Electricity Generation Cost Report 2020
Electricity Generation Cost Report 2020
Electricity Generation Cost Report 2020
GENERATION COSTS
2020
August 2020
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2
Acronym Glossary
Acronym Glossary
Advanced Conversion
ACT FOAK First of a Kind
Technologies
3
Introduction
Introduction
Electricity generation costs are a fundamental part of energy market analysis, and a good
understanding of these costs is important when analysing and designing policy to make
progress towards net zero.
This report, produced by the Department for Business, Energy and Industrial Strategy
(BEIS), presents estimates of the costs and technical specifications for different generation
technologies.
Since our last report in 2016, we have updated key assumptions that underlie our analysis.
• commissioned an external provider to produce a full set of new costs and technical
assumptions for gas plants with carbon capture, usage and storage (gas CCUS)
(2018).
• applied evidence from published reports and internal BEIS expertise to update key
assumptions for offshore wind, onshore wind and solar photovoltaics (PV) (2018-
19).
• collected new evidence on small scale solar PV using published information (2019).
Unless otherwise stated, other assumptions remain the same as in the 2016 report1.
In this report we consider the costs of planning, construction, operation and carbon
emissions, reflecting the cost of building, operating and decommissioning a generic plant for
each technology. Potential revenue streams are not considered. The majority of costs in this
4
Introduction
report are presented as levelised costs, which is a measure of the average cost per MWh
generated over the full lifetime of a plant. All estimates are in 2018 real values unless
otherwise stated.
Generation costs are used as inputs to BEIS analysis, including the setting of
Administrative Strike Price setting for Contracts for Difference allocation rounds2.
However, it is important to note that levelised costs are not the same as strike prices.
Strike prices include additional considerations, such as market conditions, revenues for
generators, and policy factors, which are not considered in levelised costs. To date, they
have also typically been expressed in 2012 prices, whereas the levelised costs reported
here are in 2018 prices. For further details on the differences between strike prices and
levelised costs, please see Section 3.
2 https://www.gov.uk/government/publications/contracts-for-difference-an-explanation-of-the-methodology-
used-to-set-administrative-cfd-strike-prices-for-the-next-cfd-allocation-round
5
Introduction
Further detail on the data and assumptions used can be found in the Key Data and
Assumptions spreadsheet published alongside this report.3
Uncertainty
As with any projection, there is inherent uncertainty when estimating current and future costs
of electricity generation. While we consider that the ranges of levelised cost estimates
presented in this report are robust for BEIS analysis, these estimates should also be used
with a level of care given the uncertainties around the future cost of generation. These
uncertainties include the potential for unanticipated cost reductions in less mature
technologies, greater uncertainty for technologies where we have access to less detailed
evidence, and uncertainty around fossil fuel prices and carbon values. To illustrate the
potential effects of these uncertainties, the report presents ranges and sensitivity analysis
on the effects of changes in parameters.
Covid-19
The analysis in this report was completed by the end of January 2020, and so this report
does not account for potential effects of the Covid-19 pandemic on electricity generation
costs.
3 https://www.gov.uk/government/publications/beis-electricity-generation-costs-2020
6
Section 1: How levelised costs are calculated
The Levelised Cost of Electricity (LCOE) is the discounted lifetime cost of building and
operating a generation asset, expressed as a cost per unit of electricity generated (£/MWh).
It covers all relevant costs faced by the generator, including pre-development, capital,
operating, fuel and financing costs. This is sometimes called a life-cycle cost, which
emphasises the “cradle to grave” aspect of the definition.
The levelised cost of a generation technology is the ratio of the total costs of a generic plant
to the total amount of electricity expected to be generated over the plant’s lifetime. Both are
expressed in net present value terms. This means that future costs and outputs are
discounted, when compared to costs and outputs today. Because the financing cost is
applied as the discount rate, this means it is not possible to express it as a £/MWh
component of the cost directly.
The main intention of a levelised cost metric is to provide a simple “rule of thumb”
comparison between different types of generating technologies. However, the simplicity of
this metric means some relevant issues are not considered. Further details on the
considerations included and excluded from levelised costs can be found in Section 3.
Chart 1.1 demonstrates at a high level how Levelised Costs are calculated and what is
included. For further information on how levelised costs are calculated and BEIS’s Levelised
Cost Model please refer to section 4.2 of Mott MacDonald (2010). 4
7
Section 1: How levelised costs are calculated
Step 2: Sum the net present value of total expected costs for each year
Step 3: Sum the net present value of expected generation for each year
5 Note that in this table, net electricity generation refers to gross generation minus any internal plant
losses/use before electricity is exported to the electricity network.
8
Section 2: Changes to generation cost assumptions
The first half of this section covers technology-specific changes to our assumptions. For
offshore wind, onshore wind, solar PV, and Carbon Capture Usage and Storage
technologies (CCUS), there have been significant updates, which we discuss below. We
have also made minor changes to CCGT, tidal stream and AD assumptions. Finally, we
discuss those technologies for which we have not updated the generic assumptions,
including nuclear and small-scale technologies (except small-scale solar PV).
The second half of this section covers changes which apply across technologies – primarily
new financing cost assumptions which apply across technologies. The section also
discusses capital cost ranges, decommissioning costs, fuel costs, gate fees, carbon prices,
load factors and heat revenues.
We present costs for 2025, 2030, 2035 and 2040 here, though for power sector modelling
the trajectory between these years is also considered.
This new information has been used to update key assumptions on capital costs, as well as
operating lifetime, operating costs and load factors. The updated assumptions for 2025,
2030, 2035 and 2040 are detailed below in tables 2.1, 2.2 and 2.4.
For onshore wind and large-scale solar PV, we have reviewed capital costs and
developed an updated learning rate – the rate at which capital costs decrease as more
plants are built, resulting from greater technical and construction experience – to reflect the
projected decreases in capital costs over time. We have also reviewed technical
assumptions for small-scale solar PV (<4kW, 4-10kW, 10-50kW) – updated assumptions
are available in the accompanying Key Data and Assumptions file.
These projections were made prior to the proposal in the CfD Allocation Round 4
Consultation for the inclusion of Pot 1 technologies. The potential impact of a competitive
auction on onshore wind and large-scale solar PV costs will be reflected in future reports.
9
Section 2: Changes to generation cost assumptions
Table 2.1: Key technical assumptions for large-scale (>5MW) solar PV (by
commissioning year) 6
Table 2.2: Key technical assumptions for onshore wind (by commissioning year)
For offshore wind, in keeping with the rapid pace of developments in offshore wind
technology, we have assumed that the £/MW capital and operating costs decrease over time
with the size of the turbine due to economies of scale. Updates to plant lifetimes and learning
rates were also made.
There are significant differences of opinion over future turbine sizes; some stakeholders are
predicting 20MW turbines as early as 2030, while others doubt the feasibility of such large
turbines. Our estimates (shown in table 2.3) represent a balanced consideration of multiple
internal and external views.
6 Note that in all tables construction costs are rounded to the nearest £100/kW, pre-development costs to the
nearest £10/kW, Fixed O&M to the nearest £100/MW/yr, Variable O&M to the nearest £1/MWh, and
load factor to the nearest 1%.
10
Section 2: Changes to generation cost assumptions
Updated cost assumptions for offshore wind are shown in table 2.4.
Table 2.3: 2019 Offshore wind turbine size and load factor projections (by
commissioning year)
Table 2.4: Key technical assumptions for offshore wind (by commissioning year)
We have also adjusted our approach to decommissioning costs for offshore wind – for
further details, please see the “Other cross-cutting assumptions” section below.
7 https://www.gov.uk/government/publications/potential-to-improve-load-factor-of-offshore-wind-farms-in-the-
uk-to-2035
11
Section 2: Changes to generation cost assumptions
While gas CCUS technologies could be deployed in the UK in the 2020s, there remains
some uncertainty around exact deployment timeframes, and the technology remains at the
first of a kind (FOAK) stage of development. We therefore present FOAK costs for 2025 and
2030 in this report, and Nth of a kind (NOAK) costs for 2035 and 2040.
The evidence base for oxy-fuel combustion with CCUS and hydrogen generation with CCUS
(both covered in the Uniper report) is limited, as the technologies are at an earlier stage of
development relative to post-combustion. As a result, we are only presenting costs for CCGT
+ CCUS Post Combustion, which is based on a wider and more robust range of evidence.
The technical assumptions for CCGT + CCUS are presented in table 2.5 below. Further
details on how these costs were reached can be found in the Uniper report.9
Table 2.5: Key technical assumptions for CCGT + CCUS Post Combustion by
commissioning year
FOAK NOAK
2025 2030 2035 2040
Pre-development
(£/kW) 10 10 10 10
Construction (£/kW) 1,500 1,400 1,300 1,300
Fixed O&M (£/MW/year) 25,800 25,800 22,300 22,300
Variable O&M (£/MWh) 5 5 5 5
Average fuel efficiency
(HHV) 47%
Load factor (net of
availability) 87% 92%
Operating period 25 years
8 https://www.gov.uk/government/publications/the-uk-carbon-capture-usage-and-storage-ccus-deployment-
pathway-an-action-plan
9 https://www.gov.uk/government/publications/power-carbon-capture-usage-and-storage-ccus-technologies-
technical-and-cost-assumptions
12
Section 2: Changes to generation cost assumptions
Table 2.6: Key technical assumptions for Biomass with post-combustion carbon
capture and storage
FOAK NOAK
2025 2030 2035 2040
Pre-development (£/kW) 100 100 90 90
Construction (£/kW) 3,400 3,400 3,100 3,100
Fixed O&M (£/MW/year) 160,400 160,400 146,200 146,200
Variable O&M (£/MWh) 4 4 4 4
Average fuel efficiency (HHV) 30%
Load factor (net of availability) 89%
Operating period 25 years
10 Assessing the Cost Reduction Potential and Competitiveness of Novel (Next Generation) UK Carbon
Capture Technology – Benchmarking State-of-the-art and Next Generation Technologies, Revision
4A, Wood, October 2018
https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/864688/B
EIS_Final_Benchmarks_Report_Rev_4A.pdf
13
Section 2: Changes to generation cost assumptions
CCGT H Class: We have assumed a higher level of efficiency for CCGT plants than in the
2016 report, increasing this from 59.8% to 62.4% on a lower heat value (LHV) basis, and
from 54% to 56.2% on a higher heat value (HHV) basis. This is in line with the benchmarking
exercise conducted for BEIS in 2018 by Wood.
Tidal stream: We have assumed a higher load factor for tidal stream plants, increasing this
from 31% to 35%. This is based on an internal review of tidal stream assumptions.
Anaerobic digestion (AD): We have reduced our assumptions around digestate disposal
cost in line with stakeholder responses to the 2017 review of support for AD under the Feed
in Tariff scheme11. Digestate disposal costs are part of variable O&M, which we have
reduced from £87/MWh to £58/MWh as a result.
The Government’s ambition is for the nuclear sector to deliver a 30 per cent reduction in the
cost of new build nuclear projects by 2030, as set out in the Nuclear Sector Deal published
in 2018.
Nuclear costs are revealed through bilateral negotiations which relate to specific projects.
Project-specific analysis is used to inform the Government’s approach to these negotiations.
Because the information and analysis used in these negotiations is commercially
confidential, it is not available to be used to update our generic cost assumptions. Our
previously published generic costs can be found in the 2016 Generation Costs Report.
We have not updated small-scale technologies other than small-scale solar PV since 2016.
For our most recent analysis on these technologies, please see the 2016 Generation Costs
Report. We have also reduced the number of CCUS technologies from the previous report.
11 BEIS (2017), Review of support for Anaerobic Digestion and micro-Combined Heat and Power under the
Feed-in Tariffs scheme: https://www.gov.uk/government/consultations/review-of-support-for-anaerobic-
digestion-and-micro-combined-heat-and-power-under-the-feed-in-tariffs-scheme
14
Section 2: Changes to generation cost assumptions
costs and generation revenues are discounted across time in producing the levelised cost
measure.
BEIS commissioned a report from Europe Economics (EE), updating the Department’s
hurdle rate assumptions for projects starting development from 2018 in a range of
technologies.
The Europe Economics (EE) report is published alongside this document12, along with a
peer review by Cambridge Economic Policy Associates (CEPA).
Europe Economics analysed developments in bond markets, the energy market and the
electricity sector, as well as changing risk drivers, to understand how hurdle rates have
changed since our 2015 update. They found the hurdle rates to have fallen across all
technologies due to falls in market-wide parameters (the risk-free rate and the equity risk
premium) and in debt premia, convergence in risks in the sector and falls in effective tax
rates. This was despite rises in systematic risk across energy markets in general and the
electricity generation sector in particular.
The CEPA peer review found that Europe Economics “broadly applied a reasonable
methodology given the challenges of the study” and stated that the updated figures were
“more likely to represent current hurdle rates” than those used in the 2016 Generation Costs
Report.
The hurdle rates presented are pre-tax and in real terms. They represent the weighted
average cost of capital (WACC), incorporating the cost of debt, equity and technology-
specific debt-to-equity ratios. For technologies which compete as part of the Contracts for
Difference (CfD) allocation framework, we assume that they receive a CfD and therefore are
not exposed to merchant risk during the period of that CfD.
BEIS has applied these hurdle rates across the following technologies:
12 https://www.gov.uk/government/publications/cost-of-capital-update-for-electricity-generation-storage-and-
dsr-technologies
15
Section 2: Changes to generation cost assumptions
The hurdle rates applied are based on investor expectations at the time the work was
undertaken. For investments to be made in future years, the hurdle rates may change.
However, such changes are difficult to project and therefore we assume a flat trajectory for
hurdle rates applied to investments to be made in future years in our modelling – sensitivities
to changes in hurdle rate are shown in section 5.
16
Section 2: Changes to generation cost assumptions
Small-scale solar
Small-scale solar technologies were not covered as part of the Europe Economics review.
We have drawn on evidence from the 2015 consultation on a review of the Feed-In Tariff
scheme13 to estimate hurdle rates, using the EE large-scale solar (>5MW) as an updated
reference point and assuming the relative differences between size categories remain the
same.
Table 2.7: Small-scale solar hurdle rates14
Solar Technology Average 2015 hurdle rates Revised 2018 hurdle rate
Output following consultation assumptions
>5MW 5.6% 5.0% (Europe Economics)
10-50kW 6.2% 5.6%
<10kW 5.7% 5.1%
<4kW 5.7% 5.1%
Further detail can be found in the Key Data and Assumptions file which accompanies this
publication.
13 Impact Assessment: Government response to consultation on a review of the Feed-in Tariff scheme
(2015):
https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/487300/FITs_Review_Govt__r
esponse_Final.pdf
14 We have reviewed solar costs by size rather than by type of developer. The review of small-scale solar
costs did not include projects between 50kW and 5MW.
15 https://www.nationalgrideso.com/charging/balancing-services-use-system-bsuos-charges
17
Section 2: Changes to generation cost assumptions
Decommissioning costs
For offshore wind, we have also made an allowance for decommissioning costs in line with
the approach outlined in Arup (2018)17. This assumes that developers must provide a
financial security to cover the costs of decommissioning the project. Developers incur a
financing cost of providing that security as well as the final cost when the project is
decommissioned. The effect on the LCOE of decommissioning costs is less than £1/MWh.
For all other technologies, the approach remains the same as in the 2016 Generation Costs
report. In line with previous reports, we take the simplifying assumption for other
technologies that decommissioning costs are equal to the scrap value of the plant (and
therefore that the net cost is zero).18
16 WRAP Gate Fees Report 2019: comparing the costs of waste treatment options
http://www.wrap.org.uk/gatefees2019
17 Cost estimation and liabilities in decommissioning offshore wind installations:
https://www.gov.uk/government/publications/decommissioning-offshore-wind-installations-cost-estimation
18
Section 2: Changes to generation cost assumptions
Carbon prices
For gas and coal plants, the total carbon price up until 2030/31 is given by the sum of the
2018 EU ETS carbon price projections and the rate of Carbon Price Support (CPS). At
Budget 2018 it was announced that the CPS rate was capped at £18/tCO2 until the end of
year 2020/21.
From 2021/22 onwards, we assume that the total carbon price for the electricity sector
remains fixed in real terms at the 2021/22 level until the price of the EU ETS rises above
this; after this the carbon price for the electricity sector coincides with the EU ETS price.
Beyond 2030, the total carbon price increases linearly to reach the appraisal value of carbon
in 205021.
Heat revenues
A simplified methodology based on the avoided boiler cost approach has been used to
estimate the heat revenue per MWh of electricity generated. This approach estimates the
cost that would have been incurred by the heat offtaker (the buyer of heat produced by the
CHP plant) if they were to produce the same amount of heat using a boiler, assuming that
100% of the heat is purchased. This would incur fuel costs at the retail gas price, which are
avoided by buying heat from the CHP plant.
Load factors
Where changes are not specified above, load factor assumptions remain the same as in the
2016 Generation Costs report. For flexible technologies such as CCGTs and CCUS plants,
the load factor assumptions represent the maximum potential generation (net of availability),
i.e. baseload of a plant. Where flexible technologies operate at lower load factors, their
levelised costs will be higher than those presented here. This sensitivity is illustrated in
Section 5.
Peaking technologies such as OCGTs and reciprocating engines are assumed to run for a
specified number of hours a year. Wind, solar PV and marine technologies operate as
intermittent electricity generation technologies, and therefore have lower load factors..
21 https://www.gov.uk/government/publications/valuation-of-energy-use-and-greenhouse-gas-emissions-for-
appraisal
19
Section 2: Changes to generation cost assumptions
20
Section 3: How BEIS uses generation cost data in modelling
The estimates outlined in this report are intended to provide a high-level view on the costs
of different generating technologies. Because levelised costs are a simplified metric, this
means that not all relevant issues are considered.
In practice, BEIS’s electricity market modelling, including BEIS’s Dynamic Dispatch Model
(DDM), does not use levelised cost estimates directly. Instead it models private investment
decisions using the same capital expenditure (capex) and operating expenditure
(opex/O&M) assumptions incorporated in the levelised cost estimates reported above. The
DDM also includes assumptions on investors’ expectations over fossil fuel, carbon and
wholesale electricity prices, as well as the financial incentives from policies such as
Contracts for Difference (CfDs) and the Capacity Market.
To model the investment decision, the internal rate of return of a potential plant is compared
to a technology-specific hurdle rate. As noted above, this report focuses on these
technology-specific hurdle rates. The technology-specific hurdle rates reflect different
financing costs for different technologies.
Levelised cost estimates do not consider revenue streams available to generators (e.g. from
sale of electricity or revenues from other sources). One exception to this is heat revenues
for Combined Heat and Power (CHP) plants. As the cost of the owning and operating the
CHP technology is included in the capital and operating costs of the plant, heat revenues
are also included so that the estimates reflect the net cost of electricity generation only.
As levelised costs relate only to those costs accruing to the owner/operator of the generation
asset, the metric does not cover wider costs to the electricity system. Further information on
Wider System Impacts, including illustrative scenarios, can be found in Section 7.
Levelised costs are less suitable for peaking technologies where the most relevant
consideration is the cost of capacity rather than the cost per MWh. A £/kW measure covering
fixed costs for peaking technologies is presented in Section 6.
21
Section 3: How BEIS uses generation cost data in modelling
This report captures some of these uncertainties through ranges presented around key
estimates. A range of costs is presented for capex and fuel, depending on the estimates,
and the tornado graphs illustrate sensitivity to other assumptions. However, not all
uncertainties are captured in these ranges and estimates should be viewed in this context.
It is often more appropriate to consider a range of costs rather than point estimates.
It should also be noted that levelised costs are generic, rather than site-specific. Land costs
are not included and use of system charges are calculated on an average rather than a site-
specific basis.
Generation cost assumptions, such as that summarised here in the form of levelised costs,
are one set of inputs into setting administrative strike prices – the maximum strike price
applicable to a technology in a Contracts for Difference (CfD) allocation round.
Other inputs, including market conditions and policy considerations, may include:
• Revenue assumptions;
• Other costs not included in our definition of levelised cost (for example the generator’s
share of transmission losses, route to market costs reflected in Power Purchase
Agreement (PPA) discounts, and technology-specific estimates for decommissioning
costs and scrappage values);
• CfD contract terms including length, risk allocation, and eligibility requirements within
technologies;
The generation costs data used here may be different from that used as part of the
administrative strike price-setting process. This is particularly where information relevant to
potential bidders in a particular allocation round is used to inform cost assumptions for
pipeline projects. Further, ASPs are normally set so as to bring forward the most cost-
22
Section 3: How BEIS uses generation cost data in modelling
effective projects, which may not be the same as the estimates of typical project costs
estimated in this report.
For all these reasons, the levelised costs presented here may be significantly different from
the administrative strike prices that are set for CfDs and therefore should not be seen as a
guide to potential future administrative strike prices.
• The Dogger Bank projects (which accounted for 5.0GW out of the 5.5GW of offshore
wind capacity awarded in CfD AR3) are significantly larger than our reference plant
size assumption, likely leading to savings due to economies of scale;
• The Dogger Bank projects, situated far from shore, benefit from good wind resource
as well as relatively shallow water depth, leading to expected load factors significantly
higher than average, without significantly higher construction costs;
Chart 3.1 is an illustration of how our offshore wind levelised costs align with the results of
the AR3 auction once the higher estimated load factors of AR3 projects are accounted for
(noting that the larger turbines expected to be used in AR3 projects are already taken into
account in our generic costs). Values are expressed in 2012 prices, in line with conventional
presentation of CfD strike prices.
23
Section 3: How BEIS uses generation cost data in modelling
Chart 3.1: Comparison of generic levelised costs for offshore wind with CfD AR3
strike prices (2012 prices)
60
50
£/MWh (2012 prices)
40
30
20
10
0
2025 Levelised cost (generic 2025 Levelised cost (using 2025 Estimated AR3 strike price*
offshore wind) estimated load factor of AR3
projects)
Error bars show sensitivites of LCOEs and strike prices to high/low capex assumptions. This plot is
illustrative, and should not be taken as a precise indicator of the levelised costs of individual
offshore wind projects.
*This column shows the approximate equivalent strike price to the LCOE shown in the middle
column. This estimate uses assumptions appropriate for AR3, and should not be taken as an
indication of the relationship between levelised costs and strike prices in future CfD allocation
rounds.
Pre-development and construction timings will vary by technology and therefore estimates
reported for ‘project start’ or ‘financial close’22 for different technologies may not be
commissioning in the same year as each other. Central estimates for pre-development and
construction timings are presented for key technologies in the accompanying spreadsheet
to this publication.
22 Financial close can also be known as the point of Final Investment Decision or FID.
24
Section 4: Generation cost estimates
This section summarises the analysis of the levelised cost of electricity generation at
technology-specific hurdle rate for a selection of technologies. All values presented are in
2018 real prices.
100
90 85 85
80
70
60 57
£/MWh
50 46 44
40
30
20
10
0
CCGT H Class Offshore Wind Onshore Wind Large-Scale Solar CCGT + CCS Post
Combustion (FOAK)
23Please note these estimates should be viewed in the context of the sensitivities and uncertainties
highlighted in the text of this report.
25
Section 4: Generation cost estimates
Chart 4.2: Levelised Cost Estimates for NOAK Projects Commissioning in 2025,
Sensitivities, £/MWh, in real 2018 prices
120
100
80
£/MWh
60
40
20
0
CCGT H Class Offshore Wind Onshore Wind Large-scale Solar CCGT + CCS
Post Combustion
(FOAK)
Table 4.3: Levelised Cost Estimates for NOAK Projects Commissioning in 2025,
£/MWh, in real 2018 prices
26
Section 4: Generation cost estimates
Table 4.4: Levelised Cost Estimates for NOAK Projects Commissioning in 2025,
Sensitivities, £/MWh, in real 2018 prices
120
99
100
87
80
£/MWh
60
47 45
39
40
20
0
CCGT H Class Offshore Wind Onshore Wind Large-Scale Solar CCGT + CCUS Post
Combustion (FOAK)
27
Section 4: Generation cost estimates
140
120
100
£/MWh
80
60
40
20
0
CCGT H Class Offshore Wind Onshore Wind Large-scale Solar CCGT + CCS
Post Combustion
(FOAK)
Boxes represent capital expenditure variation, and whiskers represent fuel expenditure
variation.
Table 4.7: Levelised Cost Estimates for Projects Commissioning in 2030, £/MWh, in
real 2018 prices
CCGT +
Large- CCUS Post
CCGT H Offshore Onshore Scale Combustion
Class Wind Wind Solar (FOAK)
Pre-Development Costs <1 3 3 3 <1
Construction Costs 7 25 26 26 22
Fixed O&M 2 17 10 10 4
Variable O&M 4 3 6 0 5
Fuel Costs 41 0 0 0 47
Carbon Costs 45 0 0 0 5
CO2 Transport and
Storage 0 0 0 0 4
Decommissioning and
waste 0 1 0 0 0
Total 99 47 45 39 87
28
Section 4: Generation cost estimates
Chart 4.9: Levelised Cost Estimates for Projects Commissioning in 2035, £/MWh, in
real 2018 prices
120 115
100
81
80
£/MWh
60
43 44
40 36
20
0
CCGT H Class Offshore Wind Onshore Wind Large-Scale Solar CCGT + CCUS Post
Combustion (NOAK)
29
Section 4: Generation cost estimates
140
120
100
£/MWh
80
60
40
20
0
CCGT H Class Offshore Wind Onshore Wind Large-scale Solar CCGT + CCS
Post Combustion
(NOAK)
Boxes represent capital expenditure variation, and whiskers represent fuel expenditure
variation.
Table 4.11: Levelised Cost Estimates for Projects Commissioning in 2035, £/MWh, in
real 2018 prices
CCGT +
CCUS Post
CCGT H Offshore Onshore Large-Scale Combustion
Class Wind Wind Solar (NOAK)
Pre-Development Costs <1 2 3 3 <1
Construction Costs 7 22 25 23 15
Fixed O&M 2 16 10 9 4
Variable O&M 4 3 6 0 5
Fuel Costs 42 0 0 0 47
Carbon Costs 59 0 0 0 7
CO2 Transport and
Storage 0 0 0 0 2
Decommissioning and
waste 0 1 0 0 0
Total 115 43 44 36 81
30
Section 4: Generation cost estimates
140
125
120
100
82
80
£/MWh
60
44
40
40 33
20
0
CCGT H Class Offshore Wind Onshore Wind Large-Scale Solar CCGT + CCUS Post
Combustion (NOAK)
31
Section 4: Generation cost estimates
160
140
120
100
£/MWh
80
60
40
20
0
CCGT H Class Offshore Wind Onshore Wind Large-scale Solar CCGT + CCS Post
Combustion
(NOAK)
Boxes represent capital expenditure variation, and whiskers represent fuel expenditure
variation.
Table 4.15: Levelised Cost Estimates for Projects Commissioning in 2040, £/MWh, in
real 2018 prices
CCGT + CCUS
Post
CCGT H Offshore Onshore Large-Scale Combustion
Class Wind Wind Solar (NOAK)
Pre-Development Costs <1 2 3 3 <1
Construction Costs 7 20 25 21 15
Fixed O&M 2 15 10 9 4
Variable O&M 4 3 6 0 5
Fuel Costs 42 0 0 0 47
Carbon Costs 70 0 0 0 8
CO2 Transport and
Storage 0 0 0 0 2
Decommissioning and
waste 0 1 0 0 0
Total 125 40 44 33 82
32
Section 4: Generation cost estimates
33
Section 4: Generation cost estimates
24https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/566567/BEIS_Electricity_Ge
neration_Cost_Report.pdf
34
Section 5: Sensitivity analysis
To illustrate the uncertainties around our levelised cost estimates, we present tornado
graphs below for selected technologies to show the effects of:
• Increasing or decreasing parameters by 10% from the central estimate while holding
all others constant.
• Applying the high or low cost estimates for individual parameters while holding all
others constant.
These graphs show which underlying assumptions have the largest effect on the costs of
each technology. The blue bars show the impact of a reduction in assumptions, and the
orange bars show the impact of an increase in assumptions. Key findings are shown below.
Chart 5.1: Offshore Wind, Commissioning 2025 LCOE Tornado Chart, £/MWh
For offshore wind, total O&M and capex have the largest effects in the high/low range
scenarios. In the ±10% scenario, the load factor is most significant but total O&M and capex
remain significant.
35
Section 5: Sensitivity analysis
Chart 5.3: Onshore Wind, Commissioning 2025 LCOE Tornado Chart, £/MWh
For onshore wind, the capex and load factor assumptions are most significant in the ±10%
scenario. For the high/low range scenario, total O&M, capex and load factor assumptions
are all important determinants.
36
Section 5: Sensitivity analysis
Chart 5.4: Gas CCUS (FOAK), Commissioning 2025 LCOE Tornado Chart, £/MWh
For gas CCUS, the fuel price is most significant in both scenarios, though capex, O&M and
load factors also have material effects.
Chart 5.5: Large Scale Solar PV, Commissioning 2025 LCOE Tornado Chart, £/MWh
For solar, the capex and load factor assumptions are most significant in both scenarios.
37
Section 6: Peaking technologies and storage
This section presents a £/kW measure for peaking technologies (OCGT and reciprocating
engines), as well as a CCGT H Class for comparison. This measures the cost of capacity
rather than the cost of generation – it therefore ignores fuel costs, carbon costs and other
variable costs. This measure is more suitable for comparing technologies where generation
varies with demand.
Chart 6.1 represents the annual cashflows required to finance the pre-development,
construction and fixed costs for a generic plant. These cashflows are assumed to be paid
over the operating lifetime of the plant. The range of costs is created by varying capital
expenditure to the high and low values.
All technologies except CCGT are assumed to run for a fixed 500 hours per year. CCGT is
assumed to run at baseload.
This metric is not meant to illustrate likely capacity market outcomes, which reflect a range
of other factors, including different contract lengths, load factor and wholesale price
expectations and other sources of revenue.
38
Section 6: Peaking technologies and storage
Chart 6.1: Peaking technologies (reciprocating diesel and gas and OCGT at 500
hours per year) and CCGT (at normal load factors), £/kW per annum for construction
and fixed operating costs, technology-specific discount rates
160
140
120
100
£/kW
80
60
40
20
0
OCGT OCGT OCGT OCGT OCGT Recip Recip Gas CCGT H
100MW 299MW 300MW 400MW 600MW Diesel 500 500 hrs Class 2015
500 hr 500 hr 500 hr 500 hr 500 hr hrs 2015 2015
Storage technologies
As the UK decarbonises, the demand for flexible technologies such as storage, demand-
side-response and interconnectors is expected to increase.
In 2018 BEIS appointed Mott MacDonald to deliver a project on storage cost and technical
assumptions, to inform future policy development in this area.
From this project, BEIS procured a robust and consistent set of cost and technical
information for a range of storage technologies that could be deployed between now and
2050. The assumptions procured include the key technical attributes for the various storage
technologies such as efficiency rates, plant lifetime and duration as well as the key cost
information for these technologies such as pre-development, construction and operational
costs. These assumptions have not been presented in the main body of the report because
39
Section 6: Peaking technologies and storage
they are not comparable with levelised costs, however detailed information on these
assumptions can be found in the following report: ‘Storage cost and technical assumptions
for BEIS’25.
BEIS intends to keep these new storage assumptions under review given that storage
technologies are not yet mature and there is considerable uncertainty regarding the future
costs.
25 Mott MacDonald, 2018, Storage cost and technical assumptions for BEIS.
https://www.gov.uk/government/publications/storage-cost-and-technical-assumptions-for-electricity-
storage-technologies
40
Section 7: Wider system impacts
The levelised cost estimates presented in this report do not take into account wider positive
or negative impacts that an electricity generation plant may have on the electricity system
due to timing of its generation, its location and other characteristics. In 2017 BEIS published
its analytical framework for how to consider these wider system impacts in the electricity
system.26 Note, the work did not consider impacts beyond the electricity system, such as
impacts on the wider economy, international trade or technological innovation.
• Impacts in the wholesale market: This category considers how timely or valuable
each MWh generated by a technology is. This will differ by technology type. For
example, a CCGT plant is dispatchable and will be able to focus its generation on
valuable/useful time periods, while renewable technologies’ generation is determined
more by availability of resource.
• Impacts in the capacity market: This category considers how firm or reliable each
MW of capacity provided by a technology is at moments of peak demand. This will
differ by technology type. For example, an OCGT plant is very reliable at moments
of peak demand (e.g. on a winter’s evening), while other technologies’ available
capacity in those moments is less reliable (e.g. solar).
26https://www.gov.uk/government/publications/whole-power-system-impacts-of-electricity-generation-
technologies
41
Section 7: Wider system impacts
As noted above, all generating technologies impose wider impacts on the electricity system
to varying degrees. Current market arrangements to allocate these impacts are rooted in the
principles of cost-reflectivity, but Ofgem, as the independent energy regulator, keeps these
arrangements under review. For example, Ofgem has recently concluded a charging review
and a second one is ongoing to ensure charges are fair, proportionate and cost-reflective.
Unlike in the levelised cost assumptions, which assume that all technologies run at
their maximum load factor, wider system impacts use projections of a plant’s load
factor from the BEIS Dynamic Dispatch Model. If this load factor differs from the
maximum load factor in level and/or profile, this will change a technology’s levelised
cost. For example, while it might increase £/MWh fixed costs (such as construction
costs) of a plant, it might lower its £/MWh carbon and fuel costs, if generation is more
27These impacts are modelled within BEIS’s Dynamic Dispatch Model, which models electricity dispatch and
investment decisions from 2010 through to 2050. Note that the modelling does not consider all balancing and
ancillary services but focuses on the Balancing Mechanism, reserve for frequency response and inertia.
42
Section 7: Wider system impacts
frontloaded when carbon and fuel prices are lower. These effects are captured in the
enhanced levelised cost ‘dots’ set out in Chart 7.1. In addition, levelised costs
presented in this report do not include the costs of unpriced carbon, which however
represents a system cost. These additional costs are therefore also included in the
enhanced levelised cost ‘dots’. Table 7.1 shows these ‘other impacts’ separately.
• System dependency: Wider system impacts are entirely system dependent and
there is no one ‘right’ estimate. Therefore, any estimates of wider system impacts
should be treated with caution; they are only valid for one state of the world. The
estimates presented in this report only reflect six28 possible scenarios and do not
cover the whole range of possibilities. The scenarios assume differing uptakes of
various low-carbon technologies, and differing projections of long-term electricity
demand. While these scenarios have been designed to illustrate the impact of
different generation mixes, different assumptions could lead to wider system impacts
outside the range illustrated.
The estimates show the wider system impact that a hypothetical small increment of
a technology, e.g. of offshore wind, onshore wind or solar, would have at the margin
of the different market segments (i.e. the wholesale market, capacity market,
balancing and ancillary service markets) when added into these different generation
mixes. While the estimates reflect the characteristics of the technology added, most
importantly they reflect the state of the background scenario, i.e. a more flexible or
diverse scenario is better able to absorb new inflexible or variable plants compared
to a less flexible or diverse system.
• Subjective nature of plant location: The wider system impacts presented in this
report include impacts on transmission networks by considering a range of possible
locations for a generic plant; distribution network impacts are not included. However,
results are still to a large extent driven by the subjective choice of the range of
locations used and should be interpreted with caution. It is important to note that
network costs and charges are likely to change going forward; this is not captured in
the estimates presented.
• Presentation: In line with other literature, wider system impacts in this report are
presented relative to the wider system impacts of a nuclear plant. Alternatively,
wider system impacts can be presented as absolute estimates or relative to any other
technology type.
28The scenarios consist of three different generation mixes (higher renewables, higher nuclear, and a
balanced mix), each taken for two different projections of demand levels. All are high-decarbonisation
scenarios consistent with the UK’s commitment to net zero emissions by 2050.
43
Section 7: Wider system impacts
• Results of three scenarios: Chart 7.1 and Table 7.1 show the levelised costs
presented elsewhere in this report, assuming maximum load factors but with
balancing charges stripped out to avoid double counting with the balancing and
ancillary service costs included in the wider system impact. On the other hand,
transmission network impacts exclude the average network charges faced by
different technologies that are already included in the levelised costs. The ‘dots’
represent a technology’s enhanced levelised cost, made up of the original levelised
cost ‘bar’, the technology’s wider system impact and its ‘other’ impacts, including
unpriced carbon and lower than maximum load factors, with the latter being
particularly important for dispatchable technologies or those that get curtailed.
While dispatchable technologies like CCGTs and CCUS generally help to reduce
system costs, they run at less than maximum load factors and therefore their levelised
costs increase. In these six scenarios, generally (but not always) the system savings
outweigh the load factor impacts, resulting in an overall cost reduction. Intermittent
technologies (e.g. wind and solar) generally impose a wider system cost, which is
more severe in scenarios with lower flexibility or a less diverse generation mix.
The results from the six assessed scenarios highlight that considering wider system
impacts changes our cost perception of different technologies. Across some of the
scenarios assessed, the ranking of technologies changes.
The enhanced levelised cost range is particularly large for CCGTs commissioning in
2035. The value of additional CCGT capacity to the system is greater in scenarios
where demand increases faster or there is a higher proportion of intermittent
renewable capacity. It should be noted that for a technology that operates at
increasingly low load factors as the system decarbonises, a £/MWh metric may not
be appropriate (see Section 6).
44
Section 7: Wider system impacts
Chart 7.1: Enhanced levelised cost for plants commissioning in 2025, 2030 and 2035
across three scenarios with varying amounts of low-carbon, £/MWh
140
120
100
80
£/MWh
60
40
20
0
2025 2030 2035 2025 2030 2035 2025 2030 2035 2025 2030 2035 2025 2030 2035
Table 7.1: Enhanced levelised cost ranges for plants commissioning in 2025 across
six low-carbon generation scenarios, £/MWh
CCGT+CCUS
Post
Combustion
(FOAK)
82 -42 to -25 13 to 23 -2 to -1 61 to 73
Onshore Wind 43 -8 to 3 5 to 21 6 to 8 56 to 73
Large-Scale
Solar 41 6 to 13 1 to 17 0 53 to 66
Offshore
Wind 54 1 to 10 0 to 10 6 to 13 69 to 85
45
Section 7: Wider system impacts
Table 7.2: Enhanced levelised cost ranges for plants commissioning in 2030 across
six low-carbon generation scenarios, £/MWh
Original Wider System Other Transmission Enhanced
Levelised Impact (excl. Impacts Network Levelised
Cost transmission Impacts Cost
network and other
(A) impacts) (C) (A+B+C+D)
(B) (D)
CCGT H Class 97 -92 to -41 18 to 36 -1 to 0 40 to 82
CCGT+CCUS 84 -65 to -37 22 to 45 -2 to 0 63 to 80
Post
Combustion
(FOAK)
Onshore Wind 42 -5 to 7 6 to 28 6 to 10 59 to 87
Large-Scale 37 8 to 15 1 to 16 0 48 to 66
Solar
Offshore Wind 45 7 to 17 1 to 10 5 to 13 62 to 82
Table 7.3: Enhanced levelised cost ranges for plants commissioning in 2035 across
six low-carbon generation scenarios, £/MWh
Wider System Transmission
Original Impact (excl. Other Network Enhanced
Levelised transmission Impacts Impacts Levelised
Cost network and other Cost
impacts)
(A) (B) (C) (D) (A+B+C+D)
Onshore Wind 42 1 to 14 6 to 23 6 to 9 60 to 87
Large-Scale
Solar 33 8 to 19 1 to 11 0 45 to 61
Offshore Wind 41 12 to 22 1 to 7 5 to 11 59 to 79
46
Annex 1: Additional Estimates
Pre-Development Costs 1 2 2 2 4 1 4
Construction Costs 16 19 22 23 38 22 89
Fixed O&M 6 7 8 8 11 -12 -40
Variable O&M 4 4 4 4 5 3 3
Fuel Costs 61 63 62 62 61 141 141
Carbon Costs 50 51 50 51 50 48 48
CO2 Transport and Storage 0 0 0 0 0 0 0
Decommissioning and waste 0 0 0 0 0 0 0
Steam Revenue 0 0 0 0 0 0 0
Additional Costs 0 0 0 0 0 0 0
Total 137 144 148 149 169 203 245
47
Annex 1: Additional Estimates
Pre-Development Costs 20 1 4 2 6 3 3
Construction Costs 509 30 118 39 88 27 31
Fixed O&M -219 -12 -40 13 46 10 19
Variable O&M 3 3 3 9 13 6 3
Fuel Costs 141 65 65 35 44 0 0
Carbon Costs 48 39 39 0 0 0 0
CO2 Transport and Storage 0 0 0 0 0 0 0
Decommissioning and waste 0 0 0 0 0 0 1
Steam Revenue 0 0 0 0 0 0 0
Additional Costs 0 0 0 0 -29 0 0
Total 502 125 188 98 168 46 57
Large-
PV 10- PV 4- PV EfW
Scale EfW AD
50kw 10kw <4kw CHP
Solar
Pre-Development Costs 3 0 0 0 3 4 6
Construction Costs 30 66 78 94 95 177 66
Fixed O&M 10 8 8 20 27 37 22
Variable O&M 0 0 0 0 27 58 58
Fuel Costs 0 0 0 0 -114 -145 -10
Carbon Costs 0 0 0 0 0 0 0
CO2 Transport and Storage 0 0 0 0 0 0 0
Decommissioning and waste 0 0 0 0 0 0 0
Steam Revenue 0 0 0 0 0 0 0
Additional Costs 0 0 0 0 0 -28 0
Total 44 74 86 114 39 101 142
48
Annex 1: Additional Estimates
Pre-Development Costs 7 3 7 9 1 12 5
Construction Costs 84 76 96 176 38 134 210
Fixed O&M 31 42 36 36 19 26 13
Variable O&M 58 22 42 42 10 14 13
Fuel Costs -12 -62 -51 -54 0 0 0
Carbon Costs 0 0 0 0 0 0 0
CO2 Transport and
0 0 0 0 0 0 0
Storage
Decommissioning and
0 0 0 0 0 0 0
waste
Steam Revenue 0 0 0 0 0 0 0
Additional Costs -32 0 0 -14 0 0 -107
Total 135 82 130 193 67 186 133
CCGT +
Hydro Tidal Biomass
Hydro CCS Post
Large Wave stream CCS
5-16MW Combustion
Storage 2015 (FOAK)
(FOAK)
49
Annex 1: Additional Estimates
50
Annex 1: Additional Estimates
Large-
PV 10- PV 4- EfW
scale PV <4kw EfW* AD
50kw 10kw CHP
Solar
High capex 51 90 104 136 138 165
Central 44 74 86 114 39 101 142
Low capex 39 58 67 91 60 125
High capex, high fuel 181 167
Low capex, low fuel 42 122
CCGT + CCS
Hydro Biomass
Hydro 5- Post
Large Wave Tidal stream CCS
16MW Combustion
Storage* (FOAK)
(FOAK)
*EfW and Hydro Large Storage – due to potential issues with the reliability of the
range of cost estimates, no capex or fuel sensitivity shown for EfW and Hydro Large
Storage.
51
Annex 1: Additional Estimates
Pre-Development Costs 1 2 2 2 4 1 4
Construction Costs 16 19 22 23 38 22 89
Fixed O&M 6 7 8 8 11 -12 -40
Variable O&M 4 4 4 4 5 3 3
Fuel Costs 64 66 64 65 64 147 147
Carbon Costs 69 71 70 71 69 75 75
CO2 Transport and Storage 0 0 0 0 0 0 0
Decommissioning and waste 0 0 0 0 0 0 0
Steam Revenue 0 0 0 0 0 0 0
Additional Costs 0 0 0 0 0 0 0
Total 159 167 170 171 191 236 278
52
Annex 1: Additional Estimates
Pre-Development Costs 20 1 4 2 6 3 3
Construction Costs 509 30 118 39 87 26 25
Fixed O&M -219 -12 -40 13 46 10 17
Variable O&M 3 3 3 9 13 6 3
Fuel Costs 147 69 69 35 44 0 0
Carbon Costs 75 61 61 0 0 0 0
CO2 Transport and Storage 0 0 0 0 0 0 0
Decommissioning and
0 0 0 0 0 0 1
waste
Steam Revenue 0 0 0 0 0 0 0
Additional Costs 0 0 0 0 -30 0 0
Total 535 151 214 98 166 45 47
Large-
PV 10- PV 4- PV EfW
scale EfW AD
50kw 10kw <4kw CHP
Solar
Pre-Development Costs 3 0 0 0 3 4 6
Construction Costs 26 61 74 89 94 175 66
Fixed O&M 10 7 7 18 27 36 22
Variable O&M 0 0 0 0 26 57 58
Fuel Costs 0 0 0 0 -114 -145 -10
Carbon Costs 0 0 0 0 0 0 0
CO2 Transport and Storage 0 0 0 0 0 0 0
Decommissioning and
0 0 0 0 0 0 0
waste
Steam Revenue 0 0 0 0 0 0 0
Additional Costs 0 0 0 0 0 -29 0
Total 39 68 81 107 37 97 142
Pre-Development Costs 7 3 7 9 1 12 5
Construction Costs 84 73 92 169 38 134 205
Fixed O&M 31 41 35 35 19 26 13
Variable O&M 58 22 40 40 10 14 13
Fuel Costs -12 -62 -51 -54 0 0 0
Carbon Costs 0 0 0 0 0 0 0
53
Annex 1: Additional Estimates
CCGT +
Hydro Biomass
Hydro Tidal CCS Post
Large Wave CCS
5-16MW stream Combustion
Storage (FOAK)
(FOAK)
54
Annex 1: Additional Estimates
55
Annex 1: Additional Estimates
Large-
PV 10- PV 4- EfW
scale PV <4kw EfW* AD
50kw 10kw CHP
Solar
High capex 46 83 99 129 133 165
Central 39 68 81 107 37 97 142
Low capex 35 54 63 86 56 125
High capex, high fuel 177 167
Low capex, low fuel 39 122
CCGT + CCS
Hydro Biomass
Hydro 5- Tidal Post
Large Wave CCS
16MW stream Combustion
Storage* (FOAK)
(FOAK)
*EfW and Hydro Large Storage – due to potential issues with the reliability of the
range of cost estimates, no capex or fuel sensitivity shown for EfW and Hydro Large
Storage.
56
Annex 1: Additional Estimates
Pre-Development Costs 1 2 2 2 4 1 4
Construction Costs 16 19 22 23 38 22 89
Fixed O&M 6 7 8 8 11 -12 -40
Variable O&M 4 4 4 4 5 3 3
Fuel Costs 65 67 66 66 65 147 147
Carbon Costs 91 94 92 93 91 109 109
CO2 Transport and Storage 0 0 0 0 0 0 0
Decommissioning and waste 0 0 0 0 0 0 0
Steam Revenue 0 0 0 0 0 0 0
Additional Costs 0 0 0 0 0 0 0
Total 183 191 194 194 214 271 313
57
Annex 1: Additional Estimates
Pre-Development Costs 20 1 4 2 6 3 2
Construction Costs 509 30 118 39 86 25 22
Fixed O&M -219 -12 -40 13 46 10 16
Variable O&M 3 3 3 9 13 6 3
Fuel Costs 147 70 70 35 44 0 0
Carbon Costs 109 89 89 0 0 0 0
CO2 Transport and Storage 0 0 0 0 0 0 0
Decommissioning and waste 0 0 0 0 0 0 1
Steam Revenue 0 0 0 0 0 0 0
Additional Costs 0 0 0 0 -30 0 0
Total 570 181 244 98 166 44 43
Large-
PV 10- PV 4- PV EfW
scale EfW AD
50kw 10kw <4kw CHP
Solar
Pre-Development Costs 3 0 0 0 3 4 6
Construction Costs 23 61 74 89 94 174 66
Fixed O&M 9 7 7 18 26 36 22
Variable O&M 0 0 0 0 26 56 58
Fuel Costs 0 0 0 0 -114 -145 -10
Carbon Costs 0 0 0 0 0 0 0
CO2 Transport and Storage 0 0 0 0 0 0 0
Decommissioning and waste 0 0 0 0 0 0 0
Steam Revenue 0 0 0 0 0 0 0
Additional Costs 0 0 0 0 0 -29 0
Total 36 68 81 107 36 96 142
Pre-Development Costs 7 3 7 9 1 12 5
Construction Costs 84 71 90 166 38 134 202
Fixed O&M 31 41 34 34 19 26 13
Variable O&M 58 21 40 40 10 14 13
Fuel Costs -12 -62 -51 -54 0 0 0
Carbon Costs 0 0 0 0 0 0 0
CO2 Transport and Storage 0 0 0 0 0 0 0
Decommissioning and waste 0 0 0 0 0 0 0
Steam Revenue 0 0 0 0 0 0 0
Additional Costs -32 0 0 -14 0 0 -111
Total 134 74 120 180 67 186 121
58
Annex 1: Additional Estimates
CCGT + CCS
Hydro Biomass
Hydro Tidal Post
Large Wave CCS
5-16MW stream Combustion
Storage (NOAK)
(NOAK)
59
Annex 1: Additional Estimates
Large-
PV 10- PV 4- EfW
scale PV <4kw EfW* AD
50kw 10kw CHP
Solar
High capex 42 83 99 129 131 165
Central 36 68 81 107 36 96 142
Low capex 31 54 63 86 54 125
High capex, high fuel 175 167
Low capex, low fuel 37 122
CCGT + CCS
Hydro Biomass
Hydro Tidal Post
Large Wave CCS
5-16MW stream Combustion
Storage* (NOAK)
(NOAK)
60
Annex 1: Additional Estimates
*EfW and Hydro Large Storage – due to potential issues with the reliability of the
range of cost estimates, no capex or fuel sensitivity shown for EfW and Hydro Large
Storage.
61
Annex 1: Additional Estimates
Pre-Development Costs 1 2 2 2 4 1 4
Construction Costs 16 19 22 23 38 22 89
Fixed O&M 6 7 8 8 11 -12 -40
Variable O&M 4 4 4 4 5 3 3
Fuel Costs 65 67 66 66 65 147 147
Carbon Costs 108 111 109 109 108 137 137
CO2 Transport and Storage 0 0 0 0 0 0 0
Decommissioning and waste 0 0 0 0 0 0 0
Steam Revenue 0 0 0 0 0 0 0
Additional Costs 0 0 0 0 0 0 0
Total 199 208 210 211 231 299 340
62
Annex 1: Additional Estimates
Pre-Development Costs 20 1 4 2 6 3 2
Construction Costs 509 30 118 39 86 25 20
Fixed O&M -219 -12 -40 13 46 10 15
Variable O&M 3 3 3 9 13 6 3
Fuel Costs 147 70 70 35 44 0 0
Carbon Costs 137 112 112 0 0 0 0
CO2 Transport and Storage 0 0 0 0 0 0 0
Decommissioning and waste 0 0 0 0 0 0 1
Steam Revenue 0 0 0 0 0 0 0
Additional Costs 0 0 0 0 -29 0 0
Total 598 203 267 98 166 44 40
Large-
PV 10- PV 4- PV EfW
scale EfW AD
50kw 10kw <4kw CHP
Solar
Pre-Development Costs 3 0 0 0 3 4 6
Construction Costs 21 61 74 89 94 174 66
Fixed O&M 9 7 7 18 26 36 22
Variable O&M 0 0 0 0 26 56 58
Fuel Costs 0 0 0 0 -114 -145 -10
Carbon Costs 0 0 0 0 0 0 0
CO2 Transport and Storage 0 0 0 0 0 0 0
Decommissioning and waste 0 0 0 0 0 0 0
Steam Revenue 0 0 0 0 0 0 0
Additional Costs 0 0 0 0 0 -28 0
Total 33 68 81 107 36 96 142
Pre-Development Costs 7 3 7 9 1 12 5
Construction Costs 84 71 90 166 38 134 202
Fixed O&M 31 41 34 34 19 26 13
Variable O&M 58 21 40 40 10 14 13
Fuel Costs -12 -62 -51 -54 0 0 0
Carbon Costs 0 0 0 0 0 0 0
CO2 Transport and Storage 0 0 0 0 0 0 0
63
Annex 1: Additional Estimates
CCGT + CCS
Hydro Biomass
Hydro Tidal Post
Large Wave CCS
5-16MW stream Combustion
Storage (NOAK)
(NOAK)
Pre-Development Costs 1 1 7 7 <1 2
Construction Costs 55 65 165 139 15 48
Fixed O&M 9 16 21 37 4 20
Variable O&M 9 6 16 5 5 4
Fuel Costs 0 0 0 0 47 99
Carbon Costs 0 0 0 0 8 0
CO2 Transport and Storage 0 0 0 0 2 21
Decommissioning and waste 0 0 0 0 0 0
Steam Revenue 0 0 0 0 0 0
Additional Costs 0 0 0 0 0 0
Total 75 88 209 188 82 193
64
Annex 1: Additional Estimates
Large-
PV 10- PV 4- EfW
scale PV <4kw EfW* AD
50kw 10kw CHP
Solar
65
Annex 1: Additional Estimates
CCGT + CCS
Hydro Biomass
Hydro Tidal Post
Large Wave CCS
5-16MW stream Combustion
Storage* (NOAK)
(NOAK)
High capex 96 279 254 85 211
Central 75 88 209 188 82 193
Low capex 57 134 124 79 183
High capex, high
102 237
fuel
Low capex, low fuel 64 173
Table 16: Levelised Cost Estimates for Projects Commissioning in 2025, 2030, 2035
and 2040, technology-specific hurdle rates, £/MWh, 2018 prices. Highs and lows
reflect high and low capital and pre-development cost estimates and capital cost
reductions over time.
66
Annex 1: Additional Estimates
67
Annex 1: Additional Estimates
Central 86 81 81 81
Low 67 63 63 63
High 136 129 129 129
PV <4kw Central 114 107 107 107
Low 91 86 86 86
High
EfW* Central 39 37 36 36
Low
High 154 150 147 148
EfW CHP Central 118 114 111 112
Low 76 72 70 71
High 138 133 131 132
AD Central 101 97 96 96
Low 60 56 54 55
High 165 165 165 165
AD CHP Central 142 142 142 142
Low 125 125 125 125
High 96 90 88 88
ACT Standard Central 82 77 74 74
Low 56 52 50 50
High 209 198 194 194
ACT Advanced Central 130 123 120 120
Low 86 81 79 79
High 326 311 305 306
ACT CHP Central 193 184 180 181
Low 112 106 103 103
High 90 90 90 90
Landfill gas Central 67 67 67 67
Low 44 44 44 44
High 237 237 237 237
Sewage gas Central 186 186 186 186
Low 100 100 100 100
High 209 198 195 195
Geothermal CHP Central 133 124 121 122
Low 14 7 6 7
High
Hydro Large Storage* Central 75 75 75 75
Low
High 96 96 96 96
Hydro 5-16MW Central 88 88 88 88
Low 57 57 57 57
High 391 309 279 279
Wave Central 296 232 209 209
Low 195 151 134 134
68
Annex 1: Additional Estimates
*EfW and Hydro Large Storage – due to potential issues with the reliability of the
range of cost estimates, no capex or fuel sensitivity shown for EfW and Hydro Large
Storage.
** CCGT + CCS Post Combustion and Biomass CCS are assumed to be FOAK for
plants commissioning before 2035, and NOAK for plants commissioning from 2035
onwards.
69
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