Supplementary memorandum by National Grid
Further to your request for additional information,
please find attached below detailed answers for the respective
questions.
1) Rules governing where we can site overhead
lines
The most cost effective method of bulk transmission
of electricity on mainland Britain is by overhead lines. To date
virtually all transmission requirements for renewables have been
met by utilising existing overhead lines although future requirements
are likely to require new lines.
The siting of our overhead lines is governed
by three factors:
1. The "Holford Rules" which are used
as the guiding principles for routeing new overhead lines. These
were originally formulated by Lord Holford, formerly an adviser
to the Central Electricity Generation Board (CEGB), and later
reviewed and supplemented by National Grid. These deal with a
number of areas including route planning considerations for areas
of high amenity value, scientific interest and urban areas.
2. We would seek to route new overhead lines
away from existing properties on the grounds of general amenity.
We would not seek to route a new overhead line over an existing
residential building (except in exceptional circumstances, such
as specifically at the request of a landowner or property owner.)
3. We would follow environmental impact assessment
procedures to route a new overhead line, having followed the two
factors above. Planning authorities, statutory and non-statutory
bodies, administrative bodies, landowners and the general public
are consulted as part of the environmental assessment process
for all major new lines.
4. If no overhead route was possible to achieve
for a new line using the 3 factors above, then an undergrounding
option would be considered based on case specifics. However alternative
corridors / reinforcement options may exist away from built up
areas and these would generally be used in preference to undergrounding.
The information provided in both the written,
as well as the oral responses, represents our preliminary views
on what the investment is required to meet the 2020 target and
does not include the level of detailed analysis of exact localities
for the lines proposed. All the investment will be carried out
in the most efficient and economic way while ensuring the above
guidelines are followed.
2) Power loses associated with transmitting
over large distances in our 2020 scenarios
Typically transmission losses account for 2%
of demand seen on the transmission system. Onshore wind locating
in Scotland should not increase overall loses significantly. However,
for offshore wind generation, particularly for the areas designated
in the Dogger Bank and the Wash on the east coast of England which
are expected to contribute around 19GW, it will result in power
being transferred over a large distance before connecting to the
onshore grid. Initial estimates indicate losses will be in the
region of 3-6%, dependent on the network technology adopted. To
accommodate these increased losses it is assumed that a correspondingly
larger volume of offshore generation will be needed to ensure
that the overall renewable target is still met. In designing extensions
for the networks, due consideration is given to minimising losses,
where it is economic to do so.
3) Level of generation reserves currently
obtained from the demand-side and changes expected with high amount
of wind on the system
Currently (2008-09) 30% of the total contracted
reserve is procured from the demand side. This has increased from
23% in 2000-01. We expect to see a modest increase (to 34%) next
year. This is generally sourced from industrial-scale demand side
providers (eg turning down demand in chemical processes and steelworks).
Looking forward, and with more renewables on
the system, our requirement for reserve will increase. There is
the potential for the demand-side to play an expanded role in
the provision of this reserve, however this may need to be sourced
from much smaller, and more distributed loads than our current
providers. In order to gain access to this reserve, and utilise
it efficiently, new technology will need to be developed. We would
expect that smart metering will have a role to play in this regard.
Demand management technologies—that allow electric appliances,
such as refrigerators and air conditioning units, to be automatically
turned off or down in response to changes in supply and demand—are
now becoming available. These technologies could help provide
a more efficient and lower carbon, solution to the intermittency
associated with renewable generation than the current approach
of using conventional stand-by generation.
4) Possible amount of UK natural gas replaced
by bio-methane and challenges for both technical and sources of
supply
Work to determine the potential contribution
of bio-methane in replacing part of the UK's natural gas consumption
is still ongoing. There are currently no definitive figures to
indicate the proportion of such consumption that it may account
for. Our analysis is based on examples elsewhere in Europe such
as Germany, Switzerland and Austria where bio-methane is already
being injected into the gas grids. A report commissioned by the
German government in 2007 on possible European biogas strategies
found that EU produced bio-methane has the potential to replace
roughly 50% of EU natural gas imports from Russia by 2020. This
conclusion certainly serves to highlight the potential for bio-methane
injection on a large scale the potential for bio-methane injection
on a large scale. Such a significant contribution to the UK Government's
overall renewables target of 15% would significantly reduce the
burden on other technologies and would also add to the diversity
of fuel sources—thus improving security of energy supply
for the UK.
4.1) Sourcing bio-methane
A proportion of bio-methane production could
come from anaerobic digestion of waste and sewage which has the
added benefit of capturing the potent greenhouse gas methane from
such sources. Another benefit of anaerobic digestion of waste
and sewage is that it avoids the need for incineration of such
waste which can cause local air-pollution.
Delivery of large-scale bio-methane production
is likely to require the use of energy crops. Clearly there is
competition in the current and developing market place for such
crops. However studies suggest that of all bio-fuels, biogas delivers
the most energy per hectare of crops and it is also the least
carbon intensive production path, with some biogas pathways actually
delivering carbon-negative bio-energy. Bio-methane can be produced
from a range of dedicated crops such as grass species (like sorghum,
Sudan grass or hybrids) or specially bred "super" biogas
maize.
4.2) Technical challenges in supplying bio-methane
Below are specific technical challenges in delivering
bio-methane through the gas the distribution network in the UK
market. These challenges are by no means insurmountable and National
Grid believes that, with support from the Government and the relevant
regulatory bodies, solutions can be found for each of these barriers.
(i) Gas quality—Regulations in the
UK have been focused on the injection of large quantities of natural
gas from the North Sea and imports from Europe and will present
some barriers to the entry of bio-methane which has different
characteristics to those of natural gas:
a. The first issue is the Calorific Value (CV)
of bio-methane. Typically bio-methane has a CV of around 36 MJ/m3.
The CV entry requirements are 36.9 to 42.3MJ/m3. As a comparison
the CV of North Sea natural gas is 40MJ/m3. In addition, there
is a cap that requires the lowest CV source has to be within 1MJ/m3
of the flow weighted average CV to avoid CV capping and the inability
to bill all the energy delivered. Bio-methane can be enriched
with butane or propane to reach this minimum level, (although
there would be an economic and environmental cost of doing this).
There are other viable solutions including removing renewable
gas from the CV cap obligation. Such solutions would require Ofgem
approval.
b. The second issue is that the oxygen content
of the treated bio-methane (typically 2%) is likely to be always
above the Gas Safety Management Regulations limit of 0.2%. The
oxygen could be removed but this is very expensive. The other
option could be to reduce the regulations on oxygen content. National
Grid is investigating the feasibility of this.
c. There is also potential for other trace elements
to enter the gas. National Grid does not currently fully understand
the potential for trace elements to enter the gas and whether
they could be a safety concern. Further work needs to be done
to assess the appropriate monitoring of the gas/feedstock to prevent
any harmful elements entering the gas network.
(ii) Equipment requirements—The current
requirements for monitoring and metering gas quality and volumes
require very expensive equipment. The economies of scale needed
to make this technology viable will require large plant deployment.
National Grid will investigate the feasibility and assess the
impact of less onerous monitoring and metering requirements for
low volume injections.
I hope the above helps to answer the Committee's
questions and we will be happy to clarify and any specific parts
of this supplementary evidence.
11 July 2008
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