Full Document Text

                
 
 
 
 
 
    
POWERFUL TARGETS: 
Exploring the relative cost of meeting 
decarbonisation and renewables targets in the 
British power sector 
 
 
 
 
 
 
 
 
 
AF-MERCADOS UK 
Version 1.0 
4 March 2012 
 
 
 
 
  

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contact details for this paper: 
 
Alice Waltham 
AF-Mercados UK, Suite 6, One St Colme Street, Edinburgh EH3 6AA 
 
alice.waltham@afconsult.com 
 
www.mercadosemi.com www.afconsult.com 
 
 
 
 
 
The information in this paper is of a general nature and is not intended to address the circumstances of any particular individual or 
entity. No one should act on such information without appropriate professional advice. Views expressed in this paper are those of 
the authors only, and do not necessarily reflect the opinions of the wider AF group. 
 
  

 
AF-MERCADOS EMI 
Powerful Targets 1 
Foreword by Clare Spottiswoode CBE 
This paper contributes to our understanding of how to 
achieve the UK's climate change targets in the power 
sector, and of the costs of taking different paths to do this.  
It does not prescribe or recommend policy.  Rather it looks 
at the lowest cost way of getting to the targets the UK has 
accepted for reducing its total greenhouse gas emissions by 
80% by 2050.  
In many ways the results are encouraging.  Our modelling 
indicates that in order to meet our 2050 target for carbon 
reduction emissions for power we need to spend around 
25% more than we would if we had no such target.  To 
achieve exactly the same amount of carbon reduction – but 
with the renewable targets as well – would add around 
another 15%, or about 40% extra overall costs compared 
to no targets.  
Without carbon dioxide reduction targets there would be no 
renewable or new nuclear.  This illustrates the obvious 
point that carbon credits or other government policies are 
required to achieve power generation that is less carbon 
intensive. 
If our only policy driver is to reduce carbon emissions, then 
the lowest cost way of meeting our emissions targets 
requires a mixture of gas and nuclear new build.  Coal has 
no place in this least cost scenario – because of its 
emissions.  Nor has wind, either onshore or offshore – 
because of its additional cost.  To meet the UK's targets 
does require some offsetting by carbon capture and 
storage.  This is a technology that is still in its infancy and 
is unproven.   
It is only when we require renewables for their own sake – 
and not only to reduce carbon emissions – that wind, both 
offshore and onshore, becomes part of the generation mix.  
Even in this scenario solar power has no role because of its 
additional cost.  
These are interesting conclusions.  If we are concerned 
about cost, then renewables have no part to play in 
reducing greenhouse gas emissions by 80% before 2050.  
Rather it is gas and nuclear alone that creates the least 
cost mix.   
What is clear is that current policies, under DECC's own 
central projections, are not delivering emissions reductions 
using the lowest cost means.  Indeed according to this 
analysis, current policy is set on a relatively high cost path.   
The model shows that the cost of having a renewables 
target over and above an emissions target alone is high.  It 
is often not clear whether the aim of that policy is to reduce 
carbon dioxide emissions, or to deliver renewables for their 
own sake.  Understanding the difference is key to 
understanding the costs to the British economy. 
Given the economic impact, it is important that the case for 
renewables is made independently and cogently.  There 
may be valid policy reasons to go for a costlier mix, but if 
this is the case, it needs to be articulated openly and 
honestly, giving stakeholders robust forecasts of the costs 
and benefits. 
We hope that this paper encourages debate and sheds light 
in this important area of our lives.  
 
Clare Spottiswoode is perhaps best 
known for her role as Director General of 
Ofgas between 1993 and 1998, where 
she oversaw the transformation of the 
gas industry from a monopoly into an 
industry where every customer can 
choose who to buy their gas from.  
Clare currently chairs Gas Strategies, and 
is European Chair and Non-Executive 
Director of Energy Solutions, a nuclear 
waste company, and as part of this role is 
also Chair of Magnox, she is a Non-
Executive Director of G4S, a FTSE 100 
company, of Enquest and Energetix.   
She is an Independent Director of the 
Payments Council, ensuring that Banks 
co-operate in the interests of the general 
public, and was a member of the 
Independent Commission on Banking 
tasked with recommending what the 
Government should do to change the 
structure and regulation of banking. Her 
previous roles also include acting as the 
Policyholder Advocate for Aviva. 
Awarded a CBE for services to industry in 
1999 she holds degrees from Cambridge 
and Yale Universities in Maths and 
Economics, and has an honorary 
doctorate from Brunel. 

 
AF-MERCADOS EMI 
Powerful Targets 2 
Deciding our energy future 
Great Britain is starting a significant program of investment in the power 
sector. Everyone in Britain will be affected by the decisions made now. It 
will affect our electricity bills and the competitiveness of our businesses for 
decades to come. 
The power sector has challenging targets for carbon dioxide reduction and renewable electricity 
generation. In this paper, we look at the least cost way of meeting these targets. To do this, we 
modelled generation development out to 2050 with the goal to determine the cheapest way of 
meeting electricity demand under three policy scenarios: 
• Scenario one established a reference case of the least cost way of meeting electricity demand 
without policy targets, including a capacity margin at peak to represent security of supply;  
• Scenario two was identical to scenario one, with the additional requirement of meeting targets 
for significant reductions to power sector carbon dioxide emissions; and 
• Scenario three was identical to scenario two, with the additional requirement of meeting 
renewable electricity generation targets.  
We have excluded existing policy elements, like feed in tariffs and carbon prices, to allow the model 
to look purely at capital and operational costs in determining the combination of generation 
technologies with the lowest overall cost to 2050. 
The total cost of generation in the period 2012-2050 in each scenario is: 
 
There are a number of key conclusions that we draw from our simulation results: 
• The scenarios show that the least cost way of meeting 2050 carbon dioxide emissions reduction 
targets is to do so without renewable electricity. 
• They demonstrate the important role of nuclear generation and gas-fired generation if we are to 
meet our carbon dioxide emission reduction targets at least cost.  In fact, gas has a significant 
role in all our scenarios. 
• For the challenging 2050 emissions targets, using DECC technology cost projections, carbon 
capture and storage may be important, highlighting the need for greater development to fully 
understand and reduce the costs. 
• Capital costs vary between scenarios. Considerably higher capital expenditure on generation is 
required in the next few years to meet the 2020 renewable electricity targets. In scenario one 
the capital spend is £28 billion by 2020, in scenario two it is slightly lower at £24 billion (as no 
new coal is built, unlike scenario one) and in scenario three the capital spend is considerably 
higher at £69 billion by 2020. This excludes the wider costs of grid reinforcement. 
• Meeting both the renewables and emissions targets at least cost (scenario three) requires 
significant amounts of new nuclear, gas and wind. These technologies have sometimes struggled 

 
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Powerful Targets 3 
to get planning permission. Policy makers need to make sure that these projects get approval, or 
we will all pay the cost of more expensive alternatives. 
As with all projections, the modelling results should be interpreted with a degree of realism. In 
particular, the limitations to what this analysis covers include: 
• All the scenarios consider the least cost ways to meet targets regardless of their political 
acceptability. If there is a policy decision to use more expensive technologies, the costs will be 
higher than shown. 
• Clearly, as with any forecast, there is considerable uncertainty about the costs of different fuels, 
so the scenarios should be considered as comparative only (this is why scenario one is important 
as a reference case). In all three scenarios we used the same publicly available DECC central 
forecasts of fuel prices. If the cost of fossil fuels are higher or lower than DECC’s forecast, the 
costs and fuel mix will change. 
• Nuclear and renewables can help to hedge against the cost of the volatility in international fossil 
fuel markets. We haven’t put any value on this hedge. The future price of gas is uncertain, and 
there is an argument that says with the advent of plentiful shale gas, the price and security of 
supply of gas is such that gas may be cheaper than the DECC price projections.  
• We haven’t included the costs of short term balancing or of reinforcing the grid to accommodate 
new generation. Only the immediate cost of connecting the new generation to the network and of 
ensuring enough generation capacity to securely meet peak demand is considered. Adding wider 
reinforcement costs would be expected to add to the cost of all scenarios. In particular the 
renewables scenario would be expected to be relatively higher because the resource tends to be 
further from demand centres and the overall capacity build is higher. As an example, in Project 
Discovery (2009) Ofgem estimated the overall cost of transmission and distribution investment in 
their Green Transition scenario as £53.4 billion by 2025 compared to £47.0 billion in their Slow 
Growth scenario (although this is not directly comparable to our scenarios).  
• We didn’t consider the impact of policy measures that are more ambitious than DECC’s central 
demand assumptions. In particular, the electrification of heat and transport that has been 
proposed to help meet targets for the wider economy would increase electricity demand in 
scenarios two and three. By not changing the demand between scenarios, we hope to show the 
comparative costs of targets on the power sector in isolation. 
• The technology operational and cost assumptions we used were based on Parsons Brinckerhoff’s 
2011 cost update report for DECC and ARUP’s 2011 report on the deployment potential of 
renewable electricity for DECC. If technology matures at different rates than envisaged, the least 
cost mix of technologies may be different. 
• There is a limit on onshore wind based on ARUP’s 2011 report for DECC which considered 
planning limitations, and if that is relaxed the renewables targets cost less. 
We prepared this paper because we feel that the debate on the costs of different energy futures often 
seems to be led by groups with vested interests. We wanted to give an independent perspective on 
the cost of targets, based on data from reputable sources. We also wanted to separate out the 
arguments for carbon dioxide emissions reduction and for renewable electricity. This paper is not 
“pro” or “anti” any particular technologies. It is certainly not a prediction of the future or a statement 
of all the possible costs. This paper does start to provide a factual basis to openly assess policy 
measures against their costs.  Policy makers, including DECC, should consider publishing similar data 
themselves, so the full implications of any policies can be understood by all stakeholders.  
At present the costs of carbon dioxide permits and of renewable generation support in our electricity 
bills are still low. In the future, the impact on bills will increase to support the increasing renewable 
generation and emissions reduction requirements. The renewable energy and emissions reduction 
targets are binding on the UK, but we feel the costs should be articulated clearly and compared to the 
alternatives. If there are policy reasons to go for a more expensive mix, they need to be dealt with 
openly and honestly. We do not see any benefit in pretending that the additional costs do not exist, or 
wishing them away by bold assumptions on efficiency gains (which could benefit any scenario).  
There are no easy answers, but we hope that our analysis will help inform the debate by bringing 
some transparency. It is certainly not the end of the story. We would like to hear views on this paper, 
other conclusions that people have drawn from it, and suggestions for future topics of research. 
  

 
AF-MERCADOS EMI 
Powerful Targets 4 
Scenario one: no targets 
Scenario one simply looked for the lowest cost generation mix, taking into account capital and 
operational costs. The requirement of the model was to meet projected demand and our de-rated 
capacity margin at peak (the capacity margin is used as a proxy for security of supply) – more detail 
on the model is provided in the background at the end of this paper. We have deliberately excluded 
all the incentives currently in the power market, to look at just the least cost investment and 
operational scenario to meet policy goals. 
Scenario one provides a reference case that we can compare the other scenarios to.  It will not meet 
UK climate change obligations, so is 
not a realistic policy option. 
Results 
The resulting mix of generating 
capacity is shown in Figure 1 and the 
electricity production for the period 
2012-2050 is shown in Figure 2. 
There are none of the existing policy 
mechanisms in this scenario, so there 
is no cost to the power sector 
associated with emitting carbon 
dioxide. The resulting mix of 
generation includes a large proportion 
of coal and gas, including combined 
cycle and open cycle gas turbines. 
The blended unit cost of generating 
electricity in 2020 is 5.12 p/kWh. This 
blended unit cost is the sum of the 
fixed and variable generation costs, 
divided by the total demand. In the 
case of new generation built by the 
model, the fixed costs include the 
annualised cost of repaying the initial 
capital outlay. 
The unit cost of electricity generation 
over the period 2012-2050 is 5.82 
p/kWh. 
Commentary 
All models make assumptions and 
simplifications.  
We have used DECC central estimates 
for fuel prices. In this scenario, the 
choice between coal and gas plant can 
be fairly finely balanced. In general in 
this scenario, open cycle gas plants 
(OCGT) are cheapest to build but most 
expensive to run, combined cycle gas 
plants (CCGT) cost a bit more to build 
and a bit less to run, and coal is more 
expensive than either gas plant to 
build but cheaper to run. Changes in 
relative gas or coal prices or 
introducing a requirement to buy 
carbon permits would have a 
significant impact on the proportions 
of coal and gas deemed optimal by 
the model.  
Nuclear and renewables are both more 
expensive, so the simulated 
investment scenario does not include 
these technologies. 
By using DECC’s long term annual 
Figure 1: Capacity development for scenario one (GW) 
 
 
Figure 2: Generation 2012-2050 for scenario one 
 

 
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Powerful Targets 5 
price forecasts extended out to 2050 for coal and gas, we are not considering the impacts of shorter 
term price increases or decreases. For example, Ofgem’s analysis suggests that recent rises in 
electricity bills have been largely due to wholesale gas price increases. On the other hand, some 
analysts’ forward projections for gas prices are lower than DECC’s and expect shale gas to have a 
downward pressure on prices. 
By deliberately not considering the cost of carbon dioxide in this scenario, we are failing to recognise 
that other parts of the economy may suffer costs associated with climate change. Other analysis 
suggests that these costs may be higher than the cost of reducing carbon dioxide emissions. 
However, this scenario is interesting. It shows that without the targets both coal and gas play a very 
important role. It also provides a reference scenario to which our other scenarios can be compared.   
Scenario two: carbon dioxide targets 
The UK has a legally binding target to reduce its total greenhouse gas emissions by 80% by 2050. To 
meet this target, the Committee on Climate Change considers that the power sector will need to 
reduce its emissions to around to 5 MTCO2 by 2050, and has set out a trajectory to reach this point 
(Fourth Carbon Budget, 2010). 
In scenario three, generation is chosen based on its capital and operational costs, as for scenario one, 
but with the added constraint that the overall generation mix must meet the Committee on Climate 
Change’s emissions targets. 
Results 
The resulting mix of generating capacity is shown in Figure 3 and the electricity production for the 
period 2012-2050 is shown in Figure 4. 
Out to 2020, the model builds gas-fired generation. The blended unit cost of electricity generation in 
2020 is slightly higher than scenario one at 5.29 p/kWh. 
However, after 2020, scenario two diverges more from scenario one. To meet the carbon dioxide 
reduction targets, the model builds nuclear generation and gas-fired generation, some of which is 
fitted with carbon capture and storage, requiring higher spend than scenario one. The blended unit 
cost of electricity generation over the 
period 2012-2050 is 7.17 p/kWh. 
Commentary 
By placing a constraint on emissions, this 
scenario recognises the wider cost of 
carbon dioxide emissions.  
This scenario does not build coal because 
of the emissions targets. This means it is 
not sensitive to the coal/gas cost 
differential as scenario one. 
Carbon capture and storage (CCS) is 
currently at a relatively early stage of 
development. Much of the technology of 
individual components is proven in other 
fields, but there are few demonstrations 
of the full chain and scale. The economics 
and practicalities are less clear than for 
other technologies. As with other 
technologies, we have used the 
assumptions about long term costs and 
technological development from Parsons 
Brinckerhoff’s 2011 cost update report for 
DECC. 
While it achieves the carbon dioxide 
emissions reduction targets sought from 
the UK power sector, this scenario 
deliberately does not take into account 
the targets for renewable energy use that 
the UK has agreed at a European level. 
These targets are mandatory and 
member states failing to meet their 
renewable energy targets may face a 
financial penalty. At the moment it is 
Figure 3: Capacity development for scenario two (GW) 
 
 

 
AF-MERCADOS EMI 
Powerful Targets 6 
unknown if and how the Commission 
would make use of its penalty-
imposing powers. 
In this scenario over 20 GW of new 
nuclear is built by 2030, and nearly 
40 GW by 2050. The model does not 
take into account the potential 
objections to nuclear that might 
prevent so much being built. It is 
worth emphasising that the model 
does include an annual provision for 
waste and decommissioning in the 
costs of nuclear based on Parsons 
Brinckerhoff’s 2011 cost update 
report for DECC. 
We have used the same DECC 
central demand projection as for 
scenario one, for comparison 
purposes. In the transition to a low 
carbon economy, there may be some 
decrease in power demand due to 
energy efficiency policies, but also an 
increase in power demand to help 
decarbonise heat and transport. We have not considered these potential changes to demand. 
This scenario shows the importance of new nuclear and carbon capture and storage in delivering 
carbon dioxide savings at the lowest cost. It demonstrates that it is possible to meet the climate 
change target without a renewables target. 
Scenario three: carbon dioxide and renewables targets 
In scenario three, generation is chosen based on its capital and operational costs but with the 
constraint that the overall generation mix must meet both emissions targets and renewables targets. 
The UK has a binding target to generate 15% of energy (electricity, heat and transport) from 
renewable sources by 2020.  The power sector is seen as having greater potential to contribute than 
other parts of the economy, so is expected to meet 30% of demand from renewables by 2020. 
In this scenario the model is free to choose from a range of technologies to meet the renewables 
target, but is constrained from choosing more than 15,000 MW of onshore wind by 2020 and 20,000 
MW by 2030.  This is based on the ARUP report for DECC and reflects a view of the practical ceiling on 
developers getting successful planning applications. 
Results 
The resulting generating capacity mix is shown in Figure 5 and the electricity production for the 
period 2012-2050 is shown in Figure 6.  
The mix of generation includes both offshore and onshore wind. From the data we used, wind had a 
lower cost than the other renewable alternatives available (for example, solar electricity). Onshore 
wind has considerably lower costs, but it was constrained based on the limits to deployment based on 
ARUP’s 2011 report for DECC. The model builds the maximum amount of onshore wind allowed. 
Offshore wind meets the remainder of the target, and is a significant source of the extra costs 
associated with this scenario. 
A significant proportion of nuclear and gas-fired generation (some with carbon capture and storage) is 
built, although less than scenario two. The overall capacity needed is higher, reflecting the variable 
nature of wind production and its lower expected contribution to peak demand. 
The blended unit cost of electricity generation in 2020 is more expensive than the other scenarios at 
6.73 p/kWh. The blended unit cost of electricity generation over the period 2012-2050 is 8.35 p/kWh.  
It should be noted that these scenarios are based on least cost choices and do not reflect the costs to 
consumers of support mechanisms like feed in tariffs.  As these currently include support to more 
expensive technologies, the real effect on consumer bills may be higher.  The cost will depend on the 
detailed development of policy. 
 
 
Figure 4: Generation 2012-2050 for scenario two 
 
 

 
AF-MERCADOS EMI 
Powerful Targets 7 
Commentary 
As noted under scenario two, renewables 
are more expensive than the other low 
carbon options, and so are used only up to 
the 30% target.  A relaxation of the 
planning limits on onshore wind would 
result in more onshore wind and lower 
overall costs. 
As for scenario one and two, we have 
used DECC’s central demand projection. 
In reality, there may be an increase in 
power demand to help meet the 
renewables targets by using more electric 
heat and transport. Higher demand would 
mean more renewable generation was 
required to meet the 30% target. 
This scenario includes a high proportion of 
wind generation. Although in general 
Britain has very good wind resource, 
output varies with wind speed. In all three 
scenarios, we require the model to build 
to a peak capacity margin taking into 
account the expected availability of 
generators at system peak (based on the 
National Grid Winter Outlook). The 
expected contribution of wind at peak is 
lower relative to conventional generation, 
and as a result the total required 
generation capacity is higher in this 
scenario than either of the other two, 
increasing the cost of this scenario. 
However, we did not include other costs of 
short term balancing, for example 
different operational costs for flexible 
fossil-fuelled plant that are ramping up or 
down more frequently.  
Good wind resource is also often further 
from demand centres. The need to 
connect these remote regions, combined 
with the higher overall capacity required in 
this scenario, would require significant 
wider reinforcement investment in the grid 
that isn’t shown in our analysis. We only 
include the immediate costs of connecting 
to the grid. For offshore wind, the costs of 
connection to the shore is included as part 
of the operational costs under the new 
offshore transmission charging regime. 
These costs are taken from ARUP’s 2011 
report for DECC.  
With all our scenarios, we have used the 
assumptions on “first-of-a-kind” and “nth-
of-a-kind” technology costs from Parsons 
Brinckerhoff’s and ARUP’s 2011 reports for 
DECC. If some renewable technologies achieve greater (or lower) cost savings than these reports 
suggest, then costs under this scenario will fall (or rise).   
Comparing cost between scenarios 
The costs in each of the three scenarios are shown in Figure 7. 
These unit costs are based on the total cost of generation divided by the total demand in each year. 
The costs of generation include fixed and variable operating costs (with an annual provision for waste 
and decommissioning for nuclear), and the amortised capital cost of generation built after 2011. As 
we have not included the capital costs of existing (sunk) assets, the costs in the earlier years of the 
Figure 5: Capacity development for scenario three (GW) 
 
 
Figure 6: Generation in 2012-2050 for scenario three 

 
AF-MERCADOS EMI 
Powerful Targets 8 
modelled period appear lower. 
However, this would only impact 
absolute values, not relative 
differences between scenarios. 
The cost of scenario one becomes 
stable in the long term because we 
extend the DECC gas and coal price 
forecasts as constant values after 
2030 and in scenario one the model is 
largely just replacing generation 
assets as they retire.  
There is little difference between 
scenarios one and two in the earlier 
years. As the emissions reduction 
trajectory becomes more challenging, 
the cost difference between these two 
scenarios increases as low carbon 
generation is built to meet the 
increasingly challenging emissions 
targets.  
Scenario three includes the 2020 renewables target. This means that the cost diverges from the other 
two scenarios earlier and remains higher. 
Comparing carbon dioxide emissions between scenarios 
The emissions of carbon dioxide in each of the three scenarios are shown in Figure 8. 
Emissions in scenario one are 
unconstrained, and depend mainly on 
the relative price of gas and coal in the 
DECC forecasts. The dip in the graph 
just shows that gas, which has lower 
carbon dioxide emissions than coal, is 
being used more in this period. 
In scenario two and three, emissions 
are constrained to the Committee on 
Climate Change trajectory. 
In broad terms, the key difference 
between scenario two and scenario 
three is that renewables replace some 
of the nuclear. There are minor 
differences in emissions between the 
two scenarios in given years, 
depending on plant operation.  
  
Figure 8: Carbon dioxide emissions in each scenario 
 
Figure 7: Cost per unit in each scenario 
 

 
AF-MERCADOS EMI 
Powerful Targets 9 
Background 
Who we are 
AF-Mercados EMI is a member of the AF group, a consultancy specialising in energy, environment, 
technology and industry with its head office in Sweden. The group employs 4,000 people 
internationally and is the sixth largest international design firm in power and the third largest 
international independent power engineering company (ENR 12/2010). Our services include techno-
economic modelling and analysis of electricity markets and transmission systems. We advise 
governments, regulators and power companies. 
Our modelling approach 
Modelling was carried out using an AF-Mercados EMI proprietary model, ORDENA plus®. The model is 
an existing, well tested dynamic electricity market dispatch and long-term investment simulation 
model that has been used internationally in many markets.  
In this paper we have used ORDENA plus® as a least cost dynamic investment model with the goal to 
minimise the capital and operational costs to 2050. There is a requirement to meet the forecast level 
of demand and a 10% de-rated peak capacity margin requirement for any given mix and amount of 
generation in each year of the simulation (the de-rated capacity margin is a proxy for the level of 
security of supply risk).  
Our analysis has looked at the impact of different scenarios on 
investment and operational costs. We deliberately excluded 
Government interventions that affect generator costs and 
revenues (such as the emissions trading scheme, the 
renewables obligation, climate change levy, feed in tariffs, the 
requirement for new coal generation to include carbon capture 
and storage capability, proposals for contracts to support low 
carbon generation and an emissions performance standard).  
We did not model the short term costs of balancing the system, 
volatility in fuel prices, ramp restrictions, short term balancing 
costs, embedded generation, or any additional markets for 
peaking units. We also do not include the costs of wider grid 
reinforcement, although we do include the immediate costs of 
grid connection.  
Our modelling was based on published and reputable sources of 
input data. Input assumptions for demand growth and fuel 
prices were taken from DECC (central 2011 data) and kept constant beyond the end of their 
forecasts. We used a representation of a load duration curve in each month. Data on existing plant, 
planned plant closures, and de-rating factors were taken from National Grid’s Winter Outlook report 
(09/10 and 10/11). We made assumptions about plant closures where no definitive data was 
available. All current plant and new build is modelled with a fixed design lifetime. Generation 
investments are modelled as first-of-a-kind or nth-of-a-kind technologies (cheaper than first-of-a-
kind), with operational and cost characteristics taken from Parsons Brinckerhoff’s 2011 cost update 
report for DECC and ARUP’s 2011 report for DECC on the deployment potential of renewable 
electricity.  Seasonal availability for thermal generation was informed by DUKES statistics on load 
factors by fuel source and generation data from the ELEXON portal. The assumed available capacity 
factor used for wind generation is 28% for onshore wind (Ofgem ROC Register) and 37% for offshore 
wind (theoretical) and excluded seasonal variations.  
Our target trajectories are based on the most recently developed pathway for how the UK intends to 
meet its targets. For carbon dioxide emissions we assumed these followed the Committee on Climate 
Change’s trajectory for the effort required in the power sector (including a limit of 102 MTCO2/year by 
the year 2020 and 5 MTCO2/year by the year 2050). For renewable electricity, we considered a target 
of 30% of electricity generated from renewables by 2020, based on DECC’s projections for how they 
expect the UK to meet its target for 15% of energy (including heat and transport) to be sourced from 
renewables. We constrained onshore wind to 15 GW in 2020 and 20 GW in 2030, informed by the 
ARUP’s 2011 report for DECC which considered planning limitations on onshore wind development. 
The model takes 2011 as the base year, and allows new build to commence from 2012 onwards 
taking into account the construction times for different technology. 
We have assumed an average effective cost of capital of 10% in all scenarios. In reality, established 
technologies might have a lower cost of capital and less established technologies may have a higher 
cost of capital. We have not considered this in our analysis. 
All figures are given in real 2011 prices, without considering inflation. 
 
Wherever possible we 
based our 
assumptions on DECC 
and National Grid 
data, or reports 
commissioned by 

 
AF-MERCADOS EMI