Risk managing cost-effective decarbonisation of the power sector in Great Britain FINAL RESULTS October, 2012 This project is funded by the European Climate Foundation
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Contents • Objectives and the methodology • Baseline analysis results • Sensitivity analysis results
• Annex - Assumptions
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Objectives of the analysis WHAT IT IS
WHAT IT IS NOT
• An attempt to change the way people think about technology choices from cost minimisation to risk management • Something different from traditional ‘equilibrium’ modelling studies
• Credible and interesting from the member state (MS)perspective as well as at a European level
• An attempt to forecast the future
• An assessment of market design choices (e.g. what drives investment, capacity mechanisms, welfare allocation) • An analysis of the future role of Emissions Trading System (ETS) and 2030 carbon caps • An evaluation of nuclear power
• Provides a focus on the role of Renewables (RES) and gas
• An evaluation of interconnection and optimising resources across the EU E3G - Third Generation Environmentalism
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A new approach is needed to move the debate from least cost decarbonisation to cost-effective risk managed delivery of policy objectives • The Investment Decision Model developed by Redpoint is an agent-based investment model with no perfect foresight, where the investors act based on future expectations of return with a five year period of foresight • A similar analysis was carried out for Germany and Poland to represent different member state circumstances and reflect EU-wide issues
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Overview of the baseline scenarios Technology Support Scenario – Renewables electricity production (RES-E) subsidy continues post 2020
Carbon Prices in the baseline scenarios
– Carbon price trajectory of the EC’s Energy Roadmap 2050 Carbon Price Scenario
– Carbon price is the single driver of decarbonisation – RES-E subsidy stops in 2015 – no further development of supply chains These two baseline policy scenarios reflect competing approaches to delivering power sector decarbonisation in the UK in line with the 50g/KWh intensity target proposed for 2030 by the Committee on Climate Change. E3G - Third Generation Environmentalism
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Technology Support and Carbon Price baseline scenarios were stress tested against a range of uncertainties SENSITIVITY
TESTED BASELINE SCENARIO1
DESCRIPTION
Electricity demand
High demand: Only half of electrical efficiency assumed under baseline
Carbon Price Scenario
(High vs Low demand)
delivered and higher electrification of heat and transport (483TWh instead
Technology Support Scenario
of 434TWh) Low demand: Less electrification (395TWh instead of 434TWh) Low electrical efficiency
Only half of electrical efficiency assumed under baseline is delivered (468
Carbon Price Scenario
(High Demand EFF)
TWh instead of 434TWh)
Technology Support Scenario
No new nuclear build
No new capacity as opposed to 12.8GW new capacity fixed in both
Carbon Price Scenario
baselines
Technology Support Scenario
CCS deployment
High CCS: 21.6 GW deployed earlier
Carbon Price Scenario
(High vs Low)
Low CCS: only 1.2 GW
Offshore wind deployment
High offshore: 41GW deployed earlier
(High vs Low)
Low offshore: 35 GW deployed
High/Low electricity demand combined
Combination of above
Carbon Price Scenario
Combination of above
Carbon Price Scenario
Technology Support Scenario
with Low CCS Low electrical efficiency combined with no new nuclear build
Technology Support Scenario
Gas price
75% higher or lower than baseline gas price assumption (60p/therm2) –
Carbon Price Scenario
(High vs Low)
introduced with no foresight and lasted for five years
Technology Support Scenario
Expensive CCS
CCS costs double
Carbon Price Scenario
1
CCS and offshore wind deployment related sensitivities were tested only for one of the baseline scenarios. This was due to the fact that sensitivity runs were decided on the basis of baseline results and different baselines had different technology mixes. 2 In line with IEA World Energy Outlook 2011 projections
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N.B. Further details of the underlying assumptions can be found in Annex
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Contents • Objectives and the methodology • Baseline analysis results • Sensitivity analysis results
• Annex - Assumptions
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In the Technology Support Scenario baseline low-carbon capacity is deployed continuously, while in the Carbon Price Scenario decarbonisation is driven by CCS in 2020s Technology Support Scenario baseline Cumulative new build (GW) 180
180
160
160 Solar Offshore Wind
120
Onshore Wind Biomass
100
Marine Oil Hydro / PS
80
Gas CCS Coal CCS
60
Gas Coal
40
Nuclear
20
140 Cumulative New Build - GW
140
Cumulative New Build - GW
Carbon Price Scenario baseline Cumulative new build (GW)
Solar Offshore Wind
120
Onshore Wind Biomass
100
Marine Oil Hydro / PS
80
Gas CCS Coal CCS
60
Gas Coal
40
Nuclear
20
-
2012
2014
2016
2018
2020
2022
2024
2026
2028
2030
2012
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2014
2016
2018
2020
2022
2024
2026
2028
2030
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Unabated gas capacity remains a significant part of the capacity mix in both scenarios Technology Support Scenario baseline Total generation capacity (GW)
Carbon Price Scenario baseline Total generation capacity (GW)
180
180
160
160
140
Offshore Wind
120
Biomass
100
Marine Oil Hydro / PS
80
Gas CCS Coal CCS
60
Gas Coal
40
Nuclear
20
Solar Offshore Wind
120
Onshore Wind
Capacity - GW
Capacity - GW
140
Solar
Onshore Wind Biomass
100
Marine Oil Hydro / PS
80
Gas CCS Coal CCS
60
Gas Coal
40
Nuclear
20
-
2012
2014
2016
2018
2020
2022
2024
2026
2028
17 GW of unabated gas capacity retires between 2012 and 2030
2030
2012
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2014
2016
2018
2020
2022
2024
2026
32 GW of unabated gas capacity retires between 2012 and 2030 driven by higher carbon prices
2028
2030
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However, the generation profile for unabated gas is significantly different in the scenarios, while coal is pushed out gradually Technology Support Scenario baseline Generation Mix (TWh)
Carbon Price Scenario baseline Generation Mix (TWh)
600
600
500
500
Solar
Solar Offshore Wind
Onshore Wind
400
Biomass Marine Oil
300
Hydro / PS Gas CCS Coal CCS
200
Gas
Coal
Generation - TWh
Generation - TWh
Offshore Wind
Onshore Wind
400
Biomass Marine Oil
300
Hydro / PS Gas CCS Coal CCS
200
Gas
Coal
Nuclear
100
Demand
2012
•
2014
2016
2018
2020
2022
2024
2026
2028
2030
Nuclear
100
Demand
2012
2014
2016
2018
2020
2022
2024
2026
2028
2030
In GB generation mix, the main trade off is between offshore wind and CCS gas (given nuclear capacity is fixed) E3G - Third Generation Environmentalism
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Installed unabated gas capacity would play a very different role under different scenarios Comparison of baseline scenarios Installed unabated gas capacity vs load factors (GW vs %)
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Under the Technology Support baseline scenario, the emissions reduction trajectory would be steadier due to continuous renewables deployment Technology Support Scenario baseline Emissions by fuel (mn tonnes CO2)
Carbon Price Scenario baseline Emissions by fuel (mn tonnes CO2)
180
180
160
160 Solar
140
Solar
140
Offshore Wind Biomass Marine
100
Oil Hydro / PS
80
Gas CCS Coal CCS
60
Gas
Onshore Wind
120
mn tonnes CO2
120
mn tonnes CO2
Offshore Wind
Onshore Wind
Biomass Marine
100
Oil Hydro / PS
80
Gas CCS Coal CCS
60
Gas
Coal
40
Nuclear
Coal
40
Nuclear
Target Line
20
Target Line
20
-
2012
2014
2016
2018
2020
2022
2024
2026
2028
2030
2012
2014
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2016
2018
2020
2022
2024
2026
2028
2030
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Power sector costs are higher in Technology Support Scenario baseline Technology Support Scenario baseline Breakdown of power sector costs, ÂŁ bn 2012-30 cumulative
Carbon Price Scenario baseline Breakdown of power sector costs, ÂŁ bn 2012-30 cumulative
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Contents • Objectives and the methodology • Baseline analysis results • Sensitivity analysis results
• Annex - Assumptions
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Relying solely on carbon pricing is an unattractive approach to incentivising investment Carbon Price Scenario Required carbon price (â‚Ź/tCO2)
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Low CCS deployment means very high carbon prices will be needed to drive rapid deployment in offshore wind
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Carbon price trajectories: impact of sensitivities in the Carbon Price Scenario 1000 //
Carbon Price Scenario Required carbon price (â‚Ź/tCO2)
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Total power sector costs under the ‘gas-heavy’ Carbon Price Scenario are more unpredictable and can be much higher Technology Support Scenario Power sector costs, £ bn 2012-30 cumulative
Carbon Price Scenario Power sector costs, £ bn 2012-30 cumulative
Technology specific support mechanisms remain critical to decarbonisation in GB alongside a lower carbon price E3G - Third Generation Environmentalism
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In the case of low electrical efficiency and no new nuclear, power sector costs would increase significantly under the Carbon Price Scenario Technology Support Scenario (Low EFF+ No nuclear) Breakdown of power sector costs
Carbon Price Scenario (Low EFF + No nuclear) Breakdown of power sector costs
Costs increase by only 6% if electrical efficiency fails and there is no new nuclear
Costs increase by 98% if electrical efficiency fails and there is no new nuclear
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Impact of sensitivities on power sector costs in Technology Support Scenario 600
Technology Support Scenario Power sector costs, £ bn 2012-30 cumulative
Power sector costs, £ bn 2012-30 (3.5%)
550
500
450 Min
400
Max
350
300
Electricity demand
Low efficiency Low efficiency + no nuclear
Gas price
No new nuclear
Delivering the target in the Technology Support Scenario baseline costs £344bn in total between 2012 and 2030
Offshore wind deployment
250
200
Overall, costs are more resilient to uncertainties. Biggest risk to costs would come from increased electricity demand, either as a failure to deliver improved electrical efficiency or as a result of higher electricity demand from other sectors. Biggest savings also come from delivering electrical efficiency, hence lower demand.
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Impact of sensitivities on power sector costs in Carbon Price Scenario 600
Carbon Price Scenario Power sector costs, £ bn 2012-30 cumulative
Power sector costs, £ million 2012-30 (3.5%)
550
500
450
Min
400
Max
350
300
250
Low efficiency Electricity + no nuclear demand + low CCS
CCS deployment
Electricity demand
No new nuclear Low efficiency Expensive CCS
Delivering the target in the Carbon Price Scenario baseline costs £297bn in total between 2012 and 2030
Gas price
200
Risks are significantly more asymmetric, and costs tend to go higher under a gas-heavy pathway. In some cases, costs can be higher than renewables-heavy Technology Support Scenario, especially in the case of low efficiency and no new nuclear
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Annual power sector costs: impact of sensitivities in the Technology Support Scenario Technology Support Scenario Power sector costs, ÂŁ bn 2012-30 annual
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Annual power sector costs: impact of sensitivities in the Carbon Price Scenario Carbon Price Scenario Power sector costs, ÂŁ bn 2012-30 annual
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Similarly, wholesale cost risks are higher in Carbon Price scenario Technology Support Scenario Wholesale costs, ÂŁ bn 2012-30 cumulative
Carbon Price Scenario Wholesale costs, ÂŁ bn 2012-30 cumulative
Under the Carbon Price Scenario, increasing carbon prices push up the costs of gas generation. This results in higher wholesale prices, creating significant rents for low-carbon generators. E3G - Third Generation Environmentalism
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Annual wholesale costs: impact of sensitivities in the Technology Support Scenario Technology Support Scenario Wholesale costs, ÂŁ bn 2012-30 annual
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Annual wholesale costs: impact of sensitivities in the Carbon Price Scenario Carbon Price Scenario Wholesale costs, ÂŁ bn 2012-30 annual
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Future value of new gas investment remains uncertain (i) Technology Support Scenario Unabated gas generation (TWh)
Carbon Price Scenario Unabated gas generation (TWh)
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Future value of new gas investment remains uncertain (ii) Technology Support Scenario Unabated gas load factors (%)
Carbon Price Scenario Unabated gas load factors (%)
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Large gas demand uncertainties (particularly in a gas-heavy pathway), raise questions as to the level of new investment required in gas infrastructure Technology Support Scenario Power sector gas consumption (bcm)
Carbon Price Scenario Power sector gas consumption (bcm)
The continued consumption of high volumes of gas depends on both the successful commercialisation of CCS technology and gas generation being cheaper than coal E3G - Third Generation Environmentalism
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Power sector gas consumption: impact of sensitivities Technology Support Scenario Power sector gas consumption (bcm)
Carbon Price Scenario Power sector gas consumption (bcm)
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Continued deployment of renewables produces steady reductions in emissions intensity with more predictable delivery Technology Support Scenario Emission intensity (g/KWh)
Carbon Price Scenario Emission intensity (g/KWh)
Policy failure in the case of Low CCS deployment; High demand and low demand combined with low CCS deployment
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Continued deployment of renewables also delivers higher reductions in cumulative emissions Technology Support Scenario Cumulative CO2 emissions (mn tonnes)
Carbon Price Scenario Cumulative CO2 emissions (mn tonnes)
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Generation in Carbon Price Scenario: impact of sensitivities (1/2) 600
600
CarbonMomentum Price Scenario Shifting
600
SM - High Demand
SM - Low Demand
baseline 500
400 300 200
400 300
200 100
100
600
SM - High Gas
100
400 300 200
600
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 600
SM - High Demand EFF
100
400 300 200 100
-
400 300 200 100
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
SM - No New Nuclear
500 Generation - TWh
200
200
-
500 Generation - TWh
Generation - TWh
500
300
300
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
SM - Low Gas
400
400
100
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
SM - Low Demand - Low CCS
500
100
600
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 600
SM - High Demand - Low CCS
Generation - TWh
200
200
-
500 Generation - TWh
Generation - TWh
500
300
300
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
400
400
100
-
600
500 Generation - TWh
Generation - TWh
Generation - TWh
500
32
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
Generation in Carbon Price Scenario: impact of sensitivities (2/2) 600
Carbon Momentum Price Scenario Shifting baseline
500
400
300 200
400 300 200 100
100
600
SM - Expensive CCS
100
400 300 200
600
200 100
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 600
SM - Low OffWind
400
300 200
400
300 200 100
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
SM - No New Nuclear
500
100
-
200
-
500 Generation - TWh
Generation - TWh
500
300
300
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
SM - High OffWind
400
400
100
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
SM - High Demand EFF No Nuclear
500
100
600
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 600
SM - High Demand EFF
Generation - TWh
200
200
-
500 Generation - TWh
Generation - TWh
500
300
300
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
400
400
100
-
-
SM - Low CCS
500 Generation - TWh
Generation - TWh
Generation - TWh
500
600
600
SM - High CCS
Generation - TWh
600
33
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
Generation in Technology Support Scenario: impact of sensitivities (1/2) 600
Technology Support Policy Momentum Scenario baseline
500
400 300 200
400 300
200 100
100
600
PM - High Gas
100
400 300 200
600
200 100
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 600
PM - High Demand EFF
400 300 200
400 300 200 100
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
PM - No New Nuclear
500
100
-
200
-
500 Generation - TWh
Generation - TWh
500
300
300
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
PM - Low Gas
400
400
100
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
PM - Low Demand
500
100
600
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 600
PM - High Demand
Generation - TWh
200
200
-
500 Generation - TWh
Generation - TWh
500
300
300
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
400
400
100
-
-
PM - Low OffWind
500 Generation - TWh
Generation - TWh
Generation - TWh
500
600
600
PM - High OffWind
Generation - TWh
600
34
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
Generation in Technology Support Scenario : impact of sensitivities (2/2) 600
600
PM - High CCS
500 Generation - TWh
Generation - TWh
500
400 300 200
400 300 200 100
100
-
-
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 600
600
PM - High Demand EFF
PM - High Demand EFF No Nuclear
500 Generation - TWh
500 Generation - TWh
PM - Low CCS
400 300 200 100
400 300 200 100
-
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
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Contents • Objectives and the methodology • Baseline analysis results • Sensitivity analysis results
• Annex – Assumptions and modelling
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Redpoint Investment Decision Model (IDM) •
The Redpoint IDM constructs detailed market outlooks in the GB power market covering the period of 20122030.
•
The IDM is based on an agent simulation engine that aims to mimic players’ decision-making with regards to their investment decisions in new plant as well as their decisions to retire existing plant.
•
The model contains a list of potential new-build projects according to their size, cost and earliest possible year of operation. Total investment in a particular technology is limited by the technology’s maximum annual and cumulative build constraints. If the constraint is binding, the projects with the highest expected returns are built.
•
Technology costs (capex and opex) can be varied over time and if required set endogenously within the model dependent on levels of deployment, which may affect rates of learning and position on the supply curves.
•
For each year, the levelised cost of energy (LCOE) of potential new-build projects are compared against their expected revenues (given assumed load factors, future price expectations, capacity payments and support levels) and where costs are less than expected revenues, projects are moved first to a planning stage, and subsequently, if still economic, to a committed development phase.
•
Additionally, retirement decisions for existing plant are also made on the basis of near term profitability expectations.
•
A 5-year forward-looking view for investing in a new plant is assumed and a 1-year forward-looking view for plant retirement decisions.
•
Where applicable, the model can include full representation of Contracts for Difference (CfDs) and a universal capacity mechanism. E3G - Third Generation Environmentalism
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Investment modelling – Non perfect foresight •
The model has a 5 year forward view of commodity prices and demand supply (1)
•
Rolling through each year, the model estimates power prices and dispatch for the forward view horizon. The resulting expected gross margin is compared to the expected levelised costs (2).
•
On that basis the model decides whether a project should enter the planning stage (3) and then rolls forward to the next year (4). During planning the project can still be cancelled. Once the planning period is over the model will decide whether to move to the construction phase at which point the project is committed.
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Generator decisions: new build and retirement •
•
Generator build decisions: For new plant the levelised non-fuel cost includes capital costs and annual fixed costs. The gross margin is calculated as the expected margin from power revenues, capacity payments and financial support less fuel and carbon costs and non-fuel variable costs. There are two trigger points which a project must pass to progress to construction. If a project is “in the money” it enters planning. If it continues to be in the money at the end of the planning period, the project is committed to the construction phase, and will become operational after a defined number of years. Generator retirement decisions: The logic for closure decisions of existing generators is analogous to that for new investments. The key difference, however, is that the capital already invested is ignored as this is considered to be a sunk cost. As a result, total annual fixed costs are compared against the expected gross margin and, when these are higher for a pre-defined number of years, the plant retires.
Capital and fixed O&M costs
Forward looking stack + prices
Compare
Expected levelised nonfuel costs
Expected transmission charges
Trigger 1
Expected gross margin
Anticipated low carbon support
Trigger 2
Planning Commit
Fixed O&M costs
Under Construction
Operational
Compare
Expected fixed costs
Expected gross margin
Expected transmission charges
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Anticipated capacity payments
Forward looking stack + prices Anticipated capacity payments
Trigger 1
Plan closure
Trigger 2
Close
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The model allowed policy intervention to correct deviation from the policy objective Carbon Price Scenario baseline
Under delivery
Over delivery
Technology Support Scenario baseline
Under delivery
Increased carbon price to €350 per tonne to deploy offshore wind • High electricity demand; No new nuclear; High electricity demand (low efficiency) • Low CCS; High/low electricity demand + low CCS
Reduced or maintained carbon price • Low electricity demand; High CCS
Increase renewable deployment rate • High electricity demand; high CCS; no new nuclear Subsidise CCS gas • Low offshore wind
Over delivery
Reduce offshore wind deployment rate • Low electricity demand
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Capital cost assumptions Capital costs (£/kW, real 2011) Nuclear 2011 2015 2020 2025 2030
2011 2015 2020 2025 2030
3582 3451 3287 3236 3184
Offshore Wind (Low) 2142 1933 1672 1602 1532
CCGT 703 692 678 653 629
Gas CCS 1335 1273 1196 1058 920
Offshore Wind Offshore Wind (Base) (High) 2535 2964 2288 2675 1979 2314 1896 2217 1813 2120
Coal & Lignite Onshore Wind CCS 2837 912 2700 912 2528 911 2219 903 1910 895
Biomass 2005 1943 1866 1850 1833
Solar PV 3316 2824 2209 1791 1372
• All capital costs except offshore wind are based on the Energy Roadmap 2050 • Offshore wind capital costs (Base/High/Low) are based on the study by ARUP for DECC • The costs evolve over time reflecting learning curves and economies of scale. In particular solar and CCS are not yet mature technologies and can therefore follow steep learning curves.
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Long run marginal cost of electricity assumptions in baseline scenarios 200 180 160 140 120 100
Carbon
80
Fuel
60
VOM
40
Fixed Capital
20
2012
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Nuclear CCGT CCGT CCS Coal CCS Lignite Lignite CCS Onshore Wind Offshore Wind
Nuclear CCGT CCGT CCS Coal CCS Lignite Lignite CCS Onshore Wind Offshore Wind
0
Nuclear CCGT CCGT CCS Coal CCS Lignite Lignite CCS Onshore Wind Offshore Wind
LRMC (â‚Ź/MWh - real 2011)
The chart on the right shows the evolving Long Run Marginal Cost (LRMC) of various technologies, split into their various components.
2030
42
Other cost assumptions Technology
Hurdle Rate
Variable Operating &
Fixed costs (% of
Maintenance (â‚Ź/MWh)
capital costs)
Gas
8.2%
1.40
3.0%
Coal
9.0%
2.50
3.0%
Lignite
9.0%
3.50
3.0%
Gas CCS
12.0%
3.50
3.0%
Coal CCS
12.0%
5.50
3.0%
Lignite CCS
12.0%
5.50
3.0%
Nuclear
11.5%
5.00
2.0%
Onshore Wind
9.0%
0.40
4.0%
Offshore Wind
11.0%
0.40
5.5%
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Baseline commodity prices
•
The Base commodity prices are based on the 450 scenario from the IEA World Energy Outlook 2011. Where applicable, the lignite fuel price is assumed to be 1.7 €/GJ (real 2011) throughout the modelling horizon.
130 120
110 100 curr/unit - real 2011
•
90 80 70
60 50 40 30 20
10 0 2011
2013
2015
ARA Coal ($/t)
2017
2019
Brent Oil ($/bbl)
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2021
2023
Gas ($/mmbtu)
2025
2027
2029
EUA Carbon (€/t)
44
Gas price shocks were introduced overnight with no foresight for beginning or ending of the event • Baseline gas price is based on the 450 scenario from the IEA World Energy Outlook 2011.
• Gas price shocks introduced overnight in early 2020s and lasts for 45 years
100
Gas price - p/therm (real
• High and low gas price shocks are 75% higher or lower than the baseline price.
120
80 Base
60
Low Shock High Shock
40 20 0 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029
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Electricity demand: baseline and sensitivity assumptions HIGH DEMAND
BASELINE DEMAND
LOW DEMAND
• Overall electricity demand is 483 TWh. This was due to a combination of failing to deliver electrical efficiency and higher demand from other sectors. • In this scenario, only half of the electrical efficiency assumed under the DECC UEP Central scenario is delivered. The difference between the DECC UEP Central scenario and Baseline Scenario was taken as the level of energy efficiency savings from climate change policies. • 54 TWh additional demand due to electrification in transport (30 TWh from Electric Vehicles) and heat (24 TWh from Heat Pumps) by 2030 is assumed, based on the higher end of the Committee on Climate Change 4 th carbon budget projections. • Overall electricity demand is 434 TWh. This is based on DECC UEP Central Scenario and 39 TWh additional demand due to electrification in heat (24 TWh from heat pumps) and transport (15 TWh from EV) is assumed, based on the lower end of CCC’s 4 th carbon budget projections.
• Overall electricity demand is 395 TWh. This is based on DECC UEP Central Scenario which includes delivery of electrical efficiency and no additional demand from other sectors.
Sources: DECC 2011 Updated Energy and Emissions Projections 2011 ; CCC 2010 4th Carbon Budget : Reducing emissions through the 2020s
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Investment decisions were taken with the expectation of base electricity demand, but were then subject to higher or lower electricity demand • Investment decisions were made with the expectation of a base demand
Annual electricity demand trajectories
• Every five years, investors readjusted their expectations in line with a base demand (red) trajectory (green and purple dotted lines); however, the demand remained higher or lower than their expectations (yellow and blue lines). For example:
500
Annual Electricity Demand - TWh
480 460 440 420
Low Base
400
High Base-Low
380
Base-High
– In 2019 expectations still follow the downward path (smaller green dashed line).
360 340
320 300 2010
– In the High Demand case, the expectation in 2015 follows the green dashed line, although outturn demand follows the yellow line.
2012
2014
2016
2018
2020
2022
2024
2026
2028
2030
– In 2020 expectations are reset but again follow the downward gradient (as illustrated by the green dashed lines).
• This 5 year cycle continues throughout the modelling horizon. E3G - Third Generation 47 Environmentalism
Technology deployment assumptions and maximum levels CCS
Nuclear
–
High Deployment: 50% higher than the baseline deployment (~30 GW by 2030)
–
Baseline: Around 21 GW of combined CCS capacity across both fuels (gas and coal). CCS initially gets deployed only in the Carbon Price Baseline scenario.
–
Low deployment: CCS technology fails a year into construction of the first commercial plant and there is no subsequent CCS deployment.
–
Baseline: We assume 12.8 GW of nuclear new build capacity by 2030 in both baseline scenario.
–
No new nuclear sensitivity assumes this new capacity does not get built
–
35, 41 and 52 GW maximum installed capacity in the Low/Base/High cases respectively based on ARUP study.
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The Low case (35 GW) refers to a maximum realisation of 60% of R3 offshore potential, the Base case to 80% and the High case to complete R3 realisation with some additional R4 projects.
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17 GW maximum installed capacity by 2030 based on ARUP’s Base scenario
Offshore wind
Onshore wind
E3G - Third Generation Environmentalism
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