INTEGRATING HYDROGEN INTO THE UK ENERGY ECONOMY A G Dutton1 , J Watson2 , A Bristow3 , M Page 3 , A Pridmore3 1
Energy Research Unit, CLRC Rutherford Appleton Laboratory, Chilton, Didcot, Oxon. OX11 0QX, UK Tel: +44 1235 445823, Fax: +44 1235 446863, E-mail:
[email protected] 2 Science Policy Research Unit, University of Sussex, Falmer, East Sussex, BN1 9RF, UK Tel: +44 1273 873539, Fax: +44 1273 685865, E-mail:
[email protected] 3 Institute for Transport Studies, University of Leeds, Leeds, LS2 9JT, UK Tel: +44 113 343 5325, Fax: +44 113 343 5334, E-mail:
[email protected], E-mail:
[email protected], E-mail:
[email protected] (all affiliated to Tyndall Centre for Climate Change Research)
Keywords Hydrogen economy, Energy supply, Transport, Hydrogen distribution
Abstract Hydrogen is likely to become a major new fuel for transport and district or domestic-scale combined heat and power systems in the 21st century. Depending on the specific production technology, hydrogen can displace fossil fuels and limit or completely displace the production of carbon dioxide. It may also enhance energy system security through increased storage capacity and reduction in the need for energy imports. This paper reports preliminary results from a project funded by the Tyndall Centre for Climate Change Research into the environmental impact of selected pathways for producing, storing, and distributing hydrogen in the context of a range of possible future energy economies. Historical examples of large scale technological change will be used to demonstrate how the integration of hydrogen into the energy supply system will depend on a complex interaction of government regulations, corporate strategies, institutional factors, and required technological developme nts. It will be shown that there is likely to be no single optimum architecture for the hydrogen economy and this will be further emphasised in exploring possible transition pathways for the integration of hydrogen into the UK energy mix. Various hydrogen production and distribution pathways will be developed and analysed, particularly for their carbon dioxide reduction potential. In particular, the capacity for the integration of water electrolysis systems associated with renewable energy power generation will be explored and compared with the conventional alternative - steam reforming of methane. 1.
Introduction
The recent UK Energy White Paper [1] has adopted the target to reduce UK carbon dioxide emissions to 60% of current levels by 2050, in order to mitigate the effects of climate change. The introduction of hydrogen to displace conventional fuels for heating and transport is cited as one of the possible strategies towards achieving this target. However, although hydrogen can be produced by multifarious processes, the principal contenders for large scale production are still likely to result in some emissions of carbon dioxide. For example, steam methane 1
reforming (SMR) will result in significant carbon dioxide emissions unless implemented alongside a carbon dioxide sequestration strategy; electrolysis using grid electricity will result in emissions elsewhere in the electricity supply network. The likely level of these emissions over time and the long term prospects for the hydrogen economy to deliver sustainable reductions in the time frame beyond even 2050 must be estimated in order to decide the immediate priority which should be accorded to hydrogen within the overall carbon dioxide reduction strategy. The carbon reduction potential of introducing hydrogen into the energy supply infrastructure depends on: (i)
the type of conventional capacity displaced,
(ii)
the new plant required to supply and distribute the hydrogen,
(iii)
the measures (if any) taken to limit harmful emissions associated with the hydrogen production, and,
(iv)
the end-use efficiency of hydrogen use.
The first three of these will vary between countries and even locally within any given country; all four will vary with time. For the analysis of longer-term developments of this kind in the energy system, conventional forecasting techniques are severely limited. Whilst these techniques are a useful tool for analysing trends over the short to medium term, the results of forecasts for periods longer than a decade into the future are often unsatisfactory. As a result, there is an increasing trend towards the use of scenario techniques to explore the uncertainties inherent in longer-term explorations of the future (see, for example, [2]). Scenarios are one way in which both governments and companies have sought to test the robustness of current decisions by developing a range of possible futures. The aim is to identify how likely it is that a particular development (in this case, the shift to a hydrogen economy) will happen, and to identify some common trends that are important for this development across a wide range of scenarios. This paper will briefly review a widely used set of scenarios in the UK (section 2.1) and what they might imply (section 2.2) for the development of a hydrogen economy up to and beyond the year 2050. It will be shown that very different end-states (and hence transition pathways) are likely depending on the prevailing geo-political framework. A software model, THESIS (Tyndall Hydrogen Economy Scenario Investigation Suite), is being developed to explore the transition pathways towards these possible end-states. Ultimately this model will be used to assess the penetration and diffusion of hydrogen into the transport fleet and the built environment, and the knock-on consequences for the rest of the energy supply system (for example, build-rate and primary fuel- mix in the electricity supply industry). As the database is still under construction, preliminary results are presented here for 2020 (section 3), based on published projections. These results clearly show the consequences for the overall energy system of a relatively modest initial penetration of hydrogen. 2.
Energy use scenarios and possible hydrogen futures in 2050
2.1.
The SPRU/Foresight Contextual Futures Scenarios
A widely used set of scenarios within the UK are the contextual futures scenarios, originally developed by the Science Policy Research Unit (SPRU) at the University of Sussex for the UK 2
Government Foresight Programme [2]. The SPRU/Foresight Scenarios have subsequently been used in projects for other Government departments. Energy-specific applications of these scenarios have included the Fuelling the Future study by the Foresight Energy and Natural Environment Panel [3] and, more recently, the energy projections of the Cabinet Office Performance and Innovation Unit (PIU) [4]. In this latter study, the PIU produced its own results from the basic SPRU framework for the UK energy system in 2020 and 2050. Some specific results from this study are presented later in this paper. The starting point for the SPRU/Foresight Scenarios is the construction of logical and consistent 'storylines' about the future. These storylines can be applied at a number of different levels from sub-national to global. The scenario construction assumes that the whole world is subject to the forces described within them. This is no more or less realistic than the assumption that any one country will conform strictly to any one scenario over time. The scenarios are defined around two main variables or dimens ions of a largely qualitative nature. The first dimension is values (individuals/consumers vs. community) and the second is governance (autonomy vs. interdependence). This means that technology is not viewed as autonomous and following its own independent path. It is rather viewed as dependent on the particular combination of dominant values and governance systems being explored. This allows the degree of success of different technologies and systems to vary according to different scenario circumstances. When the two dimensions of the scenarios are combined, they suggest four possible future states (see Figure 1).
GLOBALISATION
GLOBAL SUSTAINABILITY
WORLD MARKETS
CONSUMERSISM
CONVENTIONAL DEVELOPMENT
PROVINCIAL ENTERPRISE
COMMUNITY
LOCAL STEWARDSHIP
REGIONALISATION
Figure 1 :
The SPRU/Foresight Contextual Futures Scenarios
These four scenarios can be characterised as follows: •
World Markets combines an emphasis on the individual and consumer with a highly interdependent governance structure; this world is dominated by private consumption and a highly developed and integrated trading system.
•
Provincial Enterprise has a similar emphasis on private consumption combined with a more fragmented governance system, thus emphasising more local- level (i.e. national and regional) and variable decision processes.
3
•
Global Sustainability combines social and ecological values with a more interdependent and collective governance structure, producing a strong world regime interested in dealing with environmental issues.
•
Local Stewardship has a fragmented governance structure, as in Provincial Enterprise, but the predominant values are social and, to a lesser degree, ecological, rather than consumers and individuals.
2.2.
The SPRU/Foresight Scenarios and Hydrogen
This section of the report sets out the context for hydrogen production and use in the UK in 2050. The Tyndall Centre research team selected drivers and inhibitors to hydrogen in a number of related categories including security of supply, environmental impact, quality of life, extent of trade and competition, technical change and the policy environment. Each category was then addressed in the context of the four SPRU/Foresight scenarios. The elaboration of each scenario does not necessarily address each of these categories in detail. However, they provide a guide for the kinds of issues that need to be covered to justify subsequent quantitative judgements about the role of hydrogen in 2050. These scenarios will be developed further and published as a Tyndall Working Paper [5]. Under the World Markets scenario, with its emphasis on low energy prices, security of supply and the environment are regarded as secondary and there is very little government intervention in markets. There is no incentive for a change in the fuel mix and hydrogen is only likely to develop in specialist, niche applications, such as portable applications with fuel cells and certain types of vehicle. Overall penetration is expected to be low, perhaps less than 5% across all sectors by 2050, with SMR being the sole production route. In Provincial Enterprise, governments are inward-looking and protectionist; energy and resource policy is dominated by security concerns, so a shift to hydrogen could be expected as UK reserves of gas and petroleum run down. However, innovation may be slow due to limited import of foreign technology, although this may be countered by a stronger incentive to develop a centralised hydrogen infrastructure. A penetration of 20-25% across all sectors is expected by 2050. Coal gasification (though without carbon sequestration) and renewable electricity are the most likely production routes. Global Sustainability is arguably the most promising environment for the growth of a hydrogen economy. Global economic and political systems are highly interconnected and social and environmental goals are paramount. Energy prices reflect environmental externalities and the goals of the Kyoto treaty have been successfully followed through with a strong international emissions trading regime. Energy demand is considerably lower than in the previous two scenarios, but generation diversity is low due to the adoption of a lowest cost approach. Hydrogen emerges in local grids around areas of traffic and population density. By 2050, hydrogen is firmly established (penetration, perhaps, 25-30%) in the Domestic, Service, and Industry sectors as a fuel vector for fuel cell CHP systems and is starting to dominate the Transport sector. Hydrogen is produced from renewables and nuclear power. In Local Stewardship local and regional decision making predominate; energy and transport decisions are driven by security, local environmental, and local employment issues. The Kyoto framework has survived but is not so well regulated as in GS with varying degrees of compliance. Long distance and international travel is reduced and innovation is comparatively low. Hydrogen development is hampered by the lack of local energy sources to produce it, but
4
has established itself as the fuel of choice in the public transport sector by 2050. Renewables are the dominant source of hydrogen. 2.3.
Possible UK hydrogen futures in 2050
Any assessment of the possible impact of the hydrogen economy towards reducing carbon dioxide emissions over a given time horizon must first estimate the likely emissions over the time frame excluding the use of hydrogen and then evaluate the emissions assuming that hydrogen is introduced. The SPRU/Foresight Scenarios present a useful framework for such an assessment [6]. Figure 2 shows the historic energy consumption in the four main sectors (Domestic, Industry, Transport, and Services) of the UK energy economy over the period 1970-2000 [7]. In the World Markets and Provincial Enterprise scenarios, it is clear that the potential growth in the Transport sector is likely to dominate energy consumption. By analysing recent trends in the Transport sector only (Figure 3), it is clear that air and road travel have been and are likely to remain the major growth sub-sectors. Official projections of growth in the kilometrage of UK cars [8] suggest a likely increase from around 400 billion kilometres per annum in 2000 to 550 billion kilometres per annum by 2030. This corresponds to a growth in the car population from around 25 million to 33.5 million [9]. The problem for hydrogen forecasters is to predict the timing of penetrations of hydrogen vehicles into the new car market and their subsequent diffusion through the population. Kruger [10] has modelled the likely growth of the world market in hydroge n-powered road vehicles. Assuming a baseline of 10,000 hydrogen vehicles in 2010, Kruger produces estimates of hydrogen vehicle penetration assuming industry growth rates of between 10% and 40%. Even in the latter case, the proportion of hydrogen vehicles in the population only becomes significant after 2030, tending towards complete penetration by 2050. This is a high growth rate, bearing in mind it must cover parallel growth in vehicle production lines, fuel cell manufacture, and hydrogen production, storage, and distribution systems. The major large scale options for producing hydrogen are currently considered to be: (i)
Electrolysis (ideally using low carbon electricity),
(ii)
Steam methane reforming (SMR) (ideally with carbon dioxide sequestration).
The carbon dioxide reduction potential of any transition scenario depends on the production route, the efficiency of the hydrogen production process, and the efficiency of the end-use of hydrogen. Typical state of the art conversion efficiencies are 69% for electrolysis and 81% for SMR. It is estimated [11] that hydrogen consumption in a bivalent internal combustion engine will require similar fuel energy input per km as for petroleum. However, the fuel cell is likely to perform up to twice as well on typical urban driving cycles [11]. It has been claimed that hydrogen production, storage, and regeneration will facilitate the wider penetration of renewable energy electricity by providing increased energy storage capacity. In fact, the UK electricity grid provides sufficient buffering capacity that energy storage is unlikely to be a general driver towards the hydrogen economy until renewable penetrations exceed 20-30% [12]. In fact, if hydrogen for transport is produced using electricity, hydrogen production will constitute an additional demand, not accounted for in current industry plans. 5
Figure 2 :
Historic energy consumption data in the UK economy by end- use sector [7], compared with scenario projections [6] (and linear behaviour)
Figure 3 :
Transport sector - trends in energy consumption (mtoe) by technology and major fuel-type [7]
3.
Modelling the introduction of hydrogen to 2020
3.1.
The UK electricity generating mix
The potential carbon savings of any change in the electricity supply system must be assessed against the likely generating mix. Such predictions have been complicated by the liberalisation 6
of the electricity market in the UK, which has resulted in grid operations in Scotland and Northern Ireland being controlled separately from those in England and Wales, while national energy statistics are collected for the whole of the UK. Figure 4 shows the plant mix 1 existing in 2000 according to UK national energy statistics (DUKES) [7]. UK electricity generation plant ( 2000) 1976 4513 Gas
2705
22026
12242
Coal Oil Nuclear Renewables
6236
CHP 28302
Figure 4 :
Interconnectors
UK electricity generating plant mix (MW) by capacity (2000) after DUKES [7]
The 2002/03 winter peak demand for England and Wales was 54.8 GW, representing 82% of the installed capacity of 66.5 GW [13]. The current perceived overcapacity has arisen from historically high margins allowed by the original state-owned Central Electricity Generating Board and the so-called “dash for gas” following electricity liberalisation, as power generators installed high efficiency Combined Cycle Gas Turbines (CCGT) [14]. This shift from predominantly coal to gas has placed the UK on course to meet its Kyoto obligation to reduce greenhouse gas emissions to 12.5% below 1990 levels by 2010. The introduction of the Labour Government’s New Electricity Trading Arrangeme nts (NETA) in spring 2001 led to a fall in wholesale prices by 20% (adding to a similar sized fall before the system went live). These price falls have led to financial difficulties for some generators, notably British Energy (who operate most of the UK’s nuclear power capacity), and discouraged further investment in plant. However, the UK faces a steep decline in generating capacity over the next 20 years, due to: (i)
retirement and decommissioning of most of the current nuclear capacity (around 11.0 GW or 16.5 % of capacity)
(ii)
retirement of a significant proportion of coal- fired generation due to age and the implementation of the EU Large Combustion Plant Directive (LCPD), possibly up to the entire coal- fired generating capacity of 22.8 GW.
At the same time, the Government has a target for renewable energy to supply 10% of electricity demand by 2010 and an aspiration for this to increase to 20% by 2020. 1
Dual fuel plant distributed evenly between Coal and Oil categories; Hydro, Waste, Wind included in Renewables
7
Over the same period, the expansion of conventional demand is expected to be from around 343-345 TWh in 2000 to 387-408 TWh in 2020 [15]. Any electrical power plant capacity to supply the Transport sector with hydrogen must be considered as an additional demand to this conventional prediction. Since the UK’s current targets for renewable energy expansion are generally considered ambitious (at least within Government departments), it is unlikely that additional renewable capacity would be available to meet the additional demand from transport, which would therefore most likely be met by CCGT generation (or directly as hydrogen produced by SMR). This would not realise the expected environmental benefit from using hydrogen. In fact, on a national aggregate basis, it is not clear when there would be sufficient low carbon electricity to meet this demand, although high regional renewable energy penetration levels might create local markets for hydrogen production. The immediate options for an accelerated introduction of low carbon electricity are: (i)
accelerated renewable energy programme,
(ii)
replacement of existing fossil fuel based (coal/oil/OCGT) plant with modern, high efficiency CCGT capacity,
(iii)
increased penetration of combined heat and power (CHP) systems,
(iv)
staged programme of new nuclear construction,
(v)
large scale clean coal or steam methane reforming, with large scale carbon/carbon dioxide sequestration.
Strong objections exist to the last two options: there is likely to be widespread public opposition to a revitalised nuclear programme (on grounds of nuclear waste and cost), while technology for large scale carbon dioxide sequestration remains unproven (and the possibly catastrophic implications of leakage are not well understood). However, the ability to accelerate the installation of renewable energy capacity must also be considered doubtful given the widespread difficulty in obtaining planning permission for renewable energy plant, particularly wind farms, in the UK; the installation of 0.5 GW of wind capacity (which took 10 years) would have to be expanded at least one hundredfold. Offshore installations are likely to improve the installation rate, but, from the point of view of carbon dioxide reduction, all this electricity will best be used to displace existing fossil fuel based capacity. The National Grid Co. publishes a 7 year plan, listing likely changes to capacity available to the network in England and Wales to 2010 [13]. Projections of the UK electricity generating mix to 2020 have also been made in terms of primary fuel in Energy Paper 68 [15] published in 2000. More recently, the Energy White Paper [1] has listed some additional targets and aspirations. In the absence of any decision to re-instate the nuclear power programme and following the existing strategy, the balance of demand in 2020 seems likely to be supplied by natural gas. Figure 5 shows the authors’ best estimate 2 of the likely UK electricity generating mix in 2020. The potential to develop a low carbon electricity economy in time to meet significant demands for hydrogen fuel even in the time frame beyond 2020 therefore seem limited.
2
Figure 4 assumes that: the Government target for 10 GW of CHP and “aspiration” for 20% of electricity demand to be supplied by renewables (shown as declared net capacity) are met; nuclear capacity is phased out, as scheduled, to leave only Torness, Heysham, and Sizewell B; the coal mix declines to 13% of production (Energy Paper 68 [15], projection CH); oil-fired generation is completely phased out; and CCGT’s take up the balance of demand. Total capacity has been scaled from the capacity in 2000 according to the predicted change in total electricity demand [15] over the twenty years (i.e. identical plant margin).
8
UK electricity generation plant (projection 2020)
4600 10000
Gas Coal Oil 42163
18049
Nuclear Renewables CHP
3700
Interconnectors 11732
Figure 5 :
Projected UK electricity generating plant mix (MW) by capacity (2020), after [15] and [1]
If hydrogen is generated from electricity therefore, it must be considered to have a carbon dioxide penalty in the same way as it must if reformed directly from fossil fuels. 3.2.
The carbon implications of various hydrogen production pathways to 2020
A software package, the Tyndall Hydrogen Economy Scenario Investigation Suite (THESIS), has been developed to assess the carbon emissions implications of future energy and hydrogen scenarios. THESIS accepts as input the energy demand for various sectors of society, accounts for energy conversion and distribution losses (including those associated with electrical power generation), and outputs the total primary energy required and the associated carbon emissions. Sub- models have been developed for the introduction of hydrogen into the Transport sector. Further sub- models are being developed to include CHP systems and hydrogen storage and regeneration into the electrical grid. Table 1 shows the projections of total primary energy supply and associated carbon emissions for the year 2020 with a range of hydrogen production scenarios, assessed using THESIS. The baseline year (H1) is taken as 1990 for comparison with Kyoto climate change targets. The energy projections are based on the Central GDP Growth / High Energy Prices (CH) scenario in the UK Government’s Energy Paper 68. The historic data shows a dip in carbon emissions due to the “dash for gas” in the 1990s, as already discussed. The projection (F1), published in 2000, underestimated the primary energy demand and emissions for that year (H2), largely due to an unexpected rise in natural gas prices, which led to an increased proportion of electricity production from less efficient coal- fired power stations. For purposes of comparison, it is assumed that 5% of Transport energy demand in the UK is met by hydrogen in 2020 (since approximately half of the UK’s transport emissions come from motor cars, this corresponds to a 10% penetration of hydrogen vehicles into the car population by 2020, representing around 2.5 million vehicles). This may be considered an ambitious target, but the conclusions regarding the relative merits of different supply routes remain valid for a wide range of vehicle penetrations at this time horizon. Half the hydrogen vehicle population is assumed to have internal combustion engines (at equivalent efficiency to petrol 9
engines) and half fuel cell drives (assumed to require 60% of fuel required by petrol engine due to improved performance over a typical driving cycle). The production routes considered are: (i)
electrolysis at 69% efficiency (additional required electricity capacity provided by CCGTs) [F3a],
(ii)
electrolysis at 69% efficiency (additional required electricity capacity provided by renewable or nuclear power generation) [F3b],
(iii)
steam methane reforming (SMR) at 81% efficiency (without carbon sequestration) [F3c],
(iv)
steam methane reforming (SMR) at 81% efficiency (with carbon sequestration) [F3d].
Detailed scenario
Primary hydrogen source
Total primary energy supply
Relative C emissions 3
(1990 = 100)
(1990 = 100)
H1
Historic (1990)
100
100
H2
Historic (2000)
107
95.9
F1
EP68 projection CH (2000) [15]
103
91.2
F2
EP68 projection CH (2010) [15]
110
98.8
F3
Baseline projection (2020)
No hydrogen
114
100.8
F3a 5% transport demand (2020)
Electrolysis (increased CCGT capacity)
116
102.3
F3b 5% transport demand (2020)
Electrolysis (increased (renewables/nuclear capacity)
118
99.0
F3c 5% transport demand (2020)
SMR (without C sequestration)
114
100.5
F3d 5% transport demand (2020)
SMR (with C sequestration)
114
99.2
F3e Baseline projection (2020) + enhanced renewables capacity
No hydrogen
114
93.5
Table 1 :
Projected energy and emissions scenarios for 2020 with various hydrogen production pathways
Electricity is arguably the most convenient energy delivery vector. However, current electrolysis systems are only around 69% efficient and any additional electricity generating 3
THESIS model
10
capacity beyond current plans is likely to be the cheapest and easiest to install, which is expected to be CCGT technology. Under this scenario (F3a), carbon emissions actually increase with the change in fuel type. Clearly it would be better to opt for direct production of hydrogen from natural gas by SMR rather than utilise electricity generated in CCGT’s, but the consumer will make their decision based on production cost (which would probably favour SMR), availability and utility at the point of use (which might favour electrolysis), and additional storage and distribution considerations. Only if the additional electricity for electrolysis is generated using renewable (or nuclear) electricity (F3b) can substantial carbon emission savings be made. A very small carbon emission reduction (F3c) from the baseline (F3) could apparently be achieved by using hydrogen derived directly from natural gas without carbon sequestration, if the promised performance improvements from fuel cell vehicles can be realised. However, this reduction is likely to be more than negated by improvements to the fuel efficiency of conventional engines proposed by vehicle manufacturers for 2008 [16]. If the carbon from the SMR process can be sequestrated (F3d) then carbon savings of around 1.6% can be made for every 5% of vehicle population (note that no energy penalty has been added for the carbon sequestration). The emissions savings are slightly less than with renewable electricity due to distribution losses in the gas network. The technology for carbon sequestration remains largely unproven and the concept is not yet widely accepted. While the most beneficial hydrogen production route would seem to be by electrolysis from renewable electricity, the final scenario (F3e) in Table 1 shows that the same additional renewables power capacity required to produce the 5% penetration of hydrogen into the Transport sector would result in a greater carbon emissions benefit if used to displace coal- and then gas- fired generation and the Transport sector remained petroleum-based. 4.
Hydrogen pathways to 2050
Work is proceeding to develop full hydrogen transition pathways to 2050 from the scenarios. One of the crucial questions currently facing policy- makers is whether a hydrogen infrastructure must be centrally planned and implemented, or whether the policy framework should rather seek to encourage a more piecemeal development. Current developments at a European level [17] appear to favour the first approach. However, as has been shown above, the environmental drivers for the hydrogen economy rely on the supply of carbon- free hydrogen and this cannot be guaranteed a priori. Rather, the hydrogen supplied is likely to be derived from fossil fuel sources or as an additional demand on the existing electricity system (thereby causing the retention for longer of carbon-based generation capacity); in either case, the environmental benefit may be small or even negative. There is a danger that the gulf between current energy supply and the very long term vision of a renewables-supported hydrogen energy economy will remain so large that it becomes difficult to sustain the continued investment required to install a centralised distribution system if other technologies are seen to deliver earlier and larger carbon emission benefits. But is the centralised approach to the development of a hydrogen infrastructure the best way to proceed, in any case? Large technical systems, such as the electricity supply infrastructure, tend to consist of a complex network of new and old technologies, bespoke equipment and organisational relationships. Thomas Hughes, a pioneer in the analysis of large technical systems, has identified three distinctive features of such systems [18]: •
they combine sets of technical (e.g. power stations, transmissions lines) and non-technical (distribution companies, environmental laws) components, 11
•
there are various horizontal and vertical interconnections between the components, which means that changes in one component often lead to changes in others, and,
•
they have a control component that sets out the way in which the economic and wider social performance of the system is regulated; this control is exercised by management and economic systems (e.g. wholesale power markets), technical systems (e.g. control technologies) and regulatory systems (e.g. through regulators such as OFGEM).
These features have far reaching consequences for the operation and development of the system. These consequences are particularly important for those wishing to make radical changes to current technical systems, such as attempting to shift the UK energy system towards the use of hydrogen as its primary energy carrier. Beyond the technical challenge, Hughes also points out the powerful vested interests inherent in the existing system, which the new technology is seeking to supplant. The hydrogen energy economy as it is usually conceived represents a direct challenge to the current energy system. It calls for new technologies and infrastructures, and also new relationships between energy suppliers and consumers (e.g. through the expected deployment of fuel cell heat and power systems), new firms to supply equipment, new modes of energy service delivery and new challenges for government regulation. Faced with this wide ranging list of potential barriers, a transition to the mass use of hydrogen seems to be an enormous challenge. An important case study is the early development of the electricity industry [19]. Whilst modern electricity industries are highly integrated with large numbers of co-ordinated components and organisations, this state is the end result of decades of system development – some carefully planned and some extremely chaotic. The development of the electricity supply industry has shown that: (i)
Developing technical systems are characterised by complexity and, at times, an apparent lack of rationality. They are not just a collection of new and old technologies linked together, but incorporate new regulatory arrangements, new corporations, entrepreneurs and financiers, where success does not depend solely on attractive economics. The first electricity systems were not cost competitive, but were developed anyway due to reasons of novelty, prestige and the preparedness to take risks, a situation not unlike the current circumstances of the fuel cell industry.
(ii)
New system growth is often full of uncertainty. The national scenario exercises, carried out by experienced and influential energy experts from industry and academia, show how much uncertainty there is about the future role of hydrogen – i.e. about whether or not it has a future, and how it might be introduced. The case of the electricity industry has demonstrated that the role of the State has its limits. Whilst governments can set up new regulatory frameworks and market rules to shape developments, the transition path to a new energy system cannot be predetermined or centrally planned. This transition is likely to be accompanied by many unsuccessful technical experiments as well as corporate and policy failures [20]. The key challenge for government is to be able to set a framework that makes space for these failures, and openly acknowledges the role of the unknown and unforeseen.
(iii)
The growth of new systems is a combination of evolution and revolution. A new system might build on the old (e.g. by transporting hydrogen through gas pipelines) but may contain revolutionary elements (e.g. the concept of the fuel cell as a mobile, distributed power generation system capable of being connected to the electricity network at a time of need [21]). The more revolutionary the new system, the more it 12
will have to confront the entrenched position of existing systems [22], triggering the defenders of the old system to fight back, innovate and reassert its dominance. It could be argued from this particular case study that the hydrogen economy would be stronger for having established itself through local, niche development than from being imposed centrally in a misguided attempt to direct the pace of change. The most appropriate role of Government might be to provide the appropriate policy framework and to ensure a level playing field of standards and certification. However, it is difficult to make definite judgements about the likely balance between ‘top-down’ government direction of hydrogen development and more ‘bottom- up’ niche developments from just one historical case. The implications of a range of possibilities which include both types of development will be analysed within the ongoing Tyndall Centre project using the scenarios outlined in section 2 of this paper. Conclusions If the hydrogen economy is to be realised, it will need to establish itself against the background of existing energy infrastructures and entrenched interests, which vary from country to country. The ultimate development route will depend as much on the strength of international agreements to reduce carbon emissions and the local implementation of those agreements as on the technical merits of different technologies. Since hydrogen is only a fuel vector, the carbon-reduction potential of any given transition scenario depends heavily on the hydrogen production route. The leading contenders are usually cited as steam methane reforming (SMR) and electrolysis. Although the cheapest production route at current natural gas prices, SMR will provide only slight environmental improvements unless associated with carbon sequestration technology, which is yet to be proven and the use of which is ethically uncertain. However, the major alternative, electrolysis of water, can lead to increased overall emissions unless the source of electricity is low or zero carbon. In the UK, there will be insufficient low carbon electricity until all the current coal and natural gas generation (67% of current capacity) is displaced and the status of nuclear power (15%) is resolved. A software package, THESIS, has been developed to assess the relative carbon reduction potential of different hydrogen pathways in the context of the overall energy system. It is clear, even from the preliminary results presented here, that the implementation of the hydrogen economy is likely to require increased investment in the deployment of renewable energy technologies, especially where uncertainties remain about the merits of carbon dioxide sequestration and public opinion dictates that nuclear power is not an option. References 1.
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11.
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Milborrow, D., Penalties for intermittent sources of energy, Working Paper submitted to UK Cabinet Office Performance & Innovation Unit (PIU) Energy Review process, 2001 (see http://www.cabinetoffice.gov.uk/innovation/2002/energy/workingpapers.shtml, last accessed 22/05/2003)
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Watson, J., The technology that drove the dash for gas, IEE Power Engineering Journal 11:1, p. 11-19, 1997
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Acknowledgements The research reported in this paper was funded by the Tyndall Centre for Climate Change Research in the UK. 14
