What is pyrolysis?
When biomass breaks down it does not transform directly from wood into carbon dioxide. During the process a variety of smaller organic compounds are produced and then broken down further. At some points in the process the intermediate products can 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 gas and liquid (e.g. oil or diesel) produced from fossil fuels. As a result, they may be available as replacements, or to mix with fossil equivalents. In pyrolysis the first stage of the breakdown involves heat but no oxygen. In some aspects it is a process that has been known for hundreds of years, as when charcoal burners heated wood in insulated burners over a slow fire. The charcoal is light to carry and has good clean-burning characteristics. What the charcoal burners did not know was that the natural gases and oils produced during the process could also be burned, as we use fossil-sourced gas and oil. Some process conditions, including low temperature, favour the production of charcoal. High temperature and longer residence time increase the biomass conversion to gas. Moderate temperature and short vapour-residence time produce liquid oils. In effect, pyrolysis converts biomass to products that can replace those used in our conventional fossil-based processes. Pyrolysis is always the first step in combustion and gasification processes, where it produces a gas that can be used to operate gas turbines. Fast pyrolysis for liquid production is currently of particular interest, as the liquids are transportable and storage 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 the chemical reaction but also on transporting the feedstock to the reaction process and on removing the heat produced. The reaction takes place at a temperature of around 500 ◦ C and residence times of typically less than 2 s.
In fast pyrolysis, biomass decomposes to generate mostly vapours and aerosols and some charcoal. After cooling and condensation, a dark-brown liquid is formed that has a heating value about half that of conventional fuel oil. Bio-oil can substitute for fuel oil or diesel in many static applications, including boilers, furnaces, engines and turbines. There are a range of chemicals that can be extracted or derived, including food flavourings, specialities, resins, agrichemicals, fertilizers and emission-control agents. Upgrading bio-oil to transportation fuels is not economic, although technically feasible. While it is related to the traditional pyrolysis processes for making charcoal, fast pyrolysis is an advanced process, with carefully controlled parameters to give high yields of liquid. The main product, bio-oil, is obtained in yields of up to 75 per cent wt on a dryfeed basis, together with by-product char and gas, which are used within the process to provide the process heat requirements, so there are no waste streams other than flue gas and ash. A fast-pyrolysis process includes drying the feed to typically less than 10 per cent water in order to minimize the water in the product liquid oil (although up to 15 per cent can be acceptable), grinding the feed (to around 2 mm in the case of fluid bed reactors) to give sufficiently small particles to ensure rapid reaction, pyrolysis reaction, 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 most work has been carried out on wood due to its consistency, and comparability between tests, nearly 100 different biomass types have been tested by many laboratories ranging from agricultural wastes such as straw, olive pits and nut shells to energy crops such as miscanthus and sorghum, forestry wastes such as bark and solid wastes such as sewage sludge and leather wastes.
Part of the reason why the electricity system requires such careful management is that electricity is not a storable commodity. If a peak in demand is on the way, or may be on the way, it is not possible to store up a pile of electricity and release it at the right moment. This has important implications for managing the electricity grid. Electricity demand is not constant. It tends to go up and down depending on the time of day and of year, as different groups’ electricity requirements begin and end. The biggest peak is generally on a winter evening, when domestic demand for heating, lighting and other 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 company has to be to invest in a diverse range of generation that will give it the best opportunity to match supply and demand.
Diverse energy in the network
A mixed system makes the best use of the different types of generation. Some forms of generation are slow to start up and have little flexibility in operation, but in continuous generation they are cost-effective. These plants would typically be operated continuously 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 up within minutes or hours and cycled up and down to provide more or less power would be brought on to the system as load increases during the daytime and the industrial load increases. Finally, power would be added from very flexible generation to supply morning or evening peaks. Within this scenario different forms of renewables also have different characteristics. Wind energy is predictable in broad terms over a few days and in more detail over a few hours. Wave energy relies in part on the weather and so is affected by expected weather patterns over days and hours, but is also a function of the physical landscape. Tidal power is very predictable but not constant, as it will come on to the grid in regular peaks whose timing varies in a predictable way with the tides. The grid operator cannot predict demand in perfect detail, so ‘spinning reserve’ – effectively plants operating in neutral, or instantly available power such as hydropower – has to be available to feed into the system at any moment. This is one reason why a large proportion of a single form of generation can be costly for the
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 French grid operator, which are alleviated by selling excess power at times of low French demand to its neighbouring countries. Countries with high proportions of wind power sometimes find that additional spinning reserve is used, either because more wind than expected results in additional wind generation, so other forms of generation are taken out of supply, or to be ready for a potential loss of wind generation if wind speeds 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 available at times when the system cannot use it. Since the electricity cannot be stored, the alternative is to store a proxy – for example, by charging a battery. The biggest form of energy storage used worldwide is water.
Hydropower plants, where water is stored behind a dam or, at smaller scale, in a millpond, are already offering an opportunity to store energy in the form of water. If it is not necessary to generate at full capacity, or at all, because other generators are meeting the system needs, water can be allowed to collect in the reservoir or pool until the power is needed. In fact, in some countries this is an important feature of the projects. In Norway, for example, reservoirs are filled during the spring by snowmelt and 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 when necessary, and water can be moved from one area to another by pumping. These characteristics 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. In this type of plant there are two (or more) water reservoirs at different elevations and one (or more) generation/pumping station. Water is pumped up to the higher reservoir and released when necessary to flow down through the hydrogenerator to the bottom reservoir. It is a net energy user: it always takes more energy to pump the water up to the top reservoir than can be gained from generating on the way down. And it may be expensive to build – requiring two sets of water-storage capacity and some very robust hydro pumps/turbines in between. But the pumped-storage system adds so much to the overall efficiency of the electricity supply system that it is almost always worth the investment, and in a privatized industry there are plenty of opportunities to operate the plant at a profit. Pumping is done at times when there is excess power on the system and low demand, soaking up base-load power and the intermittent generation. Then, when demand peaks, the stored water is released. It is immediate. One of hydro’s great strengths 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
low and it knocks carbon dioxide-producing gas, oil or diesel plants out of the rankings at peak times. The economic potential of pumped storage has been fully realized in deregulated markets, where price differentials between times of low and peak demand are very clear. The UK built two pumped-storage plants in Wales in the 1970s, expected to pump and generate on a twice-daily cycle to meet peak demand. They fulfilled that role until privatization of the industry at the start of the 1990s, but now they pump and generate 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 peak hours than it does at low load, and electricity bought and sold in half-hourly slots offers many opportunities to buy or sell. Similar possibilities have been picked up by Tasmania, which has huge hydropower and wind resources and a volatile privatized market across the Bass Strait in mainland Australia. Hydro Tasmania now plans to install an undersea cable across the strait so it can operate what will effectively be a pumped-storage system without 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 view that led to the creation of reservoirs far in excess of needs, an awareness that rainfall to feed the reservoirs could vary by 30 per cent from year to year, and a recognition that long-term storage may be required. It is also beginning to develop another of its natural resources: the high wind speeds that arise because of its position in the latitude of the so-called ‘roaring forties’. Hydro Tasmania estimates that wind speeds on its west coast average 8–9 m/s – a ‘world-class wind resource’ – and it believes it has 1 000 MW of wind potential in the area. But the peak demand of the island’s half-million population is growing fairly slowly and Hydro Tasmania is anticipating deregulation and looking for new markets to grow its business. The answer is to ship power across the Bass Strait to the national electricity market to feed the growing needs of Victoria and South Australia. In this market base prices are low, thanks to the ready availability of coal, but summer peak prices are much higher and have been known to hit thousands of dollars for some short periods. Hydro Tasmania hopes to arbitrage this market. The company will save its water reserve at times when prices are low, providing perhaps 600 MW and importing power from Australia to meet demand. At Australian peak times it will generate up to 2 000 MW to supply its own customers and the Australian market. The wind turbines will feed into the grid whenever they are generating, allowing Hydro Tasmania to conserve its water so that it has maximum capacity available when the price is high. Roger Gill, general manager of Hydro Tasmania’s generation division, described the 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 uses the concept in a way that allows the company to get all the energy management and economic 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 of the benefits of large hydro, and the same is true in pumped storage.
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 the system. Water companies have a large number of reservoirs where water is stored before it is sent out to users. Maintaining supplies often requires water to be pumped from aquifers, rivers or other sources into the reservoirs. Meanwhile, water companies are increasingly installing hydro-turbines in the outfall from reservoirs, where in the past there would have been a pressure-reducing valve or settling pond to remove the energy from the water. These are the components of a pumped-storage system. It only remains for the water companies to operate them as such for the benefit of the electricity system – something that water companies are increasingly taking on board.
A situation analogous to pumped-water storage also exists in the gas transmission and distribution network. When fed into the network, gas has to be pressurized for transport, and on arrival that pressure has largely to be released for delivery. It has been proposed that turbines installed at decompression stations can recover some of the energy from the system by generating electricity. Once again, the compression and decompression process is a net energy user. But it allows energy that would otherwise be lost to be at least partially recovered.
In many cases simply using a battery storage system in conjunction with an intermittent electrical source may provide enough control. Sustainable Energy Ireland (SEI) published the results of a feasibility study for the implementation 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 and benefits 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 a number of the key revenue streams that had previously been identified in relation to the integration of wind power and storage. The analysis of the feasibility of using an energy-storage system showed that combining the turbine with a battery system could support an uninterrupted supply of wind-generated electricity to the National Grid and significantly improve the efficiency of the energy produced. The purpose of the report was to determine the optimum size for such a system in order to deliver an optimum return on investment, and to review the main benefits that this system would offer. The report concluded that the optimum battery is a 2-MW-capacity battery delivering six hours of electricity storage.
At a medium-voltage scale, and more closely associated with the end-user than pumped-storage projects, energy storage can be combined with power-quality management. Urenco Power Technologies’ kinetic-energy storage system (KESS) is being selected to resolve a range of power- and energy-management problems encountered in 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, which takes advantage of the basic physical laws whereby kinetic energy is proportional to the square of the speed. The design comprises a tubular rotor 900 mm long and with an external diameter of 330 mm, which is made up of carbon-fibre and glass-fibre composite weighing 110 kg. The bore of the rotor is lined with a patented magneticloaded composite, impulse magnetized, to produce the poles of the motor generator and the passive magnetic bearing. The top speed is 630 Hz, with a surface speed equal to 1 400 mph. It can also act as a power-levelling device, or as an energy sink. In its basic configuration, KESS offers an alternative to large battery banks used in UPS systems. It offers protection from a range of disturbances, including voltage dips, short blackouts and brownouts. For users requiring continuous operation, it provides a bridge between mains power and backup generation. In this mode, the control system operates in such a way as to maintain a constant voltage at the DC bus. The system is able to supply the changes associated with varying loads while maintaining this constant voltage, in contrast to battery systems, where the output voltage decreases with increasing load and as the battery discharges. In Japan, the system has been used to improve operation at a wind farm at Mount Obu, Oki island. A single 200 kW unit has been fitted to a 600 kW wind turbine to smooth the output. The overall variability of the turbine output (due to wind gusting and the pitching and yawing of the blades) has been significantly reduced. Other applications include a 1 MW system installed on New York City Transit’s test track to support track voltage and save energy. The system consists of 10×100 kW machines and has now been operational for 10 000 hours, reinforcing the voltage of the 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.
Moving to a hydrogen economy
An alternative method of energy storage is to use excess electricity at times of low demand to produce hydrogen. The hydrogen can be stored and used for fuel cells or other 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 the possibility that hydrogen could eventually replace gas or petroleum products and be used in the transport industry.
100 Local energy This proposal helps untie one of the biggest knots in plans to ‘decarbonize’ the world’s economy. The aim of switching from fossil fuels to fuels that do not produce carbon dioxide has been driven by the need to reduce carbon dioxide emissions to halt manmade climate change. But in the longer term there is another reason: the scarcity of fossil fuels, especially gas, means that a replacement will be needed in any 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 electricity generation. It should be clear that in this context hydrogen is not an energy source. Its role is storage and conversion of energy. Producing hydrogen is expensive, not least in the energy cost required. It may be produced by electrolysis (see above), or biological methods, and in each case energy is required to produce it. As with pumped storage, the idea is to use free or cheap energy to produce the hydrogen – possibly renewable-energy-generating facilities that are generating during low-demand periods. Hydrogen can then be pumped or transported in another form to the point of use, where it may be used to generate electricity or heat, or as transport fuel. Of course the transfer and reconversion of the hydrogen will require energy as well. Hydrogen has already been used in demonstration projects as transport fuel or for heat and electricity production via fuel cells (see Panel 10.1). Whether it will ultimately replace fossil fuels as the energy carrier of choice depends partly on whether simple and safe methods can be found to transport the hydrogen. Researchers have experimented with chemical storage systems, where hydrogen is held on a solid substrate in a different chemical form. This may be useful in the same way as rechargeable batteries, with the hydrogen-storage modules refilled at local energy schemes where hydrogen is, for example, being produced overnight by a wind turbine. More ambitious projects to build a hydrogen infrastructure that would rival the existing gas or electricity networks have also been proposed. Here, hydrogen could be produced on an enormous scale – for example, using wind farms far offshore. There are 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 how direct electrical technologies such as batteries develop and whether the costs of the new infrastructure would be justified. It is hard to see where investment in converting electricity to hydrogen and in a network to transport it would be financially viable if direct sales of the electricity were as successful for the end user.
Norway’s hydrogen experiment
In summer 2004 ten households on the island of Utsira, 20 km from the coast of Norway, became part of an experiment in new energy systems. In a pioneer project, their electricity is supplied solely from two 600 kW wind turbines and hydrogen. The hydrogen plant on Utsira started producing electricity in April 2004.
Energy storage 101 The rough weather at Utsira plays an important role in the process of supplying the island with power. The windy situation makes Utsira and its 240 inhabitants a natural choice for wind-power production, and the wind turbines installed 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 on Utsira, excess power is being stored as chemical energy in the form of hydrogen. On windy days electrolysers produce hydrogen for storage, and, when it is calm, a hydrogen engine and a fuel cell will convert the hydrogen back to electricity. The hydrogen plant is dimensioned to produce enough electricity for two 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 their electricity from renewable sources in a closed system. The power consumption of the islanders varies, but the stored hydrogen will ensure that sufficient renewable power can be generated at any time – even when consumption is high and wind activity is minimal. The hydrogen that will ensure stable power supply is produced from water and 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 company Enercon is also a partner in the project and the supplier of the wind turbines, netstabilizing equipment and the control system. Hydro Electrolysers will deliver the hydrogen plant, including electrolysers and the hydrogen-storage facility. Haugeland Kraft is the net owner for the ten households in the project, and has signed an agreement with the project on the handling of electricity supply for customers and the use of the ordinary net. It has financial support from Enova (a government body set up to promote environmentally friendly energy consumption and production in Norway), the Norwegian Pollution Control Authority (SFT) and the Research Council of Norway. The necessary infrastructure in the form of roads, water and electricity supply and the foundations for the wind turbines was set up in 2003. Hydro’s project organization, Hydro Technology and Projects, is responsible for the development, contracts and coordination of technical solutions. Hydro’s power production department will be responsible for day-to-day operations of the whole plant. Enercon contributes both technology and a considerable workload. The most innovative aspect of this project is the way it puts it all together in a system. One of the challenges is the number of interfaces between the autonomous system and the rest of the net system. The demand for electricity varies both through the year and through the day, and these variations have to be met despite the fact that the wind is unpredictable. Kraft also points out that the hydrogen engine and the fuel cell are the only components that the partners Hydro and Eneron have no experience of. One of the challenges in earlier hydrogen projects has been delays caused by problems with fuel-cell deliveries. Continues
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The island’s chief councillor, Robin Kirkhus, said that, in its first period of operation, the Utsira plant has already achieved production 97 per cent of the time. He is hoping the project will become a permanent energy solution for the island.
Hydrogen in Iceland
Commercial hydrogen filling stations in Reykjavík, Iceland, will be used to fuel three DaimlerChrysler buses, which will be operated on a commercial basis in Reykjavík by the municipal transport company Straeto. Private hydrogen vehicles are expected to follow in the future, and the Icelandic authorities have already issued all the permits necessary for the station to operate on a commercial basis. At present, the hydrogen is being supplied from geothermal and hydroelectric energy sources. Iceland has an abundant supply of geothermal energy, used for power production and heating, plus considerable hydroelectric resources. In addition, however, there are excellent opportunities for exploiting wind energy. The Icelandic Allting committed itself to making Iceland the world’s first hydrogen-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 by the Icelandic VistOrka, with a stake of 51 per cent, plus DaimlerChrysler, Norsk Hydro and Shell Hydrogen. INE’s goal is to promote opportunities for the production and use of hydrogen and fuel cells for different purposes in Iceland. As hydrogen is stored energy, there has been a discussion in Iceland regarding the possibility of producing hydrogen renewably for the European market. EURO-Hyport is a project pre-study looking into opportunities for large-scale hydrogen 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’s fishing fleet, as the fuel currently used by the fleet adds greatly to the country’s carbon dioxide emissions. However, the technology has not yet advanced sufficiently to allow this.
Energy storage 103
A hybrid PV (photovoltaic) and wind-power system on Bullerö, the main island of a national park in the archipelago of Stockholm, uses Saft Sunica batteries to provide a reliable supply of electricity. Bullerö Island is remote from the nearest electricity grid and in 1986 the cost of installing an undersea cable to provide power for the visitor facilities and the park ranger, who lives on the island all year round, was estimated at around US$100 000. Instead, in 1988, a low-cost combined PV and wind system was installed. This was upgraded in 1996 with more PV modules and a new combined regulator and monitoring system. The PV modules are mounted on an old air force tower and have an installed peak power of 1.45 kW. The modules are connected by a 100-m cable to the batteries in a battery room next to the park ranger’s house. A Rutland Furlmatic 1800 wind generator with a nominal power of 0.25 kW is installed on a mast at the 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 charge the battery bank. The battery bank comprises Saft Sunica rechargeable nickel-cadmium batteries with a nominal capacity of 571 Ah at 48 V. The system voltage of 48 V DC is converted to 12 V DC before being fed into the house. The electricity powers lighting, a refrigerator and freezer, a radio, a television and a 1 kVA inverter for a few small appliances that need AC power. The Sunica batteries are designed specifically for photovoltaic applications. Photovoltaic systems require efficient batteries with a long cycle life and a potential for both shallow and deep cycling. The nickel-cadmium batteries installed on Bullerö Island are designed specifically to meet key requirements in 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.
Fuel cells can provide heat and power, and a huge variety of fuel-cell devices currently being tested and demonstrated are likely to hit the market in the next decade.
How fuel cells work
Unlike other electricity generators discussed in this book, fuel cells produce their power as a result of a chemical reaction. Chemical reactions often involve the transfer of electrons from one atom to another, leaving one positively charged and the other negatively charged. If a carefully chosen reaction is made to take place in an electrical circuit, with a source of electrons at one ‘pole’ and a substance that absorbs the electrons to complete the reaction at the other ‘pole’, the electrons move around the circuit. A fuel cell operates a little like a battery. But a battery is a sealed unit containing its own fuel, in which the two poles are gradually consumed as a chemical process creates 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 produces electricity and water, but the fuel cell does not contain the chemicals that react: they are fed in during the reaction so the fuel cell can continue to produce electricity and heat as long as fuel is supplied. The principle of the fuel cell was discovered by the German scientist Christian Friedrich Schönbein in 1838. Based on this work, the first fuel cell was developed by the Welsh scientist Sir William Robert Grove in 1843, using similar materials to today’s phosphoric-acid fuel cell. It was in 1959 that the British engineer Francis Thomas Bacon successfully developed a 5 kW stationary fuel cell. In 1959, a team led by Harry Ihrig built a 15 kW fuel-cell tractor for Allis-Chalmers using potassium hydroxide as the electrolyte and compressed hydrogen and oxygen as the reactants. Later in 1959, Bacon and his colleagues demonstrated a practical 5 kW unit capable of powering a welding machine. In the 1960s, Pratt and Whitney licensed Bacon’s US patents for use in the space programme to supply electricity and drinking water (hydrogen and oxygen being readily available from the spacecraft tanks).
106 Local energy
The reaction that generates the power in a fuel cell will happen whenever the components are brought together: the key to producing useable power and heat from the cell is to manage the steps of the reaction so the products can be tapped at the right point. There are relatively few components in a fuel cell. One of the most common types uses a ‘proton exchange membrane’ (PEM). • The anode, the negative post of the fuel cell, has several jobs. It conducts the electrons that are freed from the hydrogen molecules so that they can be used in an external circuit. It has channels etched into it that disperse the hydrogen gas equally over the surface of the catalyst. The cathode, the positive post of the fuel cell, has channels etched into it that distribute the oxygen to the surface of the catalyst. It also conducts the electrons back from the external circuit to the catalyst, where they can recombine with the hydrogen ions and oxygen to form water. The electrolyte is the proton exchange membrane. This specially treated material conducts only positively charged ions. The membrane blocks electrons. For a polymer electrolyte membrane fuel cell (PEMFC), the membrane must be hydrated in order to function and remain stable. The catalyst is the material that helps the reaction of oxygen and hydrogen to take place. It may be made of platinum nanoparticles very thinly coated on to carbon paper or cloth. The catalyst is rough and porous so that the maximum surface area of the platinum can be exposed to the hydrogen or oxygen. The platinum-coated side of the catalyst faces the PEM.
Hydrogen fuel diffuses to the anode catalyst, where it later dissociates into protons and electrons. The protons are conducted through the membrane to the cathode, but the electrons are forced to travel in an external circuit (supplying power) because the membrane is electrically insulating. On the cathode catalyst, oxygen molecules react with the electrons (which have travelled through the external circuit) and protons to form water. In this example, the only waste product is water. The hydrogen/oxygen PEMFC used to be called a solid polymer electrolyte fuel cell (SPEFC) and is now known as a polymer electrolyte membrane fuel cell (PEFC or PEMFC, same as the short form for proton exchange membrane fuel cell). In addition to pure hydrogen, there are hydrocarbon fuels for fuel cells, including diesel, methanol and chemical hydrides. The waste products with these types of fuel are carbon dioxide and water. A typical fuel cell produces a small voltage. To create enough voltage, the cells are layered and combined in series and parallel circuits to form a fuel-cell stack.
Solid-oxide fuel cells
A solid-oxide fuel cell (SOFC) is a fuel cell that generates electricity directly from a chemical reaction, yet, unlike normal fuel cells, an SOFC is composed entirely of
Fuel cells 107 solid-state materials, typically ceramics. Their composition also allows SOFCs to operate at much higher temperatures than conventional fuel cells. They are mainly used for stationary applications with an output between a few kilowatts and 1 MW. They work at very high temperatures, typically between 700 and 1 000 ◦ C, so the gases produced can be used in a turbine to improve electrical efficiency. In these cells, oxygen ions are transferred through a solid-oxide electrolyte material at high temperature to react with hydrogen on the anode side. The high operating temperature of SOFCs promotes the fuel-cell reaction so they have 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 types of 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 passed through the inside of the tube and the other gas is passed along the outside of the tube. An SOFC is made up of four layers. A single cell consisting of these four layers stacked together is typically only a few millimetres thick. Hundreds of these cells are then stacked together in series to form what most people refer to as a ‘solid-oxide fuel cell’. The ceramics used in SOFCs do not become electrically and ionically active until they reach very high temperature and as a consequence the stacks have to run at temperatures ranging from 700 to 1 200 ◦ C. The ceramic cathode layer must be porous, so that it allows air flow through it and into the electrolyte. The electrolyte is the dense, gas-tight layer of each cell that acts as a membrane separating the air on the cathode side from the fuel on the anode side. There are many ceramic materials that are being studied for use as an electrolyte, but the most common are zirconium-oxide-based. Besides being air-tight, the electrolyte must also be electrically insulating so that the electrons resulting from the oxidation reaction on the anode side are forced to travel through an external circuit before reaching the cathode side. The most important requirement of the electrolyte, however, is that it must be able to conduct oxygen ions from the cathode to the anode. The ceramic anode layer must also be very porous to allow the fuel to flow to the electrolyte. Like the cathode, it must conduct electricity. The most common material used is made of nickel mixed with the ceramic material that is used for the electrolyte in that particular cell. The anode is commonly the thickest and strongest layer in each individual cell, and is often the layer that provides the mechanical support. A metallic or ceramic layer sits between individual cells. Its purpose is to connect each cell in series, so that the electricity each cell generates can be combined. Because the interconnect is exposed to both the oxidizing and reducing side of the cell at high temperatures, it must be extremely stable. Ceramics are most useful but are extremely expensive. Research is focusing on lower-temperature SOFCs, which will allow metal layers to be used.
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As a route to generate electrical power at the point of use, fuel cells potentially have a huge number of applications. Among them are the following. • Power generation. Portable power applications include small generators and battery replacements. Fuel cells could be used in grid-connected locations for emergency backup and directly in the many areas where access to the electricity grid is not available. In such areas they would offer alternatives to conventional generators, such as diesel generators, that would allow power to be produced without noise or on-site pollutants. Domestic generator products are currently nearing commercialization. Portable devices offer great potential as backup power supplies. Battery replacement. Fuel-cell power sources are being developed for portable electronic devices. In these applications, the fuel cell would provide a much longer operating life than a battery would, in a package of lighter or equal weight per unit of power output. Fuel cells provide a higher power density, and are unlikely to require the special disposal treatment required by many batteries. In any case the fuel cell itself would not require recharging or replacing, although its fuel supply would need to be replenished.
Fuel-cell developers claim a higher efficiency than traditional combustion technologies. The only drawback, as fuel-cell proponents concede, is that hydrogen is still more expensive than other energy sources such as coal, oil and natural gas. Three main methods are being investigated to provide inexpensive hydrogen generation. The first is known as reforming. Fuel cells generally run on hydrogen, but any hydrogen-rich material can serve as a possible fuel source, including fossil fuels such as methanol, ethanol, natural gas, petroleum distillates, liquid propane and gasified coal. The hydrogen is produced from these materials by this reforming process. This is extremely useful where stored hydrogen is not available but must be used for power, for example, on a fuel-cell-powered vehicle. One method is endothermic steam reforming. This type of reforming combines the fuels with steam by vaporizing them 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 cyanobacterium, an abundant single-celled organism, produces hydrogen through its normal metabolic function. Cyanobacteria can grow in the air or water, and contain enzymes that absorb sunlight for energy and split the molecules of water, thus producing hydrogen. Finally, renewable energy, from solar or wind power, could be used to electrolyse water into hydrogen and oxygen. In this manner, hydrogen becomes an energy carrier – able to transport the power from the generation site to another location for use in a fuel cell. This process is particularly interesting for the renewable-energy industry: it would answer objections that renewable energy is inefficient because the
Fuel cells 109 resource is not necessarily available when power is required, by using excess power to 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 anaerobic digester gas from wastewater treatment plants, from biomass technologies or from hydrogen compounds containing no carbon, such as ammonia or borohydride.
Developing the industry
Fuel cells are unlikely to reduce overall energy consumption – the generation and delivery of hydrogen fuel have their own energy requirement – but they do offer the possibility of using that energy more efficiently. That is why both the US and EU are investing in developing fuel cells, as are potential users. The transport industry has been particularly interested in the technology and has been backed by government funding. A total of 45 companies from across Europe have joined forces to push for the creation of a Joint Technology Initiative (JTI) for fuel cells and hydrogen technology. The companies, which include Rolls-Royce Fuel Cell Systems from the UK and Italy’s SOFC Power, have formed an association called the JTI Industry Grouping as a first step to creating a JTI. The group is now pressing the European Commission to accelerate plans to create the JTI (a public–private partnership) on fuel cells and hydrogen. The European Commission has also launched a thematic call for proposals in the area of component development and systems integration of hydrogen and fuel cells for transport and other applications. The call covers fuel-cell and hybrid-vehicle development 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 can provide heat and power on a near-domestic scale, offering on-site generation for an apartment block or small commercial or industrial units. Using both the heat and power output makes such units extremely efficient. Demonstration units have been in operation for several years, and manufacturers believe they will be commercially available in the next decade. In Japan, Nuvera Fuel Cells and Takagi Industrial Co. have announced an agreement to develop commercial fuel-cell-based cogeneration systems for the Japanese market. 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 the end customer’s thermal demand. America’s President George W. Bush announced that the US Department of Energy was investing more than $350 million in hydrogen research projects, along with $225 million in private-sector cost share, over the five years to 2010.
Interacting with the electricity grid
Managing the electricity supply across the grid is not simply a case of generating enough electricity to meet the needs of all the customers connected to it. Wherever customers tap into the power network it has to be able to supply power that has welldefined characteristics and that is supplied with minimal disturbances or interruptions. What is more, the quality of the grid supply has become still more important as customers at all scales from the domestic to heavy industry use electronic equipment that can be sensitive to disturbances in the supply that last a fraction of a second.
Voltage and frequency
The voltage and frequency of the network are the characteristics most often relevant for domestic users. The UK system at the domestic level is maintained at a voltage of 230 V (originally 240 V, but the standard was changed to bring the UK into line with mainland Europe). The supply frequency is 50 Hz. The US system, in contrast, is maintained at 110 V and 60 Hz. All appliances for use in the UK are designed to operate at 230 V and 50 Hz, while US-marketed appliances require a 110 V, 60 Hz supply. Special converters are required to use US appliances in the UK and vice versa. Similarly, power-generation equipment is manufactured in different versions so that it can be used in grids that operate at 50 Hz or 60 Hz. Whatever the function of an electrical appliance at whatever scale, it is converting some part of the power provided by the generator into other forms of energy – heat, light, sound, etc. This is known as a load.
Voltage can be considered as the force that pushes electrons through an electrical circuit. It measures the potential difference between two points, and in fact was once known as electromotive force (EMF). In some ways it is similar to the hydrostatic pressure in a water pipe that is higher at one end than the other. Gravity moves water down the pipe and enables it, for example, to turn a water-wheel. The voltage is provided by a generator. The power provided by the generator moves electrons that carry charge through a circuit but the charge encounters various
112 Local energy levels of resistance. This is a very useful material property: the heat and light caused when a charge passes through a high-resistance material are the basis of the light bulb, heating elements and so on. In such situations the electrical energy provided by the generator is converted into usable heat and light. But no material is entirely free of electrical resistance, and, as current flows along a wire or cable, some part of its energy is dissipated as the wire warms. This can be minimized by choosing the best material for the cables or wires, and by stepping up the voltage when transfer is over long distances. This has the effect of reducing the current – a measure of the amount of current being moved – and the heating effect. The UK’s grid operates at 230 kV or 450 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-energy industries. The circuits used to supply commercial and light-industrial premises must be of lower voltage and those at the domestic scale are at 230 V. Long circuits at this voltage can experience significant voltage drops along their length as users tap into the supply.
In an AC (alternating current) circuit the electrons are effectively being shunted back and 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 produce this 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, so a three-phase supply is used in which there are three supplies going up and down in sequence to give a near-constant output. ‘Synchronous’ generators operate at a steady frequency locked into that of the grid, and because of that they help to maintain the frequency across the network.
In an alternating current the voltage and current are constantly changing, reversing their flow (in the UK system) 50 times a second. As a current passes through a circuit component that has resistance, electric-field effects result. When the current is alternating, 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 power available in the circuit, because at any instant the power available is a product of the voltage and the current. At some points the current and voltage are exactly out of phase (i.e. the current is increasing to a maximum while the voltage is decreasing to a minimum) and the effect is that there is no net power flow – although energy is flowing backwards and forwards.
Interacting with the electricity grid
This is reactive power and it must be carefully controlled in the circuit. By convention, 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 of reactive power is a complex one but at bottom the effect of injecting reactive power is 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 vulnerable point. 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 the reactive power flow. During dispatch this is typically done automatically by switching inductors or capacitor banks in and out, by adjusting generator excitation, and other means. There are also financial incentives on customers and suppliers to the system. Those that consume reactive power – for example, industrial sites with a large number of motors, which are inductive – are penalized in their tariff. In the UK there is a market for reactive power, which allows suppliers to offer reactive power to the National Grid (or local distribution networks).
Maintaining the supply quality
The transmission system operator National Grid comments that power flows, both actual and potential, must be carefully controlled for a power system to operate within acceptable voltage limits. Reactive power flows can give rise to substantial voltage changes across the system, which means that it is necessary to maintain reactive power balances between sources of generation and points of demand. System frequency is consistent throughout an interconnected system, but the voltages experienced at points across the system form a ‘voltage profile’ that is uniquely related to local generation and demand at that instant, and is also affected by the prevailing system network arrangements. National Grid is obliged to secure the transmission network to closely defined voltage and stability criteria, and the operators of the low-voltage distribution network have the same responsibility for local networks. The variation in demand over each 24-hour period has a basic pattern whereby demand is lowest during the night and higher during the day, and increases to a morning and evening peak when domestic customers are at home. This is a crosscountry aggregate and it varies with events where a significant proportion of the population are involved. Soccer matches in which England are playing are a typical example: at half-time and full-time, there is an immediate demand surge as people put on kettles. This also happens when storylines in long-running soap operas reach a 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 is affected 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 varying requirement for power and for reactive power.
114 Local energy If the changes are planned or expected, such as the startup of an additional power station, or the regular demand of an industrial user, grid operators can ensure the transition 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 within minutes or seconds, depending on their characteristics. These vary from large power stations to small backup generators, often on industrial sites, that can provide power or reactive power at the medium voltage level. Similarly, some loads can be modulated to compensate for a loss of generation.
Bringing on the reserve
In the UK there is a market for such services, in which the system operator National Grid periodically invites offers from companies who are able to operate flexibly. The UK is not unique in this: in recent years interesting examples of demand and supply response have been developing. For example, wind power is often decried as an unpredictable and intermittent form of generation. It is certainly true that it becomes more difficult to predict wind supply over longer timescales. However, over a period of hours or minutes, operators can be pretty confident that, if there is a good supply of wind now, it will be there in an hour. This is particularly true in the offshore sector, where wind patterns can be more easily predicted. That has allowed Denmark to use its offshore wind farm at Horns Rev for this type of ‘secondary regulation’. Denmark’s power supply is largely composed of CHP plants. Although these are very efficient, the importance of their heat loads and some regulations intended to support CHP mean that the system operator has very little control over the way they are operated, especially over the hours or minutes required to help balance the grid. The fastest response available on the Danish system is the Horns Rev wind farm, because the power being produced at any time can be modulated by altering the angle of the turbine blades to catch more or less wind – a matter of a few seconds. So, when the Danish operator expects a sudden surge of power, the Horns Rev farm is held at an appropriate point below its maximum capacity. If demand surges the wind farm is modulated up and if demand stays 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 reserve market a useful one. Many different industries have to have backup generation immediately available. The ideal situation from one point of view would be if the backup generation never operated. But, nevertheless, power supply, generally in the form of diesel engines, has to be ready. The cost is more than simply the capital cost of the engine. It must also be maintained and started up on regular occasions to ensure that it is available – with the resulting use of diesel fuel. Offering that generator in the reserve market means it may be called on a few times each year for periods up to a few hours. That means test startups are no longer required; the income from the reserve function may be enough to cover the maintenance costs of the engines, and it removes the need for dedicated backup engines to be installed somewhere. Water companies
Interacting with the electricity grid
have found this particularly interesting and have the possibility of extending it and combining it with management on the demand side. They have a large power demand spread across many sites, largely for pumping, with some power generated on their sites using waste methane from sewage treatment. But in most cases water is pumped from a source into a water-treatment plant, which generally includes water storage. That means that at most times water companies have flexibility about exactly when water is pumped into the water-treatment plant: anything from a continual, steady supply to pumping all the water overnight, when there is little demand for power and prices are low. Water companies can switch between using their power, using grid power and selling their own generation depending on payments available for load-shedding power generation, reserve power, etc.
An interesting response on the demand side has been employed in several US cities. Energy-services companies take on power management of large, nonessential power users – in practice this has often been shopping malls, which have air conditioning, lighting, refrigeration, heating and many other mixed loads. The service company acts as an intermediary between the shopping centre and the power company, buying power but also offering demand-reduction services at various levels. The income from the demand reduction is shared between the shopping centre and the energyservices company. Experience so far has shown that a shopping centre can reduce its energy consumption by about 15 per cent effectively and continuously without customers being aware of any difference. Over short periods much bigger reductions are 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 demand response but for the total system cost. The generation system as a whole has to be sized to accommodate the highest likely demand peak – plus a reserve in case a generator is unavailable or for an unforeseen extra peak. At peak times electricity is in short supply and the price – in the half-hourly trading slot – can ramp up to many times the average price. This is the time at which generators that are most expensive to operate have to be brought on to the system. These may be the least efficient stations, or it may be that power stations are built and connected to be used just a few times each year at peak times. Being able to reduce demand reliably at peak times – known as peak lopping – reduces the need for such plants.
Dealing with transients
When a new demand or load is added or subtracted from the system it affects the supply: continuing our occasional water analogy, it causes ripples in the supply. As with water, the size of the ripples, how far they extend and their effect depend on the size of the pebble and the size of the pool.
116 Local energy Other disturbances can also produce transient or short-lived effects on the transmission or distribution grid. A short circuit is one example caused by an impact on 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 are regular examples of agricultural or industrial equipment striking overhead lines if their drivers misjudge their relative heights. Animals are also a frequent cause, especially small climbing creatures such as squirrels, or trees and other vegetation can be blown against the line. Lightning strikes are also frequently to blame – one effect that is important for the transmission network. In many cases now, the network is equipped with automatic circuit breakers that switch in the event of a short circuit and 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 effect is to send more ripples across the network. In some cases it can cause a voltage or frequency ‘collapse’. Such transients have an effect. As computer operators know, power electronics systems are very vulnerable to them, so most computer shops sell socket sets that include surge arrestors, which counter transient changes in the supply. Which transients have to be managed depends on how sensitive your computer is. Similarly, equipment connected to the distribution or transmission networks has to be protected against transients or faults in the grid supply, and the characteristics of each type of generation determine how much protection is required and when, in certain circumstances, generators can help even out faults and add stability to the grid. Large disturbances in the grid can affect any generating plant and, beyond set limits, most will automatically disconnect from the grid to limit the damage to the plant. But, as we have seen, the sudden removal of supply from the system can create its own fault: the result can be a domino effect that propagates faults far beyond the original area and jeopardizes the running of the system. Two such events happened within a few months of each other a few years ago. In the USA in August 2003 the loss of a transmission line in the north required power to be switched to transport across another part of the network. The unanticipated extra load caused several power stations to ‘trip’, and faults quickly cascaded throughout the interconnected system in the north-east USA, eventually causing blackouts that lasted several hours in New York and many of the surrounding states. Power cuts extended 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 a tree striking the line. For electricity-system operators, containing such an incident is easier if there are more connections and an extensive grid: having a lot of transmission and distribution lines gives the operators different options for switching power around so that no one part of the system becomes overloaded. Generators (and loads) also ideally have some ability to ‘ride through’ faults, so they are less likely to disconnect and cause the problem to cascade. Some forms of conventional thermal and nuclear generation are valuable in this respect. Because they include heavy rotating machinery, the plant has huge mechanical momentum. A brief fault is not enough to interrupt the turning
Interacting with the electricity grid
generator and it will take several seconds before a fault develops that will cause it to separate from the network. Some other forms do not have this effect. Wind turbines, for example, have in 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 by the connection. This approach was taken because turbines were relatively small and separated generators even in networks where they were widely used, and so the effect of disconnecting one small turbine from the network was very small. The situation changed somewhat when wind started to be installed in much bigger quantities and in wind 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 capacity around to share the burden. At this point, fault ride-through became an important issue 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 a group 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 incorporated that allow the wind farm to mimic the ride-through ability of a generator with large rotating machinery, and this is likely to be cost-effective in a system where faults and unavailability are penalized.
In order to manage voltage, frequency and reactive power, and meet the other requirements of supply, National Grid has a view of the electricity network that resolves down to around 8 km (5 miles). It has to take into effect not only the load and demand on its own network but, as we have seen, the cumulative effects of changes in the distribution network. This varies as load switches between consumer, industry and commercial users. Aggregate demand (the total from consumers in a region) is, of course, equally variable at the low-voltage level. The effects of the weather are well known, but are changing over time. DNOs know, for example, that, even if the temperature is relatively pleasant, if there is rain and wind at the time people are travelling home from work they will tend to switch on additional heating when they arrive. If a sunny day clouds over, lighting demand will rise because of apparent darkness, although the 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 the medium voltage used by industry and commerce and then the low-voltage domestic network. There are few points at which DG feeds in and no trading between different parts of the network. Elsewhere the situation has begun to develop somewhat differently, and a major reason has been the introduction of DG. Thanks to the feed-in tariffs that guarantee
118 Local energy export, German networks are required to accept all the power generated by wind turbines, solar photovoltaics and other renewable-energy systems. Similarly, Danish networks are required to accept wind power and electricity from CHP plants. This will ultimately make it necessary to operate distribution networks in a much more active way, more closely allied to the way in which the transmission network is managed. As this happens it will also require the interface between the distribution and transmission networks to be carefully managed. The assumptions previously used by the transmission operator to track and predict demand and supply at the distribution network may no longer be valid. This is not an insoluble problem but in countries such as Germany and Denmark it 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 transmission line that passed over a river to allow a large ship to pass underneath on its way from a shipyard to the sea. The transmission line was an interconnector – a line that joins the grids of two countries. The line had been depowered many times before for very similar reasons, but in this case the result was a local blackout that triggered blackouts centring on Germany and France and lasting only a couple of hours, but whose effects were felt far further afield and for far longer. The problem was traced to a lack of information passing between the grid operators in the two countries and poor operating practices. It highlighted well-known inadequacies in the extent of interconnection between European countries, especially in 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 of Energy (UCTE) noted that lack of information between distribution and transmission network operators had made it more difficult for operators to bring the system back on 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 connected to the transmission grid, i.e. they are disconnected at a smaller frequency deviation. When the frequency deviation reaches the threshold values of the units’ protection, they are automatically disconnected from the grid.
This was the case when the blackout happened: distribution units tripped when the frequency dropped below set limits. This worsened the situation in one of the blackout areas. The report adds,
Recovering the frequency to its nominal value required an increase of generation output in the Western area and a decrease of generation output in the North-Eastern area. After a few minutes, wind farms were automatically reconnected to the grid, being out of the TSOs’ [transmission system operators’] control. This unexpected reconnection had a very negative 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 power output from generation connected to the transmission and distribution grid in a sufficiently short time necessary for the frequency restoration. These are examples of insufficient TSO control over the generation behavior. The TSO control usually applies to generation connected to the transmission grid since traditionally the generation connected to the distribution grids has not had a significant impact on the
Interacting with the electricity grid
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 some areas significantly influences the operation of the power system due to its high share in the generation 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 distribution grids. In view of the rapidly growing share of such generation, this has multi-dimensional consequences: • • • 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-level generation, and said this could lead to ‘serious power balance problems especially in over-frequency areas’. In response, it made three recommendations that would give transmission system operators far more knowledge of, and control over, generation connected to the distribution network. • • • The regulatory or legal framework should be changed so that TSOs can assert control over generation output (allowing them to change schedules, or to start and stop the units). TSOs should receive data on a per-minute basis on the generators connected to the distribution system. Generation units connected to the distribution grid should have the same requirements, in terms of behaviour during frequency and voltage variations, as units connected to the transmission network.
Any such recommendation would likely impose requirements appropriate to the scale of differently sized DG. The effect of connecting or disconnecting a domestic system is very different from that of an industrial generator inputting tens of megawatts into the grid. However, as we have seen on the demand side, the cumulative effect of aggregating large numbers of similar systems should not be overlooked. Developing control and oversight that provide enough management capability for the distribution network, without overspecifying the generator and making it unnecessarily 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 microgeneration to the mix? Optimistic projections have suggested that domestic-scale generation could meet up to 40 per cent of household electricity consumption. It may have an important role to play in reducing peak loads, but managing import and export from the grid as millions of microgeneration units switch in and out presents its own challenges.
120 Local energy The problem is that domestic demand varies, not just in aggregate but in individual houses, as the Carbon Trust highlighted in a report on early field trials of domestic CHP. The short-term export/import balance from buildings with any form of microgeneration is critical as electricity demand and supply must be balanced second by second. The Carbon Trust said that the amount of electricity exported from microgeneration trial sites was considerably higher than forecast. ‘The reason for this appears to be related to forecasting assumptions about electrical loads in homes during heat demand periods.’ Modelling used for some purposes assumes that typical electrical demand in homes 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 also lower than typical microCHP output. Superimposed on this low demand are short periods of very high demand. This is consistent with event-based modelling which builds up total electrical load from the predicted operation of electrical equipment. Typically a base-load of 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 duration peak 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 of around 1 kW that ignores the significance of peaks and troughs. The reality of the situation is that low-voltage networks will have to be designed to cope with potentially high levels of export in addition to full load import when the units are not running and this needs careful consideration.
Making progress on policy
The need to rethink the UK’s electricity network to accommodate local energy projects was already exercising the minds of the industry at the start of the new century. In 2001 Callum McCarthy, then chief executive of the regulator, the Office of Gas and Electricity Markets (Ofgem), said that government targets on renewables and 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 top of the senior management agenda’ and said that for Ofgem, too, it was ‘emphatically not business as usual’. ‘Today a DNO might have 300 embedded generators within its entire network. If the government’s targets are to be met, by 2010 a DNO could have 300 generators connected to every substation,’ McCarthy said. Even then, he said, meeting the 2010 targets – 10 per cent renewable generation and 10 GW of CHP – would require 3 000 new renewable installations, 1 000 CHP plants 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 more commercial dimensions.
In 2003 the government set out a strategy for developing the energy sector, in a White Paper titled Our Energy Future, that would give local energy projects and microgeneration 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 will be a much greater mix of energy, especially electricity sources and technologies, affecting both the means of supply and the control and management of demand. There will be much more local generation, in part from medium to small local/community power plant, fuelled by locally grown biomass, from locally generated waste, from local wind sources, or possibly from local wave and tidal generators. These will feed local distributed networks, which can sell excess capacity into the grid. Plant will also increasingly generate heat for local use. There will be much more microgeneration, for example from CHP plant, fuel cells in 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 achieve zero carbon emissions. The existing building stock will increasingly adopt energy efficiency
122 Local energy
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, if not to generate electricity to sell back into the local network. Gas will form a large part of the energy mix as the savings from more efficient boiler technologies are offset by demand for 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 arrangements that were created for a world of large-scale, centralised power stations will need restructuring over 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 involvement from English regions and from local communities, complemented by a planning system that is more helpful to investment in infrastructure and new electricity generation, particularly renewables.
Over the last half-decade changes have been made that were intended to help promote local energy projects. But progress has been mixed.
There has been progress on making it easier to get planning permission for renewableenergy projects, including local wind farms. Planning had been a huge barrier for projects from domestic systems and up. In 2004, Planning Policy Statement 22 (PPS22) for the first time set a positive planning framework for renewable energy. It said, • • Renewable-energy developments should be capable of being accommodated throughout England in locations where the technology is viable and environmental, economic and social impacts can be addressed satisfactorily. Regional spatial strategies and local development documents should contain policies designed to promote and encourage the development of renewableenergy resources. Regional planning bodies and local planning authorities should recognise the full range of renewable-energy sources. At the local level, planning authorities should set out the criteria that will be applied in assessing applications for planning permission for renewable-energy projects. Planning policies should not rule out or constrain the development of renewable-energy technologies. The wider environmental and economic benefits of all proposals for renewableenergy projects, whatever their scale, are material considerations that should be given significant weight in planning decisions. Regional planning bodies and local planning authorities should not make assumptions about the technical and commercial feasibility of renewable-energy projects. Planning authorities should not reject planning applications for energy projects simply because the level of output is small. Local planning authorities, regional stakeholders and local strategic partnerships should foster community involvement in renewable-energy projects.
• • • •
Making progress on policy 123 For the first time, PPS22 insisted that the environmental benefits of renewables and local energy projects were a good in themselves and should have a positive impact on the planning decision. The guidance was helpful but local energy projects hit frequent barriers in gaining planning permission. As a result, the government published additional guidance to underpin and extend its support for local energy generation, making it a fundamental requirement for all new development in a revision of Planning Policy Statement 1 (PPS1). Published in 2007, PPS1 – on planning and climate change – took low-carbon generation principles more fully into account, including not just renewable-energy projects but all local energy generation that would reduce carbon emissions overall. This PPS encourages regional planning bodies (RPBs), as part of their approach to managing performance on carbon emissions, to produce regional trajectories for the 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 should prepare and deliver spatial strategies that make a full contribution to delivering the government’s climate-change programme and energy policies. In preparing a regional spatial strategy, RPBs ‘should work with all stakeholders in the region and alongside their constituent planning authorities to develop a realistic and responsible approach to addressing climate change’. That would include ‘ensuring the spatial strategy is in line with applicable national targets, in particular for cutting carbon emissions, and with regional targets on climate change’. It would also require regional planning authorities to: • ‘ensure opportunities for renewable and low-carbon sources of energy supply and supporting 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 potential for accommodating renewable and low-carbon technologies, including microrenewables to be secured in new residential, commercial or industrial development and pay particular attention to opportunities for utilizing and expanding existing decentralized energy supply systems, and fostering the development of new opportunities for decentralized energy from renewable and low-carbon energy sources to supply 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 renewable energy or for a particular proposal for renewable energy to be sited in a particular location. In an important development, PPS1 said that planning authorities should ‘ensure that a significant proportion of the energy supply of substantial new development is gained 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 supplies to meet wider needs’.
124 Local energy 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 developers to build renewable energy or energy efficiency into the fabric of new factories, warehouses and offices. If the proposed building is larger than 1 000 m2 and is not located in a conservation area, council planners will expect photovoltaic panels, solar water heaters or other energy-producing equipment to be installed. The council will expect this 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 it too costly for developers to construct commercial buildings in the borough, it was strongly supported by the appointed inspector. The idea quickly began to spread. The Mayor of London included a similar policy in his Plan for London, and several other London 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 was a 3 000-m2 light-industrial and storage unit in Durnsford Road. But an early showcase is a new office building planned for the site of the Odeon Cinema in Wimbledon Broadway. Here the Chartered Institute of Personnel Development has been granted permission to develop 5 000 m2 of office space for its own use, provided that it installs renewable-energy systems of sufficient capacity in the building. This will also give the 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 ‘most innovative action’ in its introduction of the policy. And, although developers initially argued that it was impossible and of dubious legality, the policy came successfully through all its challenges. Similar policies have already been adopted by upwards of 50 councils and the provisions of PPS1 will require a similar provision by all planning authorities.
The support of PPS22 was useful at larger scale but of little help for the smallest projects, especially at the domestic scale. For such projects the cost of applying for 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-third of all potential sales had been halted by the cost of planning permission – which it said had shown huge variation from £150 up to over £1 000 – or the opposition of planning committees. In 2007 the government department now known simply as Communities and Local Government (CLG), which has jurisdiction over planning policy, finally took forward plans that would allow domestic energy projects to become ‘permitted development’, i.e. changes that can be made without requiring planning permission, so long as the installation meets building codes. The proposals covered solar, wind, CHP, biomass and heat pumps.
Making progress on policy 125 Solar: CLG suggested that there should be a general presumption in favour of the domestic installation of solar microgeneration equipment – photovoltaic or solar thermal. The principal restriction would relate to both solar on building and solar stand-alone technologies and reflect the potential visual impact that could occur in a conservation area or a World Heritage Site. It recommended that solar technologies should be permitted, subject to their projecting no more than 150 mm from the existing roof plane or standing off no more than 150 mm from a wall. In addition, in order to ensure that the visual impact is minimized, no part of the installation should be higher than the highest part of the roof (which will generally be the ridge line). It also proposed there should be no limit on the roof area involved. Wind turbines: Micro wind turbines would be permitted with blades 2 m in diameter at a height of 3 m above the roof or 11 m above ground level (for stand-alone turbines). They would be subject to noise and vibration restrictions. CHP and biomass: The CLG recognized that most biomass installation occurs inside the property in the form of new boilers etc. It added a 1 m flue for such boilers to the permitted development scheme but did not extend the permit to a store for biomass fuel. Heat pumps: Ground- or water-source heat pumps would require assurance from the Environment Agency that no contamination of groundwater was possible. All heat pumps would be subject to noise restrictions. In 2006 the then Department of Trade and Industry and Ofgem jointly consulted on the barriers to DG that had still to be tackled.
Scotland and Wales approach
The devolved administrations in Scotland and Wales have planning responsibilities and both have produced planning policies to support renewables and local energy generation. 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 focused on 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 and international treaty, and is a key part of meeting the Assembly Government’s targets for renewable electricity production. Therefore, the land use planning system should actively steer 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 the national renewable energy target.
The Welsh Assembly identified areas in Wales that,
on the basis of substantial empirical research, are considered to be the most appropriate locations for large scale wind farm development; these areas are referred to as Strategic Search Areas (SSAs). Smaller (less than 5 MW), domestic or community-based wind turbine developments may be suitable within and without SSAs, subject to material planning considerations. On urban/industrial brownfield sites, small or medium sized (up to 25 MW) developments may be appropriate.
126 Local energy It went on to say,
Local planning authorities should facilitate the development of all forms of renewable energy and energy efficiency and conservation measures which fit within a sustainable development framework…. Local planning authorities should seek opportunities to integrate energy efficiency and conservation objectives into the planning and design of new development in their areas.
To back up TAN8, the Assembly’s Environment, Planning and Countryside Minister, Carwyn Jones, launched a new planning policy on climate change at the end of 2006. It acknowledged that ‘there are a number of emerging policy issues related to climate change that necessitate further advice for local planning authorities, landowners and developers and the community in Wales’. It said that new developments must maximize opportunities to reduce energy and water use, and to promote renewable energy 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 requiring major 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 the energy performance of buildings, efficient supply of heat, cooling and power and/or on site renewable energy.
Scotland’s planning policy on renewable energy was published in March 2007. It takes the Merton policy further forward, saying that ‘development plans must include policies on the provision of low carbon and renewable sources of energy which complement the increasingly high levels of energy efficiency required by building regulations’. In local development plans, it says,
The expectation should be that all future applications proposing development with a total cumulative floorspace of 500 sq metres or more should incorporate on-site zero and low carbon equipment contributing at least an extra 15 per cent reduction in CO2 emissions beyond the 2007 building regulations carbon dioxide emissions standard. The intention is for national targets to increase through the Action Plan that will be prepared to implement the Energy Efficiency and Microgeneration Strategy. In the meantime, the development plan process should be used to consider whether local circumstances justify going beyond 15 per cent; below the 500 sq metres threshold; and whether higher standards can be secured for particular developments, including the potential for decentralised energy supply systems based on renewable and low-carbon energy.
A microgeneration strategy
In March 2006 the then DTI (now called the Department for Business, Enterprise and Regulatory Reform, or BERR) released a strategy for microgeneration. It noted that studies had suggested that microgeneration could provide 30–40 per cent of domestic electricity 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 installations in the UK. The objective of the strategy was to ‘create conditions under which
Making progress on policy 127 microgeneration becomes a realistic alternative or supplementary energy generation source for the householder’. It could also help reduce fuel poverty for those with hard-to-heat homes that could not be insulated. The government blamed cost constraints and the high price of microgeneration technologies, along with inadequate promotion, so that take-up even of the cheapest technologies had been slow. There were also technical issues, and the DTI cited a range of issues surrounding metering, connection to the distribution network and balancing and settlement arrangements that could be preventing widespread takeup of electricity-generating technologies, and there were regulatory issues such as planning. The DTI pointed out that it had already supported the microgeneration sector by reducing the VAT level applicable to most microgeneration technologies to 5 per cent and by its grant programmes (see Chapter 17). In 2007 it also reduced stamp duty for the 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-adopter purchase decisions. • DTI and Ofgem will produce a clear guidance document covering ROCs, LECs and REGOs, including the benefits of each and how to claim them. • Energy suppliers will develop a scheme that will reward those microgenerators exporting excess electricity. • DEFRA will consider whether electricity-generating technologies (other than microCHP) could be included within the framework of the Energy Efficiency Commitment. • The department will develop an accreditation scheme for all microgeneration technologies. • It will undertake a thorough review of existing activity in this area to assess effectiveness and identify gaps. • The department will actively investigate the possibilities for microgeneration on its own estate. • It will work with CLG and planning officers to identify their information needs, assess whether these are being met adequately and, if not, develop a communications pack. • The department will lead work with other government departments and local authorities to publish a report on measures that local authorities can take to improve energy efficiency and levels of microgeneration installations. • It will work in partnership with the energy-supply companies, distributed network operators and Ofgem to ensure that network and market systems are able to cope with growing numbers of microgenerators exporting electricity. • It will continue to work with Ofgem, the distribution network operators, energy suppliers and the microgeneration industry to ensure that existing contracts between domestic customers and their electricity suppliers are not hindering the take-up of microgeneration.
128 Local energy • • • It will work with Ofgem, the distribution network operators, energy suppliers and the microgeneration industry to ensure that wiring regulations do not form an unnecessary 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 Innovation, Universities and Skills (DIUS) – will work with industry and other key stakeholders to develop a scheme for installing microgeneration technologies in schools.
Re-examining the remaining barriers
In late 2006 the regulator Ofgem and the then DTI jointly published a new call for evidence on the barriers still remaining for DG. The report said,
Some argue that Government should do more to promote DE primarily because of its potential 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 taken into account. Cost implications of any changes will be a key consideration, as will preserving the integrity of electricity networks.
In this document, DG was defined broadly, as: • all plant connected to the distribution network rather than the transmission network; • 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 turbines that supply one building or small community, again potentially selling any surplus; • large CHP plants (where the electricity output feeds into the higher-voltage distribution 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 renewable sources for use locally. It was pointed out that this definition included many plants whose output was not used 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 and efficiency benefits, the document says. It cautions that
growth and investment in distributed electricity generation will not avoid the need for continued investment in the transmission system. The transmission system will continue to play a role longer term. For example, investment will be needed for the foreseeable future
Making progress on policy 129
to ensure we have continued interconnection between the distribution networks to provide backup and security of supply. Moreover, many of the renewable projects that will be built in the coming years will necessarily be sited in remote areas, away from centres of demand.
Most electricity generators previously had to become licensed to operate in the UK electricity supply industry. That meant they had to be party to the BSC and had to enter into an agreement with the transmission system operator National Grid Electricity Transmissions (NGET) for using the system. There are significant costs associated with both. Small generators have been accommodated in this system by becoming unlicensed generators. Some large distribution-connected sites have to meet transmission standards, which is an unwarranted cost. Unlicensed distributed generators also potentially have access to what are known as embedded benefits. These reflect the fact that distributed generators have a shorter delivery path to consumers. Under current arrangements, an unlicensed generator is effectively treated as negative demand on the system and the electricity it generates is not 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 suppliers can choose to pass back some of these savings to distributed generators or pass them on to consumers in the form of lower prices. The then DTI noted in 2007 – in a programme taken on by BERR – claims that these embedded benefits are not sufficient to recognize the value of DG. Some argue that exports should be valued close to the retail price and that suppliers should have an obligation to purchase. Others argue that the export value should be linked to the wholesale price of electricity.
Distribution and private wires
Redeveloping distribution networks so they can accommodate widespread local energy projects is still ‘a real dilemma’, said the DTI. Expanding the network in areas where 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 single unlicensed operator, supplied by unlicensed suppliers and with up to 2.5 MW of demand. The DTI asked whether this should continue unchanged, whether privatewire networks should have measures to encourage them, or whether a new regime is necessary. The DTI noted that the unlicensed operator is able to avoid a number of costs that would usually apply to a licensed energy supplier, including the Renewables Obligation, the Climate Change Levy and the Energy Efficiency Commitment, as well as 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 lowercarbon DG that connects into these private-wire networks and partly passed on to
130 Local energy customers. But the DTI noted that ‘customers supplied by licensed energy suppliers are in effect subsidising the electricity costs of those linked into the private wire network’. The DTI added, ‘Some argue that by exploiting these exemptions and associated financial benefits private wire networks could provide an important boost to the development of a larger base of distributed generation in the UK.’ But the department pointed out that there are countervailing arguments. Privatewire networks operate independently, but rely on the transmission grid for backup power, and therefore they should pay charges that reflect this dependence. Patchworks of private networks may make it increasingly difficult to coordinate power flows efficiently. In the longer term, there may be concerns about ensuring private networks are adequately maintained and about safety issues. Also, the DTI pointed out that the licensing regime’s purpose is to protect the interests of the consumer. Private-wire customers experiencing unreliable supply or a poor quality of service would have no route of redress and might not be able to switch to another energy supplier.
How planning works
The planning system is central to the delivery of the government’s climate change 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 and purposes, devolved planning systems. The British planning system is ‘plan-led’. A development plan is prepared and, once adopted, its policies determine all planning applications. In two-tier local-authority areas a structure plan is prepared by the county council and a local plan by the district, borough or city councils. The development plan constitutes the two documents taken together. Development plans have to be prepared in accordance with the regional planning guidance Regional Spatial Strategies (RSSs) within their region. RSSs are prepared by regional assemblies but, importantly, can be adopted only by the government. Hence the government is ultimately responsible for setting the regional planning framework, which, in turn, guides the contents of development plans. Councils will be expected to cooperate in preparing subregional spatial strategies, covering areas with common interest and straddling existing local-authority boundaries. Local plans will be replaced with local development documents. Planning applications themselves are determined mainly by local planning authorities (LPAs), usually the local council for the area concerned. Decisions are made by elected council members of the council planning committee, taking advice from planning officers, although some officers have delegated powers.
Making progress on policy 131 The system is administered by planning officers within the LPAs. In an attempt to speed up and make the development plan’s preparation process more certain, inspectors’ recommendations following local-plan inquiries will be binding on local planning authorities. Applications for power plants over 50 MW are dealt with directly by the secretary of state and are known as Section 36 applications. Central government in each of the administrations of the UK (England, Scotland, Wales and Northern Ireland) has retained for itself the ultimate power to determine planning applications. Applications may be ‘called in’ for determination by the relevant administration. Appeals against refusal of planning permission are heard, and often decided by, inspectors or recorders appointed by the central administration.
The construction of a new building or structure nearly always needs an application for planning permission. The development plan in force in an area will indicate whether a proposal is likely to be acceptable, so it is always worth talking to a planning officer at the council before submitting an application. Try to 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 unless there are very good reasons not to do so. Points that will be considered include the number, size, layout and appearance of the proposed structures; access to the development; landscaping and impact on the neighbourhood. It is not necessary to make the application yourself. A planning consultant will 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 need to send back and how much the application fee will be. Some councils are now operating an online applications service. Decide what type of application you need to make. In most cases this will be a full application but there are a few circumstances when you may want to make an outline application – for example, you may wish to see what the council thinks of the building work you intend to carry out before you go to the trouble of making detailed drawings (but you will still need to submit details at a later stage). Outline applications may require a different form.
Before making an application for a renewable-energy project, it is advisable to consult any neighbours who might be affected by your proposal, and the local parish, town or community council. Provide information about predicted noise levels, 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 the planning process. You should also consult other bodies who might have an interest, such as the Environment Agency or the local water and sewerage company, to discuss any potential sewerage, water or flooding problems, and/or the highway authority (usually the county council in non-metropolitan areas or the local council in metropolitan areas) to discuss road safety and traffic issues (some wind-farm developments have failed to get planning permission because they have been considered a distraction to passing motorists).
How long does it take?
The council should decide your application within eight weeks. Large or complex applications may take longer. Your council should be able to give you an idea about the likely timetable. If it cannot decide your application within eight weeks, 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 revenue from fees contributes to the cost to the council of handling applications and the fee is not refundable unless the application is invalid. Where the local planning authority fails to determine your application, or where you withdraw it before it has been determined, the fee will not be refundable. However, if the local authority fails to determine your application, you can appeal. When a previous application has been granted, refused or withdrawn, one further application by the same applicant for the same type of development on the same site can generally be made free of charge within 12 months.
The local authority will let you know if an environmental-impact assessment (EIA) is needed for your proposal. It is usually required for renewable-energy projects. The EIA is a study using scientific and other information about an area to be developed. It enables decisions to be taken with full knowledge of the environmental consequences that would result, in both rural and urban areas.
The planning process
Planning staff at the council should acknowledge your application within a few days. They will place it on the planning register at the council offices so that it
Making progress on policy 133 can be inspected by any interested member of the public. They will also either notify 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 public the opportunity to express views. The parish, town or community council will usually be notified; other bodies such as the county council, the Environment Agency and the ODPM may also need to be consulted. Anyone can comment on your proposals. Your local council will assess the relevance of comments and, in the light of them, may suggest changes to the application 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 officer in the planning department the responsibility for deciding your application on its behalf. You are entitled to see and have a copy of any report submitted to a local government committee, along with any background papers used in its preparation, which will generally include the comments of consultees, objectors and supporters that are relevant to the determination of your application. Such material should normally be made available at least three working days before the committee meeting. The council grants/refuses planning permission by sending you a letter notifying you of its decision.
Refusals and delays
If the council refuses permission or imposes conditions, it must give written reasons. If you are unhappy or unclear about the reasons for refusal or the conditions imposed, talk to the planning department. As we saw above, if your application has been refused, you may be able to submit a modified application free of charge within 12 months. Alternatively, if you think the council’s decision is unreasonable, it is possible to consider appealing. The appeal route is also available if the council does not issue a decision within eight weeks.
Generators and electricity suppliers (retailers) directly connected to the electricity transmission grid pay a series of charges for using the network that can be avoided by using local generation.
Transmission network use-of-system (TNUoS) charges are paid by generators and suppliers directly connected to the electricity transmission grid. TNUoS charges relate to the costs of managing and maintaining the transmission network. The charges vary for both generators and suppliers according to their geographic location and the demand for grid usage at that location. So, generator TNUoS charges vary by location and are based on the generator’s capacity. Supplier charges vary by location and are levied on the supplier’s peak demand, measured at the three half-hours of highest system demand (known as the triad). There is also a charge for transmission losses. Up to 2 per cent of the electrical energy generated in England and Wales is lost in the transmission system. This happens because a proportion of the current flowing in transmission lines, cables and transformer windings is dissipated through heating effects. These losses increase with the distance the electricity has to travel. These costs are divided between generators and suppliers on a 45/55 split. Generators and suppliers connected to the transmission network also have to sign the Balancing and Settlement Code (BSC), and this is costly, since it requires them to meet certain standards, which include financial reserves, and pay a proportion of the general costs of administering and managing the BSC, as well as their own participatory costs. Signatories to BSC also incur other related charges including Balancing Services Use of System (BSUoS) charges. BSUoS charges are paid by suppliers and generators based on the energy taken from or supplied to the transmission network in each half-hour period. These charges are paid to cover the costs of keeping the system in electrical balance and maintaining the quality and security of supply.
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Smaller generators that are embedded in the distribution network are neither connected to the transmission grid, nor signatories to the BSC, so they are not subject to these charges. 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 has to 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 on these savings to distributed generators (subject to bilateral negotiation). In addition, where a generator is embedded within the distribution system, both the generator and the associated demand it supplies benefit from avoiding scaling for transmission losses. As with transmission network losses, there are also losses as power is transported in the distribution network. In fact they are higher, as might be expected since the transmission network is designed for bulk power transport. Around 7 per cent of electricity is lost in the distribution network. The extent to which embedded generators help avoid distribution losses will vary according to their location. In some cases there are savings but it is also possible that an embedded generator could increase distribution losses, especially if there is already substantial embedded generation in the area. Embedded generation can be used to reduce a supplier’s triad demand (and thus its TNUoS charges), simply by reducing demand on the day in which triad costs are determined. Triad benefit has been potentially the most substantial of the embedded benefits. Generators have normally expected to receive 70 per cent to 90 per cent of the total value. But the triad charge will be levied on the supplier’s demand only net of the embedded generation. Thus the benefit accrues to the supplier, and an embedded generator will have to claw it back through its energy contract with the supplier. There are other perceived benefits less easy to quantify. One would be an increase in the availability and security of supply due to the increased diversity of generation sources. Another might be avoiding the cost of reinforcing the network, where increased demand would normally require increased flow down a part of the network that would therefore need the cables reinforcing. New generation near the demand could mean bigger cables were not required. The electricity is also delivered either at or closer to the correct voltage for distribution. (Electrical output from centralized generators has to be transformed up to a high voltage, transmitted, and then transformed 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, have also been small. They point out that wrongly placed generation can actually increase their costs, as it may alter or even reverse the flows down their wires, sometimes requiring replacement of equipment.
Embedded benefits 137 Even where generation is placed in a location convenient to the DNO’s network requirements, they point out that they are obliged to provide 99.99 per cent availability of supply, whereas individual embedded generators are unlikely to exceed 95 per cent. DNOs may therefore feel obliged to reinforce the network regardless of embedded generation. Embedded generation brings most benefit where the transmission and distribution grid 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 the financial and strategic benefits of embedded generation. Where it has been possible to negotiate an increase in the price for electricity exported, on the strength of the embedded benefits, it may not mean the price paid is comparable to the retail or even wholesale energy prices. This is because suppliers buying the exported power are not obliged to buy it, and can offer low prices, arguing that the risk of over- or undersupply outweighs the embedded benefits. The smaller the likely export, the less market power the generator is likely to have to negotiate a reasonable export price.
As part of its 2005–10 Distribution Price Control Review, Ofgem introduced a new incentive mechanism for connecting DG intended to ‘encourage DNOs to invest efficiently and economically in the provision of distributed generation connections and 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 apply technical innovation in the way they pursue investment in and operation of their networks.
Innovation funding incentive
The IFI is intended to provide funding for projects focused on the technical development of distribution networks to deliver value (whether financial, supply quality, environmental or safety) to end consumers. IFI projects can embrace any aspect of distribution-system asset management from design through to construction, commissioning, operation, maintenance and decommissioning. A DNO is allowed to spend up to 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.
Registered power zones
RPZs are intended to encourage DNOs to develop and demonstrate new, more costeffective ways of connecting and operating generation that will deliver specific benefits to new distributed generators and broader benefits to consumers generally.
138 Local energy 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 will decide whether the scheme qualifies as an RPZ. An incentive package of a maximum of £500 000 per year during the price-control period is allowed to each DNO for RPZ projects. The RPZ incentive mechanism combines pass-through and capacity-related elements. The capacity-related element allows a DNO to recover £1.50/kW/annum for 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.
The government recognized early on that the small generators were likely to find export costly and difficult. Its solution was to invite companies to become consolidators, who would allow groups of small generators to sell their electricity together. Aggregating suppliers, not necessarily in the same area, should reduce the variation in supply and offer larger amounts of power, so generators should have more opportunity to negotiate better prices. Consolidation has been of very limited benefit so far, operated in the original stand-alone model by only one company, SmartestEnergy, although some other companies in effect use a modified form of consolidation. Good Energy, for example, buys power generated from small generators and microgenerators, although its main business is power supply.
Generators have to sell their power. It is possible to sell directly – strike a contract with an electricity user and sign up to the electricity market. But that incurs costs that are generally too much for a small company to bear. Getting access directly to the market is an expensive business. There are the costs of signing up to the BSC, interfacing with Elexon (the nonprofit entity that administers the BSC), National Grid Co. and the counterparties to your supply contracts. Even the 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 a contract with a local electricity supplier, which agrees to take whatever power is generated for a fixed price. There is a certain amount of competition: in the same way domestic consumers can choose their electricity supplier, a small generator can offer power to different suppliers and compare prices. But there is another option. Power can be sold to a consolidator – a specialist trading company that buys power from a variety of sources and sells it on. The basis of consolidation is that you take on the risk of a portfolio of unpredictable generation. This would build to a chunk of power that is more predictable and could be sold on to the market. The consolidator can use its several sources of power to manage the risk of not meeting its commitment.
Embedded benefits 139 A consolidator may work by offering a fixed price for power supplied. But that can vary: it may be broken down into seasons, quarters, months, weeks or even time of day. Some generators may decide that they have a very stable, predictable supply to 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 projects generators are looking for a contract of at least two to three years. Projects in development looking for finance in the form of bank loans may need a contract for five or ten 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 kW generators. 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 couple of hundred pounds. Very small suppliers are better off looking for a nearby customer that can buy the power directly.
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 on your installation and whether you hope to get some income from the export, but also on regulations that were intended for very different electricity generators and distribution network operators (DNOs) whose procedures and attitudes vary widely. However, a new connection standard designed for the job has simplified matters considerably, as have new regulations that determine the price paid for the connection and that will force DNOs to offer export tariffs to new generators. At bottom is a new attitude that acknowledges that, rather than being a nuisance or a sideshow, local energy projects can strengthen existing energy-supply arrangements, reduce the need to make expensive reinforcements to the grid when new demand in the form of new housing or business arrives in the area, introduce efficiency and persuade people to use energy with more care.
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 very new and it has a number of implications. For example, for engineers, the question of safety is paramount: staff working on electrical cabling need to be sure that, once the main 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 faults are more likely. Here are the steps you should take if you wish to connect your generation system to the network.
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
142 Local energy best used to provide heat or power – or both? Consider the alternatives: if you are far from the gas network the cost of using biomass for heating may not be very different from the cost of oil or electrical heating. Assess how much energy will be produced and whether it is required as heat or electricity, and look for other local users with whom you could combine to have a more favourable profile of needs. Look carefully at your demand to see whether, in practice, you are likely to have any electricity to export to the grid.
Step 2: Get a connection agreement
If you are working towards a small project of less than 1 MW your system supplier will probably be able to deal directly with the DNO on a connection agreement in exchange for a flat fee. Completion may take up to two months under the old G59/2 standard but should be much swifter under the new G83/1 standard (see below).
Step 3: Install suitable metering
When you calculated how much electricity you would have to export, you may have found only a few kilowatt hours. In that case, you may decide you would be paying out 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 this case, since you won’t be exporting much energy and you do not want to be paid for it you do not need a meter to record exported power. Your existing meter will continue to record imported units. However, bear in mind that some meters have antifraud features and may assume that electricity passing the ‘wrong way’ through the meter is an indication of attempted meter fraud. Meters vary in their reactions but in some cases may disconnect, so check your 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 you import 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 totals for export and import and will cost £50–100. It will have two meter identification numbers (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) and fit 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 raise the generator size limit for NHH metering, as the high cost of HH metering is an insurmountable barrier to many small generators.
Step 4: Install a ROC meter
If you want to qualify for ROCs you will need to install a new meter to record the total output from your generator.
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Step 5: Arrange a tariff with your electricity supplier
Research electricity suppliers and choose the one that offers the best deal. Don’t forget that you may be offering ROCs and Climate Change Levy (CCL) exemption along with power.
The connection agreement
Written agreement is required from the DNO before the generator can be started up and connected. In the past, generators were connected under a standard known as G59/2. But this was written many years ago to connect large power stations (over 5 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 renewable sources. Previous applicants report that connecting small-scale projects often comes up against a similar lack of experience among DNO staff, as in the past the numbers of small generators connecting to the network have been small. It is up to the applicant to demonstrate that its scheme complies with G59/2 and with the associated guidance document, known as ETR113, and to convince the DNO that the operating conditions are safe. Each distribution network operator has its own application form and its own format. The applicant will have to provide scale drawings of earthing arrangements, an electrical schematic and a description of operation under normal and network fault conditions. Some DNOs may insist on a site visit to witness tests (costs vary from zero to several hundred pounds, depending on the DNO). A new standard – G83/1 – was released in September 2003 and is designed to make 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 very low, at 16 A (approx. 3.7 kW) per phase. This is too low for many small wind turbines and the industry is protesting. The Energy Networks Association indicates that DNOs will accept G83/1 as a valid connection standard for schemes that produce more than 16 A, but this is at its discretion and it has not been tried yet. G83/1’s main features are a simplified application form and appendices giving special requirements for the technologies mentioned above. It assumes that the interface between the grid and the generator (a grid connect inverter) has undergone ‘type testing’ and passed. Once the paperwork is complete, the DNO must be notified that the project is being 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 G83/1 replaces it. Any devices that were type-approved under G77 are also approved under G83/1. Since G77 allowed up to a 5 kW connection, that level has been carried over to 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
144 Local energy easy availability at least of photovoltaic panels or solar thermal panels and domestic wind turbines in DIY shops such as B&Q. At one time these had also to be processed with the DNO by completing a connection agreement, but now the requirement is simply to inform the DNO that the installation has been made, so long as no exports are expected. Getting an agreement and tariff for the small amounts of electricity exported by such projects is more problematic and often will not be worth the trouble. In February 2004, for the first time, a standard guide to connecting small generating plants to the distribution network was published. The ‘Technical guide to the connexion of generation to the distribution network’ does not describe in detail the requirements for individual projects, which are specified with the appropriate DNO. Instead, it provides background information and a ‘route map’ of the connection process. The new guide is just one result of work done by the then DTI’s Distributed Generation Group to improve the position for small generators who want to connect to the low-voltage electricity system. Describing the new guide to a Renewable Power Association (RPA) briefing on DG, Stephen Andrews of the consultants Ilex noted that, in the past, DNOs’ response to requests for connection had been very different and there had been no consistent approach. But now any potential generator could be sure the DNO should have a copy of the new guide and could work from the same document. The document was created by just one of the technical work streams being undertaken under a joint process and a combined ‘Distribution code review panel’ with members from generation and distribution, who will work on developing connection standards.
Rethinking the network
The UK regulator has published proposals that should speed the deployment of embedded generation. Times are changing for the DNOs: increasingly, electricity is being generated by local schemes that supply power direct to the local network. Overall, the change is generally agreed to be a useful one: an extensive series of local power-generation projects helps strengthen the network, and areas with their own generation are largely protected against the consequences of a failure in the grid. What is more, they increase the overall efficiency of the network, as up to 3 per cent of the power generated at large remote stations can be lost during the long-distance transmission process. But, while generation projects ‘embedded’ in their networks should ultimately be beneficial to DNOs, developing the networks to accept such projects is far from straightforward. 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 on embedded generation projects, such as small onshore wind farms, some DNOs have in recent years gained a reputation for reluctance and obstruction in connecting their projects.
Connecting and exporting power 145 Because DNOs are local monopolies, their terms of business and financial reward are laid down by the industry regulator Ofgem. In a five-yearly distribution price review, after consultation with the DNOs and others, Ofgem sets out the investment to be made in the system and the costs that can be passed through to customers in the form 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 their financial constraints are also not designed for the purpose. It may be that a local project will benefit their network overall, but, because they cannot recover the cost of grid 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, from potential faults elsewhere as electricity flow patterns change, to changed working practices 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 have halted many embedded generation projects. Part of the problem was that it was hard to 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 nearest connection point, may mask other reinforcement required not only in cabling and substations on the immediate circuit but also at distances up to several miles. Also at stake were the other loads and generators already on the system or due to join, and whether the new installation would be the point at which the circuit would have to be stepped up to a new supply-and-demand level. Projects were expected not only to take on reinforcement costs but also to put aside financing at an early stage in the proceedings. And, thanks to the slow process of accepting new projects on to the grid, projects in the queue for connection could easily fail to proceed, changing the requirements for reinforcement elsewhere. Ofgem and the DNOs began work on the charging structure for the operating period 2005–10 with this in mind. The fourth distribution-price review (known as DPR4), which set financial terms for the DNOs from April 2005, contained proposals specifically designed to make connection of embedded generation simpler and cheaper, along with proposals intended to help begin developing more active networks. Ofgem said in its proposals for DPR4 that there is ‘a general recognition that investment to replace network assets and to improve network performance needs to increase …[and] this will require investment in the distribution networks and changes to the regulatory regime’.
To respond to embedded generators, Ofgem proposed revised connection-charging arrangements for connecting to the distribution network and incentives on DNOs to respond ‘proactively’ to requests from generators to connect to their network.
146 Local energy ‘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 but the 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 as an addition to the distribution use-of-system charge paid by all users of the network per unit of electricity transported. The benefit to the project is that these payments are not made until the power plant 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 accommodate the first project. New arrangements will allow some of the reinforcement charges to be 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 the supply in order where the network is weak, maintaining frequency and voltage, for example. In the bulk power system these benefits are quantified and rewarded. Ofgem said that, as the level of DG penetration increases and the management of the distribution networks becomes more active, there may be opportunities for the DNOs to utilize ancillary services from generation (as well as demand) to help operation of the network. But it said that, to the extent to which these opportunities will arise over the next period of DPR4 (i.e. until 2010), the effect is unlikely to be significant.
New charging regimes
The DNOs operated a temporary ‘shallowish’ charging regime from the DPR4 start date in April 2005 but it was not intended to be permanent. Instead, DNOs were required to develop ‘enduring’ charging schemes that would be able to develop in a predictable and fair way as the distribution networks develop, as expected, into fully active networks. Western Power Distribution, which owns and manages the networks in south-west England, was the first to develop a new charging methodology. Its methodology for higher voltage networks on its system was implemented on 1 April 2007. United Utilities, which operates networks in north-west England – Central Networks, Scottish Power and Scottish and Southern Energy – expected to introduce new charging methodologies in April 2008, while CE, which has networks in Yorkshire and the north-east, was aiming for April 2009. EDF Energy, with networks in London and eastern England, expected to make the change at some of its networks in April 2008 and some in April 2009. The networks were not expected to use the same methodology – Ofgem recognized that conditions in each area vary considerably and in any case the regulator’s aim is generally not to impose schemes on the DNOs but to enable them to be developed by the operator. A Distribution Charging Methodologies Forum was set up in May 2007 to enable the distribution companies to work together to deal with new problems as they arise and as their networks change.
Connecting and exporting power 147 Among the early issues identified by Ofgem as likely to require discussion by the new forum were the following: • HV/LV generator charging. The new methodologies being developed have focused on high-voltage levels in the distribution networks. Ofgem said the existing charging models for HV and LV generators are simplistic and the new models developed for EHV cannot readily be extended to cover the full HV or LV network on the same basis. There is therefore a need to extend some of the concepts now being developed to provide more cost- (and benefit-) reflective charging. Charging products and structures. The distribution companies recognized that there is scope to align definitions of the charging product (e.g. capacity) and their approaches to charging for reactive power. Ofgem said there was scope for better reflection of costs of usage at different times and potentially for longer-term or more flexible products. In the medium term, it might be valuable to develop tariffs reflective of costs at voltage levels rather than by predetermined customer profile/class. Methodology statements. A common format for each of the connections and useof-system methodologies could be used by all electricity distributors. Work on the connection methodology will be taken forward in consultation with Ofgem’s Electricity Connections Steering Group (ECSG). Existing generators: On 31 March 2005, when DNOs switched to interim charging arrangements on a ‘shallowish’ basis for the first time, there was 12.9 GW of generation capacity connected to distribution networks. These generators connected under a ‘deep’-connection-charge regime and were not currently paying use-of-system charges. But Ofgem said those generators’ decisions may have an effect in future on network costs, including charges to prospective generators. Ofgem said it had explored various options for introducing charges for these generators, 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.
One reason why connection costs have been so high is that grid rules say that new generators should be able to connect in an ‘unconstrained’ way, which means that the full theoretical output from the plant can be exported at any time. This has also resulted in extensive connection queues in areas where there is little or no capacity on 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 projects connected on a ‘constrained’ basis. The DNO would be able to take the entire output when it was possible, i.e. when there was capacity on the wires. On occasions when the capacity of the wires was fully utilized the generator would be unable to export power and would be paid an agreed fee by the DNO.
148 Local energy It has been argued that experience from other countries – the system is used, for example, in Norway – has shown that with some forms of generation the constraint is much less than might be expected. Wind is a useful example. A wind farm rated at 1 000 kW would, under the UK system, have to pay for grid reinforcement that would enable it to export 1 000 kW at any time. But wind farms of course operate only 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 proportion of its rated power. Over an average year a turbine generates around 30 per cent of its theoretical maximum over the year, and since it does this only when the wind blows it is clear that it is hardly ever producing the maximum-rated capacity. Obviously, the outcome depends on local circumstances, but experience from Norway has been that the constrained connection has been very beneficial. It has brought new capacity on line 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 nearby demand, where power can be used if it is not exported. So far, however, constrained connections have not found favour in the UK.
Finance and local generation
Using the waste heat from the electricity-generation process, plants like this one at Ludlow 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 providing power or heat conventionally. There are a number of reasons for this: the equipment is relatively new or supplied in small volumes, so it is more expensive; the technology may be new to its location, so alterations are required in existing buildings to allow for it; 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 subsidies and grants that will eventually increase the market size to a point when unit costs begin to fall. That effort has been made more difficult because the options for distributed
150 Local energy energy are so varied and apply at such different scales. Developing a volume market for the domestic scale is probably more achievable than it is at mid-scale, where energy will always have to be tailored both to the resources available and to the particular needs of the customer. One problem at mid-scale is that companies often require payback on new capital investments within a few years. A switch to so-called ‘life-cycle’ costing, whereby the purchasing and installation costs are assessed in conjunction with fuel and maintenance – and often removal at the end of the plant’s lifetime – is more likely to favour distributed energy.
The government’s biggest support scheme for renewable energy is known as the Renewables Obligation (RO). The scheme was put in place in 2001. It places an obligation on all retailers of electricity to source a proportion of their electricity from renewable sources. The Obligation will remain in place until 2027 and the renewable proportion grows each year, from around 3 per cent in the first year to reach 20 per cent of supply. To prove that the retailer has complied with the obligation, a system of electronic ROCs is employed. At the end of each financial year the amount of each retailer’s obligation is determined by Ofgem, which administers the RO. The retailers can then discharge their obligation, either by presenting ROCs to prove that they have used the required proportion of renewable power, or by paying a ‘buyout’ (fine) for each megawatt hour where non-renewable (often called ‘brown’) power was supplied instead. The cash in the buyout fund is repaid, pro rata, to the retailers who presented ROCs. The upshot is that each ROC has a value equal to at least the buyout fine, and potentially considerably more if there is a shortfall in renewables generation, and many retailers are forced to pay some buyout fees to fulfil their obligation. This has been the case every year, and in fact is designed to be so: the Obligation level is increased each year to ensure that there is a shortfall in the generation achieved, so that renewables project developers can rely on receiving buying cash. These three components provide the elevated power price required to make a renewables project financially viable. A renewables power project must first be certified by providing information about the plant to Ofgem. Once it is accepted, the plant is awarded one ROC for each megawatt hour of power it produces. The generator can sell the power, the ROC and the likely benefit from the buyout fund. The Renewables Obligation differs from many support schemes used in other countries because it does not specify which renewables technologies should be employed, nor exactly how much subsidy generators will receive. Many European countries have favoured fixed tariffs (often known as feed-in tariffs), with a different tariff set for each form of renewable energy and paid for each megawatt hour generated for a specified number of years. But the UK favoured ‘market’ instruments, whereby the government’s role was not to distinguish between technologies but to allow the market to bring forward the most competitive.
Finance and local generation 151 This was partly because of a general government preference for market instruments, and partly because the avowed intention of the Obligation was to bring renewable energy on to the grid as quickly as possible, at the lowest possible price. In this 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 20 months to install the next 1 000 MW. However, the structure of the subsidy means that it is far less useful in bringing newer technologies forward, something developers of wave- and tidal-power projects have highlighted. It also has very limited usefulness for small and distributed power generators, especially those whose business is not power generation but who have an 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 as PV 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 simplified the forms required for this process for microgenerators, below 50 kW, they are still 20 or more pages long and necessarily address technical issues that could be difficult for this group – who are generally installing domestic systems – to get to grips with. Systems over 50 kW in size require still more information. Once they are registered, it is necessary for generators to prove how much power they have generated and to make returns to Ofgem on a regular basis. For micro or domestic users this will probably require new, more sophisticated, meters and the cost could outweigh any benefit from ROCs. It has been proposed that, instead, generators at the domestic level should have a ‘deemed’ figure for the average likely generation of their installation and receive ROC benefits on that basis, but so far this has not been implemented. Companies are more likely to have half-hourly meters already in place, but will have an additional administrative burden that could mean significant costs. For this reason, many small generators will rely on an agreement with their electricity 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 is very small no price may be on offer. Companies argue that the contingent nature of the Renewables Obligation is the reason why they offer small generators low prices for the power they have available to export. The base electricity price can vary considerably, as anyone with an electricity bill knows, and the value of the renewables certificate can also vary because, although the buyout price is fixed in advance, the amount of buyout fund likely to be recycled is not known, so nor is the full value of the ROC. Some party has to bear the risk of this unknown price, so power retailers who offer fixed prices to distributed generators will pitch it very low. In practice, retailers have not been obliged to offer export deals to small generators and often declined them, but, at the time of writing, this seemed likely to change, with a new requirement on the horizon that would force retailers also to offer export tariffs. The cost and complexity of the export process have meant that small generators who may have had power available have sometimes decided not to export, as the costs
152 Local energy are far greater than the benefits. And, although the RO always included an option of selling ROCs to a consolidator, intended to provide a simpler route to market for small generators, this has never been successful. An interesting variant of the RO that has been used in Australia for several years calculates an average lifetime generation for a small renewable energy source such as domestic PV and calculates the number of ROCs that would be generated over the life of the scheme. For domestic PV, in the Australian version, the lifetime ROCs are awarded to the PV supplier at the outset, who translates them by an agreed formula into 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 is entirely focused on electricity production. No benefit or subsidy is available for heat production using this route. This clearly means that heat-only sources are excluded but 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 largescale domestic, where both heat and power are required. CHP projects using fossil fuel would not be eligible for ROCs in any case, but some could use local biomass for 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 in industry, heating in commercial premises, etc. – whereas electricity is a by-product. The amount of electricity produced, even in a large product, may be relatively small and production can vary dramatically depending on the heat needs of the site. That puts even large biomass CHP owners in a similar position to small generators: they have a few megawatt hours of power to generate, often unpredictably, so the price they can get for the power, even with ROCs, is low – and often not enough to justify investing 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 government to investigate the possibility of a renewable-heat obligation to run in parallel with the RO. There was a precedent for this: the government had already decided to introduce a renewable-transport-fuels obligation that would require transport-fuel suppliers 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 group of retailers, it would be extremely difficult to identify a group of heat suppliers to be charged with the obligation.
Electricity trading arrangements
The system by which electricity is bought and sold by power-generation companies and retailers also does not favour renewable energy. The current system was put in place across England and Wales in 2001, under the name New Electricity Trading Arrangements (NETA), and it was renamed the British Electricity Transmission and Trading Arrangements (BETTA) when it was extended to cover Scotland in April 2005.
Finance and local generation 153 Before BETTA, electricity generators made offers of electricity supply at a certain price for each half-hour of the day. The offers were known as the pool. As the halfhour arrived, the system operator would call on the cheapest offers first until demand was met, and all those called on to generate would receive the price bid by the highest bid used. Generators have different amounts of flexibility over how they operate and different constraints such as fuel price, so for some it was beneficial to bid a high price and 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 ‘price taker’: they would be called on whenever they had power to supply – i.e. when the wind was blowing – and, because the cost to run was minimal and there were no fuel costs, they could accept even low prices. However, it was thought that the pool allowed some electricity companies to manipulate the market and produced electricity prices that were too high. Also, there was no penalty if they were unable to supply for a period in which they had made a bid, which was inefficient. Under NETA and then BETTA, electricity generators and retailers made bilateral contracts for whatever period suited them. The power was still dispatched by the system operator in half-hourly slots as it had been before, but the underlying assumption was that the sum of the contracts should mean the electricity supply and demand were in balance. In practice, there would always be minor balancing actions required (see Chapter 14), but this is managed by the system operator, who called on previously agreed demand and supply ‘top-ups’ or reductions, with appropriate payments. The cost 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 were available and to penalize unpredictable generation. It was hugely successful at both. Prices dropped by more than 10 per cent and operators of unpredictable power such as wind generators and CHP operators selling their excess power found that they were paying balancing charges that in some cases outweighed the entire income from their site. Since the system went live the situation has eased somewhat. Companies have become more used to matching their supply and demand and the system as a whole has seen much less balancing required. Forecasting of wind output has become much more exact, especially as ‘gate closure’ – the point at which final contracts have to be made for each half-hourly dispatch slot – has moved to just one hour in advance of dispatch. In most cases, forecasting is very reliable at this scale. In practice now, what BETTA adds to the situation for distributed generators is another layer of risk. That means that, in selling wholesale to a power company, the price is likely to be discounted again because the power company is taking on the market risk.
Climate Change Levy
A further subsidy available to most renewable-energy generators is via the Climate Change Levy (CCL).
154 Local energy The CCL has been in operation since 2001. It is a tax on the use of energy paid by industry, commerce and the public sector, and its underlying aim is to reduce carbon dioxide emissions. It was set up in response to the UK’s commitment, under the Kyoto Protocol, to reduce carbon dioxide emissions by 12.5 per cent compared with 1990 levels. The levy is intended to encourage efficient energy use and to provide an incentive for industry to move towards energy supply that has lower carbon dioxide emissions. That means that using gas or electricity attracts a lower rate of levy than using coal. No levy is paid if renewable energy is used. In practice, because renewable energy is exempt from the CCL, generators can receive a fixed CCL payment for each megawatt hour they generate. An important distinction between the CCL and RO, however, is that good-quality CHP, however it is fuelled, qualifies for the CCL. Administration is relatively simple, especially for those generators who are already qualifying as renewable-energy sources. The CCL is also administered by Ofgem, which has worked hard to try to combine the paperwork for the two schemes.
As we have seen above, the support schemes by which the UK has attempted to promote the large-scale use of renewable energy, and persuade industry to switch to more efficient and possibly site-based forms of generation, have been most successful in persuading the existing power-generation industry to invest in renewables. They have done little to help companies, groups or individuals who propose setting up local energy 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 used locally. That means that a huge variety of energy sources have to be encompassed within a support scheme that may have very different investment and return profiles and be at very different stages of development. What is more, the support scheme must be usable by a wide range of potential suppliers and the benefits must be translatable to 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 extensive version of the current heating market, where a range of boilers is available off the shelf in domestic or industrial versions that can be fitted, at the domestic scale, by local tradespeople. That approach will always be complicated by the need to assess and make use of natural sources such as wind, but, alongside a volume industry for equipment, a similar volume industry for services such as wind assessment and designing mixed systems should develop. With sources as diverse as small hydro and microCHP to support, at scales from domestic to major industry, the government has fallen back on grant programmes intended to allow suppliers to build a volume business, on the assumption that the result should be price reductions, since ‘off-the-shelf’ technologies are mass-produced.
Finance and local generation 155 The diversity of the potential market has been a problem for the industry and government because it means that responsibility extends across more than one government department. Support for heating schemes, for example, has come from the Department for the Environment, Food and Rural Affairs (DEFRA), which has also had responsibility for trying to support the growth of the biomass supply industry. Electricity supply support schemes have to come from the Department of Trade and Industry (DTI) – now the Department for Business, Enterprise and Regulatory Reform (BERR) – while Communities and Local Government (CLG) has some responsibility for buildings, and so, although it may not be involved in grant programmes, such programmes do have to be designed with reference to CLG. As a result, grant schemes have been slow to materialize, and are sometimes unwieldy and in danger of allowing important potential projects to fall between schemes. Similar problems have been encountered in dealing with organizational and legal issues (see Chapter 13).
DEFRA’s main area of support is the biomass industry. It has offered planting grants for biomass crops such as willow and miscanthus, and a further grant programme for producer groups that aims to help farmers make the switch to these crops by helping them form cooperatives and companies that can jointly market their crop. The largest grant scheme by far, however, has been the community-energy heating scheme known as the Community Energy Programme. This provided grants for CHP projects and ‘innovative’ heating, which often meant using biomass fuel instead of gas or oil for heating purposes. This was announced with a £50 million funding commitment in 2001, and DEFRA committed a further £10 million to the Community Energy Programme in 2004, but decided that it would end in 2007. DEFRA said the decision to extend the programme was based on initial strong demand and a number of larger schemes with significant outputs. However, experience has shown that many larger schemes under the initial programme could not complete within the 31 March 2007 spend deadline and did not go ahead. The smaller schemes that can complete tend to be expensive in relation to their outputs. The high dropout rate for larger schemes is the main reason for the limited estimate of spend. DEFRA added, ‘The situation would not improve appreciably if we extended the spend deadline, as these larger schemes cannot complete within a timescale 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 22 per 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
156 Local energy a duty placed on electricity retailers to reduce carbon dioxide emissions by helping their customers use energy more efficiently. There are a range of measures within the commitment, including loft and cavity wall insulation, more energy-efficient appliances such as fridges and boilers, low-energy lighting, etc. Retailers can choose how they meet their commitment, by offering cheap low-energy lamps, or giving grants for insulation, or reducing the price of efficient appliances. It has been proposed that, in future phases of the EEC, microgeneration would be a suitable addition to the range of measures available. Retailers could provide grants 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, over how beneficial it would be to install such technologies on uninsulated houses, where large energy savings are available. There are also questions over the appropriateness of including energy generation in the programme at all. At the time of writing, that question had still to be resolved.
The former Department of Trade and Industry’s programme of support to small-scale renewables began with the solar PV demonstration programme, which eventually provided £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 and communities to take the initiative in developing and installing their own renewableenergy schemes was launched by the then energy minister Brian Wilson at the beginning 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 renewablesourced heat as well as power and it included solar water heating, wind and small hydro among the projects it supported. The scheme focused on flagship and community projects, hoping that their high visibility would act to promote renewables more generally, with a second stream that provided one-off grants for householders. At the time, the DTI said suggestions for local projects could include: • • • • a solar street, where water-heating panels are fitted to the roof of every house in a 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 million before it was ended in 2006. It and the Major PV Demonstration programme were replaced by a single scheme known as the Low Carbon Buildings Programme (LCBP).
Finance and local generation 157 Launched in May 2006, this programme had £30 million to spend and four main aims: • • • • to support a more holistic approach to reducing carbon emissions from buildings by demonstrating combinations of both energy-efficiency measures and microgeneration 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 that these costs should reduce over the lifetime of the programme against a 2005 baseline); and to raise awareness by linking demonstration projects to a wider programme of activities including developing skills and communicating the potential of microgeneration to change the attitudes and behaviour of consumers (larger-scale projects will seek to engage the construction industry in project replication by demonstrating the business case for developing low-carbon buildings).
Funding was offered in two streams. Stream 1 for householders, Stream 2 for medium and large microgeneration projects by public, not-for-profit and commercial organizations. The response to the LCBP from the household sector was immediate and far greater than the government had anticipated. Grants were initially available in monthly tranches but take-up was so enthusiastic that funding ran out within minutes each month. In March 2007 the government decided to provide a further £6 million for that 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 least because of additional funding. In March 2006’s budget statement, it was announced that there would be a further £50 million for the programme. This became the LCBP Phase 2 – a £50 million capital-grant stream for the installation of microgeneration technologies by organizations including local housing authorities, housing associations, schools and other public-sector buildings and charitable bodies. It is not open to private households or businesses. Under Phase 2, purchase and installation of technologies must be from a specific shortlist of suppliers, and of the following technologies: solar PV; solar hot water; wind; ground-source heat pumps; and biomass. The LCBP was due to end in 2008, by which time it was hoped that the industry could ‘stand on its own feet’, but the industry was not confident that the programme as it stood would do enough to pump-prime the market and called for more support over a longer period.
Changing the industry: ESCos and cooperative 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 such as heat, lighting, refrigeration or entertainment. Energy-services companies (ESCos) can operate to take advantage of the mismatch between what customers are buying now and what they really want. In the process, it is hoped that providing services rather than energy could make it possible to make big energy savings – not least because for most customers energy is an alien concept. That means it is perceived as complicated and of dubious benefit to make energy savings – customers want to be sure they will have the services they want, and are not necessarily convinced that that can be achieved if less energy is used.
The ESCo business model is of great interest to traditional utilities, partly because they are customer-service companies whose business grows by offering new products to their customers, especially services that distinguish them from their competitors. But they are also of interest because utilities also want to manage their power supplies better. For example, buying power at peak times is expensive and, if companies can reduce that requirement, their costs will be reduced, and so will the risk that they will be forced to buy more power than expected at peak times and absorb the cost.
The 28-day rule
Utilities have also been freed to operate in this way by the ending of the so-called 28-day rule for domestic customers. This rule, applied from the start of the competitive market, meant that any domestic customer had to be able to terminate their supply contract and switch suppliers at 28 days’ notice. The initial aim was to promote a competitive market and make sure customers could switch in response to power-price hikes. However, as the market has changed it has limited the abilities of companies to develop new supply contracts that would benefit both company and customer. For example, many customers are still using extremely inefficient old boilers for
160 Local energy heating. Replacing them would reduce energy costs and the capital cost might be paid back after two or three years but nevertheless the capital cost might be too high for the customer. Energy companies could offer to supply new boilers and, instead of charging an upfront fee, could recoup the cost over several years of energy bills. The difference between the old cost of heating and the new cost should mean bills would not 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 such as insulation, unless it knew the customer would stay with their energy supplier for long enough for the cost to be recouped. There may have been customers who would welcome 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 more like the mortgage market. It is possible to remain on the mortgage company’s variable rate with complete freedom to switch lenders. Alternatively, the mortgage company offers various fixed-rate or fixed-period discount schemes, whereby customers have to 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 as ESCos. It also makes it much easier for independent suppliers or local energy projects to be set up. Most would not have had to follow the 28-day rule but the situation in some cases would have been ambiguous. Now it is clear that local energy project customers, 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 a structure for selling services such as heat, which may be the energy project’s main product. The 2003 White Paper Our Energy Future laid out government’s view of how ESCos would work. In one form an ESCo would act as intermediary between energy suppliers and customers. Indeed many industrial companies use these types of service company. The ESCos manage the electricity contract with the supplier, and, at the same time, enter into a contract with customers to realize potential cost savings by reducing energy use, installing insulation, etc. The benefits are shared so that the customer pays less for energy services such as heating, lighting and power, while the ESCo makes a profit. Now that carbon dioxide emissions are a major cost for many businesses, ESCos can tailor their offering to cut emissions as well. Our Energy Future suggested several ways in which ESCos could work at the community level. • An ESCo either agrees energy-delivery partnerships with individual companies or housing developers, or seeks ‘pools’ of buildings such as the collective stock of a local authority or perhaps a street or village. • Once it has assessed a potential client’s needs, the ESCo offers an energy-delivery contract 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 necessary works (which may include energy-efficiency measures) and the energy supply.
Changing the industry: ESCos and cooperative power ownership 161 • • • The client pays for the energy services, while the ESCo focuses on how to deliver those services as efficiently as possible to maximize profits and/or environmental benefits. 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 client cannot lose out, and the financial risk to the ESCo ensures a focus on delivering energy by the most efficient and/or low-emissions means, depending on the terms of 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 customer undertakes to procure power and/or heat from the ESCo over a specified period of time. The ESCo installs a microgenerator in the customer’s building, at no expense to the customer. The microgenerator remains the property of the ESCo. The ESCo maintains, and if necessary replaces, the microgenerator and all other equipment necessary to fulfil its obligations under the contract. By undertaking initial energy-efficiency measures in the building – improving insulation, for example – the ESCo can minimize the required output capacity of the supplied microgenerator, thus increasing its own profits.
Some ESCos are already operating at the community level, offering a range of energy-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 an affinity deal (one authority makes agreement with an energy supplier), a social housing club, or as part of a CHP district heating system. The basis of an ESCo (for non-CHP-related companies) is essentially for the authority or club to buy electricity as a bulk purchase, or to sign over void properties to a specified provider, in exchange for commission payments. These payments can then be used to offer discounts on energy-efficiency measures, even in the private sector. Most commonly, these would be for cavity wall/loft insulation along with hotwater tank jackets, draught-proofing and so on. Some authorities are also offering discounts or loans for solar water heating, fridges and other measures. The level of involvement a local authority has varies greatly from part owning the ESCo and operating 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 the Home Energy Act, but there are a number of legal issues specific to local authorities that affect their participation in the provision of energy services. In particular, local authorities are prohibited from supplying gas or energy-efficiency measures to private households. But this does not prevent some local authority involvement in a scheme that delivers full energy services. A CHP-based ESCo offers heat and power at standard rates for all the customers in a particular area. This means that it can offer rates that are competitive, but also have a standard rate, no matter which payment option is being used.
162 Local energy
The affinity deal
Also known as preferred-supplier arrangements or marketing alliances, affinity deals are a relatively simple concept. Following an evaluation process, a local authority identifies 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 targeted energy-efficiency offers). The supplier may also offer payment to the local authority for every resident who signs up, which the local authority can use to fund energyefficiency programmes. Aberdeen City Council established preferred supplier arrangements with ScottishPower for the supply of gas and electricity to empty council properties, for which it gained around £60 000 a year in commission.
The energy club
A social-housing energy club offers a competitive energy supply; a range of payment options; access to full- or part-funded energy-efficiency measures; independent advice on the use of existing heating systems; and access to low-interest finance for new measures and appliances. Black Country Energy Services Club was set up by Dudley Metropolitan Borough Council 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 the member tenants and service users, plus advice on the availability of social security benefits and a system of payment through the Post Office. Fuel was supplied by ScottishPower, which also provided low-cost fluorescent light bulbs and insulation to users. Black Country Energy Services Club had a partnership agreement with ScottishPower that did not tie either party into long-term arrangements. ScottishPower paid the club a commission for each new customer, and receives all the members’ void properties. Income from commission payments of £40 000–50 000 a year is paid into a community fund, accessible to all partners, to fund energy-efficiency projects.
The CHP scheme
The Barkantine CHP project in the London Borough of Tower Hamlets was built and operated in partnership with London Electricity Services (part of EDF Energy). The CHP unit provided hot water and electricity to 540 households on the Barkantine housing estate, as well as the local school and leisure centre. The 1.4 MWe CHP unit, which has the potential to supply 1 000 households, is located in a refurbished substation on the estate, which dates back to the turn of the twentieth century and was used until the 1960s.
Changing the industry: ESCos and cooperative power ownership 163 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 every other year to invest in energy-saving measures on the estate.
One of the largest community heating and cooling networks in the UK has been developed by Woking Borough Council in an unregulated public–private joint venture with the Danish energy company Esco International. Esco International owns and operates a CHP plant and district energy network, while the council looks after the metering and billing of civic buildings. The organization formed by the partnership, Thameswey Energy, provides customers with energy services at less cost than their previous supplier. Share of any profits is recycled into other energy and environmental-service projects under its articles of association. Thameswey Energy’s projects are financed with shareholding capital and loan finance. The public–private joint venture allows Thameswey Energy to escape capital controls that would be imposed on a purely government company. This means it can implement large-scale projects primarily with private finance, with the council’s initial capitalization shareholding coming from the council’s energy-efficiency recycle fund, which is recycled with every Thameswey project. The local authority ownership must be less than 20 per cent, otherwise Thameswey would be caught by central government’s capital controls. The council owns 19 per cent and the Danish company 81 per cent. Thameswey Energy designs, finances, builds and operates sustainable-energy services both within and outside the Borough of Woking. It has taken on the running of the borough’s existing energy-efficiency schemes and plans to expand them on behalf of the council. Thameswey provides residential customers with sustainable-energy services at less cost than their previous energy suppliers, despite the higher cost of the energy plant, due to the payback from the plant by the sale of heating, cooling and particularly electricity to the customer. A nonresidential customer’s current electricity unit price is normally matched and the energy-services costs are assimilated into the heat and chilled-water unit prices. The customer’s electricity consumption will be reduced since electricity is no longer needed to generate cooling. The energy-services prices agreed at the start of the long-term contract are index-linked annually so the customer maintains the benefits of the contract throughout its duration.
The legal framework
There are a number of legal issues that affect organizations wishing to establish an ESCo. • Consumer-credit law requires drawing up credit agreements for sales involving loans 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 used to 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 to local authorities. For instance, local authorities are empowered to supply electricity and heat generated by CHP schemes, and free energy-efficiency advice; but, as we saw in 17.2 above, they are specifically prohibited from supplying gas or energy-efficiency measures 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 Sector Regulations require an open and fair selection process. The appointing local authority cannot require the charging of uniform or minimum prices for specified works. Local authorities in England are restricted to 20 per cent of any joint venture company.
Community Interest Companies
Community development and investment in renewable energy projects to date have been slow. One obstacle has been the lack of a straightforward legal structure that will foster 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 social enterprises, the Community Interest Company (CIC), which will lock in the assets of an enterprise so that they cannot be transferred out of the public interest. The CIC fills a gap in the legal forms that are currently available for the development of a community renewables project, or indeed any social enterprise that wishes to reinvest its profits in the community. The government defines a social enterprise as ‘a business with primarily social objectives whose surpluses are principally reinvested for that purpose in the business or in the community, rather than being driven by the need to maximize profit for share holders and owners’. Existing social enterprises take on a variety of organizational forms that share common values or ways of working such as cooperatives, development trusts or social firms. They also use a variety of legal structures under the Companies Acts and Industrial and Provident Society legislation.
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 you use standard forms of Memorandum and Articles of Association. However, many organizations will want to use a bespoke Memorandum and Articles of Association to ensure that their constitution reflects the governance structure and non-profit nature of the organization.
Changing the industry: ESCos and cooperative power ownership 165 Once a constitution is agreed, an application to incorporate is submitted and is processed by Companies House within seven days. The price payable for limited liability is public disclosure. The key disclosures are an annual return, which has to be forwarded to the Registrar within 42 days of the annual general meeting, and audited accounts, which have to be filed with the Registrar within ten months of the end of the financial year. If a company’s turnover is less than £1 million per annum (or £250 000 for a charitable company), it does not have to produce audited accounts. However, it may be desirable to have them audited anyway to give assurance to external supporters, financiers, etc.
The image of a CLS rarely suits the spirit of a community venture, due to its association with the commercial world. A CLG is the type of incorporation used primarily for not-for-profit organizations that require corporate status. A guarantee company does not have a share capital, but has members who are guarantors instead of shareholders. The guarantors give an undertaking to contribute a nominal amount towards the winding up of the company in the event of a shortfall upon cessation of business. However, the guarantee is nominal, normally being limited to £1. A company limited by guarantee can be established so that its Memorandum states that it cannot distribute its profits to its members. In this case, if it has exclusive charitable objects it will need to apply for charitable status. CLGs are increasingly used in the not-for-profit world as a flexible and easyto-establish model. But it should be remembered that, if the organization does not have charitable status, its constitution can be changed to make it for-profit and the assets distributed to shareholders. It is for this reason that the CIC has been proposed as a way of setting up a company whose assets are locked into the public interest.
If an organization wishes to be democratically controlled and avoid the requirements of company law, and will not be affected by the lack of a charity number, it could register as a cooperative. Legal forms that enshrine cooperative principles can be established either as Industrial and Provident Societies (IPSs) or limited companies. An IPS is a membership organization in which each member agrees to buy one or more shares. Members’ liability is limited to the amount unpaid on the purchase of 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 IPS rather than a company limited by guarantee.
166 Local energy 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 cooperative societies. It must have a minimum of seven members and rules that forbid the distribution of its assets among members. The IPS shares some features of a limited company, namely the acquisition of a distinct legal identity and the consequent limit on liability of its management committee. In general, the regulations and formalities governing an IPS are less onerous and complex and more flexible than those imposed by Companies House. But registration as any type of IPS is slow and quite expensive. A charitable IPS, unlike a charitable company, cannot register as a charity with the Charity Commission (it registers with the Inland Revenue), although it can call itself a charity exempt from registration. As such, it does not have to comply with most charity legislation and, although eligible for the tax advantages of charitable status, it is not subject to scrutiny by the Charity Commission. But the relative unfamiliarity of IPSs may make it difficult to persuade official bodies, such as the Inland Revenue, banks, local authority officers and members of the public that the IPS is charitable.
Baywind Energy Cooperative is an Industrial and Provident Society formed in 1996 on the lines of cooperative models pioneered in Scandinavia, the largest of which is a 40 MW offshore wind farm, Middelgrunden, in Denmark, with 8 500 members. The first two projects enabled a community in Cumbria to invest in local wind turbines. The original board of directors included seven members of the community from Ulverston and Barrow. Baywind’s first share offer in 1996–7 raised £1.2 million to buy two turbines at 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 for local investors, and 43 per cent of existing Baywind shareholders live in either Cumbria 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 the UK and abroad. The seven members who currently make up the board of directors draw on a range of skills and experience to conduct the business of the cooperative. The board is elected by the whole membership at an AGM and is supported by a full-time paid administrator, who is also a director. All profits derived from electricity generation are paid back to the shareholders. Since the formation of Baywind in 1996 members have received a competitive return on their investment: between 5.6 per cent and 6.6 per cent gross. Under the government’s Enterprise Investment Scheme, most members
Changing the industry: ESCos and cooperative power ownership 167 can claim back 20 per cent tax on their initial investment in the co-op, thus increasing the return to between 7 per cent and 8.2 per cent. The co-op has a minimum shareholding of £300 and a maximum of £20 000.
The Centre for Alternative Technology (CAT) at Machynlleth in Wales is powered 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 centre did not want to incur a capital cost at this point and it was considering purchasing electricity from the grid. But the community stepped in, seizing the opportunity to operate its own wind turbine and sell the power to CAT. Now the project is seen as a model for community wind-power schemes for other parts of the UK. Project partners include Powys Energy Agency, Forest Enterprise and the 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 of them, EcoDyfi, Andy Rowland had recently taken on an EU-funded project to develop community renewable energy. The proposal to build a turbine owned by the community was put to local people at a series of meetings. Following the meetings a steering group was set up with around 90 members, each paying £10 to join. This provided some development funds and a strong core of support, useful both for planning the project and in practical terms. As the project solidified the group set up a company – structured as an Industrial and Provident Society on the Baywind model, called BroDyfi Community Renewables Ltd. It was particularly important that the project got general agreement: as a community project, it depended on it for much of its funding. Capital and setup costs to install the turbine totalled £85 000. That included just £15 000 for the 85 kW turbine because BroDyfi went to Denmark to buy a turbine that had been operated for ten years. It enabled BroDyfi to buy a turbine under 300 kW and one that met a size condition on the planning permission. Construction costs were £45 000 and future annual maintenance costs are estimated at £2 320. The turbine was partly funded by grants. The European Regional Development Fund provided £19 000 via Ecodyfi, and ScottishPower’s Green Energy Trust provided £10 000. The Energy Saving Trust invested £18 000, providing both grant funding and buying shares. Continues
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When shares were offered to the 90 members of the development group the offer was oversubscribed. Those investors are hoping to average an 8 per cent return on their investment over 15 years. All the power from the turbine will be sold to CAT. The centre has signed an agreement to buy the power generated (around 163 MWh/year) for 15 years and will use 34 MWh/year to supply its site with electricity and hot water. The remaining electricity will be exported to the local grid. The 15-year agreement means the wind group has a fairly secure return on its investment. Under this power purchase agreement the output from the turbine is split into three levels. The price for the lowest level is the highest, with the price for the next two bands set progressively lower. CAT takes on the rights to the renewables obligation certificates (ROCs) generated with the electricity.
Output and generation
Load factors and variability
No form of generation will generate power or heat continuously. This variability in generation sources is of benefit to grid operators, because it means that there are a number of options available to balance supply with demand as it varies during the day, the week and the year. A diverse electricity supply industry with a variety of sources of electricity supplying the industry at different scales is the most robust. Utilities use the term load factor to compare the different outputs of powergeneration plants. Load factor is generally the amount of power produced by the plant compared with its theoretical maximum output, but this may also be referred to as ‘capacity factor’, implying that it measures how much of its total capacity the plant is supplying. There are many reasons why a generator has a load factor of less than 100 per cent. They stop generating in the case of renewable energy if there is no ‘fuel’ – it is dark (in the case of photovoltaics), say, or between tides (for tidal power). In the case of rotating machinery, even if fuel is continuously fed into the power-generating plant 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 a fuel cell supplying heat and power – may be stopped, or the power output varied over time, 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 will record 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 reflected in the availability, whereas if it is shut down to meet the demands of the grid it will not affect the figures. Availability is, however, an ambiguous term as it is not clearly defined. For photovoltaics and wind, for example, different definitions of availability do 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 different times. The demands of the grid are very different at different times, so power stations operate differently. A power station that shuts down unexpectedly in summer may stay out of operation for longer than necessary to complete outstanding maintenance work while demand – and hence prices – is low. In the winter an unexpected shutdown would be kept to the minimum possible.
170 Local energy 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 electricity 70–85 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 a year, it will generate about 30 per cent of the theoretical maximum output, and that 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 for 10–20 per cent of the time – although the array is generating at a lower level at other times. This is also moderated by the fact that high temperatures can reduce performance by up to 20 per cent. The performance of the photovoltaic array is therefore partly determined by the siting of the PV panels to ensure they receive maximum 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 tide as it interacts with the wind. Hydropower plants sited on a river can operate almost continuously while the water level in the river is high enough. Strict restrictions placed on hydro stations by the Environment Agency limit the use of plants if the host river has a low flow in 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 to one where the plant is halted at unpredictable intervals when flow drops. Hydro plants with storage in the form of a reservoir or millpond may have more control over 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 at least once per year and may be halted by unplanned maintenance at any time. The amount of halted time is a function of the age of the plant, the condition of the equipment, how well it has been maintained and so on. Availability could be as high as 90 per cent for the best stations but much lower in those that are poorly maintained. Since thermal plants can be operated at part load depending on grid demands and started up quickly, they may be used for load following, so load factors may be considerably lower than availability. For CHP plants both availability and load factor depend on how the plant is set up, and whether the major load is for the heat or power fraction of the output.
The availability and load factors of power stations that export power to the grid at large 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. This group of devices, which include microCHP systems to replace household boilers, is expected to be a major new influence in the market: government hopes that they will eventually be used by millions of homes. A trial by the Carbon Trust investigated how much electricity was exported to the grid as it examined field trials of microgeneration projects. It looked at the progress of devices with a range of electrical output up to about 25 kW and included Stirling engines, organic Rankine-cycle machines, fuel cells and internal-combustion engines. The Carbon Trust points out that, while small-CHP is mature, and a few fuel-cell devices are emerging as ‘beta’ test units from several manufacturers, there is less experience in the microCHP area. One of the most mature microCHP technologies is the WhisperGen Stirling engine unit, which has been sold as a low-voltage DC unit for remote heat and power on yachts and other off-grid installations for some years.
Progress of the field trial
The Carbon Trust initiated the trial in February 2003. By late autumn 2003, five suppliers of small and microCHP equipment had joined the trial but all the suppliers experienced significant difficulty in supplying units for the trials. By August 2004, when 74 units had been contracted for installation, there were only 7 installed. The Carbon 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.
MicroCHP for homes
The findings from the trial indicate that the different technologies exhibit different performance characteristics in different environments. Very early findings for microCHP indicate that its performance is not as encouraging as had been hoped. Data from trial units installed in representative homes in the UK suggest that the 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 existing technology modelling exercises. The amount of electricity generated is much lower than forecast. Electricity exported out of the building is considerably higher than expected.
172 Local energy • In addition, a number of other concerns have been raised during the trial. This includes notably high electricity consumption by the units during some phases of operation and the sensitivity of the units to poor installation.
The reasons for the poorer-than-expected efficiency appear to be related to the design and operation of the units at their current stage of development. A microCHP unit 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 is pumped through the heating system, but at this stage no electricity is being generated. However, warming up the mass of the unit to operating temperature absorbs energy, most of which cannot be usefully recovered (this is especially true for units installed outside the living/working areas of a house/business). If the unit was started only once a day and then ran steadily for many hours, the impact of this would be very small, possibly negligible. However, in many properties heat demand is intermittent and is required for only short periods. In some sites units are called to start up as many as five times a day. In such circumstances the repeated warm-ups absorb a significant amount of energy, which is not re-released in a useful way, thus resulting in reduced efficiency. There is less electricity generated than expected simply because the data show that running hours are lower than previously modelled. In addition, during warm-up periods units do not generate electricity, as might have been assumed in modelling. This is particularly relevant for summer operation, when the units need to provide only hot water. In this circumstance, little if any electricity is generated, as the water tank can reach the desired temperature before the microCHP has generated a material amount of electricity. Ideally, the microCHP industry needs to design units with the ability to modulate electrical output much more widely than currently. While it is still relatively early in the trial, at the current state of development of microCHP, the emerging trial data indicate there is unlikely to be a significant carbon emissions reduction opportunity from wide deployment of the technology at this stage in its evolution. From the results of the trial to date, carbon savings are in the range of plus or minus 18 per cent. The reasons ‘appear to relate to the interaction of the devices with the heating system, building and occupancy’. It is also instructive to note that these effects are also apparent to some degree in the findings relating to boilers and should be considered in any future support for efficient boilers. ‘If this trend continues for the full trial, there will be a material risk of an increase in emissions if microCHP is deployed at scale without regard to the different performance characteristics of specific technologies and the circumstances of their installation, maintenance and use.’
Small-CHP for business
The performance of small-CHP in businesses seems to be much stronger, where a number of installations appear to offer material carbon savings. The technologies
Output and generation 173 being monitored in the Carbon Trust’s field trial appear to have better performance than the microCHP units. Current data suggest that the electricity-generating efficiencies are considerably higher and that overall thermodynamic efficiencies are good. Running hours are also longer than for microCHP and less intermittent and so startup and shutdown losses are much reduced. It should be noted that the sample size for small-CHP is small at this stage and therefore this picture may change as more units come on stream within the trial. Overall it appears that worthwhile carbon emissions reductions can be foreseen from the range of internal-combustion engine devices monitored in the trial to date if they are installed and operated properly, based on current grid carbon emissions. These results from the field trial support existing modelling results and there are two main factors that explain the enhanced performance compared with microCHP. First, small-CHP units are installed in business premises on the basis of an economic business case. This tends to be based on a higher level of analysis than in a home and on long, continuous run hours with few or no starts during a 24-hour period. Under these conditions, which have been found in the trials, the units operate in steady-state and hence warm-up losses are negligible. In such circumstances the units can be expected to exhibit high levels of thermodynamic efficiency through good design, which contributes to carbon-saving potential. Second, the proportion of fuel input converted to electricity is found to be higher in the small-CHP units (20–25 per cent) than in microCHP (5–15 per cent) due to their design at this electrical output. This is due to the efficiencies of the technologies employed 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 heat element will be no more efficient than a boiler, and consequently the small-CHP units will tend to save more carbon than microCHP. Evidence from the trial also demonstrates how carbon savings from small-CHP can be very low due to poor installation, inadequate maintenance and poorly controlled operation, together with additional electrical loads such as fans being added in boiler rooms when the CHP unit is installed
The Carbon Trust also raised some larger issues over how widespread microCHP might 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 problems for managing the grid and, for example, a greater capacity of inefficient open cycle gas turbine plant may be called on to operate. If substantial numbers of Micro-CHP units are installed to deliver a capacity of over 1 000 MW then investors in new, efficient plant may defer construction. The net result will be old, inefficient plant will continue to generate with high carbon emissions. Many of the plant operating at the margin are steam-raising coal plant. This is because they are the only plant capable of operating part-loaded to provide for the sudden changes in demand/supply balance seen due to, for example, sudden rises in demand when TV programmes end or the unplanned shut-down of a centralised generating
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station occurs. These may be the only plant available to provide this service and microCHP will neither replace them nor reduce their output. Published market predictions for Small and Micro-CHP suggest potentially 400,000 per 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 be operating beyond 2020. By 2020, to meet climate-change obligations, it is likely that grid carbon intensity will have reduced. Consequently, any potential carbon savings from small and micro-CHP will reduce accordingly.
As the problem of global climate change becomes more urgent, the life-cycle cost of activities, in carbon dioxide emissions, has become a pressing issue. Take wind power. Although it has no carbon dioxide emissions at the point of generation, the construction and erection of the turbines do entail emissions. It is similar for all forms of generation: a lifetime measurement of carbon dioxide emissions from coal-fired generation includes not only the emissions from coal being burnt but from other activities such as the coal mining and transport and plant construction. Concrete manufacture is highly energy-intensive and it is an important component of most power-plant construction. As all forms of generation interact within the electricity supply system, they also require carbon dioxide emissions in the form of peaking power, spinning reserve, etc. The European Commission is one organization that has tried to quantify the carbon 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 it is assumed that the activities end: if coal transport is included, for example, should the emissions involved in constructing coal-transport ships also be included? Interested parties will argue over where those lines should be drawn; nevertheless the EC estimate is one attempt to produce a basis for comparison. What is clear is that combining biomass fuels with carbon capture and storage offers 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.
Changing energy patterns
Changes in the climate are likely to change electricity requirements over the long term. The UK Climate Impact Programme estimates that ‘by the 2020s our annual average temperature would be between 0.2 ◦ C and 0.8 ◦ C higher’. But what that means in practice is not a slightly warmer environment throughout the country, but a drier and hotter south-east and wetter northern areas, along with more extreme weather events. The basic message is that the changes are expected to accelerate. By the 2080s, the south-east could have summer temperatures as much as 6 ◦ C higher than we experience now – with perhaps 60 per cent less rain. Frost days have declined
The advantages and disadvantages of different sources of electrical energy
Energy sources Efficiency 40% 57% 40–55 400 50% 84% Very high 55–85 440
Technology considered for the cost estimate GHG emissions (kg CO2 eq/MWh) Fuel price sensitivity
Source IEA Projected cost 2030 2005 cost (e/MWh with (e/MWh) 20–30/tCO)2 EU-27 import dependency 2005 2030
Proven reserves/annual production
Open-cycle gas turbine CCGT (combined cycle gas turbine) 80–95 45–60 39% 50–65 800 800 59% 40–45% 550 82% 93% 30% 40–45%
PF (pulverized fuel with fluegas desulphurisation) CFBC (circulating fluidized bed combustion) IGCC (integrated gasification combined cycle) 55–70 750
Output and generation 175
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Energy sources Efficiency 33% 30–60% 95–98% 95–98% Nil Nil 95–98% 95–98% Nil Nil Low Medium 40–45 25–75 28–170 28–80 30 Nil 10 20 5–25 100 50–150 40–120 25–90 40–80 55–260 30 Nil 15 Almost 100% for uranium ore
Technology considered for the cost estimate GHG emissions (kg CO2 eq/MWh) Fuel price sensitivity
Source IEA Projected cost 2030 2005 cost (e/MWh with (e/MWh) 20–30/tCO)2 EU-27 import dependency 2005 2030
Proven reserves/annual production Reasonable reserves, 85 years Renewable
Light water reactor
Biomass generation plant
Large Small (<10 MW)
Source: European Commission.
Output and generation 177 as temperatures have risen by 0.50 ◦ C over the past century and we have seen less rainfall 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 and companies operating it have to prepare for change. The effects of extreme weather conditions were graphically demonstrated in 2002, when storm damage to the electricity network left thousands without power – some for weeks. Changes in the country’s weather patterns affect the electricity supply system in two 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 means that National Grid and the Distribution Network Operators (DNOs) have to deal with all kinds of temperature and weather effects. There is an impact in day-to-day management where equipment is affected by the temperature. Transformer cables have different ratings in summer and winter, depending on the external temperature. The operators start with a thermal rating based on ambient temperatures for the last 10–20 years, which gives guidance, and then on a daily basis a table is constructed for MVAr against temperature, which can be used to forecast performance. Similar temperature-dependent effects are felt throughout the system. In just two examples, the capacity of the transmission line alters depending on the temperature, because the high-tension cables expand and sag more at higher temperatures – a 400 kV line currently has a capacity of 2 190 MVA in summer and 2 720 MVA in winter. In the gas network, compressors sending the gas down the pipelines have to work harder at higher temperatures, drawing more power. Temperature is not the only issue. Extreme weather events also place stresses 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, lightning and salt pollution as likely to contribute to weather-related faults. Managing these faults requires investment in the high-voltage transmission system. Some protection is built in. For example, the west coast is subject to salt pollution from high winds and protection takes the form of a spray that is released when the salt burden gets too big. Similar equipment is increasingly required at the distribution level, where the network is more extensive. Changes in consumption require the grid to bring extra power on to the system and it can be very sensitive. On a summer’s day a shift from clear sky to thick cloud adds an 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-twelfth of 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, human behaviour changes and the electricity supply system has to be able to respond. One big effect in the long term will be from additional air-conditioning loads, which will add to both peak and 24-hour demand. National Grid has already seen a growth of 5 per cent in air conditioning in the commercial sector in five years to 2005 and it expects to see a further 6 per cent in the 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 socioeconomic factors. Similarly, a 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 double their energy use when external temperatures increase from 18 ◦ C to 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 an effect. If air quality deteriorates people tend not to use natural ventilation. Instead they 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 the smaller scale that large changes will take effect. With the south-east drier than the north, socioeconomic effects will be different in different parts of the country. On that scale, small perturbations affect the system and the grid suggests it may have to use the infrastructure differently. Most customers don’t take much account of their consumption. They use fans for cooling in the summer months – it’s a small item for one customer but for NGC it is a noticeable cooling load.
Putting a price on carbon
The European Commission’s emissions-trading scheme should impose a cost on energy generators that produce carbon dioxide, favouring renewable generation. In July 2005 Greenpeace set out a list of changes that would have to be made to support and encourage DG in the UK. Among its proposals were changes to building regulations that would ensure that distributed energy was used in new homes and business premises, changes in the rules on network access and export tariffs that would support the export of excess power from small generators, and tax changes that would give a financial incentive for installing distributed energy. Progress in some 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 is fully assessed and costed. Greenpeace raises this possibility in its wish list as a tool to make visible the effects of carbon dioxide emissions from large fossil-fuel-generating stations and impose a financial penalty accordingly. But many believe that ‘discovering’ a price for carbon dioxide 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 should reward companies and individuals who switch to the most efficient forms of energy generation, as well as those who use sources that, like renewables, do not produce carbon dioxide emissions.
The EU Emissions Trading Scheme
The European Union has attempted to develop, and impose, a price for carbon dioxide emissions with its Emissions Trading Scheme (ETS). In January 2005 the ETS commenced operation as the largest multi-country, multi-sector greenhouse-gas emission-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 is intended to give incentives to all participating companies to reduce their emissions, but also to ensure there are ‘easy wins’ and that the easiest and cheapest emission-reduction activities are completed first. The ETS requires each of the EU’s now 27 member states to set a so-called National Allocation Plan (NAP) – an annual ‘budget’ for carbon dioxide emissions from the installations in sectors covered by the scheme. In each period, or phase, each of the installations in each of the participating countries has its own annual emissions allocation. The scheme includes both heat- and power-based carbon dioxide emissions, based as it was on all combustion installations that produced more than 20 MW of thermal energy, whether or not that was used to produce electric power. In the first phase (2005–7), the ETS includes some 12 000 installations, representing approximately 45 per cent of the EU’s carbon dioxide emissions. This phase encompassed energy activities (combustion installations, mineral-oil refineries, coke ovens), production and processing of ferrous metals, mineral industry (cement clinker, glass and ceramic bricks) and pulp, paper and board activities. Because it included combustion installations it took in industrial sites, but also heating and incineration plants such as those used in large commercial buildings and even social organizations such as hospitals. The emissions allocations granted to each installation were calculated in the UK by so-called ‘grandfathering’ – taking an average of emissions in previous years. Once allocations were made, an electronic register of allocations was maintained in each country. This made the trading part of the cap-and-trade approach possible: companies or organizations that had emitted less carbon dioxide than had been expected would be rewarded, by being able to sell their extra allowances to companies that 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 up in the first phase would not have to buy their allowances. This approach was also taken elsewhere, although some environmental groups had argued that all new plants should be required to buy allowances to ensure they had strong incentives to invest in the most efficient plant and reduce their emissions – indeed, many groups had argued that even existing installations should have to buy all the necessary allowances, possibly through an auction method.
Results from Phase 1
The first phase of the EU TS had mixed success. The principle of the programme was firmly established: all countries presented NAPs, companies were given allowances, trading platforms were introduced and allowances were traded. However, it had been argued 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 NAPs were not ambitious enough (in limiting emissions). The power-generation sector was seen as most favoured by the NAPs. Ecofys suggested that the caps for Phase 1 were lenient. In most countries, the power sector would not need to reduce carbon dioxide emissions as much as the country as a whole. In other words, the other sectors must make more ambitious emission reductions than the power sector under the scheme. More strikingly, a few countries (such as the Netherlands) gave more allowances than Ecofys 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 and there would be an oversupply of carbon dioxide emission allowances, the price of allowances fell dramatically, from around e30 per tonne of carbon dioxide in April 2006 to e1–2. In addition, the generous allowances given to power-generating stations came under fire. Power companies had passed on the supposed cost of participating in the scheme to their customers, but, as Ecofys – among others – had suggested, far from being short of allowances, had found themselves with allowances to sell. Nevertheless, the fact that the ETS existed meant that emitting carbon dioxide had a price. And although that price had fallen dramatically in the course of the first phase of the ETS it was clear that the European Commission would be more ambitious in future about setting tight limits, so it was likely that the price of emitting could only increase. This has clearly influenced decisions on energy. Large pulp and paper suppliers have in some cases already switched to using biomass fuel instead of gas or oil (see Chapter 11) and major power generators, such as the UK’s largest coal-fired station at Drax, have pursued plans for co-firing with biomass and for efficiency improvements that 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 by the ETS. Knowing the ETS would be implemented, holding back any improvements until 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 upgrades had been completed after the ETS was in operation. That may be so. However, ETS supporters can argue in response that there will be only one opportunity to benefit from the introduction of the ETS. The larger picture is that the ETS has indeed done its job of altering the balance of the decision-making on how energy is produced, and its weight in the decision can only increase as the cost of carbon dioxide emissions increases. That will depend on how the second phase of the ETS is managed.
Setting up the ETS Phase 2
The second phase of the Emissions Trading Scheme is longer than the first, lasting from 2008 to 2012. The European Commission aims eventually to include all emitting sectors, including aviation, maritime and land-transport emissions, but early plans to include aviation in the second phase have been delayed. Following the collapse in carbon prices in the first phase, the EC was determined to impose stricter limits in Phase 2. It sent back almost all the National Allocation Plans submitted by the member states, requiring further cuts in the allocation. Table 19.1 Suggested carbon dioxide emissions allowances by country for the second phase of the EU Emissions Trading Scheme
2005 verified emissions 33.4 55.58 82.5 131.3 474 71.3 22.4 2.9 6.6 2.6 1.98 80.35 203.1 25.2 8.7 182.9 19.3 242.4 Proposed cap 2008–12 32.8 63.33 101.9 132.8 482 75.5 22.6 7.7 16.6 3.95 2.96 90.4 284.6 41.3 8.3 152.7 25.2 246.2 Cap allowed 2008–12 30.7 58.5 86.8 132.8 453.1 69.1 21.15 3.3 8.8 2.7 2.1 85.8 208.5 30.9 8.3 152.3 22.8 246.2
Member state Austria Belgium Czech Republic France Germany Greece Ireland Latvia Lithuania Luxembourg Malta Netherlands Poland Slovakia Slovenia Spain Sweden United Kingdom
1st period cap 33.0 62.08 97.6 156.5 499 74.4 22.3 4.6 12.3 3.4 2.9 95.3 239.1 30.5 8.8 174.4 22.9 245.3
Source: EU press release IP/07/459: ‘Emissions trading: Commission adopts decision on Austria’s national allocation plan for 2008–2012’, 02/04/2007.
Putting a price on carbon 183
Trading outside Europe
In Phase 2 the ETS should also begin to trade with similar schemes outside the European Union. Initially, this will be with European countries closely linked with, but not members of, the European Union – Norway (which began in 2007 to develop its own NAP), Switzerland, Liechtenstein and Iceland. In this phase also, the ETS will allow companies to take account of carbon reductions made outside Europe. This is accomplished through two mechanisms set up under the Kyoto Protocol, referred to as the Clean Development Mechanism (CDM) and the Joint Implementation (JI). The CDM allows European companies to invest in emissions-reduction projects outside Europe that would not otherwise have taken place, or provide funding that will help replace a high-emissions project such as a new power plant with an option that produces lower emissions. A JI project is similar to a CDM project, but the JI project must be in a so-called Annex 1 country that has signed up to limit its carbon dioxide emissions under the Kyoto Protocol. In both cases the project and its emissions credits must be validated by 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 Protocol and the Bush administration has not supported attempts to develop a global approach to reducing carbon dioxide emissions, the US picture as a whole reveals much more support for the enterprise than might be expected. US states have considerable autonomy in setting taxes and developing their own environmental policies and, for many, carbon dioxide emissions reductions have been a 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 jointly decided to set reductions targets in the mid-2000s. The cap-and-trade approach used in the ETS was familiar to US regulators, as it had already been used to address other pollutants, and the north-eastern states planned a cap-and-trade system of their own for carbon dioxide. By 2007 both groups had taken a more than passing interest in the ETS and had raised the possibility of trades between the US and European schemes. That is not likely in the near term, but Federal organizations have been under pressure to shift their position on carbon dioxide emissions. The Environmental Protection Agency already runs cap-and-trade schemes to reduce sulphur dioxide and other pollutants, and under a long-running test case was being pushed to declare carbon dioxide a similar pollutant, which would require it to be regulated and reduced in the same way. Meanwhile, the Bush administration was also under pressure from industry, which feared it would be subject to a variety of emission-reduction regulations set by tens of states. Instead, industry argued in favour of a single federal scheme. It is unlikely that such an about-turn will be on the agenda for the Bush administration but an incoming Democrat or even Republican president would have support for taking some measures to fall closer into line with the global consensus on emissions.
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Carbon trading for commerce and industry
The European Union’s ETS is in its early days, but the system of cap and trade to reduce emissions of pollutants has a longer history: it has been used to reduce pollutant emissions including sulphur dioxide as well as more recently carbon dioxide emissions. The UK government proposed in 2006 that this system should be used to limit and eventually force reductions in carbon emissions from businesses that fall outside the ETS. The ETS encompasses sites where carbon emissions are produced from heat generators producing 20 MW or more. The UK also proposes to limit carbon emissions 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, large hospitals, large local authorities and central government departments. Without new policies, emissions from these types of organization are set to increase over coming years but as explained in the Energy Review, this group of organizations have significant 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 organizations with electricity consumption higher than 3 000 MWh. At current energy prices, this would generally capture organizations with annual electricity bills above £250 000. The government estimates that this sector comprises around 5 000 large nonenergy-intensive organizations. It wants to provide ‘Policy instruments [that] can provide an important framework to help organizations overcome the various barriers to investments in energy efficiency that remain.’ The Carbon Reduction Commitment (CRC) would be a mandatory cap-and-trade proposal covering energy-use emissions. The proposal is for an auction-based cap-and-trade programme, in which participants would be required to purchase allowances corresponding to their emissions from energy use (either at an auction or from each other) and then surrender them to a coordinator. Government would cap total energy-use emissions by deciding on the number of allowances issued for auction. The revenue raised by the auction would be recycled to participants, so the proposal would be broadly revenue-neutral to the Exchequer. In addition, the proposed system for recycling CRC auction revenue to participants overall would, to some extent, create individual winners and losers, so as to reinforce the business case for driving carbon savings and good energy management. It would be accompanied by a system of voluntary benchmarking and reporting of energy use covering the sector. The government also plans to provide more information to the sector about how to reduce energy use and therefore emissions, and work towards industry-led agreements to reduce emissions. There would also be changes to building regulations, but, since they have recently been revised, this is likely to be in the 2020 timeframe.
Putting a price on carbon 185
Making the case for local energy
The Carbon Reduction Commitment is intended to replicate the effect of the ETS for smaller companies: that is, to put a price on carbon dioxide emissions that encourages companies to look for energy-efficient alternatives or to switch to renewables. Still more important, the cost of carbon-emission certificates should add weight to the financial argument for re-examining how energy is provided. The cost of carbon dioxide may tip the scales for companies and organizations considering whether they should invest in local generation for their heat and power needs. Other measures are working towards the same goal: planning documents that require new buildings to incorporate a proportion of on-site low-carbon energy generation to meet their heat and power needs and an EU Directive that requires an energy-efficiency certificate to be displayed in every public building. There are a number of other changes that will act to help ease the development of local energy projects. These include changes in the method by which the cost of connecting a local energy project to the network is calculated and smart meters that will make it much easier for local energy producers to export their excess power across the network. More broadly, there is a new opportunity for ESCos and private power networks to be set up, and to work with their customers to develop new approaches to energy supply and management. There is still a long way to go before local energy schemes become a familiar sight on most new-build projects and are backfitted to help provide energy for existing buildings, not least because the thousands of miles of existing wires and the networks that feed the UK’s millions of buildings will all, eventually, have to be re-examined and in many cases replaced by equipment that is much smarter and more flexible in operation. Nevertheless, it appears that much progress has been made since the turn of the century. As new measures begin to bite we can expect many more local energy projects to be brought into operation using local energy resources. The result should be a much more diverse and reliable network.
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Greenpeace’s wish list
In a 2005 report Greenpeace set out a ‘top ten’ list of actions required to foster the development of DG. The actions were as follows: 1. The government to use the tax system to reward householders and businesses 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-energy technologies. This would steadily cut emissions from the building stock and enable the retirement of power stations, while also transforming the economics of distributed energy by creating economies of scale and cutting installation costs. 3. Local sustainable electricity systems to be encouraged through the removal of current limits on the development of private wires. Limits on the export of power from these sustainable local systems should be raised. 4. Local government to become a key player in moving to sustainable energy systems. There should be area-based carbon dioxide reduction targets, along with a statutory requirement for all councils to develop an energy strategy. 5. All electricity suppliers to be required to purchase surplus electricity from domestic power generators, at rates that will ensure the take-off of domestic generation. 6. Inefficient, centralized power stations to be heavily penalized to reflect the 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 a tax on waste heat. 7. No new fossil-fuel generation to be permitted unless it includes cogeneration. 8. A nationwide network of biomass or biogas cogeneration plants to be developed, with Regional Development Agencies playing a leading role. 9. Energy regulation to be completely overhauled. Ofgem should be transformed into a sustainable energy regulator with its primary duty being to deliver substantial emission reductions through the encouragement of distributed energy. 10. The publication of a Decentralized Energy White Paper.
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 nonenergy intensive business and public sectors’. London: HMSO; 2006 Department of Communities and Local Government. ‘Domestic Installation of Microgeneration Equipment, Final report from a Review of the related Permitted Development 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 of barriers and incentives to distributed electricity generation, including combined heat and 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 Annual Symposium; London, 2000
188 Local energy ReFresh (Recent Findings of Research in Economic & Social History), Network industries and the 19th and 20th century British economy, issue 19, Autumn 1994 Union for the Coordination of Transmission of Electricity. ‘System Disturbance on 4 November 2006’, final report. Brussels: UCTE; 2007
AC/DC 13, 112 affinity deals 162 B&Q, Grimsby, PV scheme 75 backup generation 114 Balancing and Settlement Code (BSC) 25, 33, 135 balancing costs 33 balancing market 23, 24 Barkantine CHP project 162–3 batteries, energy storage 46, 98 Baywind Energy Cooperative 166–7 biomass 87–93 life cycle costs 176 planning consent 125 projects 31–2, 89–92 types 34–5 bio-oil 93 Black Country Energy Services Club 162 British Electricity Trading and Transmission Arrangements (BETTA) 23–5, 152–3 Bullerö Island, Sweden, scheme 103 capital costs 149–50 carbon emissions 179–85 life cycle costs 174 per MWh for different energy sources 175–6 small scale CHP 172–3 Carbon Reduction Commitment (CRC) 184–5 carbon trading 180–4 Carbon Trust, small scale CHP trials 171–4 Central Electricity Generating Board 6–7, 8 centrifuges, energy storage 99 Clean Development Mechanism (CDM) 183 Clear Skies 156 climate change 174, 177–8 Climate Change Levy (CCL) 143, 153–4 coal-fired power generation centralized power stations 5 life cycle costs 175
operating characteristics 18 combined cycle gas-fired plants 19 combined-heat-and-power (CHP) 11, 32–3, 77–85 Community Energy Programme 155 domestic CHP 79–83 economics 83, 152 efficiency 171–3 ESCo schemes 162–3 EU support 78–9 government support 77–8 grid connection 81 load factor 170, 171 metering output 81 potential markets 82–3 projects 83–5 supply management impact 120, 173–4 system suppliers 82 technology 77, 79–80 wood-fuelled 88 Community Energy Programme 155 Community Interest Companies (CIC) 164 community projects biomass 90–1 ESCo schemes 160–1 grants 155, 157 wind power 166–8 company formation incorporation 164–5 not-for-profit 165 competition 10–11 connecting to the grid: see exporting power to the grid consolidators 25, 33, 152 contracts CHP operators 33 consolidators 138–9 ESCo’s 160–1 wholesale 22–3, 24 cooperatives 165–6
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costs compared with conventional projects 149–50 per MWh for different energy sources 175–6 see also economics DEFRA grant support 155–6 demand response 115 demand variation: see load variation deregulation 9 diesel generators, life cycle costs 175 distributed generation (DG) benefits 10–11 definition 128 distribution network operators (DNOs) 9, 25–6, 143–4 distribution networks impact of embedded generation 26, 119–20, 144–5 private-wire networks 129–30 domestic CHP 79–83 efficiency 171–2 grid connection 81 load factor 171 metering output 81 potential markets 82–3 supply management impact 120 system suppliers 82 domestic heating 32 DTI grants 156 economics 149–50 combined-heat-and-power (CHP) 83, 152 hydoelectric power 53, 54–5 Electricity Council 7 electricity demand: see load variation electricity supply industry competition 10–11 before deregulation 2–3, 6–8 deregulation 9 electricity supply system 17–27 effect of climate change 174, 177–8 supply management 23, 24, 113–15, 117–20 embedded generation 25 benefits 136–7 distribution system impacts 26, 119–20, 144–5 see also exporting power to the grid emissions trading 180–4 Emissions Trading Scheme (ETS) 180–3 energy clubs 162 energy crops: see biomass energy efficiency combined-heat-and-power (CHP) 32 energy-efficiency measures 160, 161–2 gas-fired electricity generation 81–2 ground-source heat 37 heat and power 31 transmission losses 3–4, 11 Energy Efficiency Commitment (EEC) 155–6 energy mix 95–6 energy reserves 175–6 Energy-services companies (ESCos) 159–64 energy sources life cycle costs 175–6 UK energy use 30 energy storage 95–103 EU Emissions Trading Scheme (ETS) 180–5 exporting power to the grid CHP 33, 80–1 connection agreement 143–4 connection charges 145–7 connection standards 141, 143 constraining connection 147–8 distribution system impacts 26, 119–20, 144–5 export value 33, 129, 136–7, 144, 146, 151–2 grid connection 46, 80–3 hydoelectric power 67 steps by step guide 141–3 supply management impact 117–20 technical guide 144 fault ride-through 116–17 finance, grant support 154–7 Forestry Commission Wales 90–1 forward prices 10 frequency, standard 111, 112 fuel cells applications 108 development projects 109 types 106–7 fuel price sensitivity 175–6 fuel reserves 175–6 fuels: see energy sources funding, grant support 154–7
gas-fired electricity generation 11 life cycle costs 175 operating characteristics 18–19 gas storage 96–8 gas turbines 18–19 operating characteristics 21–2 gate closure 22 generating companies 9, 10 effect of competition 11 wholesale contracts 22–3, 24 generators 12–13 government grants 154–7 government strategy 121–2, 126–8 grants 154–7 grid connection: see exporting power to the grid ground-source heat 36–9 heat generation 29–39 heat pumps 37, 125 hydoelectric power 51–9 assessing hydro sites 53 benefits to the water supply system 56 economics 53, 54–5 energy extraction 56 environmental issues 55–6 life cycle costs 176 load factor 170 location factors 5 operating characteristics 20 pumped storage 96–8 short-term reserve market 114–15 small scale 53 turbine types 52 UK’s hydropower potential 53 hydrogen economy 99–102 projects 100–2, 109 hydrogen generation 108–9 Icelandic New Energy 102 Industrial and Provident Societies (IPSs) 165–6 Joint Implementation (JI) 183 kinetic-energy storage system (KESS) 99 Kyoto Protocol 183 licensing 129 load factors 169–70 load variation 17–18, 23–4 demand response 115 effect of climate change 177–8 standby power 113–14 supply management 23–4 London Borough of Lambeth, PV schemes 74 London Borough of Merton policies 124–6 London Borough of Tower Hamlets, CHP project 85 Low Carbon Buildings Programme (LCBP) 156–7 maintenance shutdowns 21–2 marketing alliances 26, 162 market mechanisms 22–5, 152–3 Mersey Docks and Harbour Company, wind cluster 48–9 metering 81, 142, 151 microCHP 80–3 efficiency 171–2 grid connection 81 load factor 171 potential markets 82–3 supply management impact 120 system suppliers 82 National Control Centre 6 National Grid 3–4, 6, 9, 10 supergrid 7 supply management 23, 24, 113–15 Norsk Hydro, hydrogen plant 100–2 North of Scotland Hydro-Electric Board 8 not-for-profit companies 165 nuclear power generation life cycle costs 176 operating characteristics 19–20 Office of Gas and Electricity Markets (Ofgem) 25, 26–7 peak lopping 115 Penwith Housing Association 38–9 photovoltaic power 69–75 chemical reaction 106 hybrid PV / wind-power system 103 load factor 170 panel types 71 street applications 70–3 planning policies 122–4
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planning system 130–3 power companies: see distribution network operators (DNOs); generating companies; retailers power flows 112–13 power stations centralized 4–7 generating characteristics 17–22 life cycle costs 175–6 load factor 170 see also specific types power units of measurement 14–15 preferred-supplier arrangements 162 private-wire networks 129–30 proton exchange membrane fuel cells (PEMFC) 106 pumped storage 96–8 pyrolysis 92–3 quality of supply 113–14 reactive power 112–13 regulation 2–3, 27 renewable-heat obligation 30–1, 152 Renewables Obligation Certificates (ROCs) 67, 142–3, 150–1 reserve power 114–15 reserves of fuel 175–6 retailers 9, 11 retail market 22–3, 33, 152–3 Scotland planning policies 126 power companies 8 wave and tidal generation 62–3, 66 shutdown of plant 21, 169 Snowdonia National Park, hydropower 58–9 social enterprises 164 solar power life cycle costs 176 planning consent 125 see also photovoltaic power solar water heating 35–6 solid-oxide fuel cells (SOFC) 106–7 South of Scotland Electricity Board 8 South Somerset District Council, hydro power 57–8 spinning reserve 24, 114 standards connection 141 frequency 111, 112 voltage 4 standby power 113–15 supergrid 7 supply companies: see retailers supply management 23, 24, 113–15 for distributed generation 117–20 supply quality 113–14 Thameswey Energy 163 tidal power 61–7 load factor 170 location factors 6 potential resources 61–2 project 66 trading arrangements 23–5, 152–3 transformers 13–14 transients 115–16 transmission losses 3–4, 11 transmission networks 6 energy dissipated 3–4 seasonal variation in capacity 22 see also National Grid units of power 14–15 Utsira, Norway, hydrogen plant 100–2 voltage 111–12 standards 4, 111 Waitrose farm, wind and solar power 46–7 Wales, planning policies 125–6 waste heat 30–1 watts 14–15 wave power 61–7 government support 66–7 load factor 170 location factors 6 marine current turbines 63–4 plant scale 62 potential resources 61–2 projects 62–3, 64–6 weather effects 22, 174, 177–8 wholesale contracts 22–3, 24 wind power 41–9 assessing wind resource 43 community projects 166–8 constraining connection 148
energy storage 46, 98, 100–3 grid connection 46 life cycle costs 176 load factor 170 location factors 5 operating characteristics 20–1 planning consent 125 short-term reserve market 114 turbines design 41–2 installation 43–4 regulation 114 rooftop 44–6 small scale 42, 45–6 Wood Energy Business Scheme (WEBS) 90 wood fuel 34, 35, 87–92 fuel supply 89–90, 91–2 projects 31–2, 89–92