Memorandum submitted by Scottish and Southern
Energy
Scottish and Southern Energy (SSE) is one of
the largest energy companies in the UK. We are involved in the
generation, transmission, distribution and supply of electricity;
energy trading; the storage, distribution and supply of gas; electrical
and utility contracting; and telecoms.
SSE owns the high voltage electricity transmission
system in the north of Scotland, and owns and operates low voltage
electricity distribution networks in the south of England and
north of Scotland.
SUMMARY OF
EVIDENCE
— Government can support the electricity
industry through clear policy objectives, and stability and certainty
in those policies and the associated support mechanisms. —
Regulatory stability is a pre-requisite for investment in the
electricity networks. The outcomes of Ofgem's regulatory reviews
need to be clear and certain to promote investor confidence.
— Investment in the transmission system
is required and this will need to take place before generation
users known. Regulated funding of the transmission businesses
must allow for anticipatory investment based on credible generation
scenarios.
— Planning remains an issue—Government
needs to ensure that the Planning Act, the National Planning Framework
and Marine Bill result in a co-ordinated system that can make
fair decisions in under a year.
— Grid access also remains an issue—Government
should support industry reform that provides certainty over the
date of access ("connect and manage") and the cost of
access (postal charging). Ofgem's preferred approach of long term
auctions of network capacity coupled with expensive charges for
users in remote locations is inconsistent with the delivery of
renewables and security of supply objectives.
1. What networks do we need to meet the EU
2020 target, and longer-term security of energy supply and climate
change goals?
The GB electricity networks have an enviable
record of providing security of supply.
Since privatisation, over £25 billion has been
invested in the networks. The overall reliability of the GB transmission
system during 2007-08 was 99.9995%. Interruptions on the distribution
networks have decreased by nearly 20% since 2000. Pan-European
benchmarking studies demonstrate that GB has amongst the lowest
levels of network interruptions in Europe[106].
The challenge in the coming decade is to maintain
this level of system security while accommodating the new generation
mix necessary to meet GB's energy policy and climate change goals:
— on the transmission system, to ensure
timely and efficient network investment to meet the needs of new
generation and facilitate further integration with the wider European
energy market; and
— on the distribution networks, adapting
to an increasing volume of local, distributed generation and changing
demand patterns.
Meeting this challenge will mean not just network
investment, but also technical, engineering and commercial innovation.
Government can support the industry through
clear policy objectives, and stability and certainty in those
policies and the associated support mechanisms.
TRANSMISSION SYSTEM
Existing transmission system
The owners of the GB transmission system are
Scottish Hydro Electric Transmission Limited (SHETL) in the north
of Scotland, Scottish Power Transmission (SPT) in central and
southern Scotland, and National Grid Electricity Transmission
(NGET) in England and Wales. National Grid also performs the role
of GB System Operator (GBSO) which includes administering access
to the whole GB transmission system, directing the operation of
the system, and setting and collecting transmission charges from
users to cover the costs of all three transmission network owners.
The activities and revenue requirements of SHETL, SPT and National
Grid are regulated through the GB transmission licence.
In addition to the existing onshore transmission
licensees, it is proposed that new offshore transmission licences
will be granted following a competitive tender process. These
offshore transmission licensees will own the transmission assets
that will connect the onshore network to offshore windfarms, and
will recover a regulated revenue allowance from the GBSO.
Existing and planned transmission circuits connecting
GB with Ireland or mainland Europe are subject to separate interconnector
licensing arrangements. These investments receive no regulated
funding allowances through the GBSO. Instead funding is derived
from entrepreneurial investment or regulated funding allowances
from other national regulators.
Future transmission system
The challenge for the owners of the GB transmission
system in the coming decade is to ensure timely and efficient
network investment to meet the needs of new generation and facilitate
further integration with the wider European energy market.
Currently, over 80 gigawatts of new generation have
applied for connection to the GB transmission system, including
over 15 gigawatts of renewable generation. This generation has
been `queued', with connection offers contingent on future network
reinforcements. Around half of this generation has been offered
a connection date after 2015.
In June 2008, as part of the Renewable Energy
Strategy consultation, the Government asked the three transmission
licensees to conduct transmission system investment studies to
identify the likely generation scenarios and associated transmission
investment costs to deliver the EU 2020 target. This work was
co-ordinated by the Electricity Networks Strategy Group (ENSG),
which is jointly chaired by Ofgem and DECC, and reported in March
2009.[107]
The ENSG report identifies transmission investments
associated with the connection of the large volume of onshore
and offshore wind generation required to meet the 2020 renewables
target, and to facilitate the connection of other proposed new
generation such as new nuclear. The total cost of the proposed
reinforcements is £4.7 billion[108]
and the resulting network would be able to accommodate a further
45 gigawatts of generation. The study also concludes that, provided
the identified reinforcements are taken forward in a timely manner
and the planning consent process facilitates network development,
the reinforcements can be delivered to the required timescales.
The ENSG study work was undertaken on a GB-wide
basis; for Scotland, three scenario levels of renewable generation
were examined: 6.6 gigawatts, 8 gigawatts and 11.4 gigawatts (all
in addition to the existing 1.4 gigawatts of hydro). The figures
overleaf summarise the transmission investment options in Scotland
and the north of England to accommodate 8 gigawatts of renewables
in Scotland (on the left), and further investments to accommodate
11.4 gigawatts of renewables in Scotland (on the right). SSE supports
the general conclusions of the ENSG report, and the specific proposals
for the Scottish network.
The ENSG study did not specifically examine the transmission investment
options for offshore wind or interconnection. Looking to the next
decade, it is likely that an offshore grid will evolve as offshore
generation technologies develop and there is further harmonisation
within the European energy market. Investment in the GB transmission
system needs to be mindful of greater pan-European integration.
Stage 1 and 2 transmission reinforcements to facilitate
Scottish contribution to renewables targets
DISTRIBUTION NETWORKS
The challenge for distribution network operators
(DNOs) in the coming decade is adapting to an increasing volume
of local, distributed generation and changing demand patterns.
There has been a surge in interest in distributed
generation in recent years. For example, in 2008, SSE received
123 applications from small generators[109]
to connect to the distribution network in the north of Scotland.
Demand patterns are slowly changing as the volume of distributed
generation increases, but also as consumers respond to energy
awareness initiatives. Going forward, the development of new technologies,
such as smart meters or electric vehicles, will contribute to
other, potentially significant, changes in demand patterns.
As a consequence, the size and shape of distribution
networks are changing, as is the job of the DNO, but this is happening
incrementally and, hence, adapting to these changes will be through
evolution, not revolution. We do not advocate a rebuilding of
the distribution networks, but rather we believe that innovation
and new network technologies are the tools of the future DNO.
Going forward, the historic model of passive
distribution networks built of copper and steel will be replaced
by a new model of active distribution networks that incorporate
more demand management solutions such as energy storage. For DNOs
to explore and implement alternatives to conventional network
solutions, the regulatory framework must be sufficiently flexible
to accommodate DNOs undertaking unconventional, and possibly unforeseen,
activities.
The regulated funding of DNOs already recognises
the role of innovation through the innovation funding incentive
(IFI) and the registered power zone (RPZ) mechanism. These initiatives,
which have been in place since April 2005, are designed to promote
research and development activities. The next step, building on
the success of the IFI and RPZ mechanism, is inclusion of innovation
as a core business activity of the future DNO, rather than as
an optional add-on.
The DNOs have a strong record in delivering
reliable, cost-effective networks and are well placed to deliver
our future network requirements. We support the strong drive within
the current distribution price control review (DPCR5) to establish
further measures to encourage DNOs to take a more innovative and
active approach to the management and development of their networks.
An important outcome of the DPCR5 should be recognition that innovation
is a core business function of DNOs.
2. What are the key components of a legislative
and regulatory framework that meets the needs of Britain's future
electricity networks?
The Government's Renewable Energy Strategy consultation,
published in June 2008, identified two grid-related constraints
to increasing the UK's proportion of renewable energy:
Tackling these barriers remains critical to
successfully achieving the transition to a secure, low carbon
energy economy.
INFRASTRUCTURE CONSENTS
AND THE
PLANNING PROCESS
Historically, the planning systems for major
transmission infrastructure projects have not delivered. In particular,
the timeline for consenting necessary new transmission network
has proved lengthy. It took six years to approve an essential
upgrade to the North Yorkshire power line, and the proposed Beauly-Denny
power line has been in the planning system since 2005. The shortcomings
of the planning systems need to be addressed if the UK is to meet
the EU 2020 target and longer-term security of supply and climate
change goals.
SSE welcomes the development of new planning systems
through the Planning Act in England and Wales and the National
Planning Framework in Scotland. This provides a necessary and
timely opportunity to ensure that essential energy infrastructure
is delivered in an efficient and timely manner, by streamlined
and co-ordinated systems that can make fair decisions in under
a year.
In England and Wales, the independent Infrastructure
Planning Commission will require the full support of the Government
in its work, to ensure that it has both the resources and expertise
to properly discharge its responsibilities in a timely manner.
The importance of National Policy Statements
(NPSs) cannot be overemphasised. The NPSs are intended to set
out the national direction of our energy requirements and, hence,
avoid piecemeal, lengthy, case-by-case assessment of strategic
infrastructure developments. To achieve this, the NPSs must be
clear and have sufficient depth to form the basis for authoritative
decisions to be made. The NPS and the approach applied to the
planning and decision making processes need to recognise the national
need for strategic investment in transmission, both onshore and
offshore.
The same imperatives apply in respect of the
Scottish National Planning Framework. The Scottish Government's
National Planning Framework 2 (NPF2) identifies and prioritises
a range of onshore and offshore strategic network reinforcements
in Scotland. These are essential to realising Scotland's renewable
energy potential and meeting the Scottish Government's energy
policy goals. The NPF2 also recognises the future potential of
developing subsea routes to harness renewable energy.
A co-ordinated approach to planning is needed
across the governing administrations and also, critically, where
infrastructure has a marine dimension. The interdependence between
the provisions of the Planning Act and the Marine Bill needs to
be clarified. Integration of the strategic planning system established
by the Marine Bill and the relevant NPS is essential to achieving
a coherent strategic development of onshore and offshore electricity
transmission.
SSE has some particular concerns surrounding
the proposals within the Marine Bill as it currently stands. These
concerns centre around the role and remit of the Marine Management
Organisation; the order of preparation of, and supremacy in guiding
decisions of, the NPSs, Marine Policy Statement, Marine Conservation
Zones and marine plans; the lack of timescales in reaching consenting
decisions prescribed within the Bill; and the absence throughout
the Bill of the need to consider socio-economic factors when designating
the use of marine areas. These will all need to be resolved over
the coming months in order to create a regime that can be trusted
by industry and other stakeholders alike.
NETWORK INVESTMENT
TO FACILITATE
GENERATION CONNECTIONS
The regulation of network investment
The ownership and operation of the high voltage
electricity transmission system and low voltage electricity distribution
networks in GB are permitted under licence, and the terms of that
licence restrict the revenue of the licensed network businesses.
This revenue restriction term assumes a pre-determined programme
of network investment. The revenue restriction term is re-visited
every five years by Ofgem at a price control review.
In 2009-10, the transmission companies will recover
around £1.5 billion and the DNOs will recover around £4
billion. These costs contribute respectively around 4% and 17%
to householders' electricity bills.
SSE supports the principle of price-control regulation
for electricity networks as practiced by Ofgem under the current
`RPI-X' framework. This approach has successfully reduced costs,
improved customer service and provided a stable investment climate.
Furthermore, this approach has been, to date, sufficiently flexible
to accommodate demands on the networks. We do not believe that
a fundamental change to the GB approach to price-control regulation
is required, but rather we believe that the current approach can
continue to evolve to address new challenges.
Investment in the distribution networks
The revenue restriction term of the DNOs is
currently under review by Ofgem, and will be reset from April
2010. As we describe above, SSE believes that the DNOs can adapt
to the challenges of increasing distributed generation through
evolution, not revolution. Consequently, the focus of the current
price control review (DPCR5) has to be to provide a stable platform
for investment, adaptation and growth. An important element must
be to ensure there is sufficient flexibility for DNOs to explore
and implement alternatives to conventional network solutions and,
hence, recognise innovation as a core business activity. This
means rewarding DNOs for innovative behaviour in developing and
managing their networks, while maintaining a high level of customer
service.
Investment in the transmission system
Significant investment in the GB electricity transmission
system is required if climate change and wider energy policy objectives
are to be met. The ENSG report identifies the necessary developments
to the transmission system in the coming decade. The total cost
of the proposed reinforcements is £4.7 billion and the resulting
network would be able to accommodate a further 45 gigawatts of
generation. The impact on householders' bills would be less than
£5 per year.
The current revenue restriction terms of the transmission
licensees do not allow for investment of this scale (both in cost
and time). Ofgem and the licensees have recognised this, and initiated
work on funding further pre-construction studies and developing
a regulatory funding mechanism for the necessary transmission
investment. This work is due to be completed during winter 2009.
One focus in the development of this funding
mechanism is avoiding unused, stranded assets. Historically, regulatory
sanction for investment in networks has only been granted when
there is clear, demonstrable need from users (either generation
or demand). However, the lead time for new network infrastructure
can be up to 10 years while the lead time for new generation developments
is, dependent on technology, typically less than four years. If
transmission infrastructure is to be available when new generation
developments need it, then the network investment must be initiated
before the generation developments; hence, there is a risk of
assets being built and, in the short term, not being fully used.
This would appear an intractable, "chicken
and egg" problem. However, we believe that the current regulatory
funding framework is sufficiently robust to allow for a solution.
One of the benefits of the GB regulatory model
is being able to consider the economics of a network investment
over the whole-life of the asset. The life of network assets is,
typically, in excess of 20 years. Cost-benefit analysis can demonstrate
that assets do not need to be fully utilised for all of their
life to be economic. Such analysis should also include the "hidden"
costs and benefits of network reinforcement such as operational
impact, environmental impact, electrical losses and security of
supply.
The onus should be on the transmission licensees
to demonstrate, through whole-life economic appraisal, that a
proposed network investment is efficient for credible generation
and demand scenarios. This means that the licensees should identify
future generation users, and undertake analysis that quantifies
and costs the potential benefits and risks of transmission investment.
This analysis can be subject to open consultation and, where the
balance is found in favour of investment, funding allowed through
the revenue restriction term of the transmission licence. There
is an opportunity to implement this approach through the new regulatory
funding mechanism scheduled to be introduced in winter 2009.
This approach would retain the many benefits
of price-control regulation while addressing the delay that has
arisen as a result of network investments only being initiated
once new generation developments have been identified. It is consistent
with the cross-industry analytical approach developed through
the work of the ENSG and could be extended for offshore generation
connections and future interconnectors. The transmission licensees
have a strong record in delivering a reliable, cost-effective
and secure system and are well placed to deliver the future network
requirements identified in the ENSG report.
Grid access and charging
New generation developers seeking connection
to the GB transmission system today are likely to receive an offer
to connect in 10 years time. Many developers of distributed generation,
including small generators, are also receiving an offer to connect
in 10 years time. Such an offer places the generation developer
at the bottom of a long queue of prospective generators seeking
connection to the electricity networks.
Grid connection offers provide no certainty to new
generation developers over the date of connection, the upfront
cost of connection or the ongoing cost of exporting power. Connection
offers are contingent on the progress of network investments and
the action of other developers that are further up the queue because
access to the transmission system is allocated on a "first
come, first served" basis. This means that projects with
planning consent can be stuck in the GB queue behind projects
that are less well developed. In the north of Scotland, SSE is
aware of over 350 megawatts of renewable generation developments
with planning consent but no access to the grid.
The current approach to grid access and charging
does not provide a stable climate for investment in necessary
new generation, be it renewable, thermal or nuclear. Given this,
it is not surprising that potential investors (particularly in
emerging renewable technologies) are opting to locate elsewhere
in the global energy market.
Stability and certainty in the grid access and
charging arrangements are essential to achieving the EU 2020 target,
and long term security of supply and climate change goals. This
means providing new generation developers with certainty over
when they will gain access to the grid, certainty over the cost
of access and certainty that the cost will remain stable over
the lifetime of their development.
SSE supports the `connect and manage' approach
to access to the GB transmission system. This means providing
generators with a firm date for grid access that is consistent
with the development time of their project (typically, four years).
To avoid speculative applications (that comprise a significant
proportion of the current grid queue), new generation developers
would be required to make a significant, but proportionate, financial
commitment before receiving their firm connection offer.
In relation to the charges for use of the electricity
networks, we support the European model of `postal' charging where
a GB-wide charge is levied for each unit of energy that is exported
onto the network. Recognising the potential upfront investment
cost associated with new generation developers in remote locations,
developers should be required to contribute to the cost of new
infrastructure that is necessary to connect them to the network.
This change would be a welcome shift away from
the peculiar current charging model, which leads to transmission
charges in Scotland being high, volatile and unpredictable. Currently
generators in the south of GB receive a payment from the GBSO
while generators in the north face a large charge. For example,
at present, it costs £22 per kilowatt in transmission charges
to have generation located in the north of Scotland, and negative
£8 per kilowatt south of London. This means an 800MW plant
in North Scotland will pay £17.6 million a year, while in
Southampton a developer would receive £6.4 million a year.
With renewable generation located in remote areas, this concept
is clearly outdated.
March 2009
106 See, for example, Council of European Energy
Regulators: 4th Benchmarking Report of Quality of Electricity
Supply 2008. Back
107
Our Electricity Transmission Network: A Vision for 2020. A report
by the Electricity Networks Strategy Group, March 2009. Back
108
Note, this does not include the cost of connecting offshore wind
which a recent report for the Crown Estate has estimated at around
£10 billion. Back
109
Small generators are those of less than 10 megawatts. 10 megawatts
is equivalent to four to eight commercial wind turbines. Back
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