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2005 Feb, Nuclear Issues v27 02 |
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Written by Nuclear Issues
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Tuesday, 01 February 2005 |
Nuclear Issues is also available as a pdf download
Follow the U.S. example
America generated a prodigious amount of electricity from nuclear power
last year. With 103 plants operating for an average of 90.6% of the
time at full power the total output for the whole country was a record
786.5 TWh. But the important thing to realise is that this sort of
production can continue for twenty to thirty years. As we reported in
Nuclear Issues in December, most U.S. plants have either obtained or
are well advanced in applying for licence renewal and there is no
reason why they should not go on operating safely, cleanly and reliably
for years to come.
And cheaply. The average cost of electricity produced by nuclear power
last year in America was an incredible 1.7 cents per kWh – cheaper than
gas, oil or coal and minute compared with the cost of wind power.These
costs will get even lower while other fuels are set to keep on rising.
Compare this happy situation with the sad state of affairs in the U.K.
Nuclear power production is already declining as we start to retire
early plants, and in about ten years time we will be left with just one
plant – Sizewell B.
Of course there is talk on both sides of the Atlantic of building some
new plants some time. The Americans are much more advanced than we are
with five different plants already approved by the Nuclear Regulatory
Commission and several groups of utilities already deeply involved in
preliminary site licensing procedures. In the U.K. there is nothing. No
regulatory approval; No site selection; No plans! Yet these things will
take years to achieve and in the meantime nuclear power is declining
unlike the U.S. where it has at least twenty or thirty years more.
Nuclear generation
France generated a record 426.8 TWh in 2004 which was no less than
78.1% of the country’s total consumption of electricity. The total
electricity production increased by 1.1% to 546.6 TWh.
Finlands nuclear plants produced 21.8 TWh in 2004 which was 25.1% of
total electricity in the country.The total electricity consumption
continues to rise increasing by 2% to 86.8 TWh.
Armenia's one operating plant at Metsamor 2 produced 2.4 TWh, a record
since the reactor was restarted in 1995. This represents 44% of Armenia
electricity consumption. Next, the plant hopes to increase output
further to2.5 TWh
Switzerland is limited to just five nuclear plants but with an amazing
90.2% average load factor there output of 25.43 TWh still represents
40% of the country’s electricity.
Germany’s 18 operating plants had a load factor of 89.8% in 2004
compared with 87.7% the previous year.This meant they generated 167.1
TWh. It is impossible to imagine what will replace this if the country
persists with its crazy nuclear phase out plan.
Ukraine produced 87 TWh of nuclear electricity in 2004 compared with
81.4 TWh the previous year. This is 48 % of total electricity in
Ukraine compared with 45.3% in 2003. The average capacity factor also
rose from 78.5% to 81.4%. With two new plants at Khmelnitshi 2 and
Rovno 4 next year should be better still.
Argentina has two operating plants, Atucha 1 and Embalse. These
increased output from 7.3 TWh compared with 7 TWh in 2003. Atucha 1
produced 2.7 TWh and Embalse 4.6 TWh which totalled 8.6% of the
country’s consumption. Work is at last about to proceed on Atucha 2
which had been halted in 1994.Completion should take about 52 months
and add a capacity 750 MWe.
Romania with one operating plant at Cernavoda 1 generated 5.1 TWh of
nuclear electricity in 2004. The average load factor was 89.7%.
Czech Republic’s two stations at Dukovany and Temelin produced 26.3 TWh
in 2004 compared with 25.9 TWh the previous year. This slightly
increased the share of total production from 31% to 31.3%. Average load
factor of the six reactors was up from 78.5% to 80.2%.
Worldwide the capacity of nuclear power plants increased. There were
seven new plants with a total capacity of 7529 MWe while only five
mostly smaller plants were retired with a total of 1381 MWe. Thus the
net increase was 6148 MWe. New plants were Ulchin 5 & 6 in South
Korea each 960 MWe, Qinshan 3 in China producing 610 MWe, Hamaoka 5 in
Japan with a massive capacity of 1380 MWe, the famous Khmelnitsky 2 and
Rovno 4 in Ukrane each 950 MWe, Kalinin 3 in Russia at 950 MWe and the
restarting of Bruce 3 in Canada producing 769 MWe. Closures were four
small 49 MWe plants at Chapplecross in the U.K. and for stupid European
Union politics the 1185 MWe plant at Ignalina 1
The cost of renewables (2)
According to a critical report by the National Audit Office the cost to
the electricity consumer, through the Renewables Obligation, and to the
public for direct support of the Government targets for renewable
electricity is even higher than the figures given last month. By 2010,
public support for the renewables sector is expected to cost consumers
and taxpayers over £1 billion a year, the equivalent of a 5.7%
increased in the price of electricity. The greater part of this is
accounted for by the Renewables Obligation.Already between 2003 to 2006
the support costs are put at £700 million a year. This is made up by
£470 million from the Renewables Obligation; £30 million
from the exemption from the Climate Change Levy; £180 million from
government grants and other public support (including surprisingly the
National Lottery); and EU research funding.
But this is not the only cost. In addition to this subsidy the NAO
finds that a substantial reinforcement of the grid network will be
required. Electricity is transmitted long distances in Great Britain
via the transmission network, and to users through local distribution
networks. The connection to these networks of renewable energy
projects, often in new and remote places, will affect the flow of
electricity across the system. The cost of upgrading is put at between
£1.1 - £1.3 billion by 2010. Although these costs will initially be met
by the owners of the transmission networks they will ultimately fall on
the consumers. A number of specific enhancements have already been
identified and Ofgem has so far approved proposals for £560 million of
funding for the first stage of this work.
The NAO usefully identifies three successive stages of innovation.
‘Blue skies’ projects are many years away from commercial
application and require support from research grants; they include
wave, tidal and solar energies. Whether or not the problems in bringing
these technologies to commercial use can be solved must remain
uncertain. Next come the ‘pre-commercial’ developments of offshore wind
and biogas which are supported through capital grants with the hope
that they will eventually develop to the third stage of ‘Closer to
market’ technologies – onshore wind, landfill gas and biomass
co-firing. These are supported through the Renewables Obligation in the
expectation that they will eventually by a process of ‘learning by
doing’ develop to the stage of providing power at a competitive price.
But none of this is yet fully established. The NAO notes that the DTI
has allocated capital grants of £117 million to 12 projects for
offshore wind, but only two of these are now fully operational. It
expects the remaining projects to come online in the next three years,
to give a total capacity of over 1,000 megawatts.
Much larger offshore wind farms in the future could provide up to seven
times as much capacity. But as the NAO points out it is too early to
say with confidence the extent to which experience from the first round
of offshore wind farms will help reduce the costs of construction and
operation. “These, and other factors, will determine the case for
support being provided to future offshore wind projects.” Neither the
NAO of the Government seem to have considered the consequences if the
experience gained fails to substantiate the expectation that the costs
of construction and operation will indeed be reduced.
The load factors so far achieved are not promising. Figures given by
the NAO for 2003/4 show that for onshore wind 1,234.9 GWh were
generated from 625.4
MWe of capacity; a load factor of 22.5%. For offshore wind only 43.8
GWh were generated from 63.8 MWe of a capacity showing a load factor of
under 8%. This low figure may in part be due to the small number of
projects on which it is based, most of which may still be only in the
start-up phase. It does show that the DTI assumptions that 40% or more
will be achieved is far from reality.
How much will be built?
Contrary to most informed expectations the NAO’s consultants are of the
opinion that the target of 10% of electricity from renewables is likely
to be met, even though during 2003-04, the second year of the
Renewables Obligation, the level of electricity from eligible
technologies accounted for 2.4 per cent of total supply in Great
Britain, significantly below the 4.3 per cent Obligation level.
Achievement of the 10 per cent target will require a more than
four-fold increase in renewable generation by 2010.
The expectation that this will be achieved comes from an assessment in
December 2004 by Ernst & Young, which rated the United Kingdom’s
renewable energy market as one of most attractive in the world for wind
power. In addition to payments under the Renewable Obligation scheme,
where the buy-out price is now £30/MWh, with certificates trading at
even higher prices, the operators also receive the full payment for the
power they produce. With electricity prices now around £30/MWh and
likely to rise by at least 10% when the EU carbon trading scheme is
fully operational, the renewable generators can expects to receive
about £60/MWh. This is almost double the on-shore wind generation cost
which the Royal Academy of Engineering in its 2004 report
generously put at about £35/MWh. (an additional cost for standby
generation, at about £16/MWh, is borne by the electricity consumer, not
by the wind generator). Not surprisingly a number of utilities – EON,
RWE, EDF – already established in the UK, as well as Elsam, and Dong
from Denmark, Norsk Hydro, Statkraft from Norway as well as oil
companies such as Shell and even British Energy are eagerly investing
in wind projects in the UK.
Nuclear is cheaper
The NAO report points out that in terms of cost per tonne of carbon
emissions saved, the Renewable Obligation, estimated at between
£70-140/ tonne, is by far the most expensive of possible mesures. Costs
for alternatives such as the EU carbon trading scheme are put at
£3-21/tonne; exemption from the Climate
Change Levy at £5-11/tonne; while energy efficiency measures (doing
without or making do with less) range from a negative cost up to
£16/tonne. The DTI however insists that the much greater potential for
emission savings from the support for renewable energy through the
Renewable Obligation justifies the expense. The words nuclear energy do
not appear in the NAO report.
The report does however repeat the DTI claim that the target 10% of
electricity from renewables would reduce carbon emissions by 9 million
tonnes a year by 2010. This figure appears to be based on the
assumption that 38 TWh of renewable electricity would replace
coal-fired plant emitting about 250 000 tonnes of carbon per TWh
generated. But the cost of subsidising the 10% electricity is already
at £700 /year, from 2003- 2006, and will rise to £1000 million by 2010.
This indicates that the total public subsidy by 2010 could amount to
about £5.5 billion, to which should be added the £1 billion required to
strengthen the transmission network, to give a total of £6.5 billion.
There is in addition the capital cost of the renewables, but this would
be borne by the generating companies and recovered through electricity
charges. The large wind component of the renewables programme means
that the electricity supply would be as an unpredictable output
requiring a significant standby of fossil-fired plant to cover for
those periods – 75% of the time – when the wind generation would not be
available.
The 38 TWh assumed to come from renewables by 2010 could be generated
by five 1000 MWe nuclear power stations. With a capital cost at
£1000/kW for a series of stations to the same design the cost would be
£5 billion. None of this however would require a public subsidy. The
power output achieved would be reliable; load factors of 90% or more
are regularly achieved by modern nuclear stations which can have
operating lives of up to 60 years.
But looking beyond the 10% of electricity by 2010 the retiring chairman
of BNFL, Hugh Collum pointed out in the annual report for 2004 that
“with twenty-first century technology, nuclear energy could supply 25%
of the UK’s electricity requirement from just ten new reactors on three
existing nuclear power station sites.
Nuclear waste from these modern reactors would be reduced by 85%, the
price of electricity would be competitive with gas and the electricity
baseload would be guaranteed with more than 90% utilisation at all
times. This would ensure ongoing security of supply for the UK and help
the country to meet its commitment to reduce emissions and greenhouse
gases. All this is technically possible, but the UK now needs to take
the strategic decision to adopt a balanced energy policy and to agree
the method for handling historic and future nuclear waste. Without this
decision, the UK’s future energy supplies will remain at risk.”
Lessons from Canada
The slow, even if small, decline in performance of British Energy’s
nuclear stations in the last few years must be a cause for reflection.
Nuclear generation has fallen from 67.6 TWh in 2001/2 to 65 TWh in
2004/4 and with the target for 2004/5 at 59.5 TWh. If this is not just
a temporary blip but the start of a downward spiral – reduced earnings
leading to reduced spending on plant maintenance leading to more
outages – what are the causes; and can they be rectified? Or is this
the inevitable consequence of an ageing plant? BE has listed to a
number of “risk factors” which could affect performance – including
corrosion of sea water cooling pipework, corrosion of concrete
prestressing tendons, boiler tubes, graphite bricks, and general
obsolescence of components and computer systems. Mike Alexander the
chief executive recently ascribed the poor reliability of the plant on
the lack of maintenance under the previous management. Experience from
Canada suggests other factors were responsible. It should be useful to
consider whether these might apply here.
Ontario Hydro was Canada’s largest nuclear electricity generator.
Between 1971 and 1993 it had commissioned 20 Candu reactors which
provided 54% of its output; 26% came from hydro power, and 13% from
fossil fuel. From a peak in 1994 when the Ontario nuclear stations
produced 92 TWh, some 67% of all electricity consumed in the province,
performance declined and output fell to about 60 TWh by 1999 meeting
only 50% of Ontario’s electricity requirement.As well as declining
revenues this brought a significant increase in air pollution as more
electricity was produced from coal. Average load factors fell to below
50% and as a backlog of essential repairs built up a number of reactors
– eventually eight in total – at Ontario Hydro’s Bruce and Pickering
stations were closed down.
Those opposed to the Canadian nuclear programme were then able to
describe the Candu system as accident prone with serious design faults
which would prove excessively costly to repair and then, at best, might
only ensure a limited extension of operating life.However it seems
unlikely that the system is at fault.Unlike the AGR the Candu reactors
have been sold abroad and Candu stations in South Korea and Romania
have performed well. The four Wolsong reactors in South Korea are among
the world’s best performing nuclear plant with load factors to end
September 2004 of between 89.9 % and 98.7%.
A second alternative explanation for the declining performance could be
deficiencies in the management of the plant. This was the blunt
conclusion of a report in 1997 commissioned by the then chairman of
Ontario Hydro. The Integrated Independent Performance Assessment (IIPA)
report using the methodology of the US Nuclear Regulatory Commission
identified a lack of authoritative and accountable managerial
leadership which was so deeply entrenched that individual managers were
unable or unwilling to take corrective action. “Managements failure to
provide consistent direction has produced inefficiencies and mediocrity
rather than excellence.” Sectors analysed in detail were Managerial
leadership; Culture and standards; People and performance; Processes
and procedures; Plant and design; Organization and resources; and
Labour relations. In most sectors performance was judged to be at the
minimal acceptable standard below which permission for the plants to
operate would have been withdrawn.
How did this come about? The IIPA report suggests that Ontario Hydro
failed to make the transition from its original and highly successful
design and construction phase, building and commissioning its 20
reactor units, to the second stage focused on operating these reactors
on three different sites. It is also possible that an earlier
restructuring of the company in 1994 had a deleterious effect with
drastic reductions in staff levels including 8 of the 14
vice-presidents.
It has also been suggested that the decline in performance was due to
insufficient funding for essential maintenance and repair by the
management of Ontario Hydro. It is claimed that now, under the new
reorganisation of the nuclear plant, the levels of expenditure have
been doubled.
Finally there were also labour and staff problems. It was said that one
obstacle to reform was the entrenched attitude of the Power Workers
Union. The IIPA report found that managers lacked the basic authority
to manage effectively. “Management is not holding itself, or its
personnel, accountable for performance results.” “Most first line
workers are essentially disconnected from management and get most of
their direction from the Power Workers Union leadership.”
Following the IIPA report (and the resignation of the chairman) Ontario
Hydro was split up. Ontario Power Generation took over the Pickering
and Darligton sites, the Bruce site was separated off and eventually
leased to British Energy in 2000, and the non-nuclear generation passed
to a new company Hydro One. It soon appeared that the lessons of the
IIPA report had not been fully appreciated. Attempts to restart one of
the Pickering reactors soon ran into problems of delay and overspend.
Another inquiry by the Pickering A Review Panel found much the same
problems as before “Manageemnt of the project from initial planning to
execution was seriously flawed.” Now at last, after further
resignations, Pickering is well on the way to recovery.
It is difficult at this distance and time to assess how far all or any
of the above four factors contributed to decline of Ontario Hydro or
the subsequnet problems at pickering – possibly all in varying degrees
– or to what extent similar causes may be responsible for the present
reductions in output from BE. The problems at BE are however being
addressed with some apparently very drastic changes. According to a
statement attributed to the chief executive Mike Alexander “70% of
senior executives had been replaced and 50% of power station directors
were new to their posts” (NEI Feb. 2005) If correctly reported these
changes seem so extreme as to amount to a complete shake up – for
better or worse – of the company.
However while there is a significant input of nuclear expertise at
director level this is largely from the water reactor industry; there
is an apparent lack of knowledge of the unique gas-cooled graphite
system. The newly appointed (July 2004) Chief Nuclear Officer Roy
Anderson (his approval by the Nuclear Installations Inspectorate is
expected to be forthcoming) comes from the US as also does a
non-executive director W. A.
Coley. Other non-executives include Pascal Colombiani a former chairman
of the French Atomic Energy Commission and Sir Robert Walmsley with
experience from nuclear submarines. All three were appointed in 2003.
David Gilchrist, previously Managing Director of BE Generation resigned
in August 2004.
Bruce Power
In contrast to the difficulties at the Pickering site the picture at
Bruce is quite different. As reported in NI (December 2004) the nuclear
reactors at Bruce Power are now performing well with load factors
already at 85% and confidently expected to improve further.Power output
in 2004 increased by about one-third over the previous year to 33.6 TWh
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The recovery of Bruce Power was presumably started when Robin Jeffrey,
then British Energy’s resident North American director, negotiated the
lease agreement (now foolishly and needlessly thrown away on the orders
of DTI Secretary of State Patricia Hewitt). In this Jeffrey was ably
assisted by Duncan Hawthorne, who later resigned his directorship at BE
to become the President and Chief Executive of Bruce Power. Hawthorne
who had previously been awarded the Ontario Energy Association’s Leader
of the Year award has now won the 2004 Hedley Palmer award “for his
outstanding contribution to Ontario’s generation industry.” It seems
that BE’s loss has been Ontario’s gain.
Following British Enerergy’s sale (at a loss) of its lease, Bruce Power
is now owned by a Canadian group in which the workers and Bruce staff
have a substantial stake. In addition to a 31.6% of the share
ownership by the Ontario Municipal Employees Retirement System, the
Power Workers Union has a direct 4% shareholding, and 1.2% of shares
are held by the Society of Engineering Professionals. The other
partners each with a 31.6% share are Cameco, a major uranium mining
company, and the Trans Canada Corporation. All partners clearly have an
interest in maintaining the highest standards and output and this
should ensure harmonious labour relations.
In contrast, a British Energy survey last summer found that “on
average, most people in the company are not very satisfied with the
state of play at the moment.” It seems that any rewards from a recovery
in British Energy’s fortunes will go more to the incoming
‘reconstruction’ management than to the shareholders, including those
employees encouraged by the Government to take shares in their company
at the time of privatisation, who have already been deprived of 97.5%
of the value of their shares. Are there any lessons that could be
learnt here from the Canadian experience? |
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Last Updated ( Thursday, 01 September 2005 )
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