Memorandum submitted by the Renewable
Energy Association (REA)
1. The REA is the largest renewable industry
body in the UK, with almost 570 corporate members. These companies
are active across the range of renewable electricity generating
technologies and the association also covers renewable heat and
transport fuel interests. The REA's grid expert is involved in
several industry/government/regulator working groups, including
the review of security of supply standards, the transmission access
review, the transmission arrangements for distributed generation,[103]
the distribution charging methodology forum and the renewables
advisory group grid group.
2. In this response we would like to make the
following general points:
— There needs to be a swift move towards
an enduring "connect and manage" approach to connecting
power generation to the networks, if we are to stand any chance
of meeting our renewables targets.
— We welcome the recent moves to divorce
strategic development of the transmission network (and providing
the finance for this development) from the financial commitment
of specific generation projects.
— The enduring arrangements for charging
for use of the networks must continue to be based on the logical
premise of net movements across boundaries between different networks
(not gross charges).
3. Over the past few years, thousands of
megawatts of renewable capacity which had been seeking connection
to the network, had not been able to get access. The grid operator
had been following an "invest and connect" approach—and
would only connect a new project if there was sufficient capacity
to accommodate the maximum output of the prospective generator
without there being a restriction on the output of existing generation.
The effect of this has been to delay the connection of zero or
low carbon generation and the loss of the carbon savings this
new plant would have delivered.
4. These frustrated projects had been held
in a waiting list and, depending on their position in this list,
could have expected to wait over 10 years for connection.
5. The Renewable Energy Association has
been advocating an alternative approach—termed "connect
and manage". This involves connecting all capacity that wishes
to connect, and where necessary constraining the total generation
delivered to the network to the level which it can accommodate
on a day to day basis. This means the connection of renewable
generation does not have to wait until enough infrastructure has
been built to allow the unconstrained operation of all connected
plant.
6. The Transmission Access Review (TAR),
which started in the summer of 2007, has been addressing this
problem. One of the conclusions of the TAR report[104]
was that any project should be able to obtain a firm connection
date within a time frame reasonably consistent with the development
time of the project. Implementation of this TAR conclusion will
primarily be via changes to the Connection and Use of System Code
(the CUSC)—the rules by which all parties connected to the
grid must adhere.
7. Three broad groups of CUSC amendments
were proposed in the spring of 2008:
— the auctioning of transmission access
capacity; and
— some short-term measures that basically
help to make better utilisation of the existing network.
8. The process of working up the detail
of and evaluating these approaches has been taking place in various
industry working groups and the proposals are now with Ofgem for
consideration and to decide which combination of them are implemented.
In our view it is important that some form of connect and manage
proposal is chosen so that renewable generation is not prevented
from connecting purely to allow higher carbon generation to continue
operating without constraint.
THE SEPARATION
OF STRATEGIC
TRANSMISSION INVESTMENT
FROM SPECIFIC
GENERATION PROJECT
COMMITMENTS
9. Until now transmission investment has
been reactive ie the transmission companies do not begin to undertake
reinforcement work until individual generating companies have
guaranteed the cost of those connections. This has caused problems
as generating companies are not generally able to provide those
guarantees until they are reasonably confident that their projects
will proceed, for example after they have got planning consent.
The time taken from the granting of planning consent to construction
is often much shorter than the time it would take to consent and
build the associated transmission reinforcement, thus delaying
the delivery of new "clean" electricity. The system
is also made harder by many transmission reinforcements being
driven by a large number of relatively small projects rather than
a small number of larger ones.
10. Fortunately the general geographical location
of a significant portion of the new renewable generation is known,
even if it is not yet known which combination of the individual
projects will succeed. This enables strategic transmission investments
to be planned in advance, potentially alleviating some of the
delay to delivering the necessary transmission. Ofgem is working
up arrangements to finance transmission owner expenditure on such
investment and methods of giving the transmission owners incentive
to "get it right".
11. The Renewable Energy Association supports
these moves and points out that if and enduring connect and manage
regime is adopted, and transmission companies pay (in part) for
the consequences of not having the right transmission infrastructure
in place, this automatically provides an incentive for transmission
companies to anticipate the necessary transmission investments
accurately.
DISTRIBUTION-CONNECTED
GENERATION—THREATS
AND OPPORTUNITIES
12. One of the greatest uncertainties for
our networks between now and 2050 is how much of the new generation
will connect at distribution network voltages, rather than to
the main transmission system. Because of this the planning and
regulation of distribution networks must be able to respond to
a wide range of generation penetration levels.
13. Distribution is 132kv and below in England
and Wales, but in Scotland the 132kv network is classed as part
of the transmission system. With the exception of all but the
largest projects, most renewable generators are "embedded"
within the distribution network, rather than connected to the
transmission network. In simple terms, these generators are nearer
the point of end use of electricity (both in terms of distance
and voltage level). Consequently they have historically avoided
various charges associated with transmitting power over the transmission
system—and enjoyed what are known as "embedded benefits".
14. The justification for these embedded
benefits is simple. Irrespective of any commercial arrangements
to sell the power from an embedded generator, power does not physically
flow on to the transmission system but is absorbed by the local
demand. It is therefore not imposing any flow-related costs on
the transmission system. We have concerns that these "embedded
benefits" are under threat, for reasons explained below.
15. Ofgem and NGC have been concerned for
some time about the ability of generation connected to distribution
systems to avoid transmission charges. This issue was discussed
at length by a special working group set up to look at the issue
(and some less important matters relating to distribution connected
generation). It was known as the Transmission Access for Distributed
Generation (TADG). The TADG held its first meeting in July 2006.
16. National Grid proposed a move to gross
charging (ie charging embedded generators and the associated demand
the full transmission network use of system charges—thus
doing away with the main component of embedded benefits). National
Grid's belief was that even if it connects to the distribution
network, a generator will have an impact on the transmission network;
therefore it should pay transmission use of system charges. We
think this is illogical, and it is the net flow onto or off the
transmission system that determines National Grid's costs and
therefore what it needs to recover by way of charges. Charging
on this net basis is cost reflective and in general retains the
status quo. Charging for gross generation and gross demand would
be like the transmission system operator trying to charge for
all the gross generation and gross demand in continental Europe,
rather than just the net flow that comes across the interconnector
with France.
17. The TADG concluded in a state of complete
polarisation of views between National Grid and industry on this
issue. It remains unresolved. Ofgem has imposed a license condition
on NGC requiring it to establish an enduring solution for charging
distribution connected generators for using the transmission system
by the end of March 2011. We are concerned that the long established
benefit of locating close to demand and not paying transmission
charges for power that does not flow onto the transmission system
will be undermined.
18. Another threat that those distribution-connected
generators that existed before April 2005 have is the imposition
of Distribution Use of System Charges. Generators connecting before
that date paid what are known as "deep" connection charges.
This means that they had to pay 100% of the cost of any work done
to connect them anywhere on the distribution network, including
a capitalised sum to reflect the ongoing operation and maintenance
cost of new bits of network that they so funded. There were no
ongoing charges.
19. Ofgem is now considering going back
on this deal and making those generators pay DUoS charges from
April 2010. The REA strongly opposes this move. It is both unfair
and is likely to result in reduced output from some projects,
through them becoming uneconomic and having to cease generation.
Project developers would have based their financial profiles on
the pre-2005 rules and would obviously not have taken into account
unexpected, additional use of system charges.
20. On the upside for generators considering
connecting to a distribution network—there has been progress
towards the point where well-located generators may eventually
be able to receive a credit for the benefit they provide to the
network. This benefit is the avoidance of reinforcement. This
should help to avoid the pressure to build unnecessary private
networks, where a suitable distribution system already exists.
What should the Government's vision be for Britain's
electricity networks, if it is to meet the EU 2020 renewables
target, and longer-term security of energy supply and climate
change goals?
21. The vision should be a transmission
network which is more strategically planned, designed to maximise
the amount of renewable and low carbon generation. This is particularly
significant for the building of new offshore networks; and a distribution
network which is actively managed to balance power flows, similar
to the way the transmission network is operated. At present the
rules governing whether new plant can connect to a distribution
system and how this plant interacts with the network are described
as "fit and forget". The active approach allows more
generation to be connected to less infrastructure, and operated
more effectively with lower distribution losses.
22. As we stated earlier there is a high degree
of uncertainty about the proportion of the new generation that
will be connected to distribution systems so their planning and
financing arrangements must remain flexible.
How do we ensure the regulatory framework is flexible
enough to cope with uncertainty over the future generation mix?
23. Some of the ideas that Ofgem is suggesting
for incentivising transmission owners to anticipate where generators
will connect are heading in the right direction.
What are the technical, commercial and regulatory
barriers that need to be overcome to ensure sufficient network
capacity is in place to connect a large increase in onshore renewables,
particularly wind power, as well as new nuclear build in the future?
For example issues may include the use of locational pricing,
or the availability of skills.
24. The correct commercial arrangements must
be put in place. In very simplistic terms the following principles
should be followed:
— Charging principles should be based on
net and not gross flows—see discussion above about loss
of embedded benefits.
25. As the question implies there are other
significant barriers; it remains to be seen how effective the
new planning regime (for larger infrastructure projects) will
be. It seems highly likely that lack of electrical engineers will
hamper the deployment of the large increase required in renewable
electricity generation. This shortage has been felt by the distribution
network operators for some time, and is anticipated to get worse.
26. A commercial/regulatory barrier projects
regularly face is difficulty in obtaining wayleaves or easements
across land (ie rights for cables to cross land). There is a standard
compensation arrangement, agreed between the Country Landowners
Association, the National Farmers Union and network operators
[1]. The amounts of money offered under this agreement per pylon
or per metre of cable laid are low, regularly leading to landowners
holding out for far higher amounts. This can seriously delay projects
and add hugely to costs.
27. DNOs have the ability to step in and
compulsorily purchase land, but are reluctant to use it to the
point of it being almost unheard of. DNO's will retire from wayleave
negotiations when a "customer connection" is being carried
out if the agreed rates are declined, despite adopting the finished
connection on energisation of the project. The end result is that
project developers are regularly left having to negotiate wayleaves
with landowners, who can be assisted in their negotiations by
companies that specialise in assisting landowners get the highest
rates.
28. This process should be reviewed. The
ideal outcome would be more realistic payments to landowners,
such that having a wayleave is not an unattractive proposition,
coupled with more rigorous approach to the DNO enforcing the standard
agreement.
What are the benefits and risks associated with
greater interconnection with other countries, and the proposed
"supergrid"?
29. Our view is that increased interconnection
is beneficial. The ability to share reserve over as large an area
as possible will have an increasing value as the amount of wind
and other weather dependent generation increases.
What challenges will higher levels of embedded
and distributed generation create for Britain's electricity networks?
30. The main effect of this will be on the distribution
networks. Depending on where within the distribution networks
the embedded generation locates the net effect could be either
to increase or decrease the amount of investment needed in distribution
networks. This is why we (in agreement with Ofgem) believe that
cost reflective distribution network charging is so important.
What are the estimated costs of upgrading our
electricity networks, and how will these be met?
31. We refer the committee to the report by the
Electricity Networks Strategy Group, entitled Our Electricity
Transmission Network: A Vision For 2020[105]
published in March 2009.
How can the regulatory framework ensure adequate
network investment in light of the current credit crunch and recession?
32. The issue of the cost of capital in the current
financial climate is primarily one for Ofgem and the network companies
to resolve. Companies with an allowed regulated income should
though in principle remain good credit risks.
How can the regulatory framework encourage network
operators to innovate, and what is the potential of smart grid
technologies?
33. Innovation policies need to include systems
technologies beyond the generator itself. In particular there
is substantial scope for actions to support active network and
load management technology:
— Adoption of smart technology whenever
new meters are fitted; and a timetable for smart metering nationwide.
— Investment in know-how and funding to deploy
intelligent networks to permit timely and economic delivery of
renewable power.
— Review of potential approaches for load
management control to be applied at the level of consumer units
or individual appliances.
— Review the potential for electric vehicle
battery charging as a balancing facility.
34. Flexible demand can be used in conjunction
with variable energy resources to balance demand with available
output and to manage certain transmission and distribution network
constraints, as an alternative to installing more hardware. This
strategy avoids constructing power stations that are only needed
for a short time every year to meet peak demands and can result
in significant carbon savings.
35. The use of demand flexibility does not
have to be centrally managed. It could evolve through the autonomous
actions of individuals (or appliances) if they could respond to
short term price and availability signals. This could be achieved
through smart metering or in the case of appliances, response
to frequency fluctuations.
36. The key incentive to make these things
happen is to ensure that there is no systematic advantage given
to a network company from investing in its own hardware rather
than contracting for others to provide services that can avoid
the need for this investment.
What can the UK learn from the experience of other
countries' management of their electricity networks?
37. In some other European Member States
renewable generation gets priority connection. In other words
its connection can not be delayed by the need to invest in network
infrastructure (other than the local connection).
38. Providing the key recommendation of the Transmission
Access Review (ie that all plant should obtain firm access in
timescales reasonably consistent with its own development) is
implemented, we do not believe that specific priority for renewable
generation is needed. If renewable generation is delayed in achieving
access in the future then, of course, priority would be needed.
April 2009
103 Which has now finished. Back
104
Published 27 June 2008. http://www.berr.gov.uk/files/file46774.pdf Back
105
http://www.ensg.gov.uk/assets/1696-01-ensg_vision2020.pdf Back
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