Select Committee on Environmental Audit Written Evidence

Memorandum submitted by Airtricity


  The Environmental Audit Committee has invited organisations and members of the public to submit memoranda setting out their views on this inquiry. This submission concentrates on the likely costs, scale and timescales for developing offshore wind, and suggests policy changes that the UK government could implement to promote the timely development and construction of offshore wind. It is structured as follows:

    —  Section 2 briefly discusses the requirements for the continued expansion of onshore wind.

    —  Section 3 sets out views on the required policy framework for offshore wind.

    —  Section 4 notes some general issues and concerns with respect to new nuclear build.

    —  Section 5 draws conclusions on some of the specific questions raised by the inquiry.


  The Energy White Paper1[1] of February 2003 set out a vision in which renewables and energy efficiency would play a key role in UK energy policy and secure the gap left by the decline of current nuclear and coal generating capacity. It is against this background that the renewables sector in general, and the wind industry in particular, has been evaluating its investment plans and project development strategies.

  The stability of the current renewables framework has enabled onshore wind to make a major contribution towards government targets, benefit from technology and cost improvements, and develop an overall infrastructure to support continued development.

  Uncertainty regarding the Government's intentions towards new nuclear capacity has the potential to damage further investment in renewables and energy efficiency. Equally, potential changes to the current government and regulatory frameworks to facilitate new nuclear build need to be fully thought through, with regard to both their direct and indirect impact on the renewables sector. Onshore wind is a success story for the UK and has delivered significant benefits. Given the appropriate framework, it can deliver much more. Although not a completely mature sector, onshore wind experience is such that the government is well informed with regard to the likely path of cost curves for the industry, as it develops further. A potential key concern for current and future development will be the coordination, efficiency and timeliness of the overall planning process. Consideration should be given to reviewing the framework applicable to wind project planning, such that each development only has to address truly significant, specific issues. If planning develops on a case-by-case basis, where no "case law" is laid down, and all issues are reopened each time, it is highly likely that the pace of onshore wind resource development will slow significantly.


 (a)   The cost of offshore wind

  The cost of offshore wind varies from project to project depending on project specifics including water depth, seabed conditions, metocean conditions, distance to shore, and connection point to the onshore grid.

  The recent trend has been of increasing costs due to:

    —  higher world steel prices;

    —  greater knowledge of contractors (who may have under-priced early projects);

    —  the more recent Round 2 projects being further offshore and in greater water depths; and

    —  pressure on turbine supply capacity pushing turbine prices up.

  Whilst these high prices may persist in the short-term, in the medium to longer term the trend will reverse:

    —  economies of scale will enable the same capacity to be built with fewer offshore foundations;

    —  improved turbine design will lead to higher efficiencies at lower cost;

    —  experience will lead to lower costs per installed megawatt; and

    —  the capacity and experience of the supply chain will be developed.

  As well as lower costs in the medium to longer term, project capacity factors will also increase due to higher wind resource further offshore and improved turbine design.

  Current costs are in the region of £1.2-£1.8 million/MW installed capacity, with capacity factors in the region of 35-40%. A 35% capacity factor with a capital cost of £1.3 million/MW will produce energy at a cost of approximately 8p/kWh. This compares with onshore wind projects that are now producing energy at a cost of 4-5p/kWh.

  Currently there is just over 600MW of installed offshore wind capacity within the EU[2] with no offshore wind projects yet commissioned outside of the EU. As more offshore capacity is built, costs will reduce due to the factors listed above. The experience of cost reduction from onshore wind is shown in the diagram below (offshore wind is at the low end of the range of cost levels for marine energy)[3]:

  If offshore wind can benefit from a similar rate of cost reduction as that experienced by onshore wind, it should become competitive with onshore wind (and conventional forms of generation) within the medium term.

  To date, all offshore wind projects in the UK have been balance sheet financed. Many, if not all of the Round 2 projects, because of their scale and associated capital requirements, will be project financed. Project financing will require a certain long-term revenue stream to underpin the debt in each project. This long-term revenue stream will usually be obtained through long-term off-take agreements with one of the (currently) six major electricity suppliers in the UK. However, these suppliers will only be willing to enter into these agreements if there is certainty with respect to the renewables market into the longer-term. The current structure of the renewables obligation does not provide sufficient longer term certainty. The percentage obligation only rises to 15.4% by 2015-16. This may or may not be reviewed. When coupled with the uncertainty surrounding what, if any, arrangements will be put in place at the end of the obligation itself, the level of uncertainty becomes significant.

 (b)   The potential scale of offshore wind

  Round 1 projects were restricted to 30 turbines and the two projects constructed to date (North Hoyle and Scroby Sands) are each 60MW projects. Two further projects are under construction (Barrow and Kentish Flats), and these will each be 90MW projects.

  The 15 Round 2 projects awarded in December 2003 range from 64MW to 1,200MW, with 10 of the projects between 240MW and 500MW. Together they total over 7GW. However, this is only a small fraction of the total offshore wind resource available within UK waters. The DTI's consultation on offshore wind in 2002[4] noted that within water depths of 5 metres to 30 metres there is potentially 327GW of offshore wind capacity in UK waters, with a further 592GW in water depths 30 metres to 50 metres. This translates into enough capacity, at a 40% capacity factor, to supply the UK's total electricity demand 10 times over.

  Whilst it will not be possible, for environmental and other reasons, to develop all of this potential resource, there will remain a vast developable offshore wind resource capable of contributing significantly to the UK's and Europe's longer-term emissions targets.

  It is important to note that whilst many other European countries are developing an offshore wind industry (notably Denmark, Germany and the Netherlands), the UK holds approximately 50% of the offshore wind resource of all the EU-15 countries. The UK performance is therefore the key factor in determining whether the EU as a whole will meet its emissions targets.

(c)   Timescales to build

  From initial screening to project commissioning, the time to build an offshore wind project is typically in the region of 5-6 years. This comprises:

    —  6 to 12 months site selection and award;

    —  18 to 24 months environmental and site surveys and consent application;

    —  12 to 18 months engineering, procurement, financing, receipt of consent; and

    —  18 to 24 months construction and commissioning.

  Given the award of the Round 2 sites at the end of 2003, the earliest conceivable commissioning date for a Round 2 project would be end of 2007, in reality it is unlikely that any project will be commissioned prior to mid-2008.

  However, many Round 2 projects are currently experiencing delays:

    —  Onshore grid reinforcement is required to connect many of the Round 2 projects and this work, as scheduled by the National Grid Company (NGC) will take longer than the construction of the offshore wind projects themselves. In addition, NGC requires project developers to provide financial security for these works, which many if not all will be unwilling to do, prior to receipt of consent for the wind project and probably also its financial close. This will particularly affect those projects in the Northwest and Wash Strategic Environmental Assessment areas.

    —  Whilst sites were initially awarded at end 2003, there has been a process to allow developers to amend their site boundaries, and in some instances wholesale site relocation, in the light of further information arising from environmental and site surveys. This will have delayed many projects.

    —  Several projects have received holding objections from statutory consultees whilst solutions are found to potential conflicts with other users of the sea or air, or from environmental organizations. Finding solutions acceptable to all parties has proven to be drawn out and may have delayed many projects.

  In addition, the following issues may delay projects further:

    —  All 15 projects were awarded sites at the same time, and therefore many of them are likely to be submitting their consent applications in late 2005/early 2006. This could be problematic for the consenting authorities and its consultees, if not properly resourced and could lead to delays in receipt of consents.

    —  Whilst uncertainty with project economics may not have delayed projects to date, if the funding gap described below is not resolved by mid-2006, it is likely to impact on the ability of projects to obtain suitable financing and therefore to result in delays.

    —  With respect to the regulation of the offshore grid, a clear regulatory framework is required to avoid delays.

  Given the potential for delay in so many areas, it is likely that a significant number of the Round 2 projects will not be commissioned prior to 2011-12.

 (d)   Policy changes required to deliver offshore wind

(i)  Project economics

  Airtricity generally supports the position promoted by the British Wind Energy Association (BWEA) with respect to the need for additional financial support for offshore wind. The BWEA is seeking an additional £300k-£400k/MW in support through one or more of the following mechanisms:

    —  Mitigating the offshore grid costs and providing fair and equal treatment with the onshore grid.

    —  A capital grants program for Round 2.

    —  Enhanced capital allowances (this is the least preferred mechanism as it disproportionately benefits the incumbent large integrated utilities over the new renewables companies).

  Providing this additional support in the short-term should enable sufficient projects to proceed, and therefore initiate the beneficial process of learning efficiencies noted above. In addition the BWEA is seeking greater certainty with respect to the renewables market post 2015-16. This could be achieved either by increasing the obligation post 2015 (to say 20.4% by 2020-21) or by guaranteeing a margin post 2015-16 between the renewables obligation and renewables supplied to avoid the cliff-edge.

  Policy mechanisms should be implemented to provide economic support for the offshore wind industry in the short term and certainty regarding the developmental framework, in the longer term.

(ii)  Long-term industry

  The cost reductions described above will come from the learning obtained during the growth of the industry, economies of scale and the development of the industry supply chain. Currently this is being hampered by the stop-start nature of the framework within which the industry is developing, whereby leases for offshore wind projects have only been awarded on two occasions, in 1999 and 2003, and with no firm plans for a further award round. This will mean that some developers, having successfully developed a site, will have no further sites available for the foreseeable future and are likely to transfer capital and resources to other markets. With regard to the supply chain, installation contractors, turbine and cable manufacturers and the rest of the service providers are unlikely to invest the required capital to facilitate either timely development of offshore wind resources or, achievement of the economies of scale/learning necessary to move the industry to a more economic footing, if they do not have confidence in either the developmental framework for the industry, or the underlying economics.

  As noted above, the UK has approximately 50% of the EU-15's offshore wind resource and will therefore be a major influence in determining the size of the offshore wind industry in Europe.

  To provide certainty to the whole offshore wind industry, necessary for the required investment in people and equipment to obtain the potential cost reductions, the UK government should institute an on-going process to award leases to offshore wind developers. The appropriate frequency of such awards will need further review, as to whether an annual or longer interval is appropriate.

(iii)  Grid reinforcements

  The delays to Round 2 projects caused by the financial risks imposed on developers could be solved in a variety of ways, including:

    —  Incentives could be put on grid companies to complete their works in shorter timescales (to ensure consistency in timescales with those of construction and commissioning of the offshore wind farm).

    —  Grid companies could have an obligation to connect projects prior to full completion of reinforcements, where this is technically possible, and to manage any congestion issues that arise.

    —  Grid companies could assume the risk of stranded assets themselves by commencing work without financial security from the offshore wind projects.

  However, it should be noted that the mechanism of requiring developers to provide financial security for grid reinforcements is long established and the problems are only now arising due to the compressed timetable between offshore site award (and hence application for connection) and the required connection dates (by 2010-11). If the process were amended to allow more time between site award and grid connection, then risks could be managed more effectively.

  Implementing further award rounds soon (and on a rolling basis) would prevent grid reinforcement being a delaying factor in meeting the 2015-16 target.

(iv)  Offshore grid

  As technology and installation methods improve, sites further offshore will become economic and there will consequently be a need to extend the grid further offshore. This grid will need to be financed, constructed, operated and regulated. Airtricity welcomes the recent DTI consultation on the regulation of offshore transmission and supports a regulated (licensed price control approach) to the development of this grid. However, at present grid companies appear to be doing little to address the issues involved in the planning and development of the grid offshore and it is instead being left to developers to plan their own connections on a (potentially suboptimal) piecemeal basis.

  It is important that a single party or consortium of parties is given the responsibility for the offshore grid in a region to ensure that it is planned, constructed and operated at least cost, and to maximize the potential benefits of interconnections between offshore projects, and indeed between countries.

  Offshore transmission licencees should be appointed with responsibility for developing and implementing plans for the offshore grid in specific regions.

 (e)   New Nuclear Build—Issues and Concerns

  The Committee has requested submissions covering a very wide remit. Detailed information concerning the costs, benefits and timescales associated with new nuclear build will be provided from many sources including those with specific recognized expertise in nuclear issues—we are not intending to make reference to specific data with regard to new nuclear build in our submission.

  However, we wish to emphasize the following high-level issues:

    —  The timescales associated with nuclear plant build—the historic record of significant delays.

    —  The uncertainty with regard to costs of any nuclear project—the record of cost overrun both in design and operation.

    —  The need to factor in technology risk—a new generation of nuclear build would use largely unproven technology—experience shows that this has a high risk of underperformance, cost escalation or both.

    —  The need to properly account for full lifetime costs in any estimation of prospective nuclear projects, ranging from the environmental costs of uranium ore extraction, refinement, through operation, plant decommissioning and long-term waste management.

  And the following concerns:

    —  Nuclear capacity is supposedly characterized as a high capital cost, low operating cost option. The minimum incremental capacity addition (plant size) is usually large (approximately 500-1,000MW). The technology requires virtually continuous (baseload) operation for reasons associated with the physics of nuclear generation. High, sustained output is also necessary to maximise economic returns. The level of incremental capital investment is therefore large. This limits the number of individual market participants who are capable of financing new nuclear build. Given that it is highly unlikely that this would not be their technology of choice for new plant build under present market structures and mechanisms, it is likely that significant changes would be required to market and regulatory structures, market mechanisms and support mechanisms (including any levies, quotas or obligations). This would increase regulatory, government and market risk for the non-nuclear components of the energy mix and could deter investment in renewable projects.

    —  When the level of nuclear plant on a system increases, other flexible plant has to regulate in order to ensure that supply and demand are dynamically matched. The flexible plant, which is displaced by nuclear, is exactly the same plant required to balance the system when a reasonable level of wind penetration is achieved. Thus nuclear plant can, in certain circumstances, act as a cap on the level of wind that a system can accept.


 (a)   The main investment options for electricity generating capacity

  Investment options are driven by the needs of the market in the UK. Companies currently in the market, and those seeking to enter, assess the most effective way for them to meet the demands of their customers, given the relevant regulatory, environmental and market structures and the overall objectives of Government policy, which in turn shapes the above. It should therefore be a decision by the market, within an appropriate and consistent framework of incentives, to decide upon the options for capacity. Renewables form a key part of the Government's strategy to address climate change issues. Renewable generation now contributes a significant proportion to the UK generation mix and can contribute further. This has been achieved within the context of a stable and consistent set of policies. Any form of prescription or intervention with regard to generation capacity choice is likely increase the perception of market risk, result in inefficient investment decisions and lead to undesired outcomes.

 (b)   The attitude of financial institutions to investment in different forms of generation

  Financial institutions are likely to base their attitude to investment in generation on the following general principles:

    —  Security and stability of the counterparty to whom any loan is made.

    —  Ability of the counterparty to redeem the loan regardless of the specific project status (financial strength).

    —  Technology risk.

    —  Specific project risk (including market/merchant risk elements).

    —  Regulatory/government risk.

    —  Liquidity/tradability of the loan risk on the financial markets.

 (c)   What impact would a major programme of investment in nuclear have on investment in renewables and energy efficiency?

  The impact would depend on exactly how the programme was implemented. There are many variables that would need to be considered. The key driver would be to ensure that the net impact on renewables and energy efficiency was at worst neutral and at best positive. If a private company, with no government incentives or subsidy, initiated the major programme of nuclear investment they would bear the total risks (and any rewards) of the programme. Any government facilitation, intervention or subsidy in favour of new nuclear build would require the place of renewables and energy efficiency in the overall energy portfolio to be properly reviewed and equivalent additional support measures to be put in place in order to ensure a level playing field in the energy arena.

 (d)   How does the nuclear option compare with a major programme of investment in renewables, micro generation, and energy efficiency?

  Renewables, micro generation and energy efficiency have many benefits over the nuclear option:

    —  Renewables can deliver reliably.

    —  Renewables do not require fuel importation and as such increase security of supply.

    —  Renewables are not dependent on world fuel prices and therefore provide a more stable price environment.

    —  Wind is a proven technology.

    —  The minimum incremental capacity addition is an order of magnitude smaller than nuclear.

    —  Energy efficiency is a lower cost option than new nuclear build.

    —  Micro generation could significantly improve overall energy efficiency—it requires the right incentives to be put in place.

20 September 2005

1   1 Energy White Paper: Our energy future-creating a low carbon economy, DTI, February 2003. Back

2   Offshore wind: implementing a new powerhouse for Europe, Greenpeace, 2005. Back

3   Harnessing Scotland's Marine Energy Potential, Forum for Renewable Energy Development in Scotland, July 2004. Back

4   Future Offshore: A strategic Framework for the offshore wind industry, DTI, November 2002. Back

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