Life cycle sustainability assessment of UK electricity scenarios to 2070

Laurence Stamford; Adisa Azapagic

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Energy for Sustainable Development

Life cycle sustainability assessment of UK electricity scenarios to 2070

Laurence Stamford, Adisa Azapagic *

School of Chemical Engineering and Analytical Science, Room C16, The Mill, Sackville Street, The University of Manchester, Manchester M13 9PL, UK

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ARTICLE INFO

ABSTRACT

Article history: Received 6 January 2014 Revised 21 September 2014 Accepted 22 September 2014 Available online xxxx

Keywords: Carbon targets Electricity GHG emissions LCA

Life cycle sustainability assessment Scenario analysis

Decarbonising the UK electricity mix is vital to achieving the national target of 80% reduction of greenhouse gas (GHG) emissions by 2050, relative to a 1990 baseline. Much work so far has focused only on costs and GHG emissions ignoring other sustainability issues. This paper goes beyond to assess the life cycle sustainability of different electricity scenarios for the UK, extending to 2070. The scenarios include the main technologies relevant to the UK: nuclear, gas, coal with and without carbon capture and storage (CCS), wind, solar photovoltaics and biomass. Three levels of decarbonisation are considered and the implications are assessed for techno-economic, environmental and social impacts on a life cycle basis. The results show that decarbonisation is likely to increase electricity costs despite anticipated future cost reductions for immature technologies. Conversely, sensitivity to volatile fuel prices decreases by two-thirds in all the scenarios with low-carbon technologies. To meet the GHG emission targets, coal CCS can only play a limited role, contributing 10% to the electricity mix at most; the use of CCS also increases other sustainability impacts compared to today, including worker injuries, large accident fatalities, depletion of fossil fuels and long-term waste storage. This calls into question the case for investing in coal CCS. A very low-carbon mix with nuclear and renewables provides the best overall environmental performance, but some impacts increase, such as terrestrial eco-toxicity. Such a mix also worsens some social issues such as health impacts from radiation and radioactive waste storage requirements. UK-based employment may more than double by 2070 if a renewables-intensive mix is chosen. However, the same mix also increases depletion of elements nearly seven-fold relative to the present, emphasising the need for end-of-life recycling. Very low-carbon mixes also introduce considerable uncertainty due to low dispatchability and grid instability. With equal weighting assumed for each sustainability impact, the scenario with an equal share of nuclear and renewables is ranked best.

(http://creativecommons.org/licenses/by-nc-nd/3.0/).

Introduction

Achieving the UK's legally-binding target of reducing greenhouse gas (GHG) emissions by 80% by 2050 on 1990 levels (see Fig. 1) will require a complete decarbonisation of the UK electricity mix (UKERC, 2009). This is due to at least three reasons. First, electricity is by far the highest contributor to UK GHG emissions, being responsible for 79% of emissions from the energy sector and 28% of the total national emissions in 2012 (DECC, 2013). Secondly, the share of electricity is expected to grow significantly in the future owing to the anticipated electrification of other sectors, including transport (UKERC, 2009). It is also widely regarded that decarbonisation of electricity is going to be relatively easier than of other sectors as low-carbon technologies are either already available or will be deployable in the near-to-medium future. Whilst in other countries with differently structured economies, different sectors such as agriculture or transport can make greater contributions to national emissions, many nations face a similar challenge to that of the UK owing to the increasing significance of electricity as an energy source.

* Corresponding author. E-mail address: adisa.azapagic@manchester.ac.uk (A. Azapagic).

The decarbonisation of electricity is a very ambitious target, given the current electricity mix in the UK which is dominated by fossil fuels, contributing more than 87% to the total (see Fig. 2). Much work has been carried out so far in an attempt to find out how this might be achieved, often using scenario analysis. Examples include work by the Tyndall Centre (2005), UK Energy Research Centre (Ekins et al., 2013) and UK government Department of Energy and Climate Change (DECC, 2011a).

However, thus far the focus has been on direct GHG emissions from power plants and the costs of transforming the electricity system to meet the GHG emission targets. Indirect emissions from the whole life cycle of power generation have only been considered in this context by the Committee on Climate Change (2013) and the Transition Pathways consortium (Hammond et al., 2013; Hammond and O'Grady, 2013), with the latter also considering some environmental issues other than climate change. This leaves many other sustainability issues overlooked or sparsely addressed, including a broad range of life cycle environmental and social aspects. Therefore, if decarbonisation is seen as an opportunity to provide more sustainable energy, these other issues should be considered across the whole life cycle of power options (rather than just emissions from power plants) to prevent 'leakage' of impacts from one life cycle stage to another.

http://dx.doi.org/10.1016/j.esd.2014.09.008

900 800 I 700 g 600 500 ® 400 g 300 g 200 100

Total UK GHG emissions

Power plant GHG emissions

target

<# # ^ ^ ^ ^ # & <C$> dP J>

Fig. 1. UK greenhouse gas emissions and the 2050 legally-binding target (DECC, 2012).

Previous papers have discussed how different electricity technologies can be assessed on a range of sustainability issues on a life cycle basis and how some present-day options compare under UK conditions (Stamford and Azapagic, 2011; Stamford and Azapagic, 2012). With regard to future electricity scenarios, the European NEEDS project carried out life cycle sustainability assessment for several countries in Europe considering different environmental, economic and social aspects (Schenler et al., 2008). However, no equivalent analysis exists for the UK.

Therefore, this paper applies a life cycle approach to assess the sustainability of future electricity scenarios for the UK. Five scenarios up to 2070 are considered with a range of technological options suitable for the UK. The novelty of this work is at least three-fold: firstly, it applies a full life cycle approach to scenario analysis of electricity generation in the UK which has not been done previously; secondly, it considers the most comprehensive range of sustainability issues to date; and thirdly, it goes beyond the usual time horizon of 2050 to consider the implications of the electricity system transformation up to 2070. The longer time frame is chosen to reflect better the longevity of modern power plants, particularly nuclear reactors which have lifespans of 60 years. Additionally, this allows the electricity mix to change radically whilst allowing for reasonable build rates for individual technologies.

The following section outlines the methodology and data used in this study, including a description of the scenarios themselves. The results are presented and discussed in the Results and discussion section and the conclusions are drawn in the Conclusions section. Further details on the assumptions and results can be found in Supplementary information. The life cycle models for the scenarios are available within the Scenario Sustainability Assessment Tool (SSAT) v2.1 developed as part of this work. SSAT, which can be downloaded from www.springsustainability.org/?page=tools, is an interactive tool which also allows users to define their own scenarios and examine the related sustainability implications.

□ Bioenergy & biomass

Fig. 2. Electricity generation mix in the UK from 2005 to 2012 (DECC, 2013).

Methodology

Life cycle sustainability assessment

A life cycle approach has been applied to assess the sustainability of future electricity systems using techno-economic, environmental and social sustainability indicators developed by Stamford and Azapagic (2011) following extensive engagement with stakeholders from industry, government, academia and non-governmental organisations. In total, there are 36 indicators which are summarised in Table 1. Each indicator assesses a particular sustainability issue on a life cycle basis, from 'cradle to grave'. As shown in Fig. 3, the life cycle includes the construction and decommissioning of power plants, extraction and processing of fuels (if relevant), generation of electricity and waste management. The following electricity generation options are considered, each being relevant to UK conditions and expected to play a major role in the future electricity mix (DECC, 2011a):

• coal (subcritical pulverised) with and without carbon capture and storage (CCS);

• natural gas (combined cycle gas turbine, CCGT);

• nuclear (pressurised water reactor, PWR);

• solar photovoltaics (PV);

• wind (offshore); and

• biomass (wood and Miscanthus pellets).

Further details on the technologies can be found in the Technology data sources and assumptions section, following the description of the scenarios.

Future scenarios

Three main scenarios are considered, each with either one or two sub-scenarios depicting possible futures for electricity in the UK to 2070; their characteristics are summarised in Table 2. All the scenarios are driven by the need to reduce GHG emissions, as this is one of the main energy policy drivers in the UK (DECC, 2011a,c). The three main scenarios explore three different GHG reduction levels for electricity -65%, 80% and 100% - by 2050 relative to 1990. The 100% reduction from electricity is what is required to achieve the national target of 80% reduction ofGHG emissions. The other two targets are chosen to examine the implications of falling short of this target with the 80% scenario matching the national GHG emission reduction target and 65% being less ambitious still. Note the following:

• The year 2050 is the target year for UK policy hence the reduction targets in the scenarios relate to this year; however, the scenarios extend to 2070 to consider implications beyond the target year.

• UK GHG emission reduction target refers to the direct emissions of GHG rather than the life cycle emissions. Therefore, the reduction targets considered in the scenarios also refer to the direct emissions; however, the implications of reaching these targets are estimated on a life cycle basis.

• The decarbonisation targets in the scenarios refer only to CO2, as opposed to the basket of GHGs included in the national targets; however, direct emissions of non-CO2 GHGs from power plants typically cause around 1% of the direct global warming impact, so this simplification should have negligible effect.

The narratives for scenarios 65% and 100% are based on those developed by the Tyndall Centre (Azapagic et al., 2011) but have been developed further to focus on electricity (as opposed to the original scenarios which considered the whole UK energy system). The third scenario (80%) has been developed as part of this research. The scenarios are summarised in Table 2 and described in more detail below, together with the sub-scenarios. They are also differentiated in terms of their emission pathways in Fig. 4. The year 2009 is considered as a reference year in this research as the most complete data sets were available for

Table 1

Summary of the indicators used for assessing the sustainability of electricity scenarios (after Stamford and Azapagic, 2011).

Sustainability issue Indicator Unit

Techno-economic Operability 1. Capacity factor (power output as a percentage of the maximum possible output) Percentage (%)

2. Availability factor (percentage of time a plant is available to produce electricity) Percentage (%)

3. Technical dispatchability (ramp-up rate, ramp-down rate, minimum up time, Summed rank

minimum down time)

4. Economic dispatchability (ratio of capital cost to total levelised generation cost) Percentage (%)

5. Lifetime of global fuel reserves at current extraction rates Years

Technological lock-in resistance 6. Ratio of plant flexibility (ability to provide trigeneration, negative GWP and/or thermal/thermochemical H2 production) and operational lifetime Years-1

Immediacy 7. Time to plant start-up from start of construction Months

Levelised cost of generation 8. Capital costs £/MWh

9. Operation and maintenance costs £/MWh

10. Fuel costs £/MWh

11. Total levelised cost £/MWh

Cost variability 12. Fuel price sensitivity (ratio of fuel cost to total levelised generation cost) Percentage (%)

Environmental Material recyclability 13. Recyclability of input materials Percentage (%)

Water eco-toxicity 14. Freshwater eco-toxicity potential kg 1,4 DCBJ eq./kWh

15. Marine eco-toxicity potential kg 1,4 DCBJ eq./kWh

Global warming 16. Global warming potential (GHG emissions) kg CO2 eq./kWh

Ozone layer depletion 17. Ozone depletion potential (CFC and halogenated HC emissions) kg CFC-11 eq./kWh

Acidification 18. Acidification potential (SO2, NOx, HCl and NH3 emissions) kg SO2 eq./kWh

Eutrophication 19. Eutrophication potential (N, NOx, NH+, PO4-, etc.) kg PO3- eq./kWh

Photochemical smog 20. Photochemical smog creation potential (VOCs and NOx) kg C2H4 eq./kWh

Land use & quality 21. Land occupation (area occupied over time) m2 yr/kWh

22. Terrestrial eco-toxicity potential kg 1,4 DCBJ eq./kWh

Social Provision of employment 23. Direct employment Person-years/TWh

24. Total employment (direct + indirect) Person-years/TWh

Human health impacts 25. Worker injuries No. of injuries/TWh

26. Human toxicity potential (excluding radiation) kg 1,4 DCBJ eq./kWh

27. Total human health impacts from radiation (workers and population) DALY¥/kWh

Large accident risk 28. Fatalities due to large accidents No. of fatalities/PWh

Energy security 29. Amount of imported fossil fuel potentially avoided toe/kWh

30. Diversity of fuel supply mix Score (0-1)

31. Fuel storage capabilities (energy density) GJ/m3

Nuclear proliferation 32. Use of non-enriched uranium in a reactor capable of online refuelling; use of reprocessing; requirement for enriched uranium Score (0-3)

Intergenerational equity 33. Use of abiotic resources (elements) kg Sb eq./kWh

34. Use of abiotic resources (fossil fuels) MJ/kWh

35. Volume of radioactive waste to be stored m3/TWh

36. Volume of liquid CO2 to be stored m3/TWh

' 1,4-Dichlorobenzene. ¥ Disability-adjusted life years.

this year; as shown in Fig. 2, this year is fully representative of the electricity mix in recent years.

Potential electricity mixes to 2070

In total, five sub-scenarios are considered representing possible electricity mix pathways to 2070: two based on the 65% scenario, two based on the 100% scenario and one based on the 80% scenario. The electricity mixes are depicted in Table 3 and Fig. 5. It should be noted that, congruent with using scenario analysis as a tool, the intention is not to predict what will happen, but simply to explore a range of possible and, in some cases, extreme futures, to find out what will be needed to achieve the GHG emission targets.

Scenario 65% assumptions. In the 65% scenario, limited action is taken to prevent climate change. GHG emissions from the economy as a whole reduce by just 15% by 2050 compared to 1990. By 2070, the reduction reaches 24%. This means that the UK misses, by a large margin, its legally binding requirement to reduce GHG emissions by 80% by 2050 (Climate Change Act, 2008). The majority of the emissions reduction achieved in this scenario is due to the electricity sector which decarbonises by 65% by 2050 and 80% by 2070.

As shown in Table 3 and Fig. 5, two potential electricity mixes have been investigated within the 65% scenario: 65%-1 and 65%-2. In 65%-1, carbon capture and storage (CCS) technologies become commercially successful, but new nuclear build does not occur, perhaps as a result of political opposition or economic difficulties. Under the 65% scenario,

GHG emission constraints are not particularly tight, meaning coal and gas continue to play a role well into the future, together contributing 13% of electricity even in 2070. In fact, it is assumed that the UK withdraws from the EU Large Combustion Plant Directive (LCPD), which would otherwise reduce output from coal by 2016 (European Commission, 2001). (It is not clear what, if any, penalty the UK would incur by withdrawing from the LCPD.) In 65%-1, coal CCS delivers the majority of the GHG savings, although solar PV and wind also experience some growth. Since coal plants in earlier periods continue to operate rather than converting to biomass, large-scale biomass output does not grow. Current nuclear power plants shut down according to their commercial schedule, with Sizewell B being granted a life extension of 20 years as anticipated (World Nuclear Association, 2013). No further nuclear power plants are added.

It is assumed that coal CCS is not viable until after 2020 (apart from demonstration plants of negligible capacity). However, assuming present-day capacity factors (see Table 6) approximately 9 GW of coal CCS would then be installed between 2020 and 2035, 20 GW between 2035 and 2050 and a further 18 GW before 2070. This growth rate correlates well with the 'core MARKAL' scenario in the Government's Carbon Plan (DECC, 2011a), which anticipates 28 GW of CCS capacity by 2050 (cf. 29 GW here). Expansion of renewables in 65%-1 is far less than presently anticipated. For instance, planned offshore wind capacity could exceed 33 GW in the next 10-15 years (The Crown Estate, 2014), but that level is not reached until the 2060s in 65%-1, perhaps as a result of reduction or withdrawal of government support. Until 2050, growth

Extraction & processing of raw materials

Exploration &

site preparation

Vertical drilling

—^ Extraction —^

Treatment & Preparation

Liquefaction Regasification

CCGT construction

CCGT operation

CCGT decommissioning

Waste treatment and disposal

NUCLEAR (PWR)

Extraction & processing of raw materials

PWR construction

Exploration & site preparation

Mining & Fuel PWR

Conversion Enrichment

milling fabrication operation

Deconversion & storage

PWR decommissioning

Waste treatment and disposal

BIOMASS Extraction & processing of raw materials

_________±_________________________ Plant construction

Processing (e.g. debarking, chipping) *

' Cultivation and ^ harvesting Drying Pelletisation —Transport Plant operation

Plant decommissioning

Waste treatment and disposal

Fig. 3. The life cycles of the electricity generation technologies considered in this study.

of solar PV remains at its current (2013) low rate of 30-40 MW/month (Feed-in Tariffs Ltd., 2013); post-2050 deployment accelerates to around 115 MW/month.

Sub-scenario 65%-2 is similar to 65%-1, but with the assumption that nuclear new build goes ahead as well as coal CCS (see Fig. 5). Since, in contrast with 65%-1, both of these technologies are available, the required installed capacity can be reached with quite low build rates of each: nuclear capacity in 2070 is only around 18 GW, whilst coal

CCS totals approximately 16 GW. An amount of load-following is expected with CCS plants whereas nuclear plants are mainly expected to provide baseload, hence the total output of coal CCS is lower than that of nuclear despite installed capacity being similar. In terms of new nuclear, it is assumed that around 1.6 GW comes online by 2020, equivalent to one Areva EPR (AREVA NP and EDF, 2007), followed by a further 6.4 GW by 2035, another 6.4 GW by 2050 and finally 4 GW by 2070. The peak growth rate is therefore around 0.4 GW/year: far

Table 2

Summary of scenarios and sub-scenarios considered in this analysis (all reductions relative to 1990 levels).

Scenarios

Sub-scenarios

• Limited action is taken to prevent climate change.

• Total (direct) UK GHG emissions reduce by 24% (including international aviation and shipping) by 2070.

• Electricity is significantly decarbonised, with emissions reduced by 65% by 2050 and 80% by 2070.

• Electricity demand increases slowly, increasing by 50% by 2070.

• Decarbonisation of electricity is intermediate between scenarios '65%' and '100%', reaching 80% reduction by 2050 (in line with Government targets for the whole economy) and eventually 98% by 2070.

• Follows the same electricity demand profile as the 100% scenario.

• Similar cumulative whole-economy GHG emissions to UKERC's 'Carbon Ambition' scenario (UKERC, 2009) in line with the UK GHG budgets.

• Total UK GHG emissions reduce by 80% (including international aviation and shipping) by 2070.

• GHG emissions from electricity are effectively zero by 2050.

• Total energy demand reduces by 30% by 2070, but electricity demand increases by 60% as transport and other services switch to electricity (demand peaks in 2050 at 78% higher than 1990, then declines to 60% with efficiency improvements)

► 65%-1 Sub-scenario with coal CCS but no new nuclear build. The mix in

2070: 68% fossil and 32% renewables.

► 65%-2 Sub-scenario with both new nuclear build and coal CCS. The mix in

2070: 37% fossil, 30% nuclear and 33% renewables.

► 80% Only one sub-scenario considered. Includes new nuclear build and

some coal CCS. The mix in 2070: 10% fossil, 29% nuclear and 61% renewables.

► 100%- Sub-scenario with no new nuclear build, dominated by solar PV and

1 offshore wind. The mix in 2070:100% renewables.

► 100%- Sub-scenario with new nuclear build and renewables. The mix in

2 2070: 50% nuclear and 50% renewables.

lower than the historical maximum of 4.5 GW/year (in France from 1979-88) and sitting at the bottom end of the possible range suggested by the Carbon Plan (DECC, 2011a). Thus, the required build rates of both coal CCS and nuclear plants should be easily achievable.

Output from gas plants gradually declines as installed capacity is replaced with coal CCS, nuclear and biomass due to their lower GHG emissions. Conventional coal power only provides 3% of electricity by 2070, with some plants retired and others converted to biomass-only (4.9% of supply in 2070). Expansion of solar PV in 65%-2 is almost identical to that in 65%-1. Offshore wind, however, expands slightly more slowly, having an installed capacity of about 30 GW in 2070 (compared to ~35 GW in 65%-1) due to less capacity being necessary as a result of new nuclear build (which has lower assumed costs and is therefore installed preferentially).

Scenario 80% assumptions. The 80% scenario provides a steady decarbon-isation path for the electricity sector that achieves the Government's stated aim of 80% GHG emission reduction by 2050 (DECC, 2011a). The scenario assumes, therefore, that other sectors reduce their emissions by similar percentages. This is contrary to the approach taken in the 100% scenario and in the Carbon Plan, in which electricity brings about the majority of UK emissions reductions, becoming virtually 'zero carbon' before 2050. Annual electricity demand steadily increases as more services are electrified, finally beginning to decline post-2050 as efficiency improvements outpace demand increases.

Only one illustrative electricity mix has been investigated within this scenario (see Table 3 and Fig. 5). It assumes a future energy mix that includes both new nuclear and coal CCS. Renewables continue to increase their grid penetration at a steady rate, resulting in a mix that is quite evenly balanced between fossil, nuclear and renewable sources until 2050 when renewables begin to dominate. Thus, growth rates required

-•-65% -±-80% -B-100%

Fig. 4. Assumed pathways for reduction of direct GHG emissions from UK electricity for different scenarios.

for individual technologies are modest. Nuclear power, for example, experiences 1.6 GW of new build by 2020, followed by 8.6 GW by 2035 and a further 8.6 GW by 2050, after which new build ceases. As in the other scenarios, currently operating nuclear power plants shut down according to their commercial schedule, with Sizewell B being granted a life extension of 20 years (World Nuclear Association, 2013). Offshore wind has a total installed capacity of approximately 23 GW by 2035, which is considerably less than the currently planned capacity of over 33 GW by that time (The Crown Estate, 2014). By 2070, however, this increases to around 50-55 GW. Solar PV experiences expansion slightly higher than current rates until after 2035, at which point installation accelerates, culminating in a total capacity of around 104 GW by 2070. This is equivalent to about 35 million residential installations at current sizes, although this number would likely decrease as PV efficiency improves allowing higher capacities to be installed per unit area.

In comparison to scenarios in the Carbon Plan, this electricity mix is most similar to "Higher renewables; more energy efficiency", requiring broadly similar installed capacities of nuclear (19 cf. 16 GW), CCS (8 cf. 13 GW) and renewables (128 cf. 106 GW) in 2050 (DECC, 2011a).

The GHG emission targets in Scenario 80% allow a relatively modest rate of expansion of variable-output renewables as well as retention of some fossil capacity well into the future alongside development of biomass capacity. Thus, energy storage and demand-side management ('smart grid') requirements are likely to be relatively low. However, as noted in the Results and discussion section, the consequences of grid variability are very much an ongoing area of research.

Scenario 100% assumptions. The 100% scenario describes a future in which the UK's national GHG emission target of 80% reduction by 2050 is met via a combination of low-carbon technologies and efficiency improvements that allow reductions in demand. The GHG emission pathway for the economy as a whole follows closely the GHG budgets set out by the Committee on Climate Change (2008). The scenario also operates on the widely accepted principle that an effective way to reduce GHG emissions is to electrify transport and heating, on the basis that electricity is easier to decarbonise than other energy forms. This approach is also taken in the Carbon Plan and similarly requires electricity to be virtually 'zero-carbon' (at the point of generation) by 2050 (DECC, 2011a). Subsequently, electricity demand increases greatly, although this is partly offset by efficiency improvements. Two potential electricity mixes have been investigated within this scenario: 100%-1 and 100%-2 (see Table 3 and Fig. 5).

In 100%-1, new nuclear build is not successful. Currently-operating nuclear power plants shut down according to their commercial schedule (World Nuclear Association, 2013). GHG emission constraints in the 100% scenario are extremely ambitious - electricity is effectively 'zero-carbon'

Table 3

Electricity generation and emissions constraints from 2009-2070 for the different scenarios.

Sub-scenario Year Electricity generation (GWh)a GHG emission constraintsb (Mt CO2/yr) Contribution of each technology to electricity mix (GWh)

Coal (subcritical) Gas (CCGT) Nuclear (PWR) Wind (offshore) Solar PV Biomass (large-scale wood) Biomass (large-scale Miscanthus) Coal CCS

Reference 2009 375,663 n/a 110,533 170,104 73,012 9831 21 6081 6081 0

65%-1 2020 336,441 176.1 114,368 173,233 27,312 10,091 1346 5046 5046 0

2035 376,540 148.0 79,113 186,858 8852 33,906 7535 5651 5651 48,975

2050 407,734 74.6 16,314 134,592 8852 64,441 12,236 6118 6118 159,063

2070 455,539 43.4 9111 50,109 0 100,218 31,888 6833 6833 250,546

65%-2 2020 336,254 176.1 107,640 168,188 39,234 10,091 1009 5046 5046 0

2035 376,814 148.0 86,648 147,490 68,461 22,604 5651 7911 7911 30,138

2050 407,764 74.6 32,628 93,807 116,148 40,785 12,236 11,216 11,216 89,728

2070 455,521 43.4 13,666 63,775 137,100 91,108 36,443 11,161 11,161 91,108

80% 2020 352,463 155.0 73,991 191,672 39,234 31,711 3523 6166 6166 0

2035 383,942 98.8 57,207 115,182 84,853 72,949 11,518 11,518 11,518 19,197

2050 535,285 42.5 10,702 74,916 148,932 165,886 53,512 19,264 19,264 42,809

2070 483,491 5.1 0 4837 140,081 174,123 77,388 21,765 21,765 43,531

100%-1 2020 352,345 144.1 81,038 176,170 27,312 38,757 3523 7928 7928 9689

2035 383,961 21.6 0 38,394 8852 145,897 76,788 18,621 18,621 76,788

2050 534,870 0.2 0 0 8852 208,695 181,939 66,622 66,622 2140

2070 483,676 0.1 0 0 0 198,307 198,307 43,047 43,047 967

100%-2 2020 352,406 144.1 81,038 162,076 51,156 31,711 3523 6166 6166 10,570

2035 383,901 21.6 3839 42,233 161,600 95,985 26,492 15,358 15,358 23,036

2050 535,159 0.2 0 0 251,013 160,535 67,960 26,756 26,756 2140

2070 483,515 0.1 0 0 242,161 125,756 67,231 24,184 24,184 0

a Both 65% sub-scenarios share the same electricity growth path, whilst 80%, 100%-1 and 100%-2 follow a different path. The actual generation within each growth profile varies by <±0.1% due to rounding in the calculations.

b Direct CO2 emissions limits that cannot be exceeded in order to meet the emission targets specified for each time period in different scenarios.

Fig. 5. Contribution of different sources to the electricity mix from 2009 to 2070 for different scenarios.

by 2050 - meaning coal CCS cannot play a major role as it emits too much CO2 (75-92 g CO2/kWh; see Results and discussion section) despite the carbon capture. Consequently, coal CCS follows a fast roll-out period and an even faster period of retirement or mothballing. Use of coal CCS peaks by 2035, at which point it provides 20% of electricity, equivalent to around 17 GW capacity, virtually all of which must then come offline between 2035 and 2050 to meet the GHG emission targets. As a result, this sub-scenario relies almost entirely on renewables, which provide 98% of electricity (524 TWh) by 2050. It is assumed that biomass, peaking at 25% of supply in 2050, is the primary means of matching supply to demand (load-following) given the extreme levels of variable-output renewable capacity, thus biomass plants have a capacity factor of only 50%. However, even with biomass, huge amounts of cheap energy storage would be required to make grid management tenable. Moreover, solar and wind power expand to extreme levels: for instance, about 265 GW of solar PV capacity is needed by 2070, equivalent to 88 million residential installations at typical current sizes. This is more than three times the current number of households in the UK (ONS, 2012). Similarly, at its peak in 2050, installed wind power capacity is equivalent to more than 12,000 of the largest turbines currently available. As for biomass, the assumption of a 50:50 split between wood and Miscanthus pellets leads to demand in 2050 of about 35 million tonnes of wood pellets and 38 million tonnes of Miscanthus pellets (the difference being due to calorific value). The Miscanthus pellets alone would require around 2.5 million ha of agricultural land: an area larger than Wales. For these reasons, this sub-scenario is perhaps unrealistic. Nevertheless, it is still considered here as an extreme case to explore what may be needed for a complete decarbonisation of the electricity sector and the possible sus-tainability implications.

In 100%-2, both new nuclear and coal CCS become a commercial reality. As in 100%-1, aggressive GHG emission constraints mean that coal CCS cannot play a major role. As a result, nuclear power is assumed to dominate the market, ultimately providing 50% of electricity by 2070 (see Fig. 5). Nuclear growth rates are therefore ambitious, albeit more realistically so: 3.2 GW come online by 2020, equivalent to the twin EPR plant planned at Hinkley Point by EDF Energy (World Nuclear Association, 2013), followed by another 17.3 GW by 2035 and a further 12 GW by 2050, after which no more new nuclear capacity is required as efficiency improvements decrease electricity demand. Thus, the maximum build rate is around 1.2 GW/year between 2020 and 2035, which is easily within the range suggested by the Carbon Plan (DECC, 2011a). The recently published UK Nuclear Fission Technology Roadmap (NNL, 2012) also exceeds the demands of this scenario, with about 7.5 GW extra nuclear (LWR) capacity by 2050 in its 'expansion' scenario (40 vs 32.5 GW).

It is assumed in 100%-2 that around 2 GW of coal CCS is installed by 2020, providing 3% of electricity. This increases to 6% by 2035, but then rapidly declines in order to meet GHG emission targets: by 2050, coal CCS cannot generate more than 0.4% of electricity, meaning installed capacity has to decline from over 4 GW in 2035 to around 400 MW in 2050. This is less than even the least CCS-intensive scenario in the Carbon Plan ('Higher nuclear; less energy efficiency'), which assumes 2 GW in 2050 (DECC, 2011a).

Solar installation continues at a pace similar to today's until 2020, after which it accelerates, eventually providing 14% of electricity in 2070. This represents an installed capacity of approximately 90 GW, equivalent to around 30 million residential installations at today's typical sizes (although as mentioned previously, PV efficiency gains will allow greater capacity per unit area, reducing the number of installations required). Wind power peaks in 2050 at 30% of electricity, representing an installed capacity of about 50 GW. Given current plans to build 33 GW in the next 10-15 years (The Crown Estate, 2014), that level is not unrealistic. Biomass does not reach the same levels as in 100%-1, peaking at 10% of supply (about 12 GW in 2050), and mainly provides load-following. With over 40% of power coming from wind and solar, it is also anticipated that nuclear plants will vary output to an extent

in order to minimise the need for energy storage and demand-side management.

Reference electricity mix

To provide context and enable comparison with future scenarios, sustainability assessment of the present electricity mix, here taken to correspond to the year 2009, has also been carried out. For these purposes, it has been necessary to adapt the actual electricity mix in that year to be able to compare like for like, as some of the present technologies are not considered in the future scenarios. The first and most significant adaptation is related to nuclear power which in 2009 generated 18.4% of electricity (BERR, 2010). Of this, Magnox and advanced gas-cooled reactors (AGR) accounted for an estimated 16% and PWR for the remaining 2.4%. Since all AGRs and Magnox reactors are scheduled to close down by 2023, they are not considered in the future scenarios. They will be replaced by PWRs (and perhaps BWRs) (World Nuclear Association, 2013) which feature in the future scenarios. Therefore, the sustainability impacts from nuclear power in 2009 are assumed to be equal to those of PWR to enable like-for-like comparisons between the present situation and future scenarios.

A further adaptation of the electricity mix is with respect to wind which contributed 2% in 2009, the majority of which was from onshore installations. Since the growth of onshore wind is expected to slow post-2015 owing to limited availability of suitable sites (DECC, 2011d), future development of wind electricity will be mainly offshore, particularly post-2020. Thus, onshore wind is not considered in the future scenarios. The electricity generated by onshore wind in 2009 has been modelled using data for offshore wind owing to the aforementioned lack of data for onshore wind. The remaining technologies contributing to the electricity mix in 2009 were hydro (2.4%) and oil (1.2%). As they will not play a considerable role in future electricity mixes (owing to a limited resource (Committee on Climate Change, 2011) and emissions restrictions, respectively), they are not considered in the future scenarios and have been omitted from the 2009 mix. However, to keep to the original amount of electricity generated in that year, the contributions of the technologies that are considered in this work have been scaled up proportionally, giving the adapted mix in 2009 shown in Table 4. As can be seen, the differences between the original and adapted electricity mix are relatively minor but provide a better basis for comparison between the present and future scenarios.

The following section describes the data and assumptions used to project the characteristics of the analysed technologies out to 2070.

Technology data sources and assumptions

As mentioned previously, eight electricity generation options are considered in this work (see Table 3 and Table 5). These have been chosen because they are currently considered as the most promising options for the future UK electricity mix (UKERC, 2009; DECC, 2011a). The capacities considered here are given in Table 5; they have been chosen to correspondent to current standard capacity sizes but also based on availability of life cycle inventory data. Note that, whilst many coal and gas plants have greater capacities than those stated, they are normally modular designs consisting of units of similar capacity to those chosen so that the assumptions are still appropriate. Except for coal CCS, technologies which are currently being developed but are not commercially available are not considered due to lack of data. This is one of the limitations of this study. Other limitations include uncertainty of technological development and future costs of immature technologies such as wind and PV over time and life cycle data for future technologies. Similar limitations are also inherent in most previous studies (Tyndall Centre, 2005; DECC, 2011a; Ekins et al., 2013). Further limitations related to specific assumptions are discussed in the text below.

Coal (subcritical pulverised), natural gas (CCGT) and nuclear power (PWR, once-through cycle) are relatively mature technologies so that

Table 4

Electricity mix in 2009 compared to the mix adapted for the purposes of this work.

Electricity source Original electricity mix in 2009 Adapted electricity mix in 2009

Gas 44.6 45.3

Coal 27.9 29.4

Nuclear 18.4 19.4

Oil 1.2 0

Hydro 2.4 0

Biomass 3.1 3.2

Wind 2.5 2.6

Total 100 100

technological changes occurring over the coming decades should be modest. Moreover, any changes that do occur will take time to affect the electricity mix as old plants must first reach the ends of their lives. Therefore, as discussed in the following sections, their characteristics in future time periods are based on those reported by Stamford and Azapagic (2012).

The UK is the current world leader in offshore wind installed capacity (3653 MW at the time of writing, representing about half of the worldwide total) (RenewableUK, 2013), whilst the global capacity of solar PV is speculated to increase more than 100-fold between 2010 and 2050 (IEA, 2010). Given the immaturity and accelerating uptake of these two technologies, major improvements can be expected in the medium term. Their assumed future characteristics are discussed below.

There are no large-scale coal CCS plants currently operating, but any new coal plant proposed in the UK must have CCS fitted to at least 300 MW of its capacity (DECC, 2011b); development of CCS is also supported by the government's plans to demonstrate the technology before 2020, including £1 billion of capital subsidy (DECC, 2010). Illustrative figures for coal CCS have therefore also been added to the analysis, as described in Table 6 and in Supplementary information.

Finally, emissions restrictions in the LCPD have prompted several large coal plants to plan conversion to 100% biomass combustion: RWE npower's Tilbury plant (750 MW) converted to 100% wood pellets in 2011, followed by E.On's Ironbridge (600 MW) in 2013; Drax (4 GW) has also proposed full conversion (Selby Times 4 August, 2012), as has Eggborough (1.96 GW) (Webb 5 November, 2012). Thus, as part of this analysis, large-scale combustion of wood and Miscanthus pellets in converted coal plants has been assessed, as described in Supplementary information.

The key assumptions for each technology are summarised in Table 6 and discussed in detail in Supplementary information.

Results and discussion

This section presents and compares the sustainability impacts of the five electricity scenarios. The results are discussed in turn for each sustainability indicator defined in Table 1, expressed per unit of electricity generated. For full results, including the impacts per year, see Supplementary Information.

Table 5

Size and type of electricity plants considered in the scenarios.

Electricity source Plant size and type

Coal 460 MW subcritical pulverised plant

Coal CCS 500 MW power plant

Natural gas 400 MW combined cycle gas turbine (CCGT)

Nuclear 970 MW pressurised water reactor (PWR)

Solar PV 3 kWp

Wind 3 MW and 5 MW offshore turbines

Biomass 500 MW plant fired with wood and Miscanthus

Techno-economic sustainability assessment

Capacity and availability factors

As shown in Fig. 6a, the total system capacity factor decreases in all scenarios. This is mainly due to the increased adoption of wind and PV which, being variable in output, have low capacity factors. This is particularly apparent in sub-scenario 100%-1 which, by 2070, derives most (82%) of its electricity from wind and PV. As a result, it has the lowest capacity factor of the scenarios, at 33% compared to 65% in 2009.

Availability factors show the opposite trend (Fig. 6b): increased renewable penetration brings higher values, increasing from 88% in the present to 94% in 2070 in the highest case (100%-1). This means slightly fewer unscheduled production outages would be expected in future, particularly in 100%-1. However, this does not necessarily mean that supply to consumers would be more reliable: such high levels of renew-ables mean that output would be highly variable and grid management would be far beyond what is currently achievable, necessitating enormous energy storage schemes. This would of course increase the cost of electricity to consumers, but the extent of this increase is not currently known (and therefore cannot be quantified here).

Technical and economic dispatchability

In all scenarios, dispatchability of the electricity mix as a whole is lower than in the present (Fig. 6c & d). Sub-scenario 100%-1 is the worst in this respect, with technical dispatchability gradually deteriorating from the summed rank of 7.7 in 2009 to 14.0 in 2070, and economic dispatchability from 42 to 71 (lower scores being preferable in both cases). This is because the most dispatchable technologies of those assessed are coal, gas and biomass power, each having relatively low capital costs and high load-following ability (Stamford and Azapagic, 2012). As GHG emission targets force the replacement of fossil capacity, it thus becomes more difficult to match supply to demand.

Wind and solar power in particular are inherently non-dispatchable as output cannot be controlled. Nuclear power, on the other hand, is capable of following load to an extent, but this depends on the price incentive: high electricity sale prices at times of peak demand would be necessary to incentivise nuclear plant owners to reduce output at other times. Although biomass would be used to follow load in all the low-carbon scenarios, this is unlikely to be sufficient in scenarios with high penetration of wind and PV. Thus, in 80% and 100%-2, nuclear power might also load-follow (within limits). This in turn will affect other aspects, such as cost. However, so will the other grid balancing services that will likely be necessary (such as energy storage), but this is an ongoing area of research in which technological requirements in the long term are impossible to predict, thus impacts cannot yet be accounted for.

Lifetime ofglobal fuel reserves

The effective life of fuel reserves for electricity generation correlates positively with renewables penetration because they are fuel-free and have reserve lifetimes that are essentially infinite, being only constrained by local availability of natural resources (sunlight, wind, etc.). This is seen in sub-scenario 100%-1 (Fig. 6e) which has a reserve lifetime noticeably higher than all other scenarios from the mid-2020s onward, reaching about 1000 years by 2070 (which is the artificial cap set on fuel lifetime for renewables to enable calculation). The result is much lower in 100%-2 (509 years by 2070) due to nuclear power providing 50% of electricity: at current consumption rates, identified economically exploitable uranium reserves will only last another 20 years by 2070 (to 2090). However, as discussed in Supplementary information, the quantification of future fuel reserve lifetimes is not very robust: the lifetime of uranium reserves is very likely to increase substantially in future due to the relatively low level of exploration in recent decades and the increasing possibility of extraction from alternative sources such as phosphates and, at higher prices, sea water. The global reserve of uranium in phosphates is estimated at 9 to 22 Mt U (World Nuclear Association, 2012); if this is

Table 6

Key assumptions for each technology from 2009 to 2070.

Coal CCS

Natural gas Nuclear

Solar PV

Offshore wind

Biomass

Capacity factor

Availability factor

Technical dispatchability

Based on data from current plants. Assumed the same as coal.

Based on data from current plants.

Based on current plants in 2009 and new plants from 2020 onward.

Worst rank for every parameter.

Lifetime of fuel reserves

All fossil fuels and uranium assumed to decline linearly from 2009 to 2070.

Infinite. Capped at 1000 yrs to enable calculation.

30% in 2009 increasing to 50%

from 2035 onward.

81% in 2009; 95% from 2020

onward.

Worst rank for every parameter.

Infinite. Capped at 1000 yrs to enable calculation.

Levelised costs Carbon tax/cost excluded.

Recyclability of input materials Life cycle assessment modelling assumptions

Costs decline from 2009 to 2070 with an 18% learning rate.

First-of-a-kind premium Carbon tax/cost First-of-a-kind

included in 2009; excluded from excluded. premium included in

2020. Carbon tax/cost excluded. 2009; excluded from

Costs decline from 2009 to 2070 2020 onward. with 3.5% (PC) and 4.9% (IGCC) learning rate.

Assumes all major materials are 100% recyclable apart from concrete which is calculated to be 79% recyclable (when used as aggregate in new concrete). For nuclear plants, 1.44% of materials deemed too contaminated to recycle.

Round 2 projects in 2009. Round 3 projects begin 2020. Costs decline with a 12% learning rate.

Assumed the same as coal.

Assumed infinite (depends on global demand). Capped at 1000 yrs to enable calculation. Assumes conversion from coal to biomass in 2009. FGD and SCR gradually added by 2050.

Subcritical pulverised coal. Average plant size 460 MW, efficiency 36%. Flue gas desulphurisation (90% SO2 captured) and selective catalytic reduction (79% NOx captured).

Mixed dataset of 500 MW plants. Post-combustion CCS in 2020, incorporating oxyfuel combustion plants from 2035 onward.

Employment (direct + indirect)

Worker injuries Fatalities due to large accidents

Diversity of fuel supply mix

Fuel storage capabilities (energy density)

Nuclear proliferation Volume of radioactive waste

to be stored Volume of liquid CO2 to be stored

Assumed constant throughout time period.

Based on coal: 10% higher throughout life cycle; 25% in fuel supply stages. Employment declines to 2070 using the same learning rate as in levelised cost calculations.

Sector-specific injury rates in the present day extrapolated to 2070 based on historical trend.

400 MW CCGT, Pressurised water

efficiency reactor, 1000 MW

57.5%. North class. Once-through

Sea gas fuel cycle (no

comprises 90% reprocessing).

of fuel, LNG

Assumed Assumed constant

constant throughout time

throughout period.

time period.

Assumes constant mix of technologies throughout the period. All panels 3 kWp. Efficiencies improve overtime (e.g. multi-Si panel progresses from 13.2% in 2009 to 25% by 2050)

Employment declines to 2070 using the same learning rate as in levelised cost calculations.

3 MW turbines in 2009 increasing to 4 MW in 2035 and 5 MW from 2050. Capacity factors increase from 30% in 2009 to 40% in 2020 and 50% by 2035.

Employment declines to 2070 using the same learning rate as in levelised cost calculations.

500 MW plant, efficiency increases from 35% in 2009 to 40% from 2050. Wood is 50% waste, 50% virgin. Half of the Miscanthus requires fertilisers, and half does not.

Assumed constant throughout time period (apart from adjustments for increased power plant efficiency).

Net energy density of steam coal used in the UK = 24.9 GJ/t Density of coal = 850 kg/m3.

Net energy density of natural gas used in the

UK = 0.0358 GJ/m3.

Assumes current once-through cycle policy is maintained throughout time period.

Fuel assembly design for an Areva EPR is used. Burn-up of 50 GWd/tU assumed in order to give conservative results.

Fuel storage not possible.

Data only available for wood CHP as opposed to large-scale power plants. Data for wood are representative of pellets and briquettes. All Miscanthus assumed to be indigenous. Wood pellet value taken from ecoinvent (12.164 GJ/m3). Miscanthus calculated from composition (15.651 GJ/t, 660 kg/m3).

Assumes average value for Areva EPR and Westinghouse AP1000. Conservatively assumes high burn-up (65 GWd/tU), therefore waste is more radioactive. Waste is packaged in bentonite. Assumes 0.79 kg CO2/kWh captured and injected at a pressure of 11 Mpa (supercritical CO2 density = 950 kg/m3).

j) Levelised cost: fuel k) Levelised cost: total l) Fuel price sensitivity

Fig. 6. Techno-economic sustainability of different scenarios from 2009-2070, expressed per unit of electricity generated. [For definition of indicators, see Table 1.]

included in the estimate, uranium reserve lifetime increases by about 600 years (NEA, 2007), meaning the overall result for 100%-2 would come closer to that of 100%-1. Moreover, all sub-scenarios show a gradual improvement over the current value (138 years), culminating in a minimum 150% improvement by 2070.

Ratio of plant flexibility and operation lifetime

As shown in Fig. 6f, all future scenarios are less resistant to technological lock-in than the present-day electricity mix. This is primarily due to the inability of solar, wind and nuclear power (at least in terms of PWRs) to provide these services, together with the long 60 year lifetime of nuclear plants. Some scenarios enable a slight improvement in the short term (2020) owing to expansion of gas power but, as gas is constrained to meet GHG emission targets, lock-in resistance deteriorates in all cases, falling from 10.7 yrs-1 in 2009 to 2.4 yrs-1 in the worst case (100%-2) by 2070.

Time to start up

Construction times are quite similar in all sub-scenarios apart from 100%-1 which is preferable in this respect due to its extreme use of solar power (Fig. 6g): solar installations are modular and, in the case of small systems, can normally be completed in 2-3 days, giving 100%-1 an average time to plant start-up of 7.0 months in 2070 (compared to 47.3 months in 2009). Interest accrued during construction is therefore negligible and, from the system management perspective,

installed capacity on the grid can be increased quickly according to changes in national electricity consumption.

Capital, operational, fuel and total costs

Fig. 6h illustrates the trend towards capital-intensive technologies in all future scenarios. This is because low-carbon technologies tend to have high upfront costs and low operating costs: around three quarters of the levelised cost of nuclear power, for example, is capital expenditure, whilst the corresponding figures for wind and solar are around 75% and 94%, respectively. This means that future electricity mixes have lower marginal costs and are inherently less dispatchable, as discussed above. Moreover, it means that interest accrued during construction becomes a more important feature of economic viability in the future, as construction times will need to be as short and as fixed as possible to avoid significant cost overruns. This illustrates the importance of initiatives such as the Green Investment Bank which will specialise in lending to 'green' projects where problems with availability of capital would otherwise inhibit development (Vivid Economics and McKinsey & Co., 2011).

The results suggest that the total cost of electricity will increase relative to the present in all cases, even taking into account technological learning rates (see Fig. 6k). Of the scenarios in which GHG emission targets are met, 100%-2 is the cheapest option by 2070, being only 14% more expensive than the current electricity mix per unit of electricity generated (8.7 cf.7.6 pence/kWh). In 100%-1, which meets the emission

targets without nuclear power, total cost is much higher than the other scenarios in every time period from 2020 onwards, with a final cost in 2070 of 10.95 pence/kWh (43% higher than 2009). Scenario 100%-2 is comparable in terms of overall cost to 65%-2 and 80% despite having considerably lower GHG emissions and is in fact cheaper than 65%-1. This is because nuclear power, the biggest energy source in 100%-2 by 2070, is expected to be cheaper than coal CCS in that time period. However, Fig. 6k also demonstrates the fact that meeting GHG emission targets (100%-1 and -2) will likely increase costs very rapidly prior to 2035, followed by a steady reduction thereafter as the cost of renewables declines. In contrast, the cost of other scenarios increases more gradually but without the later reduction.

It should be noted that the costs shown here exclude any system costs incurred due to increased energy storage requirements, balancing mechanisms and output restrictions that might be necessary in renewable-intensive scenarios. The magnitude of this extra cost is not currently known, but the topic is being assessed by the National Grid (2011). It is therefore likely that total costs will increase by more than the percentages estimated here, particularly in sub-scenarios 80% and 100%-1 which rely heavily on the variable output of wind power.

Additionally, it is important to bear in mind that electricity generation cost is not the same as cost to the consumer: the latter is generally much higher. The difference reflects other costs incurred by utility companies, such as administration, research and development, network transmission fees and profit. As a result, an increase in generation cost of x% would

probably cause an increase in domestic electricity bills that is lower than x%.

Fuel price sensitivity

Following a brief increase in fuel price sensitivity in 2020 (mainly because of increased gas usage), all scenarios become less sensitive thereafter. In sub-scenarios 80%, 100%-1 and 100%-2, sensitivity to fuel price volatility is at least two-thirds lower than in today's energy mix by 2070 (Fig. 6l). Even in 65%-1 and 65%-2, which rely more on fossil fuel generation, overall sensitivity gradually decreases to 23% and 22%, respectively, compared to the 2009 value of 45%. As a result, electricity prices are less exposed to volatile international fuel markets, meaning prices paid by consumers should be more stable (despite being higher). This is primarily a result of decreased reliance on natural gas.

Environmental sustainability

The environmental sustainability of the scenarios is presented in Fig. 7 and discussed below.

Recyclability of input materials

The average recyclability of materials in future electricity mixes is likely to be slightly higher than is the case today: in the scenarios assessed here, the 2009 value of 86.4% increases to 88.3-96.8% by 2070 (Fig. 7a). This is mainly due to the increasing adoption of wind

- 65%-1

- 65%-2

-100%-1 -100%-2

-65%-1 -65%-2 -80% -100%-1 -100%-2

^ ^ jP ^ ^ # ^ ^

400 K S 300

g » 200 a m ! g 100

65%-1 65%-2

100%-1 100%-2

a) Material recyclability

b) Freshwater eco-toxicity potential

c) Marine eco-toxicity potential

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ÜÜ o o o 0.2 0.1

65%-1 65%-2

100%-1 100%-2

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65%-1 65%-2 80% -100%-1 -100%-2

d) Global warming potential

e) Ozone layer depletion potential

f) Acidification potential

65%-1 65%-2 80% 100%-1 100%-2

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65%-1 65%-2 80% 100%-1 100%-2

g) Eutrophication potential

h) Photochemical smog potential

i) Land occupation

65%-1 65%-2

100%-1 100%-2

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j) Terrestrial eco-toxicity potential

Fig. 7. Environmental sustainability of different scenarios from 2009-2070, expressed per unit of electricity generated. [For definition of indicators, see Table 1.]

(99.4% recyclable) and solar PV (99.8% recyclable) and reflects the fact that renewable technologies tend to use proportionally more metal and less concrete, the latter currently being the main limiting factor in recyclability (Stamford and Azapagic, 2012). However, as the materials used in the present-day mix are already highly recyclable (86%), improvements to actual recycling rates are likely to be more significant than improvements in potential recyclability. Moreover, because the environmental impacts of wind and solar power are almost entirely due to the manufacturing stage, recycling can dramatically improve all life cycle impacts (Stamford and Azapagic, 2012). As a result, the benefits of end-of-life recycling increase as the electricity mix becomes more reliant on renewables.

Freshwater aquatic eco-toxicity potential (FAETP)

FAETP decreases in all scenarios, falling from a present-day value of about 34.6 Mt DCB eq./yr (92 g/kWh) to a range of 8.3 to 13.5 Mt DCB eq./yr (18.1-27.8 g/kWh) by 2070 (Fig. 7b). The lowest value is found in sub-scenario 65%-1 which is less carbon constrained than the 80% and 100% scenarios and relies more heavily on coal CCS (55% by 2070). Despite this, it should not be concluded that coal CCS reduces FAETP: as mentioned in Supplementary information, the FAETP for coal CCS is probably underestimated, thus the FAETP of 65%-1 as a whole is underestimated. Over 90% of the present-day FAETP of electricity production is caused by coal power, primarily due to emissions of heavy metals like nickel and beryllium during coal extraction. It is likely, therefore, that any move away from coal as a fuel source will be beneficial in terms of FAETP. Moreover, the 100%-1 and 100%-2 sub-scenarios achieve a more rapid decrease in FAETP than the others, and therefore a lower cumulative impact by 2070, despite emissions in the final year being slightly higher than for the other options.

Of the low-carbon technology options, solar PV has the highest impact. For this reason, the 2070 FAETP of 100%-1, the extremely renewables-intensive sub-scenario, is a quarter greater than that of its nuclear-intensive alternative, 100%-2.

Marine aquatic eco-toxicity potential (MAETP)

Emissions of hydrogen fluoride from coal and coal CCS power plants are largely responsible for MAETP. This impact is highest for 65%-1 (Fig. 7c) which in 2070 emits 262 kg DCB eq./kWh (119 Gt DCB-equivalent per year). In contrast, the best scenario in terms of MAETP is 100%-2, emitting only 54 kg DCB eq./kWh (26 Gt DCB eq./yr) in 2070 and achieving the lowest MAETP from 2035 onwards owing to the avoidance of coal-fired generation.

Global warming potential (GWP)

As shown in Fig. 7d, the GWP of annual electricity production reduces markedly in all scenarios. From an estimated 184 Mt CO2 eq. in 2009, by 2070 the total GWP ranges from 10.5 Mt in 100%-2 to 51.4 Mt in 65%-1. The 100%-2 sub-scenario therefore represents a reduction of 94% over the present despite total electricity demand growing from 376 to 484 TWh per year. Per kilowatt-hour, even the least ambitious scenarios (65%-1 and 65%-2) represent a reduction of around 75% over the present-day value of 490 g CO2 eq./kWh. It should be noted that current policy addresses only GHG emissions at the point of generation, aiming for virtually 'zero-carbon' electricity by 2050 (DECC, 2011a). Both 100%-1 and 100%-2 are in line with this goal, each emitting just 0.3 g CO2/kWh (0.174 Mt CO2 annually) in 2050 in direct GHG emissions. However, when the whole life cycle is considered, the 2070 mix of 100%-1 has a carbon footprint twice that of 100%-2 (41 vs 22 g CO2 eq./kWh). This is due to 100%-1 relying more heavily on solar PV and biomass which, even in 2070, have a GWP of around 50 and 100 g CO2 eq./kWh, respectively, compared to 4.7 g for wind and 6.2 g for nuclear power (see Supplementary information). The 80% sub-scenario in fact has a lower GWP in 2070 than the 100%-1 sub-scenario (32 vs 41 g CO2 eq./kWh) owing to its greater use of nuclear power. This suggests that it is possible to achieve a cheaper electricity mix

(see Fig. 6k) with lower climate change impacts by considering the whole life cycle rather than only direct emissions.

As mentioned above, it is notable that, by 2070, solar PV has a GWP higher than the grid average: this work estimates the GWP of solar PV at around 49 g CO2 eq./kWh in 2050-2070. Lower estimates exist in literature; for example, NEEDS (Schenler et al., 2008) estimate 3.611 g CO2 eq./kWh under German conditions. However, such estimates apply to large, non-residential installations (420-46,600 kWp in NEEDS cf. 3 kWp here), meaning lower emissions can be expected owing to the economies of scale (via sharing of components and other resources). Additionally, the relatively low levels of insolation in the UK lead to reduced capacity factors. Nevertheless, in order to improve confidence in this area, further work on future thin-film solar technologies under UK conditions is recommended.

This analysis also suggest that coal CCS can only have a limited role in decarbonising the UK's electricity supply. In 100%-1 and 100%-2, GHG emission constraints are such that it can provide a maximum of about 0.5% of electricity by 2050. This raises serious problems in that any substantial deployment of coal CCS pre-2050 would likely require mothballing or decommissioning of that capacity before the end of its lifetime. Even in the less ambitious 80% scenario - which would likely involve missing the UK's national GHG emission targets - coal CCS only provides about 8% of electricity from 2050 onwards, corresponding to roughly 8 GW installed capacity. This calls into question the economic case for investing in new coal CCS, and its associated infrastructure, on a large scale.

Ozone layer depletion potential (ODP)

ODP improves relative to the present in all scenarios, particularly in 80% and 100%-2 (Fig. 7e). The relatively high ODP of 100%-1 in 2070 (2.53 t CFC-11 eq./yr or 5.22 ^g/kWh) is mainly due to production and use of tetrafluoroethylene in the solar PV life cycle (Stamford and Azapagic, 2012). However, even this level of ozone layer depletion is 10% lower than today's. Moreover, by 2070 the mix of solar PV technologies will likely include a greater contribution from thin-film laminates (as opposed to panels), which tend to have lower ODP values, meaning the figure of 2.53 t is an overestimate. The best scenario from the ODP perspective is 100%-2 with an emission rate of 2.4 |ag CFC-11 eq./kWh. As shown in Fig. 7e, 100%-2 also results in the fastest reduction in ODP with the lowest impact throughout the time period.

Acidification potential (AP)

Decreased acidification potential is seen in all scenarios compared to the present, with sub-scenario 100%-2 being the preferred outcome, reducing acid gas emissions by 160,000 t SO2-equivalent per year relative to today: a reduction of 62%. The 65%-1 sub-scenario has the highest AP values in 2070 due to extensive use of coal CCS; however, at 0.48 g SO2 eq./kWh, it still represents a reduction of 31% over the 2009 value of 0.69 g/kWh (Fig. 7f).

Eutrophication potential (EP)

All scenarios show a reduction in annual eutrophication of at least two-thirds relative to today's electricity supply (Fig. 7g). In 2070, the renewables-intensive 100%-1 sub-scenario is the worst in terms of EP, emitting 0.15 g PO|- eq./kWh (73.3 kt PO|- eq. per year). The 80% and 100%-2 scenarios are the best options, both emitting less than ~0.08 g PO4- eq./kWh (41 kt PO4- eq. per year) compared to the present day figure of0.585 g PO4- eq./kWh (220 kt/yr). However, it is likely that 100%-2 would in fact be markedly better than 80% in terms of EP: coal CCS provides about 9% of electricity by 2070 in the 80% scenario and, as discussed in Supplementary information, its EP results are probably underestimated. In contrast, there is no coal CCS by 2070 in 100%-2.

Photochemical oxidant creation potential (POCP)

Scenarios 100%-2 and 80% are the best options for this impact, with 2070 results of 11.7 and 14.1 kt C2H4 eq./yr, or 24 and

29 mgC2H4 eq./kWh, respectively (Fig. 7h). Similar to most other environmental impacts, 100%-2 also achieves the fastest reduction in emissions. Sub-scenario 65%-1 provides the least improvement over the present with a result of 52 mg C2H4 eq./kWh. Coupled with increased electricity demand, this leads to an annual impact of 23.5 kt C2H4 eq./yr, which is in fact slightly higher (~2%) than in 2009. This is due to high emissions of non-methane volatile organic compounds (NMVOC), methane, sulphur dioxide and nitrogen oxides in the coal CCS life cycle.

Land occupation

By far the biggest influence on land occupation is the proportion of power generated from biomass. The peak in biomass demand is 2050 in sub-scenario 100%-1 (Fig. 7i), at which point wood and Miscanthus each provide 12.45% of electricity (i.e. 24.9% in total). In the case of Miscanthus, this level of demand would require about 2.5 million ha of agricultural land for crop cultivation. This study assumes that 75% of Miscanthus is UK-grown, meaning about 1.88 million ha is needed domestically. England is thought to have about 3 million ha of grade 4 or 5 agricultural land ('poor' or 'very poor' grades, which are therefore less likely to interfere with food production) (RCEP, 2004), meaning this level of Miscanthus deployment is technically possible, albeit rather extreme.

However, even in scenarios lacking biomass power, land use tends to increase relative to 2009. This is due to the coal CCS life cycle: large volumes of coal are required and, consequently, a large area of land must be devoted to mining. It should be noted that, in terms of public acceptability, larger areas of land devoted to growing energy crops may be preferable to smaller areas of land devoted to mining (although mining areas are likely to be outside the UK, whereas energy crop farms are not, making this an issue of conflict between national and international impact).

Terrestrial eco-toxicity potential (TETP)

In all scenarios, TETP increases over the coming decades. However, this is mainly due to an increase in electricity demand rather than an increase in emissions per unit output. The worst scenario from this perspective is the renewables-intensive option, 100%-1, with total emissions 87% higher than in 2009 (680 vs 363 kt DCB eq./yr) and emissions per kilowatt-hour 45% higher than the present (1.41 vs 0.97 g DCB eq./kWh); see Fig. 7j. Half of this impact is due to Miscanthus despite the fact that it only comprises 9% of the mix by 2070: the cause is the common disposal option for biomass ash of spreading on farmland as a low-grade fertiliser and liming agent, which has the unintended side-effect of increasing heavy metal contamination in agricultural soils. In this study, 25% of ash is assumed to be disposed of by agricultural spreading. Note that the metal content of Miscanthus, and therefore the resulting TETP of Miscanthus power, is highly variable depending on the cultivation site.

Other contributors to the general trend of increasing TETP over the present include the emissions of mercury to air during combustion of coal at coal CCS power plants and heavy metal emissions in the life cycles of nuclear, wind and solar power.

Social sustainability

The social sustainability of the scenarios is presented in Fig. 8 and discussed below.

Direct employment

Direct employment (in plant construction, operation, maintenance and decommissioning) increases in all scenarios (Fig. 8a), rising from 52 person-yrs/TWh in 2009 (19,600 jobs) to 84-159 person-yrs/TWh (38,100-76,800 jobs) by 2070. Since this employment is direct, it is likely to benefit the UK. However, offshore wind and solar PV create more direct employment than the other technologies; therefore 100%-1 (being very renewables-intensive) creates the most work. In contrast,

nuclear power is less labour-intensive, meaning 100%-2 achieves the same GHG emission targets with 30% less employment.

Total employment

The total employment estimates in Fig. 8b, which include raw material extraction, manufacturing, construction, operation, maintenance, and decommissioning, show the same increasing trend as for direct employment. The total life cycle employment of sub-scenario 100%-1 is 226 person-yrs/TWh in 2070 (or 109,300 jobs), compared to the 2009 figure of 123 person-yrs/TWh (46,100). The fact that the total and direct employment figures for 100%-1 are quite similar is a reflection of the fact that 80-85% of work in the wind and solar life cycles are in operation and maintenance or installation. In contrast, 70% of jobs in the coal CCS life cycle occur in the coal mining stage, meaning much of the employment provided by 65%-2 will occur outside the UK.

Worker injuries

As shown in Fig. 8c, worker injury rates diverge greatly between scenarios. By 2070, projected improvements in worker injury rates (see Section S1.3.2 in Supplementary information) are balanced out by increases in electricity demand and, in the case of 65%-1, an increase in the proportion of relatively high-risk work (coal mining). Throughout the whole life cycle, about 1065 injuries per year (2.34 per TWh) are associated with 65%-1, compared to 690 today (1.84/TWh). The best scenario from this perspective is 100%-2, with around 510 injuries per year and the lowest injury rates of all scenarios from the mid-2020s onwards (Fig. 8c).

Human toxicity potential (HTP), excluding radiation

All scenarios show a decrease in HTP per unit output by 2070 (Fig. 8d). However, increases in electricity demand mean that the total impact is similar to today's in most cases. The worst option in terms of HTP is 100%-2, with a 2070 impact of 42.8 Mt dichlorobenzene (DCB) eq./yr, 19% higher than in 2009, despite the impact per kilowatt-hour being 8% lower at 89 g DCB eq./kWh. The best option appears to be 65%-1 (27% lower than today) but its impact is likely underestimated owing to its reliance on coal CCS and the less comprehensive background LCA data available for that technology (as discussed in Section S1.2.2 in Supplementary information). In the life cycle of coal without CCS, the main contributors to the HTP are emissions of heavy metals and selenium during coal mining, which can be expected to be equally applicable to the coal CCS life cycle. Thus the real impact of 65%-1 could be significantly higher than indicated.

Total human health impacts from radiation

Nuclear power has a greater radiation-induced health impact than other technologies. As a result, 100%-1 and 65%-1 - neither of which has nuclear power - show a gradually declining radiation impact, finally reaching 0.25 disability-adjusted life years (DALYs) per TWh by 2070 (Fig. 8e). Per year, this equates to 118 DALYs for 100%-1 and 127 DALYs for 65%-1 compared to 1534 DALYs in 2009. The scenario with the most nuclear power, 100%-2, has approximately 10.2 DALYs/TWh, or 4947 DALYs/yr by 2070 (although the annual figure peaks in 2050 at 5133 DALYs when electricity demand is higher). This impact is mainly due to radon emissions from uranium mill tailings over a period of thousands of years. To put this into context, road traffic accidents in the UK in 2004 are estimated to have caused 108,000 DALYs (World Health Organisation, 2009).

Fatalities due to large accidents

As shown in Fig. 8f, large accident fatalities diverge greatly based on the choice of scenario. Scenario 65%-1 has the highest impact at 9.87 fatalities/PWh or 4.49 per year in 2070, 41% higher than today's. This is because 65%-1 relies heavily on coal CCS which, in 2070, is estimated to cause over 50 times more fatalities per unit of electricity generated than offshore wind, solar PV or nuclear power. This is a direct

-65%-1 -65%-2 -80% -100%-1 -100%-2

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Fig. 8. Social sustainability of different scenarios from 2009-2070, expressed per unit of electricity generated. [For definition of indicators, see Table 1.]

result of its high coal mining requirement. The best option from this perspective is 100%-2 owing to its use of renewables: it causes 0.085 fatalities/yr in 2070, or 0.18 fatalities/PWh. This scenario also has the lowest impact over the entire time period.

Avoidance of fossil fuel imports

The GHG emission constraints of the scenarios mean that, even accounting for coal CCS, fossil fuel usage cannot be as high in 2070 as in 2009. Clearly, however, scenarios 100%-1 and 100%-2 avoid the most fossil fuel use due to 99.8% of electricity coming either from re-newables or nuclear power in 2070. Relative to the 2009 fossil fuel fleet, this saves 0.2 tonnes of oil equivalent (toe) per MWh (Fig. 8g) or 97 Mtoe/yr. This would represent a national increase in resilience to

fossil fuel price volatility. Even the less extreme 80% scenario saves 87 Mtoe/yr relative to the 2009 fossil fleet.

Diversity of fuel supply mix

This indicator reflects the resilience of national electricity production to fuel supply disruptions, whether they are economic, technical or political. However, results here are highly tentative as future fuel supply mixes cannot be known. Assuming that supply mixes stay the same as in the present, resilience increases with penetration of wind and PV, meaning 100%-1 has the highest resilience surpassing 90% in 2035 and reaching 97% by 2070 compared to the average 2009 value of 81.8% (Fig. 8h). However, as UK steam coal currently has a very non-diverse fuel supply (Stamford and Azapagic, 2012), any electricity mix with little

coal or coal CCS is preferable: for example, the 80% scenario reaches 91% in 2070 despite only 52% of electricity coming from wind and PV. It is of note that wood pellet combustion currently has the worst supply diversity score of any technology (66.5%), owing to overreliance on Canada and the USA. However, as a relatively new power option, its fuel supply chain could broaden in future.

Fuel storage capabilities

The fuel storage abilities of nuclear power far exceed any other electricity source due to the extremely high energy density of nuclear fuel (Stamford and Azapagic, 2012). Therefore it is far easier to stockpile energy reserves in scenarios with large amounts of nuclear power. Consequently, 100%-2 has the highest average fuel storage potential in all time periods, reaching 5.19 PJ/m3 by 2070,158% higher than today's electricity mix (2.01 PJ/m3); see Fig. 8i. In contrast, it is not possible to stockpile much fuel in sub-scenario 100%-1 as it relies greatly on wind and PV. However, as those technologies have no fuel, the main energy security obstacle to renewable-intensive scenarios is not fuel storage but the difficulty of matching supply to demand given variable-output generators.

Use ofnon-enriched uranium, reprocessing and requirements for enriched uranium

Clearly this indicator increases proportionally with nuclear power's contribution to the energy mix, meaning scenario 100%-2 carries the greatest proliferation risk due to 50.1% of its electricity coming from nuclear power stations by 2070. Its proliferation risk elevates quickly between 2020 and 2035 as around 17 GW of new nuclear capacity is brought online. In 2070 it is rated at 16.5 relative to today's rating of 6.4 (Fig. 8j). However, as discussed in Section S1.3.7 in Supplementary information, if reprocessing of spent fuel occurs, the rating would double owing to the extracted products becoming potential targets of theft or terrorism. As noted previously, the ordinal scale used here is simplistic and is not appropriate for the evaluation of any Generation IV reactors that may or may not be online by 2070.

Use ofabiotic resources (elements)

Depletion of elements is positively correlated with renewable electricity output because wind and solar power have a much higher life cycle impact than other power sources. This is demonstrated in 100%-1, in which depletion rapidly increases to 2.95 kg Sb eq./GWh (or 1429 t Sb-eq. per year) by 2070: six and a half times the amount in 2009 (Fig. 8k). This is due to the higher metal requirements of the re-newables relative to their electrical output. However, end-of-life recycling can reduce this depletion considerably. The less renewable-intensive scenarios show a more modest increase over the present, but depletion increases in all scenarios.

Use ofabiotic resources (fossil)

The depletion of fossil resources is obviously greatest in the life cycles of coal, coal CCS and gas power. Therefore, fossil resource depletion is lowest in scenarios 100%-1 and 100%-2 (Fig. 8l) which, by 2070, use around 0.51 and 0.26 MJ/kWh (or 246 and 127 PJ/yr), respectively. This compares to 5.9 MJ/kWh (2200 PJ/yr) in the 2009 electricity mix, equating to a saving of 94% for 100%-2 and 89% for 100%-1. The less extreme 80% scenario also results in significant improvements over the present with a value of 1.25 MJ/kWh (603 PJ/yr). The result is that far more fossil fuel would be available for use by future generations in any of these three scenarios compared to business-as-usual. The converse is true for the 65%-1 scenario: increased electricity demand and widespread use of coal CCS cause total annual depletion of 3043 PJ, 38% higher than in 2009.

Volume of radioactive waste and liquid CO2 to be stored

The most nuclear-intensive scenario, 100%-2, has an operating nuclear capacity of around 32.5 GW in 2070 producing a total of

2460 m3 of radioactive waste per year requiring geological storage (or 5.1 m3/TWh; see Fig. 8m). This is around three times as much as the equivalent amount for 2009 (although, as noted in the Reference electricity mix section, the 2009 figure is based on PWRs and therefore does not accurately reflect the amount of waste produced by the current UK nuclear fleet). All of the radioactive waste production figures include packaging and are based on a 'once-through' cycle in line with current policy, in which no reprocessing of fuel occurs; if this changes in the future, the waste produced would be much lower in volume but with higher heat output, necessitating greater packaging space per unit volume (NNL, 2012).

Scenario 65%-1 has the greatest contribution from coal CCS, particularly from 2035 onwards, and therefore produces the most CO2 in need of storage (Fig. 8n). In 2070, this amounts to 187.5 million m3 per year of supercritical, pressurised CO2.

Ranking the scenarios

In an attempt to summarise and consolidate the results discussed above, the scenarios have been ranked based on their sustainability performance. A simplified approach - summed-rank analysis - has been used for these purposes, as shown in Table 7. The 2009 mix and the results for 2070 for each sub-scenario have been ranked for each sustain-ability indicator and their individual ranks summed up to obtain a single score; the lower the score, the better the option. To avoid bias owing to the different number of indicators for the techno-economic, environmental and social dimensions of sustainability, the summed ranks have first been created for each dimension and then the overall ranking estimated based on the summed ranks for the three dimensions. It should be stressed that this is a simplistic analysis that ignores both the distribution of results for individual indicators and the importance of the issues addressed by each indicator: each indicator is given equal weight within its group. A more robust approach would be to use stakeholder preference weightings in a multi-criteria decision analysis, but this is beyond the scope of the study. Therefore, the summed-rank results discussed below are only valid within the limits described above and should be viewed tentatively: they are a generic simplification of the complex information created by the study.

As shown in Table 7, the 2009 mix is preferable from the techno-economic perspective with a score of 37, followed by 100%-2 which has an equal share of nuclear and renewables, with 39. The renewable-intensive 100%-1 and CCS-intensive 65%-1 have the joint worst score of 47 for techno-economic performance. In terms ofenvironmental impacts, 100%-2 has the best score of 21, followed by 80% with 25. The 2009 mix and 100%-1 are the worst ranked options. However, 100%-1 appears to be the best option from the social perspective, followed by 100%-2, with the 2009 mix being the worst.

The overall ranking suggests that all 2070 electricity mixes are superior to the 2009 mix with the exception of 65%-1 which scores the same (13). The best option, within the limitations of this simplified ranking approach, is 100%-2 (score of 5), followed by 80% (9). It is important to note that, as discussed in the Future scenarios section, the lower carbon scenarios would require energy storage and demand-side management solutions in order to match supply to demand, but the impacts of these have not been included in this study because of lack of data.

Conclusions

This study has assessed the techno-economic, environmental and social sustainability of potential future electricity scenarios for the UK. Whilst the scenarios and technologies considered are only a sample of possible electricity futures, they do provide some robust conclusions and implications for energy policy. Compromises appear inevitable and, of the scenarios analysed, no one represents an obvious winning solution.

Summed rank analysis of each sub-scenario in 2070.

2070 electricity mix

Issue addressed Indicator 2009 mix 65%-1 65%-2 80% 100%-1 10C

Techno-economic Operability 1. Capacity factor 1 4 2 5 6 3

2. Availability factor 6 5 4 2 1 3

3. Technical dispatchability 1 2 3 5 6 4

4. Economic dispatchability 1 2 3 4 5 6

5. Lifetime of global fuel reserves at current extraction rates 6 4 5 2 1 3

Technological Lock-in resistance 6. Ratio of plant flexibility 1 2 3 4 5 6

Immediacy 7. Time to plant start-up from start of construction 6 4 5 2 1 3

Levelised cost of generation 8. Capital costs 1 3 2 5 6 4

9. Operation and maintenance costs 1 6 3 5 4 2

10. Fuel costs 6 5 4 2 3 1

11. Total levelised cost 1 5 2 4 6 3

Cost variability 12. Fuel price sensitivity 6 5 4 2 3 1

Summed techno-economic scores 37 47 40 42 47 39

Techno-economic sustainability ranking 1 5 3 4 5 2

Environmental Material recyclability 13. Recyclability of input materials 6 3 5 2 1 4

Water eco-toxicity 14. Freshwater eco-toxicity potential 6 1 4 2 5 3

15. Marine eco-toxicity potential 6 5 4 3 2 1

Global warming 16. Global warming potential 6 5 4 2 3 1

Ozone layer depletion 17. Ozone depletion potential 6 4 3 2 5 1

Acidification 18. Acidification potential 6 5 3 2 4 1

Eutrophication 19. Eutrophication potential 6 3 4 2 5 1

Photochemical smog 20. Photochemical smog creation potential 6 5 3 2 4 1

Land use & quality 21. Land occupation 1 2 3 4 6 5

22. Terrestrial eco-toxicity potential 1 5 2 4 6 3

Environmental summed score 50 38 35 25 41 21

Environmental sustainability ranking 6 4 3 2 5 1

Social Provision of employment 23. Direct employment 6 5 4 2 1 3

24. Total employment 6 3 5 2 1 4

Human health impacts 25. Worker injuries 5 6 3 2 4 1

26. Human toxicity potential (excluding radiation) 6 1 3 4 2 5

27. Human health impacts from radiation 3 2 5 4 1 6

Large accident risk 28. Fatalities due to large accidents 5 6 4 3 2 1

Energy security 29. Amount of imported fossil fuel potentially avoided 6 5 4 3 2 1

30. Diversity of fuel supply mix 5 6 4 2 1 3

31. Fuel storage capabilities 4 5 2 3 6 1

Nuclear proliferation 32. Online refuelling; reprocessing; enriched uranium 3 1 5 4 1 6

Intergenerational equity 33. Use of abiotic resources (elements) 1 2 3 5 6 4

34. Use of abiotic resources (fossil fuels) 5 6 4 3 2 1

35. Volume of radioactive waste to be stored 3 1 5 4 1 6

36. Volume of liquid CO2 to be stored 1 6 5 4 3 1

Social summed scores 59 55 56 45 33 43

Social sustainability ranking 6 4 5 3 1 2

OVERALL SUSTAINABILITY SUMMED SCORE 13 13 11 9 11 5

OVERALL SUSTAINABILITY SUMMED RANKING = 5 & 6 =5&6 =3&4 2 =3&4 1

The key considerations arising from this analysis are summarised as follows for each scenario in turn.

A failure to meet UK GHG emission targets is illustrated by the 65%-1 and 65%-2 sub-scenarios (although substantial decarbonisation still occurs). The total cost of 65%-2 is the lowest of all the scenarios considered (8.7 pence/kWh in 2070) owing to considerable use of nuclear power, coal CCS and natural gas, all of which are expected to be cheaper than offshore wind and solar PV even beyond 2050. However, all scenarios are more expensive than the present-day electricity mix: even 65%-2 is estimated to be 14% more costly per kilowatt-hour. Conversely, due to replacement of gas capacity with other options, both 65%-1 and 65%-2 are less than half as sensitive to fuel price volatility - a major cause of recent energy price increases - as the present day.

By 2070, both 65%-1 and 65%-2 achieve direct GHG emissions 80% lower than in 1990 but this is too late according to UK targets which require full decarbonisation of the electricity sector by 2050. It is also evident that emissions reduction results in an increase in other environmental impacts, particularly in 65%-1, for which annual photochemical smog, terrestrial eco-toxicity and land use go up compared to present day. The primary cause of these increases is the adoption of coal CCS, which provides 55% of electricity in 65%-1 by 2070. Owing to a lack of data for the coal CCS, it is also likely that human toxicity, freshwater eco-toxicity and eutrophication impacts of 65%-1 have been underestimated.

Although employment in the electricity life cycle increases in all scenarios, it is notable that 65% scenarios are only competitive with the 80% and 100% scenarios in terms of total employment: half of the total is indirect, predominantly in coal mining, because of coal CCS. Use of coal CCS in the 65% sub-scenarios also results in higher worker injury rates, large accident fatalities and depletion of fossil fuels than in any other scenario. In the case of large accident fatalities and depletion of fossil fuels, the 2070 impacts of 65%-1 are worse than the present day (by 41% and 38%, respectively). This worsening of fossil fuel depletion is a clear deterioration in intergenerational equity, as is the burden of care and risk associated with the 188 million m3/yr of supercritical CO2 requiring storage by 2070 in 65%-1 (and 68 million m3/yr in 65%-2). This rate of CO2 production is equivalent to filling Windermere (England's largest lake) every 20 months (calculated with data from International Lake Environment Committee, 2012).

A more ambitious attempt to decarbonise is represented in the 80% scenario, in which the electricity sector matches the UK's whole-economy reduction target of 80% by 2050. In this case, a balanced electricity mix is used. Whilst per-kWh costs are higher than the present (by 25%), and capital expenditure much higher (by 96%), sensitivity to fuel price changes is greatly reduced (by 73%), meaning a large increase in the cost of coal, gas or uranium would have very little effect on the generation cost of electricity. This provides more security against a potentially volatile future fuel market. The move away from gas and coal

also increases the effective fuel reserve lifetime approximately five-fold over the present.

The environmental impacts of the 80% scenario are considerably better than those of the 2009 electricity mix despite an overall increase in electricity consumption. Apart from terrestrial eco-toxicity potential and land occupation, all annual environmental impacts decrease by about 40% or more by 2070. In the case of terrestrial eco-toxicity, the impact per unit generated in 2070 only increases slightly relative to the present (17%), but higher electricity demand in future results in a 50% increase in the annual burden.

The social impacts of 80% are mixed relative to the present: employment, avoided fossil fuel use, fuel storage capabilities, large accident fatalities and depletion of fossil fuels all improve by at least 50% (on an annual basis; more per kWh). On the other hand, health impacts from radiation, potential for nuclear proliferation, depletion of elements and long-term waste storage all worsen by at least 90% owing to a combination of increased nuclear generation, production of solar PV components and CO2 from CCS. Thus the overall judgement will depend on societal preference and context: for instance, health impacts from radiation may be seen as very minor compared to everyday hazards such as road traffic and air pollution and depletion of elements could be greatly reduced by improving end-of-life recycling rates.

The 100%-1 and 100%-2 sub-scenarios reflect the scale of electricity decarbonisation thought to be necessary to meet the UK's 80% reduction target for the whole economy. In both cases, coal CCS expansion is severely curtailed by ever-tightening GHG emission constraints, meaning plants may not be able to operate for their full lifespan: even with CCS, direct emissions from coal plants are too high. Therefore, it would not be advisable to allow coal CCS penetration of more than about 10% at any time in the coming decades. This is in contrast with UK government's policy which expects up to 48% of supply to come from CCS by 2050 (although this also includes gas and biomass CCS) (DECC, 2011a). This suggests that, a) CCS investment should proceed with caution to avoid short-termism that would penalise alternative options and, b) large-scale investment in infrastructure for CCS should not be motivated by coal: gas and biomass may be more appropriate but both require sustainability assessment (which was beyond the scope of this study).

Decarbonising electricity to the extent required by the 100% scenario creates considerable uncertainty: the variability of wind and PV coupled with the low dispatchability of nuclear power mean that such a mix is not technological feasible under today's conditions. Huge amounts of grid-level storage, demand management and other balancing mechanisms would likely be necessary, despite the use of biomass for load-following. All ofthis creates extra costs, environmental impacts and social consequences. The effects of these are currently unknown and should be prioritised as a focus of research.

Nevertheless, the 100%-1 and 100%-2 sub-scenarios demonstrate several points. Firstly, achieving this level of decarbonisation is not necessarily more costly than achieving far less ambitious reductions: the overall cost of 100%-2 is comparable to both 65% sub-scenarios. However, costs increase significantly if nuclear power is avoided: by 2070,100%-1 (which lacks nuclear) costs 43% more per kilowatt-hour than the present day, taking into account cost reductions for immature technologies. If nuclear is included, as in 100%-2, costs are only 14% higher than the present. This is because in this scenario nuclear provides 50% of electricity, reducing the amount needed from the renewables such as wind and solar PV, therefore reducing the costs per kilowatt-hour generated. Capital intensity also increases greatly, particularly in 100%-1, emphasising the importance of market confidence and capital interest rates.

Regarding environmental impacts, increasing penetration of nuclear and renewables generally improves environmental sustainability: 100%-2 is the best option for six out of ten indicators. It is noteworthy that 100%-1 has around twice the life cycle global warming potential of 100%-2 in 2070 despite their both having the same direct GHG emissions. This is mainly because solar PV still has higher life cycle GHG

emissions than nuclear power, even given technological advances by 2070. This outcome demonstrates the need to focus on life cycle emissions rather than direct emissions. This is particularly important as decarbonisation of electricity leads us away from the use of fossil fuels, reducing the importance of direct GHG emissions from fuel combustion and increasing the influence of construction materials used in non-fossil technologies.

Increasing the installed capacity of renewables increases employment, particularly in operation and maintenance, meaning much of the employment creation is likely to be in the UK. In the most renewable-intensive scenario (100%-1), total employment increases by 137% over the present to 109,300 full-time-equivalent jobs in 2070. Of these, 70% are 'direct' jobs (in installation and operation/maintenance) that are likely to be based in the UK. By 2070,100%-1 and 100%-2 avoid 97 million tonnes of oil-equivalent per year compared to the present-day fossil fleet. Sub-scenario 100%-2 is also the best option in terms of fuel storage capabilities (158% better than 2009) owing to high penetration of nuclear power; this provides security against supply disruptions. Conversely, 100%-2 also has the highest human toxicity potential (19% higher in 2070 than in 2009) and radiation health impacts (223% higher) although, as discussed earlier, the radiation-induced health impacts are still extremely small. It should also be borne in mind that the human toxicity impacts of coal CCS-reliant scenarios, such as 65%-1, may have been underestimated and might in fact be worse than 100%-2. Finally, 100%-2 produces the most nuclear waste - nearly 2500 m3/year - but this compares to 724,000 m3/year of supercritical CO2 for storage in 100%-1 despite coal CCS only providing 0.2% of electricity by 2070; thus the total volume of long-term nuclear waste is small compared to scenarios with serious contributions from coal CCS. When nuclear is avoided and more emphasis is placed on re-newables, as in 100%-1, depletion of elements is 6.5 times higher than for the present mix, mainly owing to the solar PV life cycle. This increases material scarcity for future generations, although recycling could mitigate some of the effect.

If equal importance for all sustainability indicators is assumed, then scenario 100%-2 is found to be the best option, followed by 80%. However, if the latter is realised, the UK misses its GHG emission targets. On the other hand, the former is probably unrealistic without energy storage and demand-side management solutions in order to match supply to demand.

As this work demonstrates, the decarbonisation of the UK electricity mix introduces many questions regarding sustainability, some of which have been addressed in this paper. Despite a relatively limited number of technologies considered, this study illustrates that the level of decarbonisation achieved and the approach taken can lead to greatly diverging outcomes, each involving trade-offs and compromise. Therefore, decisions on the future of the electricity system in the UK (and elsewhere) should be based on an open stakeholder dialogue which considers a range of sustainability aspects rather than climate change alone to ensure that the GHG emission targets are not met at the expense of other sustainability issues. As this analysis demonstrates, decarbonisation in line with government targets requires extreme electricity mixes with uncertain impacts owing to the current technological limitations of matching electrical supply and demand. These should be explored and understood fully to warrant 'no regret' decisions and a sustainable transformation of the electricity system in the UK.

Acknowledgements

This work was carried out as part of the SPRIng project (Sustainability Assessment of Nuclear Power: An Integrated Approach) funded by the UK Engineering and Physical Sciences Research Council (EPSRC) and the Economic and Social Research Council (ESRC) (Grant no. EP/F001444/1). The authors gratefully acknowledge this funding. We are also grateful to the SPRIng project partners for their support (for the list of partners, see www.springsustainability.org). Additionally,

we thank Peter Burgherr and the Paul Scherrer Institut for data regarding large accident fatality estimates.

Appendix A. Supplementary Information

Supplementary information to this article can be found online at http://dx.doi.Org/10.1016/j.esd.2014.09.008.

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Life cycle sustainability assessment of UK electricity scenarios to 2070 Academic research paper on "Earth and related environmental sciences"

Abstract of research paper on Earth and related environmental sciences, author of scientific article — Laurence Stamford, Adisa Azapagic

Similar topics of scientific paper in Earth and related environmental sciences , author of scholarly article — Laurence Stamford, Adisa Azapagic

Academic research paper on topic "Life cycle sustainability assessment of UK electricity scenarios to 2070"