Memorandum submitted by the Institution
of Mechanical Engineers
EXECUTIVE SUMMARY
This response has been prepared by the Institution
of Mechanical Engineers (IMechE) on behalf of its membership,
comprising over 75,000 professional engineers, of which over 15,000
have a specific interest in the electricity/power sector.
The views expressed have been collated from
IMechE members in senior management positions in companies and
utilities operating in the field, academics, and experts in all
aspects of renewables, fossil and nuclear power generation. It
is therefore hoped that this response is balanced and does not
unduly favour one type of power generation technology over the
rest.
Hard challenges are facing the power sector:
1. Growth in electricity generated
from renewable sources has been slow and will be unable to offset
planned retirement of coal-fired and nuclear stations.
2. The country has now become a net
importer of oil and gas, this endangers security of supplies and
exposes consumers to world price volatility.
3. Dependence on coal and gas is contributing
to overall CO2 emissions growing at 1-2% a year.
The development of new nuclear generation is
therefore important to minimise CO2 emissions and reduce
reliance on gas, however, such development should not be at the
detriment of renewable or clean coal power generation. All these
technologies together have an important role to play in providing
fuel diversification and minimising environmental emissions.
The IMechE strongly supports a balanced approach
to the development of new power generation in the UK, recommending
the use of renewable, fossil and nuclear sources to a point where
the country is not overly reliant on any one option. The resulting
mix of generating technologies will minimise technical, fuel supply
and financial risks, while retaining competitive electricity prices.
QUESTION 1—SUPPLY
AND DEMAND
Increased in consumption and retirement of both
existing coal and nuclear plants will result in an estimated shortfall
in generation of approximately 120TWh per year, by 2015. The expected
decrease in nuclear capacity is shown in the graph below:
Theoretically there are sufficient renewable
resources to provide the UK energy needs, although this may not
be the most cost-effective or publicly-acceptable solution. Economic,
technical, planning and social factors have constrained the growth
of renewable energy, micro generation and energy saving measures
to date; it is therefore highly unlikely that these sources, on
their own, will be able to meet future shortfalls in generation,
for the period under review.
Even with renewables developed to the fullest
practical extent, there will remain a significant need for additional
nuclear, gas and clean coal generation. Such a generation mix
will minimise over-dependence on a particular technology (and
therefore fuel) and would serve the best interests of the UK.
QUESTION 2—GENERATION
COSTS
Independent reports indicate that nuclear electricity
is price competitive with gas and clean coal technologies. However
it should be noted that the assumptions used to derive costs for
nuclear, fossil and renewable generation, are a hotly debated
subject, and the findings of such reports should be treated with
caution.
Published costs estimates for nuclear plants
are considered realistic and cost overruns are less likely than
in the past, as construction contracts will be based on fixed
prices with performance penalties, thus shifting construction
risks from plant owners to contractors.
There is sufficient experience to quantify decommissioning
and waste disposal costs, however, Government policy on waste
management will determine the final cost of waste disposal. Investors
will require such costs to be clarified before committing any
investment. The introduction of legal requirements for future
operators to create financial reserves (based on conservative
estimates) to finance these activities is recommended.
QUESTION 3—FINANCING
A NEW
NUCLEAR PROGRAMME
Current estimates indicate that the economics
of new nuclear plants are robust and will not require financial
support from Government.
Given the past regulatory UK track record, financiers
are nervous to fund additional power infrastructure and nuclear
in particular. There is a need for Government to create a stable
regulatory and planning environment for the electricity sector,
to attract investment and, with regards to nuclear, may in addition
be required to underwrite part of the risks associated with construction,
insurance and waste disposal of nuclear plants.
If the financial community were to regain its
past confidence in the sector, and if investment opportunities
were structured in such a way as to allocate risks to those parties
capable of managing them, then there should be sufficient funds
to finance fossil, renewable and nuclear projects.
QUESTION 4—PUBLIC
BENEFITS OF
A NUCLEAR
PROGRAMME
It is estimated that the first new nuclear plant
will not be operational before the middle of the next decade,
with almost a further decade to complete the replacement of existing
nuclear facilities. Electricity production lost from retiring
plants will be partly replaced by renewables, but predominantly
by additional gas or clean coal plants. This will therefore result
in an increase in CO2 emissions in the short term,
followed by a stabilisation in emissions once the nuclear program
is underway. Any delays in commencing nuclear construction will
result in a further net increase in CO2 emissions from
the UK's power generation capacity.
Nuclear can also contribute to security of supply
by providing fuel diversification without over-dependence on gas
and by moderating electricity prices volatility.
Terrorism will remain a concern. This risk is
manageable and it is not unique to nuclear plants. The transmission
grid is considered to be far more vulnerable.
QUESTION 5—COMPATIBILITY
OF NUCLEAR
WITH THE
ENERGY WHITE
PAPER
Investments in the development of a nuclear
program, renewables and clean coal technologies are not incompatible;
on the contrary they are complementary and necessary to ensure
a diversified generation mix thus ensuring security of supply.
QUESTION 6—NUCLEAR
CARBON EMISSIONS
Quoted CO2 emissions from nuclear
plants (including fuel production and reprocessing, construction,
operation and decommissioning) are approximately 5 grams of CO2
per kWh for Torness in the UK, and 3.3 grams of CO2
per kWh for Vattenfall PWR in Finland; these figures are similar
to emissions produced from renewable sources and considerably
less than for fossil plants. The graph below shows CO2
emissions for different technologies.
QUESTION
7—MANAGEMENT OF
NUCLEAR WASTE
Scientifically acceptable solutions to deal
with nuclear waste are already available, but it is important
to reach public consensus on the approach to be adopted for the
UK. The public needs to be engaged to address their concerns through
the provision of facts, figures and credible arguments. In addition
it is possible that financial institutions will be unwilling to
provide finances if their participation in the proposed nuclear
program would result in adverse publicity.
Licensing of new nuclear plants will most likely
be required before these issues have been completely resolved.
Delays in licensing will threaten the security of supply, potentially
de-stabilise energy prices and lead to increased CO2
emissions.
Finally it is worth noting that replacing all
the current UK nuclear capacity with reactors would add, over
their lifetime, less than 10% by volume to the UK's nuclear waste
inventory.
INTRODUCTION
The Institution of Mechanical Engineers (IMechE)
is a professional body representing over 75,000 professional engineers
in the UK and overseas. Of these, over 15,000 have a specific
interest in the electricity/power sector.
Our membership is involved in all aspects of
power generation using fossil fuels, renewable sources and nuclear,
therefore it is hoped that our response will be balanced and will
not unduly favour one type of power generation technology over
the rest.
The IMechE strongly supports a balanced approach
to the development of new power generation in the UK, thus recommending
the use of renewable, clean fossil and nuclear sources to a point
where the country is not overly reliant on any one option. Such
a "portfolio" approach will minimise technical, fuel,
environmental and financial risks, while retaining competitive
electricity prices.
The remainder of this response is dedicated
to answering the specific questions asked by the Select Committee.
Any issues requiring a more detailed analysis, are covered in
appendices.
In addition, it is worth noting that the IMechE
published a response to the Energy White Paper. Much of the response
is relevant to this inquiry. The text can be found at http://www.imeche.org.uk/media/parliament/position_statements.asp
QUESTION 1
What are the latest estimates of the likely shortfall
in electricity generating capacity caused by the phase-out of
existing nuclear power stations and some older coal plant? How
do these relate to electricity demand forecasts and to the effectiveness
of energy efficiency policies?
The recent defence of the reserve margin, made
by the National Grid Company last winter suggests that there is
no immediate problem, and the fact that generation was able to
meet peak demand during the relatively mild winter of 2004-05
provides limited evidence that their assessments were accurate.
However, demand is rising year-on-year, at a greater rate than
energy-saving initiatives are able to reduce consumption. Without
new plant being brought into service, the only way in which this
demand can be satisfied, is by reducing margins. This is not sustainable,
requiring only a period of severe weather before power cut measures
become necessary.
Severe weather in winter often results in increased
gas consumption, that is co-incident with an increased demand
for power. The consequence is that many utility companies with
both power and gas businesses have to make a commercial choice
between selling gas and producing power. This can result in some
gas fired plants being turned down or off, because it is commercially
to the utilities' advantage to do so, as they are responding to
the power and gas markets pricing signals.
In addition lead times for the construction
of power plants is at least four years and there are uncertainties
regarding the ability of the market to respond in a timely manner
to supply and demand signals. There is thus the potential for
a short-term generation gap.
In the medium term, existing coal power stations
are life-limited by a number of factors:
1. The age of existing plants.
2. The Large Combustion Plant Directive,
reducing coal-fired plant capacity and/or limiting operating hours.
However 15 GW of coal fired plant are or will be fitted with FGD/LoNOx
and therefore available beyond 2015.
3. The EU Emissions Trading Scheme,
raising costs and limiting emissions and therefore generation.
4. The likelihood of even tighter emissions
controls in the future (eg Mercury, which is becoming an important
issue in the USA).
Unless there is a substantial improvement in
incentives for micro-generation, it is not expected that this
technology will be able to contribute in a meaningful way to energy
production, and without similar incentives for energy efficiency
measures, electricity demand will continue growing (recent historical
data shows a 1.5% increase per year).
The life of the Magnox stations will not be
extended, with the last plant at Wylfa due to close in 2010. The
majority of the AGRs are scheduled to shutdown by 2015. The lives
of most AGRs have been extended and it is not clear at this time
that further substantial life extensions will be possible. By
2015 nuclear plant closures will reduce nuclear generation capacity
from the current level of 12,000 MW to less than 4,000 MW, see
graph below:
While it is hoped that the current regulatory
framework will enable renewable sources to contribute 15% of electricity
production by 2015, the present rate of growth is too slow to
meet this target, and the renewable contribution to overall electricity
production will be insufficient to meet forecast shortfalls in
generation.
The graph below (produced by the DTI) indicates
a need for 120TWh per year of additional electricity production
by 2015. This equates to 18-27GW of additional capacity, depending
on type of plant and load factor assumptions.
It is unlikely that any single technology on
its own will be able to fulfil the forecast shortfall in generation.
Over-dependence on a particular technology (and therefore fuel)
would not serve the best interests of the UK.
QUESTION 2—FIRST
BULLET
What are the likely construction and on-going
operating costs of different large-scale technologies (eg nuclear
new build, CCGT, clean coal, on-shore wind, off-shore wind, wave
and tidal) in terms of the total investment required and in terms
of the likely costs of generation (p/kWh)? Over what timescale
could they become operational?
It is almost impossible to answer this question
with great accuracy and there is a high level of debate within
the industry regarding published figures.
Historically many cost comparisons were based
solely on construction and operating costs, but there is now a
realisation that other factors have a significant impact. Some
of these factors are listed below:
1. Method of financing: off or on-balance
sheet will significantly affect the cost of capital for the project.
2. Financial charges: level of gearing,
interest rates and loan duration will change depending on the
financial community's perception of construction, technological
and operational risks.
3. Project required rate of return
will change depending on the level of risks perceived by investors.
4. Additional infrastructure required
such as: grid connections, grid reinforcements, additional roads,
gas pipelines and railway lines.
5. Avoided cost with embedded generation
for additional transmission lines.
6. Plant and local issues such as cooling
systems, transmission charges and local taxation.
7. Estimates of future fuel prices.
8. Plant reliability and availability.
9. Development costs and timescales
associated with bringing the project to the point of construction.
10. Back-up for intermittency (if appropriate).
11. Costs of carbon emissions trading
or carbon capture and CO2 storage.
12. Incorporation of full "end-of-life"
costs, including decommissioning and "making good" the
land utilised.
Many people are now advocating a true "whole
life cycle" (or "cradle-to-grave") analysis for
each of the generating technologies, only then can a true cost
comparison be made. In sustainability terms (economic, environmental
& societal), to consider only construction and operating costs
is not considered adequate. Until the market (rather than society)
is forced to pay for these additional costs, it will continue
to only react to the known costs including regulatory and fiscal.
In addition countries and utilities look at a portfolio of plants
rather the costs of any technology in isolation, since a portfolio
approach will decrease risk.
Notwithstanding the above, recent published
studies demonstrate that nuclear power will generate electricity
at a cost comparable with gas or clean coal (fuel costs assumptions
for gas and coal greatly impact this analysis). These studies
focus primarily on construction and operating costs and, depending
on the study, take into consideration some of the factors listed
above, therefore the findings of these studies should be treated
with considerable caution.
On the subject of costs, Annex 1 provides a
list of recent studies, while Annex 2 provides a critical appraisal
of recent reports, as well as a summary of construction and operational
costs for different types of plants, as required by the Select
Committee.
With regards to the construction period, the
major issues to be considered are:
1. Availability of materials; for example
delivery times of eight months for certain steels is now commonplace.
2. Ability to pre-order major components
such as gas turbines.
3. Development period required to bring
a project from the drawing board to start of construction. This
is the principal area of uncertainty and this timeframe is highly
dependant on planning and permitting.
Bearing these issues in mind, the table below
provides an estimate of timescales for:
1. Project Development: starting from
project inception to a firm commitment to build (including all
regulatory and planning approvals).
2. Construction: starting from the
end of the Project Development phase to the production of the
first unit of commercial electricity (including detailed, site-specific
design, construction and commissioning).
| Plant type | Project development
| Construction | Total
|
| Months | Months
| Months |
| 800 MW CCGT | 24-36
| 24-30 | 48-66 |
| 900 MW coal (with FGD) | 24-36
| 30-36 | 54-72 |
| 800 MW IGCC | 36-48 | 30-40
| 66-88 |
| 1,000 MW nuclear PWR | 55-65
| 50-60 | 105-125 |
| 20 MW wind onshore | 24-36 |
12 | 36-48 |
| 100 MW wind offshore | 30-42
| 18-24 | 48-66 |
CCGT = Closed Cycle Gas Turbines
FDG = Flue Gas Desulphurisation
IGCC = Integrated Gasification Combined Cycle
PWR = Pressurised Water Reactor
Note that a reduction in project development timescales may be possible for nuclear and IGCC units following successful approval of the "first of a kind" plant. Though for the former a clear planning and regulatory framework is required.
QUESTION 2—SECOND
BULLET
With regard to nuclear new build, how realistic and robust
are cost estimates in the light of past experience? What are the
hidden costs (eg waste, insurance, security) associated with nuclear?
How do the waste and decommissioning costs of nuclear new build
relate to the costs of dealing with the current nuclear waste
legacy, and how confident can we be that the nuclear industry
would invest adequately in funds ring-fenced for future waste
disposal?
The UK track record in the construction of nuclear plants
is no longer a yardstick to forecast the future. Previous practices
were based on cost-reimbursable construction contracts managed
by the CEGB, where the designs often changed as the construction
progressed, resulting in cost and time overruns. The current deregulated
UK electricity market means that any future plants will be funded
largely by the private sector, based on commercial firm price
contracts with penalties for non performance, from established
international vendors where the design will be fixed before construction
starts. Worldwide experience (France, China and Finland) has shown
that this strategy produces plants that operate safely and reliably
with predictable construction and operating costs.
Nuclear fuel accounts for 5% of the overall cost of the electricity
produced in nuclear power plants, therefore any change in fuel
prices have little impact on the overall cost of electricity.
Notwithstanding the fact that market prices for nuclear ore have
trebled over the last two years, fuel costs are still considered
stable compared with natural gas.
Experts in the field believe that the costs of decommissioning,
waste disposal and security are all reasonably understood and
conservative provisions for all these activities should be built
into the cost projections for new nuclear plants. New plant operators
should establish a fund to finance decommissioning and waste disposal,
built-up from a proportion of operating revenues, this approach
has been adopted in other countries. The creation of financial
reserves for decommissioning and waste disposal should be made
a legal requirement on all nuclear plant owners.
Insurance of nuclear facilities is understood, as long as
current arrangements continue the insurance of new facilities
should be no different from the current facilities.
Government policy on waste management and the allotment of
costs for disposal of existing and newly generated waste will
determine the final cost of waste disposal. Investors will require
Government policy for nuclear power and its waste management together
with the associated costs to be clarified before committing significant
investment.
QUESTION 2—THIRD
BULLET
Is there the technical and physical capacity for renewables
to deliver the scale of generation required? If there is the capacity,
are any policy changes required to enable it to do so?
It has been demonstrated that, in theory, there are sufficient
renewable resources to provide the UK energy needs, although this
may not be the most cost-effective or publicly-acceptable solution
to meeting the energy needs of the nation. The growth of renewable
energy to date has been constrained largely by:
1. Cumbersome planning/permitting procedures.
2. Economic constraints.
3. Visual-impact considerations, as well as a "not in
my back yard" culture.
4. Long lead times in the power industry.
It is not yet clear how much these factors will change in
future, it is therefore considered unlikely that renewable sources
will be able to supply sufficient electricity to fill the gap
created by plant closures and increases in demand, for the period
under review.
From a technical and commercial viewpoint, power generation
from hydro-electric, tidal barrages, biomass, waste combustion
(using conventional boiler technologies) and landfill gas recovery
is very well-proven. Among the newer technologies, only onshore
wind and photovoltaics have truly passed the demonstration phase
and are now mature technologies exploited commercially. Many other
renewable technologies (wave, tidal, marine current, solar Rankine
cycles and offshore wind) are at different stages of development
and will require time to become commercially viable. Offshore
wind technology has now almost reached maturity and is expected
to make a significant contribution to meeting Government renewable
targets over the next 10 years. It should also be noted that well-proven,
non-generating, renewable technologies, such as solar thermal,
air, aquifer and ground-source heat pumps, as well as "passive"
solar buildings, can significantly reduce the amount of natural
gas required for domestic heating.
Government funding has provided a stimulus in academic research
to help exploit some of the renewable energy sources mentioned
above, although little support has been provided at the demonstration
and implementation stage of renewables and other low carbon technologies.
Funding in this area could significantly reduce the long lead
times in the industry to bring technologies to the commercial
stage and support potential exports.
A limiting factor to all generating technologies based on
large-scale centralised plant, is that a power transmission grid
infrastructure is required. As most renewable generation is from
relatively small-scale, de-centralised plants, embedded within
the distribution grid, this problem is largely alleviated, although
other problems are created and are currently being addressed.
This problem will however remain as long as power generation remains
located remote from consumption, as is sometimes the case for
wind power.
From a regulatory viewpoint, the Renewable Obligation Certificates
("ROCs") system appears to have provided a necessary
stimulus to develop renewable generation and needs to be extended
to certain other areas to ensure that Government's sustainability
and emissions targets are achieved. However, the market discontinuities
should the ROC quota ever be achieved (they become worthless)
does need to be considered when setting targets.
The financial incentives supplied by ROCs are expensive,
although one could foresee a reduction in subsidies in the future
as technologies mature and the true cost of carbon emissions become
apparent.
Support for early stage of technology adoption, upgrading
of the grid and streamlining of the permitting process, as well
as public re-education programs, are the areas that will provide
the greatest stimulus to the growth of the renewable sector. Furthermore
efforts to develop viable energy-efficiency measures will maximise
the effectiveness of renewable power generation and minimise the
impact of alternatives.
In any event the choice is not between nuclear and renewables
technologies, but rather to minimise the effect of ageing fossil-fired
plants, so that any additional growth in renewables beyond current
forecasts, can be used to cover the shortfall left by retiring
fossil fired plant.
QUESTION 2—FOURTH
BULLET
What are the relative efficiencies of different generating
technologies? In particular, what contribution can micro-generation
(micro-CHP, micro-wind, PV) make, and how would it affect investment
in large-scale generating capacity?
As for generation costs, defining plant efficiencies is complex
and open to debate. In addition efficiencies are only an important
comparator where fuel costs are a high percentage of total costs.
For nuclear plants, where fuel costs are low, or for many renewable
technologies where the "fuel" is freely available, efficiency
is not relevant. A better parameter to evaluate different types
of plants is on their lifetime costs.
Notwithstanding the above, the table below provides indicative
efficiencies for different types of new large scale generation
plant, where efficiency is defined as the ratio of output energy
over input energy.
| Type of new plant |
Plant efficiency (LHV) Low Heating Value |
| |
| 500 MW CCGT | 57%-60%
|
| 900 MW coal (with FGD) | 44%-50%
|
| 800 MW IGCC | 42%-50% |
| 1,000 MW PWR | 33%-35% |
With regards to micro generation:
1. Micro-wind typically consists of 1-2kW devices
for use typically rated at 12m/s wind speed.
2. Photovoltaic in the UK has a typical load factor
of around 8% and produces around 750kWh/kWp/year.
3. Micro-CHP units are available up to 6kW in size,
but a typical domestic unit will be 1-2kW.
Despite its size, micro-generation has several advantages:
1. It can make a significant contribution to an
individual building's energy requirement.
2. When aggregated across the country's building
stock, it would make a large contribution to energy requirements.
3. It serves as a potentially useful form of generation
to help manage peak load periods, thus reducing the overall large-scale
generating capacity required.
4. It helps provide diversity of supply and
5. It promotes customer engagement which helps to
focus customers on their energy usage.
To date market penetration of micro-generation has been very
slow and a large uptake from households will be required to make
any contribution to UK generation. Under the current capital grant
schemes, micro-generation will not have an impact on the planning
of new large-scale generating capacity.
If the Government were keen to support micro-generation,
it would have to consider:
1. More attractive grant schemes.
2. Availability of "two-way metering"
systems for the measurement of power used and power produced.
3. Exploiting the DIY/house owning culture in the
UK, which will install generation and heating schemes for prestige
as well as economy.
Funding for any of the initiatives proposed above should
not be at the expense of developing carbon abatement and renewable
technologies.
QUESTION 3—FIRST
BULLET
What is the attitude of financial institutions to the risks
involved in nuclear new build and the scale of the investment
required? How does this compare with attitudes towards investment
in CCGT and renewables?
Investment decisions by banks, utilities, investors and insurance
companies will depend on the perceived balance between risks and
financial returns compared not only with similar investments in
the electricity sector but also with investments in other sectors
of the economy.
Investors in the power generation sector (nuclear, fossil
and renewable plants) will closely analyse the following:
1. Market structure and its regulation, to ensure
that the investment will provide adequate, predictable and stable
cash flow over its lifetime.
2. Ability of the plant to repay its debt even under
adverse market conditions, and associated level of financial guarantees
provided by equity holders/government at different stages of the
plant life (construction, operation and de-commissioning).
3. Political and regulatory risk. Many organisations
consider this to be highly relevant given the recent track record
of insolvencies in the sector resulting from regulatory changes.
4. Potential environmental liabilities in the event
of an accident or at the decommissioning stage.
5. Structure of the investment, to ensure that each
stakeholder only bears those risks and liabilities that it is
capable of managing both from an operational and financial standpoint.
In comparing the perceived risks associated with nuclear
and CCGT plants, there are several differences that do not "favour"
nuclear:
1. Construction risks: costs overruns, construction
delays and performance guarantees
It is predicted that in future, nuclear and CCGT
plants will use similar contract strategies for plant construction,
demanding performance guarantees from contractors, thus removing
most construction risks from investors. The length of the construction
period (approximately five years for nuclear compared with two
years for CCGTs) coupled with potential delays (and therefore
cost overruns) arising from public interference on a new nuclear
plant build will cause investors to exercise a higher level of
scrutiny over this aspect. The present banking practices to postpone
the commencement of debt repayment until start of commercial operation
may also have to be revisited due to the long construction period.
2. Decommissioning
Although decommissioning costs are only a small
proportion of overall costs, and companies owning new nuclear
facilities will make financial provisions, the risk of decommissioning
cost overruns remains.
3. Political and regulatory risk
This issue is particularly relevant for nuclear
plants because of the long lead times providing more scope for
political intervention, change of Government, etc Changes in environmental/decommissioning
laws may also be a significant deterrent to investment.
4. Spent fuel and waste disposal costs.
5. Terrorist attacks on the plant or its supply
chain (although other forms of power generation suffer from the
same risk).
6. Potential for widespread public resistance (although
public attitudes are changing).
7. Availability of construction, plant operational
and environmental liability insurances.
8. Cash flow profile
Because nuclear fuel costs are low, the majority
of expenditure will be disbursed during the construction period,
while for fossil plants fuel costs are over 50% of total expenditure
and this cost can be financed from electricity sales.
On a risk spectrum, nuclear plants are going to be perceived
as more risky investments than CCGTs or other conventional fossil
fuelled power plants for all the reasons discussed above.
The perceived risks associated with renewable plants very
much depend on the technology used. Onshore wind is well proven
and perceived as very low risk, offshore wind, wave and tidal
are considered more risky but such perception will improve as
these technologies demonstrate a successful operational track
record. Photo-voltaics, hydro and biomass combustion are also
proven and low risk, while biomass gasification is still perceived
as risky. ROCs payments for renewable energy help to provide a
bankable revenue stream, thus reducing the overall investment
risks in these technologies.
It should be noted that it is impossible to discuss risks
in such a generic manner. Risks should be discussed in relation
to specific projects, since each project will have a unique risk
profile. At the extreme, even the development of a nuclear project
could be perceived as relatively low risk by investors, if all
the risks are taken by other parties.
The challenge will therefore be to structure the investment
in any new nuclear build, in such a manner that the risks to investors
and financial institutions are not substantially greater than
present investments in other forms of generation. If this can
be achieved, financial institutions will be willing to provide
long term debt facilities. Recent experience in Finland could
be one of the ways in which a nuclear project in the UK could
be financed.
Finally, the willingness of banks to finance a nuclear programme
will also depend on public acceptance of the technology, otherwise
their involvement will lead to adverse publicity and damage their
retail business.
QUESTION 3—SECOND
BULLET
How much Government financial support would be required to
facilitate private sector investment in nuclear new build? How
would such support be provided? How compatible is such support
with liberalised energy markets?
Government support can be provided in several ways:
1. Direct financial support.
2. Absorbing some of the risks that would otherwise
be carried by investors.
3. Providing a stable environment that will ensure
long term regulatory and commercial certainties.
Current estimates indicate that the economics of new nuclear
plants are robust and do not require Government support for construction
and operation. However, before commercial companies decide to
invest, they will require confidence that the engineering design
is going to be acceptable to the regulatory bodies, primarily
the NII and EA (or SEPA), and that it is likely to receive a licence
to allow construction. The assessment of the potential nuclear
power plant designs and their licensability is a pre-licensing
activity that will need to be requested by the Government. For
this activity to be perceived by the public as a truly independent
assessment of the technology, it will require Government funding
with minimal involvement from potential owners and vendors.
Once the technology has been assessed as licensable, it will
be up to commercial companies to seek the necessary licenses,
finance construction and to put in place electricity trading contracts
to assure a return on the investment. Such an approach is entirely
compatible with a liberalised energy market.
Any risks in excess of the risks currently taken by investors
in funding CCGTs or projects using established renewable technologies,
will have to be borne wholly or in part by government. Depending
on the structure of the project, these may include certain aspects
of construction, operation, insurance and decommissioning risks
that can not be covered by the private sector.
Any involvement by government, in the development/implementation
of a single project, providing investors with a competitive advantage
is incompatible with a liberalised energy market, particularly
if government were to supply financial support/guarantees to individual
private companies, even if such support were in some way "ring
fenced".
However it is the responsibility of governments to set direction,
address market failures, and to put in place policies and measures
that minimise, for example, the risk of power supply disruptions
and to develop regulations to ensure that liberalised markets
have adequate incentives to support government policies. An obvious
case in point is the current government support for the renewable
sector. In this respect providing clear and predictable regulatory
and policy framework, to remove uncertainty for potential investors
in nuclear power would not be incompatible with a liberalised
energy market.
QUESTION 3—THIRD
BULLET
What impact would a major programme of investment in nuclear
have on investment in renewables and energy efficiency?
With regards to the issue of capital flows, it is believed
that there is sufficient liquidity in the market to finance any
project in the power sector, provided that such project has been
properly structured and risks have been adequately mitigated.
Lack of liquidity would only arise if the market were to
perceive the electricity sector as more risky than other industrial
sectors. It is the responsibility of governments and regulators
to ensure that this problem does not develop. The regulatory track
record in the UK of frequent legislative changes, uncertainties
with carbon emissions, combined with recent energy market price
volatility, means that financial institutions will be much more
cautious in future in financing any new major development in fossil
generation. Financing of renewable projects on the other hand
is considered an easier proposition because of the government's
regulatory and financial support for the sector, the small size
of each individual investment and the comparatively short lead
times.
It is considered that replacing nuclear capacity with nuclear
will not in itself have a detrimental influence on renewables
and energy efficiency, provided that policies and incentive mechanisms
in these areas are adequately maintained. Furthermore, new build
is likely to be funded by the private sector/privatised companies,
rather than public funds.
The main effect of new nuclear capacity will be to discourage
the construction of additional gas or coal plants.
In addition, any near-term investment in nuclear is likely
to be in construction rather than research and development ("R&D"),
as leading contender designs for new nuclear plants have already
been approved and licensed in other Western nations, and in some
cases new plants are already under construction. Therefore a major
investment in nuclear will not affect R&D for renewables,
energy efficiency or clean coal technology/carbon sequestration.
QUESTION 4
If nuclear new build requires Government financial support,
on what basis would such support be justified? What public good(s)
would it deliver?
The Energy White Paper states that reducing carbon emissions,
maintaining a secure electricity supply and providing affordable
electricity are important goals for the UK. A nuclear construction
programme will contribute to fulfilling these goals. Government
should therefore:
1. Provide policy support for nuclear power.
2. Work towards public acceptance of this technology
to ensure its continuing role in a mixed generation portfolio.
3. Ensure that the proposed new nuclear plants are
safe and environmentally acceptable through regulatory scrutiny.
If commercial organisations then decide that there is an
economic incentive to build such plants then the Government should
provide support at a policy level rather than through direct financial
support.
QUESTION 4—FIRST
BULLET
To what extent and over what timeframe would nuclear new build
reduce carbon emissions?
Given current regulatory and political timeframes, it is
expected that it will take five to six years before building of
a new nuclear station could begin. Coupled with a five year build
period, the first nuclear plant will not be operational before
the middle of the next decade. Assuming a further construction
programme of one 1,000 MW unit a year, it will take almost a further
decade to replace the nuclear capacity scheduled to close over
this period.
Based on the timeframe forecast above, new nuclear capacity
will not be built in time to replace retiring plants. Consequently
the power generation "mix" will comprise primarily of
fossil and renewables together with a declining proportion of
nuclear. It is therefore expected there will be an increase in
carbon emissions form the power generation sector over the next
15 years.
Such a nuclear programme cannot provide short-term emission
reduction from the present levels, but it will ensure that emission
increases are minimised and, in the long-term, stabilised. The
construction of each new nuclear plant will avoid the production
of over three million tonnes of CO2 per year by negating
the need for new CCGT plants. This figure would be even higher
for clean coal or LNG fuelled plants.
QUESTION 4—SECOND
BULLET
To what extent would nuclear new build contribute to security
of supply (ie keeping the lights on)?
Security of supply is determined by several factors:
1. Availability of stand-by generating capacity.
2. Electricity grid redundancy.
3. Availability of fuels.
4. Quality of operational staff.
Nuclear generation contributes to security of supply by reducing
fuel supply risks and providing large amounts of reliable base-load
generation:
1. Plants are relatively immune from fuel shortages
and supply disruptions as reactors are refuelled on a bi-annual
basis.
2. Even if there were to be a problem in replacing
fuel, and a scheduled refuelling were missed, a nuclear station
would not have to close. Unlike a conventional fossil station,
the output power level would decrease steadily over several months.
3. Fuel requirements are very low—finished
fuel requirements for a fleet of 10 new reactors would be of the
order of 100m3 per year—small enough to easily fit into
a modest house. It is therefore perfectly feasible to maintain
a strategic stock of fuel, in case of interruptions to supply.
4. Uranium is estimated to be relatively abundant
and available from stable and friendly sources, eg Australia and
Canada.
5. There are no specialised transport or infrastructure
requirements for the import of uranium, unlike gas which requires
pipelines, LNG transport vessels, import terminals and specialist
storage facilities.
6. Increased diversification in fuels and fuel suppliers,
thus reducing risk.
7. Reducing reliance on gas supplies sourced from
politically unstable regions of the world.
In addition, nuclear plants in the generation mix serve to
temper price volatility.
It is also relevant to note that to ensure reliability and
avoidance of accidents, it is important to create an environment
where some of our best Engineers are employed in the nuclear industry;
where the availability of operational, maintenance and service
staff will be fundamental to security of power generation supply.
This needs a realistic and supportive training culture to be embedded
within the power sector's regulatory structure, to ensure that
the operational phase is fully supported. It will not simply happen
by itself.
QUESTION 4—THIRD
BULLET
Is nuclear new build compatible with the Government's aims
on security and terrorism both within the UK and worldwide?
Yes, nonetheless like any strategically important infrastructure
facility, there will always be a need to consider the implications
of malicious attack on a nuclear plant. However this risk can
be reasonably managed because:
1. Nuclear power plants are some of the most robust
civil structures ever constructed and can withstand massive impacts.
2. Safety and security measures built into these
plants means that they are relatively protected against sabotage
and external attack.
3. Civil nuclear power plants are subject to regulation
by the Office of Civil Nuclear Security (OCNS) which liases closely
with NII. The NII has the specific remit to ensure security of
such installations, and the ability to close them if not satisfied
that security can be assured.
4. The number of plants is limited and each plant
is in a single location of limited size, it is therefore much
easier to secure than pipelines running across continents. However
the security arrangements for the nuclear fuel supply chain from
exporting countries will also need to be protected.
5. Nuclear fuel is not sourced from politically
unstable or hostile countries.
Given the recent level of terrorist activities, it would
be advisable for the UK to review its security measures not only
for power plants, but also for the transmission network, because
this is the most vulnerable part of the electricity infrastructure.
QUESTION 5
In respect of these issues [Q 4], how does the nuclear option
compare with a major programme of investment in renewables, micro-generation,
and energy efficiency? How compatible are the various options
with each other and with the strategy set out in the Energy White
Paper?
The IMechE advocates that a balanced approach to the development
of new power generation is the best and safest approach to meeting
the goals set in the Energy White Paper. Therefore the use of
a mix of renewable, fossil and nuclear sources, micro-generation
and energy efficiency measures is recommended to a point where
the country is not overly reliant on any one option.
Within the advocated generation mix, new nuclear plants that
approximately offset retired nuclear capacity, will offer:
1. A secure base-load supply of electricity that
complements modulating generation produced from gas and coal.
2. Technological and fuel diversification, thus
reducing overall generation risks.
3. Long-term stabilization in carbon emissions by
avoiding the need for additional new coal and gas fired plants
to cover the shortfall.
4. Electricity production at competitive prices,
thus allowing for the provision of financial incentives to further
develop renewable energy sources, micro-energy systems and the
hydrogen economy.
Renewables, micro-generation and energy efficiency measures
will almost certainly not, on their own, provide sufficient generation
to meet demand in the available timescale, even if a major programme
of investment were undertaken. Constraints for growth are mainly
associated with permitting and public acceptability (although
these issues are by no means restricted to renewables). An investment
programme will help but not significantly remove these obstacles;
diverting resources from nuclear, clean coal technologies and
traditional forms of generation could endanger security of supply,
carbon reduction goals and could be an extremely risky political
and economic strategy.
Although this Inquiry is focussed primarily on the role of
nuclear and renewable technologies, the IMechE believes that developments
in industry-related areas such as advanced clean fossil power
generation, CO2 capture, storage and Enhanced Oil Recovery
technologies, should also be further encouraged to retain fuel
diversification and provide potential export opportunities.
Investments in the development of a nuclear program, renewables
and clean coal technologies are not incompatible, on the contrary
they are all necessary to ensure a diversified generation mix
thus ensuring security of supply.
QUESTION 6
How carbon-free is nuclear energy? What level of carbon emissions
would be associated with (a) construction and (b) operation of
a new nuclear power station? How carbon-intensive is the mining
and processing of uranium ore?
As with many issues regarding nuclear power, there is a wide
range of numbers available depending on the source.
The most thorough study of CO2 emissions from
nuclear plants has been carried out by Vattenfall in Finland,
for its 3 PWRs and their BWR (Boiling Water Reactor). The results
were published in their 2004 Environmental Product Declaration
publication and show CO2 emissions of 3.3 grams per
kWh.
British Energy carried out a similar independent study for
the life-cycle emissions associated with the AGR nuclear power
station at Torness, the results are shown graphically below and
indicate CO2 emissions of 5.05 grams per kWh:
When compared with operational emissions of gas and coal
fired plants, CO2 emissions / kWh from a nuclear plant
through its life-cycle are about a factor of 80 and 180 lower respectively.
The most comprehensive generic study that compares the amount
of greenhouse gases generated by power plant "chains"
which include fuel production, construction, operation and decommissioning
was undertaken by the IAEA in 2000. The findings are shown in
graphical form below:
QUESTION 7
Should nuclear new build be conditional on the development
of scientifically and publicly acceptable solutions to the problems
of managing nuclear waste, as recommended in 2000 by the RCEP?
Scientifically acceptable solutions to deal with nuclear
waste are already available and have been adopted by countries
around the world. CoRWM is due to report in 2006 and will make
recommendations based on extensive public consultation, it will
then be up to DEFRA to adopt and implement these recommendations.
It is important to reach practical compromises balancing
public and media opinion, with cost effective engineering solutions.
This will require government, in partnership with industry and
professional engineering institutions, to engage the public openly,
to address their concerns through the provision of facts and credible
arguments.
While some significant movement towards an acceptable solution
is required to provide public confidence in the industry and the
technology, it is most likely that licensing of new nuclear plants
will be required before these issues have been completely resolved.
Delays in licensing will threaten the security of our electricity
supply, potentially de-stabilise energy prices and lead to increased
carbon emissions. The process of licensing a new nuclear design
will take time and it should be started as soon as practical,
in the expectation of a successful output from the CoRWM process.
Finally it is worth noting that additional nuclear reactors
will have little impact on the volume of accumulated nuclear waste
to date. Replacing all the current UK nuclear capacity with AP1000
reactors would add, over their lifetime, under 10% in volume to
the UK's nuclear waste inventory. In addition spent fuel can be
safely stored for at least a century on the reactor site, making
a new build programme technically independent of a long term waste
solution.
Annex 1
COST OF GENERATION (LIST OF SOURCES)
| Source Ref | Date
| Author | Title
|
| Eon | 9 August 2005 | Fathing
| Power Technology response |
| CER | 26 July 2005 | Foley
| Best New Entrant Price 2006 |
| DTI | 1 June 2005 | DTI
| Microgeneration Strategy And Low Carbon Buildings Programme
|
| IEA/OECD/NEA | 1998 | NEA
| Projected Costs of Generating Electricity: 2005 Update
|
| SPRU | 5 November 2004 |
Awerbuch & Sauter | Exploiting The Oil-Gdp Effect To Support Renewables Deployment
|
| IMechE | 1 May 2004 | IMechE
| UK Energy Policy—Challenges and Opportunities
|
| APGTF | 1 May 2004 | Otter
| A Vison for clean Fossil Power Generation |
| Carbon Trust | 1 April 2004
| Mott MacDonald | Renewable Networks Impact Study
|
| BWEA | 10 March 2004 | BWEA
| True Cost of Wind Power |
| RAE | 1 March 2004 | PB Power
| Cost of Generating Electricity |
| OXERA | 1 February 2004 |
OXERA | Results of renewables market modelling
|
| OECD/NEA | 10 November 2003
| OECD/NEA | Nuclear Electricity Generation: What are the External Costs
|
| CCS | 1 September 2003 |
DTI | Review of the Feasibility of Carbon Dioxide Capture and Storage in the UK
|
| DTI No 4 | 1 June 2003 |
DTI | DTI Economics paper No 4 Options for a Low Carbon Future
|
| EWP Annex | 7 March 2003 |
FES | ENERGY WHITE PAPER—Supplementary Annexes
|
| EWP | 1 February 2003 | DTI
| ENERGY WHITE PAPER—Our Energy Future—Creating a Low Carbon Economy
|
| FES | 1 February 2003 | FES
| Options for a Low Carbon Future—Phase 2
|
| Awerbuch | 1 January 2003 |
Awerbuch | The True Cost of Fossil-Fired Electricity in the EU: A CAPM-based Approach
|
| ExternE | 2003 | EC
| External Costs: Research results on socio-environmental damages due to electricity and transport
|
| Ilex/UMIST | 1 October 2002
| Strbac | Quantifying the System Costs of Additional Renewables in 2020 (SCAR Report)
|
| IEA | 5 September 2002 |
Awerbuch & Berger | Energy Diversification and Security in the EU: Mean-Variance Portfolio Analysis of Electricity Generating Mixes and its Implications for Renewables
|
| PIU | 1 February 2002 | PIU
| Performance and Innovation Unit Report, The Energy Review
|
| IEA | 2001 | IEA
| Nuclear power in the OECD |
| RCEP | 1 June 2000 | RCEP
| Energy the Changing Climate |
| ExternE | 1999 | EC
| ExternE: Externalities of Energy: National Implementation
|
| Treasury | 1 November 1998 |
Marchshall | Economic Instruments and the Business Use of Energy
|
| IMechE | 1998 | IMechE
| 2020 Vision: The Engineering Challenges of Energy
|
| IEA/OECD/NEA | 1998 | NEA
| Projected Costs of Generating Electricity: 1998 Update
|
Annex 2
COST OF GENERATION (APPRAISAL OF RECENT REPORTS)
This analysis sets out to collect and summarise electricity
generation costs worked out by and reported from four "up
to date" and recognised sources, which give international
as well as UK coverage. These are:
| Royal Academy of Engineering (RAE) |
Cost of Generating Electricity, March 2004 |
| International Energy Agency |
Projected Costs of generating Electricity 2005 |
| Enviros Consulting Ltd |
Costs of Supplying Renewable Energy 2005
|
| Canadian Energy Research Institute (CERI) |
Economics of Nuclear Power 2005 |
The figures given are based purely on "financial"
costs and do not take account of the societal and environmental
impacts of each of the technologies as would be required by a
"sustainability" analysis.
There are many other papers on this subject but these are
often examining one specific generation route only, eg wind-power.
Others are directed primarily at intermittency of renewables and
carbon saving capability; this analysis does not attempt to address
either of these issues. Many of these more specialised papers
reference and use data from the above sources.
The RAE, Enviros and CERI papers provide an established typical
plant cost without detail of the various sources. The IEA Report
lists all the plants used in their data gathering, column 2 below
shows the average of this data. Column 4 gives an average from
1, 2, and 3. The "range" of costs is established from
the scope of plants listed by the IEA paper (leaving out non standard
extremes) and this range is extended to include overflow of costs
from 1 and 3, where this arises.
It is not claimed that the reported figures below are precise
values, there is obviously much variation in plant costs dependent
on country, location, financing route and other project details,
for instance discount rates ranging from 5% to 10% may be used
in calculating production costs. It can also be misleading to
try to make direct comparisons between the purely financial costs
of a newly-developed, privately-funded technology with that of
conventional, often state-funded, technologies. Conversion rate
for $/£ varies with time. It is not practical to re-adjust
all figures to a common base.
PLANT CAPITAL COSTS IN £/kW OF CAPACITY
|
1 |
2 |
3 |
4 |
5 |
| Plant Type | RAE | IEA (average)
| CERI | Average | Range
|
| Coal | 818 | 781
| 800 | 799 | 469-937
|
| Gas | 315 | 375
| 352 | 347 | 225-626
|
| Nuclear | 1,150 | 1,093
| 1,173 | 1,138 | 687-1,562
|
| CHP | — | 750
| — | 750 | 343-1,060
|
| Wind Onshore | 740 | 805
| — | 805 | 625-1,062
|
| Wind Offshore | 920 | 1,265
| — | 1,093 | 920-1,656
|
| Wave | 1,400 | —
| — | 1,400 | —
|
| Biomass | 1,840 | —
| — | 1,840 | —
|
| Hydro | — | 1,875
| — | 1,875 | 937-4,753
|
| Solar | — | 2,819
| — | 2,819 | 2,026-6,526
|
ELECTRICITY COSTS IN p/kWH (INCLUDING CONSTRUCTION COSTS
BUT EXCLUDING CARBON COSTS)
|
1 |
2 |
3 |
4 |
5 |
6 |
| Plant Type | RAE | IEA(Average)
| CERI | Enviros | Average
| Range |
| Coal | 3.54 | 2.37 (1.75-3.68)
| 2.95 | — | 2.95
| 1.75-3.68 |
| Gas | 3.10 | 2.37 (2.6-3.69)
| 3.75 | — | 3.29
| 2.68-3.75 |
| Nuclear | 2.26 | 2.03 (1.94-3.25)
| 3.65 | — | 2.64
| 1.94-3.65 |
| CHP | — | 2.99 (2.19-5.0)
| — | — | 2.99
| 2.19-5.0 |
| Wind Onshore | 5.35*** | 5.04* (2.87-9)
| — | 4.0-10.0 | 5.19
| 2.87-10 |
| Wind Offshore | 7.19*** | 5.04*
| — | 7.5 | 6.57
| Up to 10 |
| Wave | 6.63** | —
| — | 13.7 | 10.16
| — |
| Biomass | 6.67 | —
| — | 6.6 (2.7 |
| |
| co-fire) | 6.63 | —
| | | |
|
| Tidal | — | —
| — | 10.8 | 10.8
| — |
| Hydro | — | 4.06
| — | 6.7-8.4 | 5.8
| 3.87-9.25 |
| Solar | — | 36.1
| — | 55.5 | 45.8
| 12.5-117 |
| | |
| | | |
Note:
* IEA costs for "on and offshore" wind are combined.
** Cost predicted from prototype data.
*** These figures include highly controversial and contested figures for "back-up" supply costs; without this, the figures are 3.68 (not 5.35) for onshore wind and 5.5 (not 7.19) for offshore.
GENERAL OBSERVATIONS
The cost range for all technologies is quite wide and indicates
that, whereas the basic hardware costs are well established, other
project factors, which include discount rate, country economy,
location and installation/hook up details etc. strongly influence
the final costs. Volatility of fuel prices, waste disposal costs
and "end-of-life" plant costs have not been included
in these figures. Furthermore, historical cost curves showing
technology advances, confidence by financiers with respect to
risk and growth in capacity have demonstrated that capital and
generation costs of the newer technologies will continue to fall.
OBSERVATIONS FOR
COAL PLANTS
UK costs appear to be at the top end of the range. It should
be noted that the coal plants referenced by IEA numbered 27, being
mainly PF or FBC, however there were three IGCC plants included,
of which two were within the cost range and the third (proposal
only), which included carbon capture, was marginally over the
cost range for coal at £1,030/kWe and its production cost
was reported at 3.7p/kWh.
OBSERVATIONS FOR
GAS FIRED
PLANTS
The IEA referenced 23 plants, all of which were CCGT except
one. On the face of it, gas would seem to be competitive with
coal, but it is not thought that any of the reported gas plant
performances has taken into account the escalating wholesale gas
prices (approximately 40% change over the last year has been stated).
If this trend were to continue, gas plant costing will need to
be re-assessed, bearing in mind that up to 70% life costs are
accounted by fuel. It is worth noting that a major new build of
gas fired plants to strengthen the grid was planned in the USA
two years ago, but because of high local gas prices, this programme
has been replaced with a "coal build" one.
OBSERVATIONS FOR
NUCLEAR PLANTS
Plant costs are becoming reasonably established for standardised
PWR and BWR, both cost and delivery are being endorsed by various
plants recently or currently being built, there are about 16 projects
in progress in the far East. The technology is basically competitive
but economics are influenced by the more complex long term funding
arrangements needed. Besides the reported plant costs, a further
costing by MIT in 2004 cited a capital cost of £1,111/kWe
and production cost of 3.6p/kWh—just above the range but
explained by a higher 12% interest rate. Discount rate (or rate
of return) is the biggest influence on nuclear economics.
OBSERVATIONS FOR
RENEWABLES
There is not yet much useful data on tidal and wave costs
to facilitate cost range reporting and reported solar photovoltaic
data is also sketchy, which is disappointing as both Germany and
Japan have extensive installations. It is clear, however, that
none of these technologies is yet near financial competitiveness.
Biomass is more financially competitive for co-firing than for
dedicated plants, although this does not take account of the benefits
that these dedicated plants will have on distributed generation.
The main core of large-scale hydropower is longstanding and installation
of new landfill gas sites is reaching a limit.
The most financially competitive source of renewable energy
is currently wind power, where much more information on costs
is available. It is clear that whereas engineering and hardware
costs are well defined, the overall project costs are strongly
influenced by other factors including load factor, country, site,
grid connection, accessibility and other details, both IEA and
Enviros report a wide range of prices. Windpower Monthly Data
also reports costs ranging from 2.9p/kWh to 5.0p/kWh onshore and
5.2p to 6.9p offshore. Enviros notes that with the best sites
onshore costs of 4p/kWh are likely, but notes that the best sites
are rapidly being used up. Over 3,000 MW of new installation has
been applied for, much off shore, and about 500 MW of build is
thought to be in hand. To date just over 1,000 MW of wind-power
is operational and this produced 1,905 GWh in 2004.
In conclusion, reliance in basing energy planning on typical
costs for plant types, related mainly to the hardware costing
is questionable, as the project circumstances, location and conditions
can vary the final price significantly. Also awareness of probable
fuel cost increases is likely to be a much more important ingredient
in future pricing.
21 September 2005
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