Memorandum submitted by Airtricity
1. INTRODUCTION
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.
2. ONSHORE WIND
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.
3. OFFSHORE WIND
(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.
5. SPECIFIC ISSUES
IDENTIFIED BY
THE COMMITTEE
(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).
— 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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