Supplementary memorandum submitted by
National Grid PLC
Annex: supplementary questions
1. TO WHAT
EXTENT DO
THE VARIOUS
GENERATING OPTIONS—MICRO-GENERATION,
WIND, NEW
NUCLEAR ETC—REQUIRE
SIGNIFICANTLY DIFFERENT
INVESTMENT STRATEGIES
ON YOUR
PART (DEPENDING
ON WHICH
IS PROMOTED
MOST)?
1.1 The power flows on the transmission
system are a function of the location of demand and generation
across the country. To meet these power flows, National Grid is
obliged to invest in the network and provide sufficient capacity
to meet requirements that are stipulated in the Security and Quality
of Supply Standard (SQSS). It is therefore the location of generation,
rather than its type, which is the principal driver for transmission
investment. Of course, certain technologies, due to the availability
of their fuel or other planning issues, will tend to be associated
with particular locations. If new generation displaces/replaces
existing plant, then the location of the displaced generation
will be equally important in determining new power flow patterns.
However, assuming the pattern of plant closures/retirements will
be the same for all new generation development options, then:
1.2. Micro-Generation
As micro-generation is likely to be installed
within premises near to load it is likely to be uniformly spread
across the GB system. It is therefore unlikely to trigger significant
new transmission investment and may reduce the requirement to
provide additional capacity to the DNO networks.
1.3 Wind
In Great Britain, our most significant wind
resources are in Scotland and offshore locations therefore potential
wind generation sites are generally located away from main centres
of demand. In order to transport electricity from points of generation
to demand, there will be a requirement to invest in the networks
in order to not only extend them to allow wind farms to physically
connect, but investment will also be required in order to increase
the transmission network capacity of the system to allow bulk
transfers of power from the north, to the large demand centres
to the south.
1.4 Nuclear
The investment required to accommodate a new
nuclear fleet of power stations is dependent upon the choice of
site and location. If new nuclear power stations are equivalent
in size and site to existing nuclear power stations, investment
requirement should not be significant, although there may be some
requirement to refurbish or replace ageing infrastructure. However,
if more nuclear power stations are sited in the north, this could
trigger significant investment to accommodate increased bulk power
transfer on the transmission system (similar requirements to wind).
2. IN YOUR
EVIDENCE, YOU
SUGGESTED THAT
SOME EARLY
CLARIFICATION OF
HOW OFF-SHORE
WIND WILL
CONNECT INTO
THE SYSTEM
WOULD BE
HELPFUL [Q465].
COULD YOU
PROVIDE THE
COMMITTEE WITH
MORE INFORMATION
ON WHAT
CLARIFICATION IS
NEEDED, AND
ON THE
SCALE OF
INVESTMENT WHICH
IN YOUR
VIEW IS
REQUIRED? [CF
Q471].
2.1 In order to meet the timescales to meet
the Government 2010 renewable targets, it is necessary to bring
wind farms forward on an unprecedented scale. It is expected that
this can only be done by building offshore windfarms. In order
to achieve this, a number of steps are required. These include
legal, technical, and commercial issues. Initial clarification
is needed on the regulatory regime that will operate offshore.
The DTI is currently consulting on two options for regulating
the offshore networks. The frameworks in which offshore transmission
might be developed are a merchant (ie developer funded) approach,
or a price regulated approach (funded via the GB use of system
tariff). We believe that the latter approach permits additional
policy choices over those available in the merchant model and
these choices may be selected to facilitate, sooner than might
otherwise be the case, the development of the offshore wind industry.
Given the pressing nature of the Government climate change and
renewable energy targets, we believe this to be an important issue
that needs clarity. If a regulated route is chosen then the following
steps are required; the appointment of a system operator in offshore
areas, the allocation of offshore transmission owner licencees
and a number of changes to existing industry licences and codes
to ensure that the appropriate legal and commercial framework
is in place. To meet the Government 2010 targets, these issues
will need to be resolved before the physical construction work
of building offshore transmission networks can actually begin.
This work may in itself take a number of years to complete and
the timetable which was set out in the Government consultation
on offshore wind networks may need to be revisited in order to
allow the 2010 targets to be met.
2.2 At present the security standard (ie
the inherent redundancy designed into the network) for the offshore
connections to wind farms has not been formalized. Preliminary
design work by National Grid and engineering consultants acting
for the DTI suggests that there could be substantial benefits
in adopting different security criteria to those used onshore.
Such changes would reduce network costs by reducing the number
of connection cables and hence the backup capacity that is needed
in onshore overhead line networks. Such designs should provide
connection availability acceptable to wind generators and would
not significantly affect the supply reliability experienced by
GB consumers.
2.3 The appropriate form of the offshore
network security standards depends on the allocation of responsibilities
for design and operation of the offshore networks and this will
in turn depend on the outcome of the DTI's consultation on how
offshore networks should be regulated. If the establishment and
operation of the offshore networks (and the losses, constraints
and unavailability that result) are the responsibility of the
offshore generators they serve then the scope of security criteria
could be limited to just the interface with the onshore network.
If, on the other hand, responsibility for design, build and operation
are divided between a price controlled transmission owner and
the GB system operator then aspects of the design of offshore
networks will need to be specified more explicitly.
2.4 The most comprehensive study of the
likely cost of offshore networks has been undertaken by Econnect,
consultants acting for the DTI. They suggest that for the sites
being considered in the three offshore strategic areas, connection
capital costs would range from £130/kW to £250/kW depending
on distance of the wind farm from the shoreline. For a total Round
2 offshore development of 5GW, they suggest total capital costs
will be in the region of £750 million.
2.5 In terms of the onshore network costs
to accommodate offshore wind farms, we are presently progressing
a number of onshore connection applications from large offshore
windfarms. Due to the defined strategic areas for offshore wind
farms, the connections tend to be clustered and connected at similar
locations (in the North West, North East, The Wash & the Thames
Estuary) on the National Grid network. The network investment
required in these areas are interactive with investments required
to accommodate new Combined Cycle Gas Turbine (CCGT) power stations
as well as, in the north, investments needed to accommodate the
transfers resulting from wind generators in Scotland. Therefore,
the investment figures provided below consider the impact of all
the potential generation connecting in a give area.
2.5.1 North West
We have received interest (either signed connection
agreement or application in progress) to connect approximately
1.5GW of wind generation in this area. This will require major
reinforcements in the Heysham area to accommodate this volume
of wind generation. The cost of these reinforcements are in the
order of £150-200 million. However, a number of these reinforcements
are also required to accommodate the additional power flows from
Scotland and discussions are ongoing with Ofgem on how to take
these reinforcements forward.
2.5.2 North East
We have received interest to connect approximately
0.75GW of wind and approximately 3GW of CCGT generation seeking
to connect in the North East. If all of this generation was to
connect, the cost of the additional reinforcement would be in
the order of £150 million.
2.5.3 The Wash
We have received interest to connect approximately
1.5GW of wind generation and approximately 1.3GW of CCGT generation
seeking to connect in this area. The transmission network can
accommodate approximately 1.5GW of generation before any major
expenditure is triggered. However, if all of this generation was
to connect, it would trigger requirements for additional investment
in the network at a cost of £150 million.
2.5.4 The Thames Estuary
We have received interest to connect approximately
1.3GW of Wind generation and interest to connect a further 2.5GW
additional generation in this area. If all this generation was
to connect, the cost of the additional reinforcements would be
in the order of £200 million.
2.5.5 Wales
We have received interest to connect approximately
1GW of wind generation (onshore and offshore) and interest to
connect a further 4.8GW CCGT in this area. If all this generation
was to connect, the cost of additional reinforcements would be
in the order of £200 million.
2.5.6
In total we have received firm interest to connect
(ie applications to connect) some 6GW of wind generation by 2011
and interest to connect a further 11.6GW of other types of generation
within the same areas. If all this generation was to proceed,
the cost of additional reinforcements would be in the order of
approximately £850-900 million.
2.5.7
It should be noted that there may be additional
projects which as yet we are not aware of and so these costs could
eventually increase.
2.6 However, it is unlikely that all this
generation will proceed, and, where it does eventually proceed,
experience with generation projects tells us that it is often
not to the timescales indicated in initial applications. There
could be a number of project specific reasons for this such as
planning issues, financial issues etc Therefore, if we were to
undertake all of this investment, it is very likely that a significant
proportion would not be utilised and National Grid could have
a significant number of stranded assets. To avoid this, we require
users to make financial commitments in the form of indemnities
(called Final Sums Liabilities). These indemnities ensure that
if a network investment is initiated to accommodate a new network
user, and that user subsequently terminates the connection agreement
before completion and payment of transmission charges, then the
user will pay for any investments that would otherwise become
stranded. National Grid, by requesting developers to provide this
financial commitment, obtains a clear indication that the user
believes their project will proceed.
3. YOU REFERRED
TO THE
INTRODUCTION OF
COST-EFFECTIVE
CHARGING AND
THE EXTENT
TO WHICH
THIS IMPOSED
EXTRA COSTS
ON REMOTE
GENERATION [QQ467FF].
CAN YOU
PROVIDE SOME
INFORMATION ON
THE SCALE
OF SUCH
EXTRA COSTS?
3.1 National Grid recovers the cost of network
investments through the Transmission Network Use of System (TNUoS)
tariff. The tariff is constructed such that the difference in
charges between zones reflects the annual cost of financing the
associated network capacity between those zones. For generation
and half-hourly metered demands, the charge is levied on a measure
of the capacity required by that generator or demand in that year.
3.2. The network investment costs needed
to accommodate wind generators in the North of Scotland and transport
the power to the major load centres in England were assessed in
a recent study by the three transmission licensees. (See the Renewable
Energy Transmission Study undertaken for the DTI's Transmission
Issues Working Group). This analysis demonstrates the cost-reflectivity
of this tariff, in the order of £250/kW. The annual financing
cost of such an investment, at regulated rates of return, would
be circa £20/kW/yr. This matches closely the difference between
the tariff zone for the North of Scotland and that of the Midlands
& South East.
4. DURING THE
COMMITTEE'S
RECENT VISIT
TO DENMARK,
REPRESENTATIVES FROM
THE DANISH
COMPANY E2 WHO
ARE INVOLVED
IN THE
LONDON ARRAY
PROJECT RAISED
THE ISSUE
OF THE
FINAL SUMS
LIABILITY OF
£100 MILLION ASSOCIATED
WITH THE
PROJECT. THEY
SUGGESTED THAT
THEY COULD
NOT PROVIDE
SUCH A
GUARANTEE BEFORE
OBTAINING PLANNING
CONSENT, AND
THAT THIS
WAS HIGHLY
LIKELY TO
DELAY THE
PROJECT. CAN
YOU PROVIDE
MORE BACKGROUND
INFORMATION ON
THE FINAL
SUMS LIABILITY
AND ITS
IMPACT ON
PROJECT IMPLEMENTATION
IN THE
LIGHT OF
THE DANISH
COMMENTS? [THIS
QUESTION IS
BEING PUT
TO OFGEM
ALSO.]
4.1 As stated above, some 4.8GW of generation
have expressed interest in connecting in the Thames Estuary. If
all this generation was to connect, additional reinforcements
would be triggered at a cost of approximately £200M. However,
if we undertook all this investment and all the generation in
this area did not proceed, it would result in un-necessary investment
(stranded assets) and a cost which the industry as a whole and
consumers could potentially be exposed to. Therefore, to ensure
that a party that triggers the need for the investment only does
so once they are committed to progressing their project to completion,
we require the user to provide an indemnity to cover any costs
incurred if they terminate the connection agreement and do not
complete their project. In the case of London Area, all parties
seeking to connect in this area have been requested to provide
final sums liability in proportion to the works that they trigger.
This mechanism therefore fulfils two purposes:
4.1.1 It indemnifies National Grid against
the project specific risk of a developer failing to complete its
project and our investment becoming stranded and the assets unused.
4.1.2 It forms part of the evidence National
Grid uses to demonstrate to OFGEM that projects are required and
therefore should ensure that we should receive appropriate funding
though our price control mechanism.
5. IN YOUR
MEMORANDUM, YOU
SUGGEST THAT
A GROWTH
IN MICRO-CHP
MIGHT ACTUALLY
DELAY THE
NEED FOR
GRID REINFORCEMENT.
BUT TO
WHAT EXTENT
CAN THE
LOCAL DISTRIBUTION
NETWORKS THEMSELVES
COPE WITH
A SUBSTANTIAL
GROWTH IN
MICRO-GENERATION?
OR IS
SUBSTANTIAL INVESTMENT
REQUIRED TO
PRODUCE MUCH
"SMARTER" LOCAL
SYSTEMS?
5.1 National Grid does not own or operate
Distribution Networks within Great Britain; rather our focus is
purely on the ownership and operation of transmission assets.
It may therefore be more appropriate to address this question
directly to a Distribution Network Operator who would be able
to provide the Committee with a more complete response to this
question.
6. IF WIND
POWER AND
MICRO-CHP WERE
TO SUPPLY
PERHAPS 20% OR
MORE OF
ELECTRICITY GENERATED,
TO WHAT
EXTENT WOULD
THEY BE
IN COMPETITION
WITH NUCLEAR
FOR SUPPLYING
BASELOAD CAPACITY?
IN SUCH
CIRCUMSTANCES, WOULD
THE INFLEXIBILITY
OF NUCLEAR
POWER ADVERSELY
AFFECT THE
FINANCIAL VIABILITY
OF THESE
OTHER FORMS
OF GENERATION?
DOES NUCLEAR
POWER IMPOSE
ANY OTHER
COSTS ON
OTHER FORMS
OF GENERATION—FOR
EXAMPLE, IN
TERMS OF
THE NEED
TO MAINTAIN
SUFFICIENT SPINNING
RESERVE?
6.1 Our understanding is that the observed
inflexibility of current nuclear generation may be a characteristic
of those particular designs and may not be a feature of future
reactor designs. (Others will be more qualified to provide information
on this). The inflexibility of current nuclear generators has
meant that they prefer to operate at a constant output, delivering
baseload power. Given the current daily/seasonal demand cycles,
the national minimum load is approximately 40% of peak demand.
This means that there is at least 25 GW of base load opportunity.
For comparison, there is approximately 12GW of existing nuclear
capacity. If wind power and micro-CHP were together providing
20% of electricity requirements, then on average they would produce
circa 8 GW (although with considerable variability around this
mean). This would suggest there would be ample opportunity for
nuclear generators to continue to operate in an inflexible way.
While significant domestic CHP is unlikely to operate at times
of low electricity demand (because there is less need for heat)
it is possible that a large proportion of the wind generation
could be operating on a windy low demand day (although these are
much less frequent than windy winter days). However, using the
above figures suggests that nuclear would only need to be curtailed
from full output if more than 17GW of wind operates at minimum
load.
6.2 If there is insufficient flexible generation
or load to meet demand cycles, plant breakdowns and frequency
control requirements then additional costs would need to be incurred
to bring on flexible plant. At present there is adequate flexibility
throughout the year and the inflexibility of existing nuclear
generation can be accommodated without significant cost. On this
basis we do not see how current nuclear inflexibility in particular,
would impact on the financial viability of any other generation
types.
7. SOME ORGANIZATIONS
AND INDIVIDUALS
HAVE ARGUED
THAT THE
CURRENT INCENTIVE
STRUCTURE FOR
DISTRIBUTION NETWORK
OPERATORS (DNOS)—WHICH
IS LARGELY
BASED ON
ASSET VALUES—FAILS
TO PROMOTE
ADEQUATELY THE
DEVELOPMENT OF
ENERGY SERVICES;
AND THAT
THAT THE
UK LOST AN
OPPORTUNITY TO
ADDRESS DEMAND
MANAGEMENT MORE
RADICALLY BY
FAILING TO
ALLOCATE METERING
TO DNOS.
WHAT IS
YOUR VIEW?
7.1 National Grid does not own or operate
electricity Distribution Networks within Great Britain; rather
our focus is purely on the ownership and operation of transmission
assets. It may therefore be more appropriate to address this question
directly to a Distribution Network Operator who would be able
to provide the Committee with a more complete response to this
question.
13 January 2006
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