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Onshore Wind Cost Reduction Taskforce Report

April 2015

Onshore Wind Cost Reduction Taskforce Report

Foreword ______________________________________________________________________________________________ 1Exectuve Summary ____________________________________________________________________________________ 2Table of Key Recommendations ________________________________________________________________________ 3 Introduction ___________________________________________________________________________________________ 5Where We areToday ___________________________________________________________________________________ 6Establishing the Baseline ________________________________________________________________________________ 7Interventions ___________________________________________________________________________________________ 9Part A: Maximising Energy Yield ________________________________________________________________________ 10Part B: Minimising Deployment Costs __________________________________________________________________ 15Part C: Industry Monitoring and Best Practice ___________________________________________________________ 21Conclusion ____________________________________________________________________________________________ 22Appendix 1: Report Methodology _______________________________________________________________________ 24Appendix 2: Contracts for Difference (CfD’s) _____________________________________________________________ 27Appendix 3: Grid Charging Regimes _____________________________________________________________________ 28Appendix 4: LCNF Projects _____________________________________________________________________________ 29References ____________________________________________________________________________________________ 30

Contents

1Onshore Wind Cost Reduction Taskforce Report

The UK’s current success has come about because we have built a vibrant UK industry, with strong local supply chains, high and stable levels of public support. We are also making a significant contribution to cutting UK climate emissions at a lower cost than other alternatives. Onshore wind is already cost competitive with new nuclear and remains ahead of solar.

Even better news is that onshore wind is now in sight of being cost-competitive with new gas, meaning that very soon onshore wind will be the low-cost choice, even without taking into account the additional benefits of carbon reduction, price stability and UK employment. That is a good position for the UK to be in, and it is within reach by 2020.2

To help ensure onshore wind’s shift to being the lowest-cost technology RenewableUK established a taskforce, which I was proud to chair, to review the current underlying costs of onshore wind, identify inefficiencies and policy barriers to cost reduction and probe areas where reductions in cost were thought to be possible. This follows on from the approach adopted in offshore wind in 2012 where an industry-led group was asked to identify and action measures to drive the cost of offshore wind down to £100 per MWh by 2020.

Current evidence shows that offshore wind is on track to hit that before 2020, proving that the wind energy industry can really deliver.

The UK’s Committee on Climate Change is clear that onshore wind is a cost-effective technology. Its analysis, conducted for its Fourth Carbon Budget, projects that onshore wind could deliver up to 25GW by 2030, which represents a significant contribution to decarbonising our economy. As this report shows, there are clear, simple steps which can be taken by our industry, working alongside Government, to provide that level of power at the lowest cost to the consumer.

The next Government could choose to work with our industry so that in the next five years, the cost of decarbonisation falls more quickly and UK consumers benefit. In doing this it would be following the example of many countries where onshore wind is proving it can compete when a level playing field is created in the market. Alternatively, Government could choose to hold back onshore wind, continuing to impose unnecessary costs and failing to take the opportunity that is being offered.

The first CfD auction has shown that onshore wind has ongoing potential

to reduce costs. The UK onshore wind sector is confident about its technology, and about its future. But having confidence that Government supports a low-carbon technology like onshore wind is critical.

Developers need to operate in a stable business environment. Without this, innovation will not take place and efficiencies and competition will be frustrated. Industry will continue its drive to bring down costs; we are looking to Government to help us deliver the next stage of the taskforce’s work, and implement its important recommendations.

Colin MorganRegional Manager, W Europe and Latin America, DNV GLChair of the Cost Reduction Taskforce

Foreword

Onshore wind is a UK success story. Its success has come despite the fact that in the 1980s the UK let its early advantage in onshore wind slip away. As a result, Danish and German companies reaped huge economic advantages from the global shift to wind energy.


Delivering on this target will mean competing with new Combined Cycle Gas Turbine (CCGT) generation on price. The best marker for comparison is the established and well understood levelised cost of energy (LCOE) benchmark. New CCGT is expected to set the target LCOE for onshore wind by 2020, with a predicted LCOE of £65–75/MWh in 20202. This report looks at costs across three different types of site, corresponding to different wind profiles: Type 1 (high wind speed, large site), Type 2 (medium wind speed, medium site), and Type 3 (lower wind speed, small site). The taskforce agreed a number of high-level aims to achieve the target:

(a) Industry will make use of the most up-to-date, innovative and efficient technology to ensure that sites being developed are as advanced and efficient as possible

(b) Industry will drive down the cost of connecting to the grid through value-engineering and exploiting cutting-edge technological innovation

(c) Industry will seek to streamline planning timescales and increase approval rates through engagement with Government on the consumer benefits of an effective planning system

(d) Industry will monitor progress against these aims and ensure that best practice becomes standard practice

Achieving these aims will require a shift in both Government policies and industry norms. The taskforce’s recommendations seek to unlock the potential for cost reduction through industry partnership with local and national Government, regulatory authorities and communities around wind farms.

Executive Summary

Onshore wind is the UK’s lowest-cost large-scale renewable generation technology. Costs have more than halved in real terms since the first commercial turbines were erected in the early 1990s1, and are expected to continue to fall. The industry is committed to taking active steps to cut the cost of wind energy to ensure onshore wind is the lowest-cost new generation technology in the UK by 2020.


Monitoring progress and sharing best practice

1 Establish an industry forum to enable the onshore wind sector to monitor and coordinate joint action on cost reduction. This forum will lead on coordination between industry, Government and regulators, and encourage uptake of good practice in development and operation via an accelerator programme.

2 RenewableUK to explore with leading research institutions how best to facilitate increased industry-academic cooperation and knowledge transfer.

3 Establish within the wind industry a framework to monitor the UK content of onshore wind projects with a view to finding cost-effective opportunities to increase this. Increasing UK content will remove some of the exchange rate risk currently factored into development cost, while also helping to demonstrate wider economic benefits stemming from onshore wind.

Technology

4 Encourage rapid adoption of new technology and good practice on site optimisation via an accelerator programme of developer days and events to share good practice on innovation and lessons learnt within the onshore sector.

5 Industry to explore with Government the potential for developing further planning guidance on the characteristics of wind energy projects.

6 Planning conditions to be justified not only based on mitigating adverse impacts but with due and explicit consideration of the impact on the national clean energy targets and cost to the electricity consumer.

7 Developers to provide better information to allow planners and communities to judge the relative merits of alternative proposals on the same site.

Grid

8 RenewableUK (and partners) to scope out and implement a training programme on the use of ICPs/self-build of transmission assets.

9 Ofgem should reopen consideration of, and fully assess, the case for opening up connections at transmission level.

10 Government should introduce powers to consent grid connections alongside permission for generating stations to all relevant consenting regimes across GB.

11 Ofgem to develop a national strategy and milestones for deployment and mainstreaming of innovation beyond sporadic Low Carbon Network Fund projects.

Planning

12 Action: RenewableUK in partnership with Government, to review the consenting framework for onshore wind and its implementation, with a view to exploring:

I. The current relationship between policy and decision-making, including timescales for determination;II. Potential opportunities to address any gaps in policy read-across into decision-making;III. Potential for the local plan process to include the mapping of existing and future energy demand and

sources of energy supply; andIV. The scope for a more strategic view of planning for onshore wind – possibly as part of a review of

planning for climate change mitigation and adaptation as a whole.

Table of Key Recommendations


The impact of each of the interventions for the different site types (Type 1 – high wind speed, large site; Type 2 – medium wind speed, medium site; Type 3 – lower wind speed, small site) are shown in the above figure.

The results show that if the relevant measures are implemented, the lowest cost wind farms in 2020 will generate at a lower cost than the lowest cost new CCGT, and even the higher-cost wind farms will generate at a lower cost than the marginal CCGT.

The results also imply that support paid to wind farms under the Contract for Difference (CfD) scheme in the best-case cost reduction scenario would be nearly half that if no specific actions were taken to reduce costs3. Consequently, if 1,000MW of capacity was built in 2020 that achieved the maximum savings, it would need £46 million less each year to support it, saving the consumer nearly £700 million over the 15-year span of the CfD. If cost reductions are rolled out to capacity built earlier than 2020 and continue to be implemented in capacity built later, the total consumer benefit will run to billions of pounds.

Some of the identified cost reductions require the buy-in and support of Government and the regulator to be delivered. For example, developers cannot optimise site layouts to maximise turbine performance if planning rules restrict choice of turbines or constrain the ability of a developer to make changes in a proposal prior to site construction. On the other hand, many of the interventions require small changes to existing practice and are low-impact from the point of view of wind farm neighbours.

However, it is important to note that cost reduction on the scale set out above will require continued deployment out to 2020 and throughout the next decade. The successful implementation of these measures will also require a continuation of the generally favourable environment for investment in onshore wind. In particular, a long-term, stable regulatory framework and visibility of target capacity, strategic investment in network infrastructure, and continued efforts to manage the balance between energy and aviation interests will be of central importance.

Figure 1. Opportunities for cost reduction shown against estimated CCGT LCOE in 2020 (£/MWh)

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5Onshore Wind Cost Reduction Taskforce Report 5

To deliver on this commitment, RenewableUK established a taskforce to establish a clear pathway of cost reduction.

The taskforce worked internally and with the wider industry to undertake a review of the current underlying costs of onshore wind and identify opportunities to reduce these costs. As part of this process, RenewableUK also commissioned consultants Mott MacDonald and DNV GL to provide technical input to some aspects of this work programme.

The taskforce reviewed current cost reduction trajectories, and established what additional actions would be required to bring costs below those of new entrant gas plant by 20205. The interventions identified do not require ground-breaking shifts in current practice or policy. With sufficient focus and prioritisation, all are achievable within the timeframes discussed, and many simply involve the removal of barriers to ensure the UK’s excellent wind resource is maximised, with little or no impact on communities around wind farms, and to the significant benefit of all consumers.

Our onshore taskforce reviewed current costs across a range of sites typical of the UK project pipeline to develop a cost baseline for onshore

wind. Site characteristics were clustered for ease of analysis, and three categories of project were defined to broadly reflect the UK operational fleet and development pipeline for onshore wind. The baseline considered key site-specific cost drivers, including turbine class, construction costs and use of system and other charges. These baseline costs were compared and reconciled with figures coming out of the first allocation of Contracts for Difference (CfDs)6 to derive cost forecasts for projects coming online in 20207.

This report sets out the findings of the taskforce. First it reviews the current position of wind, before going on to establish a levelised cost of energy baseline against which cost reductions can be measured. The report then runs through actions which can be taken by industry and Government to deliver cost savings. These actions are grouped under the themes of maximising energy yield, minimising deployment costs, and industry monitoring and best practice. While Government has an overarching role in supporting cost reduction through maintenance of a stable and supportive policy environment, there are also practical policy steps which it can take in planning, grid policy and guidance. Some of these recommendations relate to the UK

Government and Northern Irish Executive which have responsibility for Great Britain’s and Northern Ireland’s energy policy respectively, including energy regulation. Some of these recommendations relate to all four administrations – the UK Government, Scottish Government, Welsh Government and Northern Irish Executive – and their relevant planning policies covering England, Scotland, Wales, and Northern Ireland.

The work of the taskforce has demonstrated that industry can and must work together to deliver cost reductions. But as has been demonstrated in sectors like offshore wind, this is best done alongside Government. Competitive processes do work to drive down costs, but so too does sharing good practice and encouraging rapid adoption of new innovation. RenewableUK, on behalf of industry, will work with the four Governments of the UK in taking forward the recommendations set out here and delivering important and valuable cost reductions by 2020.

Introduction

Onshore wind is already cost competitive with nuclear and other forms of low carbon generation. The industry is committed to taking active efforts to cut the cost of onshore wind energy, pledging to drive down cost and be the lowest-cost new build generation technology in 20204.


The sector is on target to deliver on, or exceed, the 13GW of capacity set out in the Government’s 2013 Roadmap update and, given the development pipeline, could easily deliver the Committee on Climate Change’s forecast capacity of 25GW9 by 2030, given the right conditions.

These impressive levels of generation capacity are matched by equally impressive financial benefits to the UK economy, with £1.6 billion of investment – £729 million of which was spent in the UK – delivered from projects that were commissioned in 2013/14 alone. In addition, these same onshore wind farms will deliver £2.55 million of annual community benefits to local people, and have already contributed almost £6 million to local councils through their business rate payments – equivalent to a lifetime value of £149 million10.

The onshore wind industry continues to work increasingly closely with Government, community organisations and cross-sector groups to enhance the quality of community engagement and involvement in the development and delivery of wind energy projects. While community benefit provision has long been common practice, in the last few years the industry has significantly increased the value of

community benefits committed in line with voluntary best practice11. It is useful to compare the level of community benefit committed by onshore wind to the commitments of other energy sources.

• The taskforce is unaware of a comparable system of community benefits provided by CCGT operators.

• New nuclear sites have guaranteed a community benefit package of £1,000/MW per year, though this is realised through locally retained business rates (a scheme already in place for renewable energy projects in England), so is not directly comparable.

• Shale gas sites, though not generating stations, will be expected to pay £100,000 plus 1% of revenue. For comparison, wind farms paying £5,000/MW equates to around 2.5% of revenue12.

The industry recognises the value of community benefits contributions, and will continue to support communities through this mechanism.

The industry is committed to delivering cost reduction over the course of this decade with a view to becoming the lowest-cost form of new generation – across all technologies – by 2020. In order

to meet this objective it will be necessary to make a number of changes to the way the industry operates, both internally and in terms of how external policy and regulatory regimes support onshore wind deployment.

Where We are Today

The onshore wind industry has developed steadily over the last decade and now stands at over 8GW of installed capacity across the UK. The industry is currently deploying at a significant rate, having built an additional 1.1GW of onshore capacity in 2013/148 and expecting to deliver around a further 1GW of capacity in 2014/15.

7Onshore Wind Cost Reduction Taskforce Report 7

Establishing the Baseline

It is necessary to understand the current cost of energy from onshore wind in order to establish an appropriate cost reduction target. The metric for comparing like-for-like costs of different forms of energy generation is the ‘levelised cost of energy’ (LCOE). Levelised cost analysis considers all cost inputs required to consent, build, operate and decommission a generation facility, and the projected lifetime energy output of the facility, in order to show the effective cost of each unit generated13.

The aim of the taskforce is to determine if and how onshore wind could generate a lower LCOE than new-entry CCGT in 202014. The methodology was as follows (see also flowchart below):

1. Establish the types of sites likely to be brought forward in this period;

2. Establish the cost of these projects in 2014 as a baseline;

3. Forecast likely costs in 2020 across these site types in a ‘business-as-usual’ scenario for 2020;

4. Compare these with forecasts for the cost of new entry CCGT in 2020.

This section summarises our methodology and assumptions; a more detailed discussion can be found in Appendix 1.

Overview: the taskforce undertook an iterative process to derive reasonable forecasts for the cost of wind farms commissioning in 2020, and then compared this to estimates for the cost of CCGT commissioning in the same year. The high-level process is illustrated in the following flowchart:

Generic 2014

cost dataType 1

Type1 2014 LCOE

Type1 2020 LCOE

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DNV GL analysis of UK pipelines

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forecasts

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CfD auction results

CCGT 2020 LCOECOMPARE


DNV GL analysis of current pipeline: site-specific factors will be key drivers in the cost of individual projects. To capture this variability, DNV GL analysis of the UK pipeline of projects informed an assessment of the typical site types expected to come forward in 2020. Sites in the UK fall into three types, which correspond to different wind turbine classes: Class I (type 1); Class II (type 2); and Class III (type 3)15.

Generic cost data: RenewableUK data and input from the taskforce informed a baseline view of the underlying costs associated with each of these types of project in 2014. This input allowed the taskforce to capture relative differences in construction, turbine and other costs across the different site types.

Mott MacDonald cost model: a project cost model was developed by Mott MacDonald and validated by the taskforce. The generic cost data was fed into this model to generate baseline LCOE for projects commissioned in 2014. The model was also designed to allow for sensitivity testing of the cost parameters, for example, to show the LCOE impact of reducing grid connection costs by a certain percentage.

2020 wind LCOE forecasts: results from the CfD allocation were compared and reconciled with the 2014 baseline to derive LCOE forecasts for projects commissioning in 202016, which constitute a ‘business-as-usual’ cost reduction scenario, i.e. the cost reduction that would be achieved without specific actions beyond those already being undertaken.

2020 CCGT LCOE forecast: CCGT is expected to be the lowest-cost new-build technology in 202017. The taskforce reviewed a number of industry expert forecasts as to the likely cost of new-build CCGT in 2020. All agreed that there were significant uncertainties, driven primarily by uncertainty in the price of gas. As with wind, the underlying costs of different CCGTs (including the price paid for gas) will vary across different plants and operators, so the survey was used to produce a range of £65–75/MWh18, which was agreed as the target for wind in 2020.

Comparing the relative costs: as the above graphic shows in Figure 2, the modelling results indicate that the business-as-usual scenario will not be sufficient to drive the cost of wind below the cost of CCGT in 2020. The taskforce then worked to identify what changes, additional actions and reforms would be necessary to bring costs down to the required level.

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Figure 2. Forecast LCOE in 2020 in a business-as-usual scenario against target CCGT LCOE range (£/MWh)


Part A:

Maximising Energy Yield – considers opportunities to enhance revenues, primarily through use of technology and site optimisation to ensure increases in energy yield (or Annual Energy Production – AEP), which effectively reduce the cost of each unit of electricity generated;

Part B:

Minimising Deployment Cost – considers measures to reduce costs for key areas of capital and development expenditure.

Part C:

Industry Monitoring and Best Practice – considers how industry can coordinate efforts to accelerate adoption of best practice and monitor cost reduction.

Interventions

The previous analysis demonstrates that in the business-as-usual scenario, onshore wind will be unlikely to be the lowest-cost new-build technology in 2020. As such, distinct actions are required to accelerate cost reduction if that aim is to be achieved. The remainder of this report examines a number of possible interventions that could help unlock the potential for further cost reduction. The interventions are considered from three perspectives:


Technology and Site Optimisation

For any given site there is an optimal layout and choice of turbine to maximise yield, and therefore revenues. LCOEs are highly sensitive to revenues, so optimisation of sites is considered to be a key driver in maintaining downward momentum on the cost of energy.

The issues: There are a number of different factors that determine the wind resource available at a site.• Wind speed: In general, higher

average wind speed sites will generate more energy than those sites with lower average wind speeds. Yield is highly sensitive to long-term average wind speed, which in turn varies significantly due to topography, ground cover and height above ground (see below).

• Turbulence: turbulent air flow consists of relatively chaotic local variation in wind flows. Turbulence creates aerodynamic inefficiencies that affect the amount of energy that can be harnessed. In general, lower turbulence means more of the available energy resource in the wind can be converted into electrical energy.

• Shear: this is the common term for the variation in long-term wind speed with height above local ground level. High wind shear is typical in sites with dense ground cover and level terrain. It adversely impacts the aerodynamic efficiency of wind turbine rotors, though it is also responsible for the strong link between wind turbine hub height and annual energy production.

• Rotor diameter: energy capture is extremely sensitive to rotor diameter. In general, a larger rotor will allow more energy to be captured and thus more electricity to be generated.

Site-optimised turbines: In theory19, optimum site conditions for wind energy would involve consistent and high wind speeds, with low turbulence and low shear. Higher altitudes tend to exhibit these features to a greater extent than those on lower ground, and in addition a larger rotor (for the same site conditions) will maximise the potential energy that can be captured, thus increasing yield. While a number of robust landscape protection measures limit the development opportunities on many hill tops and mountain peaks, there can be significant yield increases from installing turbines with higher hub heights and/or larger rotor diameters. Specifically, comparable levels of output could be reached with fewer turbines installed. The extra capital costs associated with installing site-optimal turbines are more than outweighed by the extra energy yield. In the UK, the feedback received from taskforce members, and supported by RenewableUK’s data on our UK wind energy database (UKWED), suggests that many projects are subject to

Part A: Maximising Energy Yield

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Figure 3. Current pipeline of UK onshore wind projects by tip height (m)20


informal tip height restrictions, often of 125m. This in turn has limited hub heights and/or rotor diameters. This view is supported by the pipeline data, as shown above.

The picture in comparable markets is very different, where permitted tip heights and rotor diameters continue to keep pace with technological developments. In Sweden, approximately half of all applications in planning are for tip heights in the range 171–200m,22 and rotor diameters of 100–105m are common.

Similarly, in Germany, the average tip height for all projects under construction is around 165m,23 and the average rotor diameter is 99m. Finland and Norway issue ‘box permits’ which allow developers to optimise their sites to best suit site conditions – including unrestricted tip heights and rotor diameters24. In contrast, the majority of applications within the UK are for tip heights of 110–125m, and rotor diameters of 100m and above are relatively rare.

The most notable barriers to technology optimisation lie in the implementation of turbine height restrictions (or in some cases restrictions on rotor diameters). These restrictions are often introduced at an early stage in the planning process through a ‘normative’ limit that appears to have coalesced at a tip height of around 125m as shown in Figure 3, and which is then often enforced at the point of consent through the use of planning conditions which place explicit limits on the size of the turbines that can be installed on a given site. In some cases such conditions can go so far as to prescribe matters such as rotor diameter (see Figure 4), or place limitations on other characteristics, such as the installed capacity of the wind farm. Such limits on turbine height mean that the UK is being left behind in international markets, as turbines around 125m high:

• Are scarcer in number as larger machines replace them in manufacturers’ model ranges;

• Do not benefit fully from

volume benefits of large-scale manufacture; and

• Do not benefit from the latest innovations.

Optimised site design: As well as the wind profile of sites, energy yield can be significantly impacted by siting of individual turbines in relation to each other and the topography of the site. Turbines towards the ‘front’ of an array25 create a wake effect which can impact the potential energy yield for turbines behind them if not suitably positioned. Likewise, better wind conditions tend to be experienced at higher elevations than lower ones. For a given site, there is an optimal layout for the turbines, and the science of determining this layout is highly advanced (see the next section for a discussion of this). As with restrictions on the ability of the industry to select optimal turbines, however, the taskforce found that developers were struggling to realise the full generation potential of sites, primarily because of concerns regarding the effects of more optimal schemes on other planning matters, including landscape characteristics and visual amenity, which can lead to requests for potential turbine numbers to be reduced. Equally common are requests to site turbines in a way that makes suboptimal use of the available resource, including moving to lower elevations or repositioning turbines in a way that will increase wake effects and therefore reduce generation output from the scheme.

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Figure 4. Current pipeline of UK onshore wind projects by rotor diameter (m)21


Technical innovation: though onshore wind is a mature technology, ongoing research and innovation will continue to improve efficiency and reduce costs. Taskforce discussions with turbine manufacturers have highlighted a wide range of efforts and investment in turbine innovation. For their part, developers are open to adoption of new technology to help siting and operation, and to manage costs.

A number of innovations that will contribute to driving down the LCOE of onshore wind are identified in a 2014 report by BVG Associates for KIC InnoEnergy26. In particular, 21 discrete innovations are identified that are likely to have a positive yield impact, including improvements in blade aerodynamics, pitch control, drive train reliability, resource characterisation (modelling and measurement), and introduction of novel towers and active aero control on blades27. Key innovations include:

• Resource assessment: as mentioned above, understanding of wind resource and how best to exploit it is a highly advanced discipline, albeit one that could improve with more research and operational history. BVG Associates identifies further potential improvements in resource modelling and measurement, as well as enhanced understanding of complex terrains and forested sites through use of 3D LiDAR28 and advanced modelling techniques to help increase energy yield through better siting, especially in more complex terrain;

• BVG Associates identifies improvements to gearbox design, either through optimised design of current high-speed designs or a move to medium-speed designs, with higher reliability and therefore greater yield. Direct drive machines, which have no

gearbox, are shown to have similar net benefits. The testing of these components is also highlighted as an area in which to improve component availability and lower operational costs;

• Innovations in blade design, assembly and aerodynamic control are expected to reduce costs and increase yields through enhanced aerodynamic efficiency; and

• Best practice in operations and maintenance (O&M) can also drive down operational costs as well as reducing down-time. BVG Associates identifies a number of areas in this space, including better weather forecasting for service schedules, asset management and blade inspection strategies, and wind farm-wide control strategies.

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Figure 5. Potential cost reduction available from use of optimal tip height/rotor diameter combinations (savings against forecast shown in blue) (£/MWh)

…though onshore wind is a mature technology, ongoing research and innovation will continue to improve efficiency and reduce costs.


The impact: The results of the analysis undertaken by DNV GL were used to derive costs and yield impacts of optimal turbine choices, modelling the impact of installing 150m to tip in place of an assumed tip height of 125m. A clear benefit was evident across all site types. The figures illustrate the benefit that could be achieved from more flexibility in turbine choice, including an optimal hub height/rotor diameter combination of up to 150m tip height29.

The taskforce’s research also found that site optimisation could increase yields by approximately 5%, which was independently verified by turbine manufacturers. Site optimisation could thus allow a LCOE reduction of £3–4/MWh. The following figure considers a best-case scenario: it should be noted that not all of this benefit would be realised for all sites.

BVG provided estimates of the LCOE value of the innovations identified in their study, for projects commissioning in 2020. While there is an expectation that commercial drivers will result in such innovations increasingly becoming business-as-usual, in the short term and without specific actions by industry, it may not be possible for all or even a majority of projects to benefit.

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Figure 7. Potential cost reduction available through innovation (savings against forecast shown in light green) (£/MWh)

Figure 6. Potential cost reduction available from optimal site design (savings against forecast shown in green) (£/MWh)


Interventions

Restrictions on maximum tip heights and on the siting of turbines within a development site will reduce the efficiency of the scheme and increase the cost of energy for the consumer by increasing the LCOE. There are other approaches that can be taken to ensure that new developments respond sensitively to their local surroundings, while also making the most of the generation potential of appropriate sites.

Other development control regimes, such as that in Finland, consent schemes within a broad ‘envelope’, setting relevant limits at the boundaries of the envelope and allowing developers to choose turbines and layouts that maximise the available resource. While this particular model may not necessarily be appropriate for the UK, a move to a more flexible approach in planning conditions and site layout will be necessary to maximise the clean generation and cost-saving benefits to the consumer. Making the best use of a site, and therefore driving down LCOE, should be a key consideration in planning.

In parallel, decision-makers and local authority planners should be given more information to help them assess the value of the turbine siting and sizing choices made. In parallel, this greater flexibility for developers will need to be complemented with a close and ongoing engagement with communities and other stakeholders around the site at all stages of the project lifecycle – from site layout and turbine selection, through to the construction and ongoing operation of the project.

Discussions across industry highlight that while there are examples of best practice and emerging techniques within the industry, more needs to

be done to ensure that this best practice is adopted across industry as a whole. While the sector is competitive, it is in its interests to encourage adoption of best practice and the dissemination of innovation and lessons learnt. RenewableUK will establish an accelerator forum to encourage shared learning and rapid adoption of innovation and good practice. Such a programme will enable industry to discuss and share experiences on a range of development, construction and operational issues, but in the first instance will address bringing manufacturers and developers together to look at adoption of new technology.

As the industry matures, more emphasis is placed on managing and optimising operating schemes and improving scheme reliability and performance. An example of how industry is seeking to improve is in the area of blade inspection and repair. The Renewables Training Network (RTN), a part of RenewableUK, worked throughout 2014 to coordinate industry effort to introduce a training standard to cover blade inspection and repair. Industry now has an agreed training standard, and in 2015 we will be developing materials for intermediate and advanced skill levels. Better maintained blades will mean better performing turbines and reduced costs. The RTN will continue its efforts to support industry in development of effective training and programmes which support use of good practice.

Action:

Encourage rapid adoption of new technology and good practice on site optimisation via an accelerator programme of developer days and events to share good practice on innovation and lessons learnt within the onshore sector.

Action:

Industry to explore with Government the potential for developing further planning guidance on the characteristics of wind energy projects, including the relationship between turbine size and generation capacity, and the potential to move to a more flexible approach to planning conditions and/or project sizes.

Action:

Developers to provide better information to allow planners and communities to judge the relative merits of alternative proposals on the same site. Industry to work with Government to produce guidance on what form this should take, and how decision-makers should approach these assessments.


This section deals with areas of project spend identified as carrying some level of unnecessary or avoidable expenditure. Some of these are linked to planning policy and practice, and others to achieving greater cost efficiency through embracing new opportunities in grid connection, which is one of the largest capital costs after the turbine itself30.

Grid Costs

Overview

The transmission network was originally designed to connect large coal power stations, often sited near their fuel sources, or nuclear reactors in coastal areas, to demand centres. The distribution network was historically a passive system designed to distribute electricity from the transmission network into homes and businesses. The growth of renewable generation, including onshore wind, has caused a rethink of both these systems.

• First, as wind resource tends to be highest in areas not traditionally exploited for other forms of large-scale energy generation and away from demand centres, larger wind farms will often require new and fairly lengthy grid connections to be able to connect to the transmission network.

• Second, the cumulative effect of this shift is also to require incremental upgrades to the wider system itself, most noticeably in Northern Scotland and to improve connections between Scotland and England.

• Third, commercially viable smaller-scale wind farms will connect straight to the distribution network. As well as requiring dedicated connection assets, this embedded generation poses new challenges

for a network which was not designed to handle large volumes of generation.

As a consequence, individual wind farms can trigger the need for significant and costly reinforcement works. Developers are liable for some portion of the associated costs, which can be a significant factor in the viability of individual wind farm projects31. Grid connections are highly sensitive to the specific circumstances of the project and the section of network it is connected into. The taskforce therefore suggested a number of innovations, as well as changes to policy and practice, which projects could benefit from, with the caveat that any benefits accrued will vary widely from case to case.

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Part B: Minimising Deployment Costs

Figure 8. Potential cost reduction available from combined grid interventions (savings against forecast shown in orange) (£/MWh)


The impact

The taskforce modelled the impact of three different policy shifts that can help reduce the cost of connections. These are: use of independent connection providers; use of overhead lines; and use of innovative connections. Each is discussed in more detail below.

Figure 9 shows the potential cost reductions for the three turbine types through grid interventions. As can be seen Type 3 sites have the most to gain through changes to provision of grid infrastructure. However, not all actions are relevant to all site types. Some grid interventions may be mutually exclusive or already assumed to be included (for example, the innovative connections may already assume an overhead line connection). Others are potentially complementary, for example the use of overhead lines together with the use of an ICP. Because of this Figure 8 models expected cost savings which could be delivered by industry as a whole, rather on an individual site basis. This shows that through either one grid

intervention, or combination of these, the UK onshore sector will be able to secure grid cost reductions of £1, £4 and £5 per MWh for Types 1, 2 and 3 respectively.

This research suggests that in certain circumstances, use of independent connection providers (ICPs) for “contestable works” (a subset of all the relevant connection assets, effectively from the wind farm up to the existing network), rather than the incumbent distribution network operators (DNOs), can deliver savings in the range of 15–25% on the cost of a connection32 (in other cases, the DNO offer may be the cheapest, so these savings should be seen as indicative). No equivalent policy is yet in place for transmission connected sites, though there is an option to self-build some assets33. Our feedback suggested that this was not widely used, but that savings in the order of 25% could be achieved for connection/construction where this option was taken up. The cost and viability of a developer delivering operations and maintenance of those connections assets is not determined here.

Undergrounding of connection circuits is generally significantly more expensive than use of overhead lines. Nonetheless, consenting overhead lines as a separate development to the wind farm – as required by most planning regimes in the UK – represents an extra risk to developers, both in terms of timescales and the risk that the overhead lines may themselves be refused. Underground cables usually constitute permitted development, so do not require planning permission, and are therefore the preferred solution in many cases. The taskforce has applied industry data to the possible savings for the distribution connection sites (and has assumed that the larger transmission connected sites in type 1 are already connected by overhead lines).

Unless otherwise specified and agreed, a standard grid connection offer is designed on the basis of fully secure, firm and unrestricted access capacity against a fixed (or static) set of infrastructure parameters. This can trigger the need for expensive reinforcements, the costs of which are currently borne by individual users34. Under the Low Carbon Network Fund (LCNF), DNOs are trialling smarter, dynamic technologies that make better use of existing assets and avoid or defer the need to pay for costly reinforcements. Such connections typically take the form of dynamic monitoring or operation of the network to allow generation capacity to exceed static thresholds (such as thermal limits, which vary with environmental conditions), together with uncompensated curtailment on those occasions where relevant limits would be breached. The availability of such innovative connections and the appropriate connection type will vary significantly depending on where on the network a project wishes to connect. As a result, data on LCNF

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Figure 9. Potential cost reduction available from individual grid interventions (£/MWh)


projects to date was taken from a case study produced by UKPN to demonstrate the potential impact of using innovative connections on the overall LCOE. Note that the use of innovative connections, as shown in Figure 9, only applies to distribution-connected sites at around 10MW, so the impacts have only been modelled on site type 3. Non-firm and other non-standard connections are common at transmission level, so the benefit of these is already assumed to be included in the forecast.

Interventions

Independent Connection Providers: Since 2012, there has been scope for tendering for delivery of connection assets deemed ‘contestable works’. The principle is to drive costs down through opening up competition with the DNO for delivery of these assets. Taskforce members reported that genuine savings were achievable, but there has been a reluctance to take this route for a number of reasons:

• Simplicity and associated (perceived) lower risk in contracting directly with the DNO;

• Lack of clarity on ICP rights to statutory land access and acquisition powers; and

• Lack of competent and experienced ICPs in the market.

Nonetheless, feedback from developers who had successfully undertaken independent connections suggested that none of these issues are insurmountable,36 and that while the ICP regime represents a departure from normal business processes, it is fit for purpose in its current form. It was therefore suggested that the main barrier to wider use of ICPs was a perception that the risks outweighed the benefits of lower connection costs. Similarly, research conducted by Ofgem into

the ICP regime concluded that “previous experience of using an ICP… can be the greatest driver of future use”37. With the additional pressure of competitive allocation of support under the CfD regime, developers will increasingly consider the savings available by going independent as a means of making their projects more cost-competitive. Industry participants may therefore benefit from bespoke training in how better to manage the increased complexity of ICPs and other lessons learnt. Similar points were made with respect to self-build of transmission assets. DNOs also reported that despite there being rigorous standards governing the technical specification of such assets, the administration of these standards was insufficiently robust to ensure that all connections were of an appropriate standard at the point at which they are passed on to the DNO. As the wider rollout of independent connections will be dependent on the success of previous projects, it is important that assets are delivered to the highest standards in order to breed confidence in the industry.

Contestability is currently only a feature for distribution connections38. Under its Integrated Transmission Planning and Regulation (ITPR) workstream, Ofgem is introducing competition for a new type of asset39, which is somewhere between a connection asset and an integrated part of the main transmission network. The case for introducing competition at the level of connections seems not to have been considered in detail, in spite of its potential benefits in terms of cost reduction.

Undergrounding: our feedback suggested that the majority of distribution connected projects will have underground connection assets as standard, while undergrounding

of transmission assets will vary largely depending on connection configuration, voltage, location, and project profitability. The primary reason cited for undergrounding was the extra risk associated with consenting overhead lines, which may in themselves be fairly insignificant developments (wires on short wooden poles, in the case of lower-voltage connections), with landscape and visual impacts driving part of the extra risk. Such consents would be sought by the DNO with no guarantee that the relevant timescales would match the developer’s requirements.


Innovative connections: The LCNF process is considered to be a good way of trialling new technologies to enable smarter, cheaper and quicker connections. Initial results from a number of trials show great promise in redefining the possibilities for connecting in the UK. While the technical progress is impressive, the ultimate aim is to see such technologies rolled out beyond trial phases into business-as-usual. In addition, even with smarter connections, physical upgrades to the network will eventually be needed. These upgrades and how costs are apportioned should be planned in a coherent manner and in line with a sound investment policy, such that uncompensated curtailment is not a persistent feature of embedded generation40. The regulatory mechanism for approving DNO investment, specifically the price controls under ‘RIIO ED1’41, must sufficiently incentivise the DNOs to offer such connections where appropriate. There is as yet insufficient experience of the new price control regime to see whether innovative connections of the kind discussed here are deliverable under this mechanism, so it is important that the regulator, with industry input, monitors the situation.

Action:

RenewableUK (and partners) to scope out and implement a training programme on the use of ICPs/self-build of transmission assets.

Action:

Ofgem should resume consideration of, and fully assess, the case for opening up connections at transmission level, noting issues experienced at distribution level and mitigating these as appropriate.

Action:

There exists provision in the Planning Act 2008 (in England) for projects to simultaneously apply for a grid connection alongside the generating station it would connect to. Government should roll out similar powers to other consenting regimes across the UK and for all scales of development.

Action:

Ofgem to develop a national strategy and milestones for deployment and mainstreaming of innovation beyond sporadic LCNF projects, including any regulatory amendments required to unlock these.


Planning

Overview

Broadly, the UK has maintained a consistently supportive policy towards the continued deployment of onshore wind. The Climate Change Act set legally binding emissions reductions targets, with the EU Renewables Directive further strengthening the case for investment to 2020. The Government’s Renewables Roadmap, adopted in 2011 and updated in 2013, suggested that 13GW of onshore wind would be brought forward to meet the renewables target, a figure considered conservative by industry, but still implying a fairly healthy annual growth rate of 13%42 over this period. However, planning permission is a necessary step to achieving these goals, and there has been a clear and consistent drop in planning approval rates over time.

Impact

The cost of failed projects directly translates into an increase in the investment returns that successful projects are required to deliver. The increasing risk associated with planning success rates in the UK has also driven a higher Cost of Capital than in comparable markets. While the modelling assumes a scenario where no projects are refused, it does illustrate the financial benefits of greater planning certainty. In reality, we would not expect to eliminate refusals from the planning system altogether, but rather improve read-across from planning policy into planning decisions, which would provide greater planning certainty for developers, and ultimately be reflected in higher approval rates for those projects that are taken forward to determination.

In fact this modelling is likely to underestimate the real cost of a highly challenging planning process. The reality of developing onshore wind farms is that for every successfully consented project, the developer has considered perhaps 100 sites, significantly appraised perhaps 10 sites, and pursued up to 5 through the full planning process, all over a period in excess of five years, while spending hundreds of thousands of pounds at risk.

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Figure 10: UK annual planning approval rates by project (%)43

Figure 11: Potential cost reduction available from lower refusal rates in planning (savings against forecast shown in yellow) (£/MWh)


Interventions

A core principle of a well-functioning planning system is clarity of policy, with a corresponding level of certainty in decision-making, so that project developers are able to satisfy themselves that, subject to clear, specific and evidence-based policy criteria being met, their project will be approved. In particular, this requires decision-making to reflect policy, which would in turn be assisted by giving planning authorities greater clarity as to how the Government’s national energy and wider climate change commitments are expected to be delivered at the local level.

Action:

RenewableUK, in partnership with Government, to review the consenting framework for onshore wind and its implementation, with a view to exploring:

a) The current relationship between policy and decision-making, including timescales for determination;

b) Potential opportunities to address any gaps in policy read-across into decision-making;

c) Potential for the local plan process to include the mapping of existing and future energy demand and sources of energy supply; and

d) The scope for a more strategic view of planning for onshore wind – possibly as part of a review of planning for climate change mitigation and adaptation as a whole.


Overview

Clearly, the industry will have to innovate to meet our cost reduction targets. These interventions are unlikely to be rolled out at the rate required without a clear framework for taking these initiatives forward. As identified, the innovations necessary to bring forward the levels of cost reduction required are not simply limited to new technology but also include the need for process improvements that are likely to benefit from shared industry learning and collaboration.

Based on the feedback received, the taskforce believes that there are significant benefits to be gained in establishing a clear framework for the delivery of these cost reduction objectives and for the sharing of industry experiences as we progress along this path.

The taskforce also believes that there would be clear advantages to establishing a structured means of monitoring the progress made on cost reduction as industry and Government move towards 2020 and into the next decade.

The impact

The sharing of best practice – for example on site optimisation, contracting, asset management, maintenance strategies, health and safety and standards – between project developers, operators and the wider supply chain has the potential to accelerate the adoption of cost savings in the market. Similarly, there may be the potential to share experiences of efforts to increase UK content, with a view to finding cost-effective opportunities to increase this.

There is also likely to be benefit in establishing a greater level of collaboration between industry, Government and regulators, to review policies and regulations that currently prevent the industry from introducing new, innovative and lower-cost practices (e.g. enabling competition in grid connections).

Similarly, the UK has a long standing and well-deserved reputation as a centre of wind energy expertise, which is reflected in the leading role played by a number of UK research institutions. This provides a strong platform for ongoing research and innovation to continue to drive down costs beyond 2020. The taskforce sees that there is more which could be done to facilitate academic and industry collaboration.

Interventions

A clear focus on cost efficiency is required now, but will need to be sustained over the longer term. While the scope of the Cost Reduction Taskforce is to consider cost reductions to 2020, the need for continued innovation to deliver yet more cost efficiencies beyond this date should not be ignored. Maximising our ability to deliver in the short and long term depends on industry collaboration, sharing of best practice and Government engagement. The following interventions are therefore proposed:

Action:

Establish an industry forum to enable the onshore wind sector to monitor and coordinate joint action on cost reduction. This forum will lead on coordination between industry, Government and regulators, and encourage uptake of good practice in development and operation via an accelerator programme.

Action:

RenewableUK to explore with leading research institutions how best to facilitate increased industry-academic cooperation and knowledge transfer.

Action:

Establish within the wind industry a framework to monitor the UK content of onshore wind projects with a view to finding cost-effective opportunities to increase this. Increasing UK content will remove some of the exchange rate risk currently factored into development cost, while also helping to demonstrate wider economic benefits stemming from onshore wind44.

Part C: Industry Monitoring and Best Practice


Conclusion

This taskforce report clearly demonstrates that onshore wind can deliver on its commitment to be cost competitive with new entrant gas by 2020. However, this cannot be done through a business-as-usual approach; rather, project developers, operators and the wider supply chain need to work together across a number of fronts, with the support of Government, to accelerate the cost reductions identified here.

The LCOE reductions assessed in this study are summarised in the above figure. It should be noted that not all actions are relevant to all site types. In the case of the grid interventions, the actions discussed may be mutually exclusive or already assumed to be included (for example, the innovative connections may already assume an overhead line connection). Others are potentially complementary, for example the use of overhead lines

together with the use of an ICP. As such, there may be more than one possible combination of actions to achieve the necessary cost reduction. The above chart shows the best-case cost reduction achievable for projects commissioning in 2020 for each of the three different site types.

For all sites, the use of optimised turbines and more attention to site design would clearly deliver the

greatest benefit in term of cost reduction, and these should therefore be priority issues for industry and Government to consider. These two actions alone would be sufficient to cause Type 1 and Type 2 projects to fall below the middle of the target range of £65–75/MWh. Actions on grid costs and benefiting from technical innovations would see these types of project cost competitive with the lowest-cost CCGT.

Figure 1. Opportunities for cost reduction shown against estimated CCGT LCOE in 2020 (£/MWh)

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For Type 3 projects, using optimised turbines and giving more attention to site design will result in significant progress towards the CCGT target, but would require low-cost grid connections to get to the top of the CCGT LCOE range. Any further benefit from innovation or planning performance could see Type 3 projects delivering at a LCOE comparable with mid-range CCGT projects.

This significant cost reduction should translate directly into lower support levels through the CfD. Support levels in our best-case cost reduction scenario are nearly half of that in the business-as-usual scenario45. Consequently, if 1,000MW of capacity was built in 2020 that achieved the maximum savings, it would need £46 million less each year to support it, saving the consumer nearly £700 million over the 15-year span of the CfD. If cost reductions are rolled out to capacity built earlier and continue to be implemented in capacity built later, the total consumer benefit will be in the billions of pounds. This is clearly a prize worth pursuing.

The work of the onshore cost reduction taskforce shows that onshore wind, as found across a diverse range of UK site types, has the ability to become cost-competitive with new-build gas generation by 2020. However, industry cannot do this without a shift in the current trajectory in cost reduction. Instead, industry needs to work hard to manage costs while also looking afresh at innovation and new ways of working. Industry is ready and able to do this. However, while industry is making an effort to bring costs down in this way, Government and regulatory support is also needed.

This report highlights the critical role that planning and regulation has in defining what turbines are chosen, and how sites are developed. It is

important that all parties understand how these policies can be used to drive or hinder cost reduction. Industry will take the lead in making the case for optimising projects to deliver significant savings to the consumer and enable decision-makers to better understand the relevant considerations at play. Industry also needs to learn from others. RenewableUK will work with partners to facilitate further engagement and knowledge-sharing, and will also work to build partnerships between industry and different parts of Government, to ensure that all those who can help deliver cost reductions to benefit the consumer are able to do so.


Appendix 1: Report Methodology

The Project Pipeline

Levelised cost analyses tend to either focus on a single price for a ‘typical’ project,46 or exclude varying international requirements for grid connection or other costs47. There are a range of factors that impact the current levelised cost of onshore wind projects in the UK, including: the cost and availability of turbines; appropriate grid infrastructure; the cost of the consenting process and the removal of barriers to development; and access to the skilled workforce required in the construction, operation and maintenance of these assets. The LCOEs for onshore wind projects are also affected by wider external factors, including the availability and cost of the finance necessary to bring forward these projects, and the euro exchange rate.

On a site-by-site basis, conditions for construction, the wind profile of the site, and the need for ancillary infrastructure and off-site works (like bridge improvements or roads) will create fairly significant variability in LCOE, even within the UK. To capture these differences and establish a representative view of the current baseline, and also the types of project likely to come forward in the period 2015–2020, an analysis of the current pipeline of onshore wind projects was undertaken by DNV GL. Projects were classified by IEC wind class48 and shear exponent. DNV GL found seven dominant site types. When modelling the costs and impact of interventions, it was found that for the purposes of the taskforce’s analysis, some of these sites were sufficiently similar in terms of the cost base and sensitivity to cost reduction to treat as a single site-type. As such, the list of seven sites was reduced into three main types for ease of analysis and presentation.

The site-types included in the analysis were:

Type 1: Larger, high wind speed sites:

These correspond to IEC Class I and average 50MW49 (these are taken as indicative of costs for projects of 50MW+). These characteristics are typical of sites in northern Scotland. Such sites are considered to be complex construction operations and are likely to require a lot of supporting infrastructure and wider road improvements, tree felling, and so on. Complex construction and operational environments will result in higher costs than for the other site types. These sites are also assumed to pay transmission charges (TNUoS50) and balancing charges (BSUoS), which will impact levelised costs. TNUoS will cover the cost of connection assets and network upgrades and includes some level of cost socialisation.

Type 2: Medium size, medium wind speed sites:

These sites correspond to IEC Class II wind profiles and average just over 30MW (these are taken as indicative of sites between 20 and 50MW). These characteristics are typical of sites in northern England and parts of Wales. Such sites include forested sites, but they are generally less remote than Type 1 sites. Type 2 projects benefit from more favourable conditions for both construction and operation. These sites do not pay TNUoS or BSUoS, but pay for the totality of their connection cost and for wider reinforcements through Generation Distribution Use of System Costs.

Type 3: Smaller, lower wind speed sites:

These sites correspond to IEC Class III wind profiles and average 12MW in capacity (we take these to be indicative of sites between 5 and 20MW). Construction costs and operations are considered much less complex and therefore generally have lower associated costs. Charges payable are the same as Type 2 sites.

Forecasting costs in 2020

In developing a business-as-usual forecast for 2020, indicative and generic cost data51 was derived using existing RenewableUK data and input from the taskforce. The data was further compared and reconciled with the strike price announcements from the first Contracts for Difference (CfD) allocation round52. While strike prices and LCOE are different measures, the CfD results give a good indication of the likely future cost curve for onshore wind in GB. The relationship between the two measures is not straightforward and varies for different projects, as under the CfD allocation process, projects with different underlying LCOEs will receive the same strike price (more detail of this is provided in the next appendix). The taskforce’s analysis suggests that LCOEs for onshore wind are at least 5% lower than the equivalent strike price, which was adopted as a conservative assumption for the purposes of this report.

As part of the CfD process, Government initially published ‘administrative’ strike prices, which were the maximum prices that could be awarded to projects. These were based on analysis by National Grid of project data provided by industry, and therefore provide a good benchmark for understanding current


costs. The strike prices are all in 2012 prices, so need to be adjusted for inflation to compare with our baseline. The table above shows the £2012, £2014 and LCOE equivalent prices of the strike prices 53:

These administrative strike prices suggested that projects commissioned in 2015 would deliver at a LCOE of £95/MWh, whereas projects delivering in 2018/1954 could deliver at a strike price of just over £90/MWh. Following the auction, the actual clearing price55 for 2018/19 implied a LCOE of just under £83/MWh. These results show that cost reduction measures already being implemented are proceeding more quickly than had been assumed at the time that the strike prices were set, and show an impressive fall of 13% on levelised costs. These results provide a valuable and empirical foundation on which to base a forecast for costs in the period under discussion58.

The CfD results suggest an annual cost reduction rate of just over 4% pa to 2018/19, implying a LCOE of just under £80/MWh in 2020 in the business-as-usual scenario. There is, equally, a case for suggesting that the 2018/19 LCOE is a reasonable proxy for the expected 2020 LCOE: the nature of the allocation results is to award contracts to the lowest-cost qualifying schemes. Allocation rounds for future delivery years may therefore be expected to deliver at similar or even slightly higher

prices than earlier rounds. While it is possible that lower-cost schemes did not participate in this allocation round (because of grid connection dates beyond 2018/9, for example) and that more competition in later allocation rounds would drive the LCOE down even further, the lack of visibility of these projects suggests that a cautious and conservative approach should be taken59. On this basis, the assumption that the 2020 LCOE will be as per the 2018/19 LCOE has been made, which should be considered a conservative but reasonable view. More than half of the awarded CfDs were for projects in type 2 (see following chart), so the strike price is likely be most representative of projects in that type60.

Combining this analysis with baseline costs yielded the forecasts for 2020 discussed in the main report. It is important to interpret these figures carefully. In using the generic cost data, the taskforce has attempted to derive a reasonable range of costs and expects actual project costs to fall somewhere between the extremes of types 1 and 3. Combining the CfD results with this analysis allows for a reasonable forecast based on project data in the market. The results are reasonable but illustrative, so should not be considered to be typical or binding.

Administrative strike price for 2014/15 (£/MWh)56

Administrative strike price for 2018/19 (£/MWh)

Clearing price for 2018/19 (£/MWh) 57

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Figure A1: February 2015 CfD auction results by CRT site type (numbers of projects)61

Table A1: Strike prices and equivalent LCOEs


The cost of CCGT

Similarly, CCGT LCOE in 2020, and therefore the target price for wind, is subject to some uncertainty62, which is driven primarily by difficulties in accurately forecasting the price of gas. The taskforce consulted with a number of expert analysts and derived a range of £65–75/MWh. This spread reflects CCGT’s sensitivity to gas prices, which is also reflected in results for the capacity market63. The results of this auction indicate that much new-build CCGT will struggle to be cost-competitive with existing plant, but that some projects – those awarded capacity contracts – are able to deliver at a lower price than their new-build competitors (and some existing plant that was unsuccessful in the auction).

Consumer Impact

As discussed above, CfDs guarantee generators a fixed price for the energy the produce. The subsidy element is a ‘top-up’ on the (day-ahead) wholesale price, known as the reference price, up to the strike price. DECC projects a wholesale electricity price of £55/MWh in 202064 (all prices are in £2014). The business as usual (BAU) scenario for Type 2 projects implies a strike price of £87/MWh, whereas the best-case cost reduction (BC) scenario requires a strike price of about £68/MWh. The top-up in BAU is therefore £42/MWh, but only £23/MWh under the best-case cost reduction scenario, a 45% reduction.

Assuming a load factor of 27.7%, as per DECC assumptions for Levy Control Framework budgeting, and deployment of 1GW in 2020, we can get an idea of the savings achievable over the lifetime of these projects:

Strike price (£/MWh)

Top-up (£/MWh)

AEP (MWh)

Annual Payment

Lifetime payment

BAU £87 £42 2426520 £101,913,840 £1,528,707,600

BC £68 £23 2426520 £55,809,960 £837,149,400

Difference £19 £46,103,880 £691,558,200

Table A2: Assumptions for calculations of consumer savings


CfDs are the new support mechanism for renewable and low-carbon generation (of 5MW or greater) in the UK. With the existing scheme – the Renewables Obligation (RO) – closing to new applicants in March 2017, new generators in the meantime will have a one-off choice of their preferred support mechanism until this date, after which the CfD will completely replace the RO for new projects. Under the CfD mechanism, developers can be awarded a private law contract – the CfD itself – counter-signed by a Government-owned company (the Low Carbon Contracts Company – LCCC). This contract in effect guarantees the project owner a fixed revenue stream for the term of the contract (15 years in the case of onshore wind), up to the ‘strike price’. The LCCC will pay the difference between the contracted strike price and a market reference price, assumed to be roughly what the generator would have been able to sell their power for in the market. In the case of variable renewables, the reference price is the day-ahead price, set for each half-hour from a weighted average of trades in the day-ahead market across the two main power exchanges.

Total annual spend on support for renewables and low-carbon generation across all support mechanisms is capped under the Levy Control Framework (LCF), which is set at a maximum of £7.6 billion65 in 2020. For CfDs, DECC has opted to release portions of the LCF annually and award CfDs on a competitive basis within allocation rounds. Onshore wind projects compete with solar, energy from waste and other ‘mature’ technologies. Within each round, eligible projects can bid in to any delivery year for which there is a published ‘administrative’ strike price for that technology. The bid must include a project-specific strike price which is at or below the administrative strike price. Bids are stacked in order of the submitted strike prices across all delivery years, until the budget cap for any delivery year is reached. Under the pay-as-clear system, all winning bids in a year receive the clearing price (the highest successful bid) for that delivery year.

Appendix 2: Contracts for Difference (CfDs)


The charging regimes for grid connections in the UK differ depending on whether a project is connecting to the transmission or distribution network. In England and Wales, the distribution network is defined as any network at or below 132kV, whereas in Scotland, 132kV or above is considered to be transmission. This appendix briefly summarises the respective charging regimes for both these categories.

Transmission: the principle behind transmission connections is known as ‘shallow’ connection charging. This roughly means that project owners are expected to directly cover the cost of connection assets (i.e. the assets that connect their wind farm to the wider network, or sole-use assets66) as capital expenditure, but that any wider reinforcements costs needed to transmit that extra generating capacity are borne by all transmission users. These wider costs (and O&M costs) are recovered through Transmission Use of System Charges (TNUoS) which comprise a locational element (generally leading to higher charges for generators in Scotland and the North) and a residual element to recover all other relevant costs. There is some flexibility around which assets are defined as “connection assets”, which means that in certain circumstances, developers can choose to build, own and operate fairly extensive offsite assets. Depending on where this boundary is drawn, any cost saving from self-building of assets would be realised either in terms of capital expenditure, or lower TNUoS.

Distribution: distribution connections are governed by the principle of deeper (or “shallow-ish”) charging. As with transmission-connected projects, sole-use/connection assets are covered entirely by the developer, but they are paid for ‘up front’ rather than through ongoing charges. In addition, where that project would trigger the need for an upgrade of the wider network, the developer would also need to cover that as a direct cost on the project (this would apply to any reinforcements to the network at the connection voltage and at the next voltage level up). Costs of reinforcements at any higher voltage levels would be socialised across users of the DNO network through Distribution Use of System Charges. Alternatively, DNOs can charge developers for any relevant costs associated with reinforcements up to a ‘high cost cap’, currently £200/kW. At the time of writing, Ofgem was undertaking a review on which of these two rules should take precedence. Generation Distribution Use of System Charges (GDUoS) are also levied on developers through the project lifetime to recover the costs of wider works (as noted previously) and O&M. Where a distribution project would also impact the transmission network, the developer may also have to contribute to reinforcement costs at the transmission level.

Appendix 3: Grid Charging Regimes


Ofgem awards funding for DNOs to trial and demonstrate innovation projects through the Low Carbon Network Fund (LCNF). The taskforce modelled LCOE impacts from these projects, making use of publicly available data on capital costs and modelled curtailment levels. It is important to note that this work has deliberately highlighted projects that show a net LCOE saving relative to our baseline. It should not therefore be inferred that such saving would be generally available to a given developer in all circumstances; in fact, some projects show a net increase in LCOE from accepting an LCNF connection offer (these offers may still be preferable to a business-as-usual offer, which may be even more costly still, or because they offer a much quicker route to connection). Nonetheless, the case studies highlighted demonstrate that for at least some projects, innovative connections offer not just a technical solution to grid issues, but can also drive real savings on the cost of the project overall. This appendix briefly summarises the LCNF project drawn on for case studies. More information is available on the project at the link given below.

UK Power Networks—Flexible Plug and Play (FPP)

FPP was awarded £6.7 million from the LCNF, with a further £3 million provided by UKPN and partners. The project commenced in January 2012 with the aim of trialling methods to provide faster and cheaper connections to constrained areas of the distribution network in the East of England area (between Peterborough and March and Wisbech in Cambridgeshire). Business-as-usual connections can be considered to be ‘fit and forget’, whereby connections and reinforcements are made in line with static (and, by their nature, fairly conservative) limits on the

network. Broadly speaking, each new connecting generator will take up some level of capacity in line with technical and safety requirements, and once these levels are breached, different connection points or costly reinforcements will be needed to connect new generators. FPP moves to a more active ‘fit and flex’ approach, whereby active monitoring and management of the network allows for more renewable generation to be connected and controlled in conjunction with other generators connected to the network, making better use of the existing network beyond static limits and deferring the need for wider reinforcement. The active network management scheme (ANM), supplemented by a range of enabling communications and commercial arrangements, includes the following:

• Dynamic line rating (DLR): electricity that flows through a power line generates heat as result of resistance. This waste heat in turn heats the lines themselves, which will start to sag as they get hotter. Sagging lines could pose a safety threat if they drop below clearing distances. The cold temperature and wind around the line can serve to cool the lines and therefore reduce this effect. At present, transfer capacity of lines is subject to static seasonal limits, with more transfer capacity (and hence lower curtailment) in winter. DLR technologies allow for real-time monitoring of prevailing weather conditions to account for within-season variation, and therefore to make maximum use of the existing infrastructure.

• Generator control mechanisms: current DNO control of generator output is limited to an automatic relay to reduce output when part of the network goes down unexpectedly. FPP will make use of sophisticated electronic control

mechanisms that allow for output to be managed in such a way as to match available network capacity more closely.

• Voltage support: adding high volumes of new generation runs the risk of breaching statutory limits on system voltage. The ANM scheme allows for control of active and reactive power of the connected generators, which will ensure that these limits are not exceeded.

• Flexible network configurations: electricity will tend to take the ‘path of least resistance’ (technically impedance) route along the network to where it is needed. Depending on where generators connect, this may lead to situations where power flows disproportionality on some parts of the network, which can become constrained, over others, which are under-utilised (this is particularly the case when parts the network are down for maintenance). Flows can be managed with use of switchgear. FPP will make use of a new design of switches better suited to frequent use, which will enable more active management of flows, and therefore a reduction in constraints67.

Appendix 4: LCNF Projects


References

1 See http://www.ieawind.org/index_page_postings/WP2_task26.pdf Projects supported in the first Non-Fossil Fuel Obligation rounds received above-market support equivalent to £210/MWh in 2014 prices (though only for seven years). Projects commissioning in 2015 receive above-market support of around £38/MWh for 20 years.

2 This figure was derived from consultation with industry experts. More detail is given in the main report. 3 See Appendix 1 for calculations.4 http://www.renewableuk.com/en/publications/reports.cfm/general-election-manifesto. This should be taken to mean projects commissioning in 2020. 5 Projects are assumed to reach FID in 2018. All LCOEs are in £2014. 6 More information on CfDs can be found in Appendix 2. 7 These will be CfD projects reaching financial close in 2018. All values are in 2014 prices (£2014 hereafter). 8 http://www.renewableuk.com/en/publications/reports.cfm/state-of-industry-report-20149 http://www.theccc.org.uk/wp-content/uploads/2013/12/1785a-CCC_AdviceRep_Singles_1.pdf 10 http://www.renewableuk.com/en/publications/reports.cfm/state-of-industry-report-201411 The generally accepted figure is an annual payment of £5,000/MW of installed capacity, following the introduction of RenewableUK’s updated Community Benefit Protocol in

October 2013. This equates to a lifetime value of more than £1.2 million for the smallest project modelled (12MW), and more than £6.5 million for the largest. 12 This proportion will increase as the £/MW is fixed, but competition for CfDs will reduce revenues. 13 Inputs and revenue assumptions are discounted over time. 14 This refers to new-entry CCGT commissioned in 2020. All costs are in £2014. 15 For further information on the three different project types and turbine classes, please see Appendix 1. 16 Please note that the CfD results were for strike prices not LCOE. The relationship between the two is not straightforward. More information on our approach to reconciling these

different measures can be found in Appendix 1. 17 Though unabated coal prices are generally lower than unabated CCGT, no new coal (without CCS) is expected to be built because of restrictions under the emissions

performance standard. Similarly, DECC expects new nuclear to be slightly lower-cost than CCGT in 2019 (the last year for which there are DECC forecasts). However, given the anticipated timeline for the most advanced new nuclear project – Hinkley Point C – no new nuclear is expected to be delivered before 2020 (the February 2015 Transmission Entry Capacity register shows a grid connection date of 2022 for the first Hinkley C unit).

18 This is slightly below DECC’s CCGT estimates (£80/MWh for 2020) in its most recent levelised cost report (https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/269888/131217_Electricity_Generation_costs_report_December_2013_Final.pdf). The latest DECC figures were produced in late 2013, but DECC has since revised down its gas price projections, which would in turn be expected to reduce the CCGT LCOE to within our range.

19 Note that in practice, turbine technology has evolved to match machines to site conditions, and turbines are optimised to the wind profile of the site under development. There is a broad class of turbines designed for lower wind speed sites, for example. There is a more detailed discussion of the relevant points in the DNV GL study for RenewableUK published alongside this report.

20 Data from RenewableUK UK Wind Energy Database.21 Data from RenewableUK UK Wind Energy Database (Data on rotor diameter is less commonly available for projects in planning or approved awaiting construction).22 All Swedish data from https://www.vindlov.se/23 2014 data from https://www.wind-energie.de/system/files/attachments/press-release/2015/vdma-bwe-windenergie-land-2014-rekordzubau-von-4750-megawatt-deutschland/

factsheet-status-des-windenergieausbaus-land-deutschland-2014.pdf. 24 Wind speeds and topography differ both between these different areas, and within each nation.25 Wind direction changes of course, though site design will take account of prevailing wind directions (among other things). 26 http://www.bvgassociates.co.uk/Publications/BVGAssociatespublications.aspx27 Detailed discussion of each of these innovations is available in the report itself, along with quantification of the potential effect of each on CAPEX, OPEX and AEP.28 LiDAR technology is an alternative to traditional forms of meteorological equipment, utilising laser emissions and sensing to provide a highly accurate characterisation of wind

resource over a much wider area than a fixed met mast. This rich data source, together with accompanying modelling capability, allows for better-informed decision-making on siting issues.

29 Aviation lighting requirements at 150m or above as well as logistical constraints will determine which configurations are appropriate for a particular site.30 Turbine prices are assumed to remain subject to market forces and competitive pressures, so are not examined in this report, aside from the discussion in Part A above on

innovation and turbine supply. 31 More detail on grid charging is given in Appendix 3.32 25% should be seen as a maximum, with some developers reporting savings of around 15%, with fairly wide variation depending in part on which area of the country the

development is in. 33 These can include all assets up to the Main Integrated Transmission System, depending on where the point of connection is defined. In these circumstances, the developer

would be responsible for maintaining those assets. 34 It is important to note that such solutions are seen as a short-term measure to get more users connected and ultimately to spread the eventual cost of reinforcements, where this

represents the more cost-effective option. 35 More information on this can be found in Appendix 4.36 Ofgem is, at the time of writing, undertaking an assessment of some of the key procedural issues around use of ICPs –- this issue is therefore not revisited here, but

RenewableUK and industry will engage with this work as it develops. 37 https://www.ofgem.gov.uk/ofgem-publications/92528/cicconsumerresearch.pdf38 There is some evidence that transmission operators may be starting to offer more ‘generator build’ options for certain assets. We should also note the different charging regimes

at distribution and transmission, as discussed in Appendix 3. 39 i.e. new from a regulatory perspective. 40 For example, compensated constraints under the Balancing Mechanism provide an investment signal for major upgrades, whereas uncompensated constraints do not. One

principle for investment, therefore, could be that reinforcements are triggered when the cumulative cost of foregone generation for connectees is expected to exceed the cost of reinforcements, such that no connecting party is worse off from contributing to the cost of the reinforcement.

41 The RIIO-ED1 price control sets the outputs that the 14 electricity DNOs need to deliver for their consumers, and the associated revenues they are allowed to collect for the eight-year period from 1 April 2015 to 31 March 2023. More information can be found at https://www.ofgem.gov.uk/network-regulation-%E2%80%93-riio-model/riio-ed1-price-control.

42 https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/48128/2167-uk-renewable-energy-roadmap.pdf 43 Data from RenewableUK Wind Energy Database January 201544 RenewableUK’s ‘Local Supply Chain Opportunities in Onshore Wind: Good Practice Guide’ contains some relevant discussion: http://www.renewableuk.com/en/publications/

index.cfm/Local-Supply-Chain-Opportunities-Onshore-Wind.45 See Appendix 1 for more detail.46 E.g. DECC Levelised Cost Estimates47 Developer liability and charging regimes vary across different markets, so some analysis, such as World Energy Council’s/BNEF’s ‘World Energy Perspectives’, excludes these

altogether to allow for accurate international comparisons. 48 IEC classes I,II,III refer to turbine designs for different wind speed, with I as the highest; each class is further split into different turbulence levels, either A (higher) or B (lower). 49 However, project economics are generally more sensitive to AEP than project size. 50 The TNUoS rate modelled for these sites was Zone 2 East Aberdeenshire, among the highest rates in the UK. 51 All data provision and discussions thereof were undertaken in line with competition law, and no commercial project data was used in deriving the baseline. 52 Information on the CfD is given in appendix 2. 53 All adjustments were made using the Bank Of England inflation adjuster tool http://www.bankofengland.co.uk/education/Pages/resources/inflationtools/calculator/flash/default.

aspx. 54 This was the last delivery year for which CfDs were available.


55 Note that the auction is operated under a pay-as-clear system, whereby all projects for a certain delivery year will receive the highest winning bid for that year. 56 https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/263937/Final_Document_-_Investing_in_renewable_technologies_-_CfD_contract_terms_and_

strike_prices_UPDATED_6_DEC.pdf 57 https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/407059/Contracts_for_Difference_-_Auction_Results_-_Official_Statistics.pdf58 Like all forecasts, however, they are not without their limitations, so should not be seen as definitive, not least because of the macroeconomic drivers of cost discussed

previously. However, the taskforce is particularly confident that the 2018/19 prices are a good marker, given than 84% of the allocated capacity for onshore wind was for delivery in that year.

59 Clearly, if future projects deliver at a lower cost, then onshore wind will be even closer to meeting the target LCOE. 60 DECC has not revealed which project set the clearing price for any delivery year, so we have had to make an assumption based on likelihood. Our baseline data suggests that

type 3 projects are generally more costly than type 2, which is borne out by the auction results. If, therefore, the clearing price was indeed set by one of the type 3 projects, it would be reasonable to consider these to be outliers rather than typical of their type.

61 https://www.gov.uk/government/statistics/cfd-auction-allocation-round-one-a-breakdown-of-the-outcome-by-technology-year-and-clearing-price62 Note, however, that the LCOE of a wind farm is more or less fixed at the point of commissioning. 63 https://www.gov.uk/government/statistics/capacity-market-location-of-provisional-results64 https://www.gov.uk/government/publications/updated-energy-and-emissions-projections-201465 2011/12 prices https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/223654/emr_consultation_annex_d.pdf66 These terms differ from those used under the Connection and Use of System Code.67 More information on FPP is available at http://innovation.ukpowernetworks.co.uk/innovation/en/Projects/tier-2-projects/Flexible-Plug-and-Play-(FPP)/

The following companies were represented Cost Reduction Taskforce, whose leadership and assistance is gratefully acknowledged:

DNV GL (Chair)Airvolution EnergyBanks RenewablesBVG AssociatesEDF Energy RenewablesESBInfinergyNordexRESRWE InnogyScottish Power RenewablesSgurr EnergyTata SteelVattenfall

RenewableUKGreencoat House, Francis StreetLondon SW1P 1DH, United Kingdom

Tel: +44 (0)20 7901 3000Fax: +44 (0)20 7901 3001Web: www.RenewableUK.com Email: [email protected]

Our vision is for renewable energy to play a leading role in powering the UK.

RenewableUK is the UK’s leading renewable energy trade association, specialising in onshore wind, offshore wind, and wave & tidal energy. Formed in 1978, we have a large established corporate membership, ranging from small independent companies to large international corporations and manufacturers. Acting as a central point of information and a united, representative voice for our membership, we conduct research, find solutions, organise events, facilitate business development, advocate and promote wind and marine renewables to government, industry, the media and the public.

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