Memorandum submitted by Scottish Power
ScottishPower is a major owner and user of electricity
networks in Great Britain. We own the high voltage transmission
network in the South and Central Belt of Scotland, working with
National Grid who act as the GB System Operator. We also own and
operate the electricity distribution network in the same area,
together with that in the Merseyside and North Wales (Manweb)
area. As a network user, ScottishPower has some 6,000 MW of power
generation, being mainly coal fired units in Scotland and gas
fired units in England, and sells electricity to over 3 million
customers.
SUMMARY
We welcome this inquiry, which is timely as
the GB network is beginning to be re-configured toward a low carbon
future in which renewables, nuclear and carbon capture and storage
are expected to be the key technologies for power generation.
The main points we would like to make are as follows:
(a) In practice, the decarbonisation of our electricity
will mean a considerable increase in the use of wind generation
in the North of Britain, especially Scotland. There will also
be the need to accommodate significant new inflows of nuclear
power, likely in our judgement to come from existing nuclear sites
both in the South of England but also in Wales and the North.
(b) Against this background, the essential task is
to get on with ensuring that the new generation plants, whose
location is essentially fixed by the resource or other constraints,
can be connected without undue grid constraint problems. This
can only be achieved by pressing ahead with the significant grid
upgrades that have been identified in the Energy Network Strategy
Group (ENSG) final report. Ofgem has granted the funding to allow
for the design of the key high priority upgrades and it will be
important that the construction funding is made available in a
timely manner.
(c) We have been concerned that Ofgem have allowed
themselves to be distracted by creating elaborate schemes of locational
price signals and incentives around the necessary grid enhancements.
These will not change the underlying realities of what needs to
be done, but could increase costs and delay delivery by deterring
and distracting investors. Instead, we would urge Ofgem to utilise
the mechanism in the existing transmission price control to fund
the necessary investments.
(d) More generally, it is important that price
controls for the ongoing operation and refurbishment of the networks
reflect the challenges to investment posed by current credit conditions.
We see the markets applying significantly higher premia to both
equity and debt; in order to attract capital which the markets
(or holding companies) could allocate elsewhere, network companies
will need to show rates of return which are competitive with other
similar opportunities elsewhere. Recent price control innovations
in Britain have increased the risk borne by network companies,
which could cause investors to question whether they can be sure
that efficiently incurred expenditure will be remunerated.
(e) The availability of suitably skilled individuals
needed to deliver the required investment represents a significant
risk.
(f) Smart metering and smart grid can play a
helpful role in mitigating some of the variability in wind generation
and in more efficiently handling micro generation, and we support
their continued development. However, significant back-up will
be necessary for wind (where calm conditions can last several
days) and we consider that large scale low carbon sources such
as wind farms, CCS and nuclear will inevitably be the mainstays
of the future network.
THE COMMITTEE'S
QUESTIONS
1. 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?
1.1 The UK faces a significant challenge
in delivering its share of the EU Renewables Energy target. Critical
to success is Government support and recognition of the need for
significant investment in network infrastructure and the creation
of a more efficient and supportive planning framework. Enhancements
to the networks will also be needed to support the new nuclear
build that is likely to play a key role in decarbonising the electricity
sector while maintaining security of supply.
1.2 There is a need for significant investment
in the network infrastructure to manage the increased contribution
from renewable energy, and to manage the associated peak capacity
and operational and system stability issues. Innovative approaches
to optimising use of present network assets as well as network
expansion require serious consideration.
1.3 Delivery of the 2020 renewable energy target
and the longer term goals will require swift action to ensure
that; the supporting infrastructure is in place; planning decisions
are made in a timely manner; and that key issues such as technology
supply chain constraints are addressed. In addition to planning
and infrastructure, including identifying Offshore Transmission
Owners, coordinating connection between offshore and onshore infrastructure
followed by construction.
1.4 We fully support the recommendations
in the Energy Network Strategy Group (ENSG) final report. This
sets out a programme of priority transmission investments to resolve
the constraints in the GB network and it is essential that it
is implemented promptly. We welcome Ofgem's proposals to fund
the necessary design work for the key priority projects and look
forward to the early go-ahead for the actual construction.
2. How do we ensure the regulatory framework
is flexible enough to cope with uncertainty over the future generation
mix?
2.1 We do not consider that uncertainty
is a major problem at this stage. The ENSG recommendations identify
the key and immediate transmission upgrades that are required
and which will enable a significant proportion of the required
renewables to be connected. Additional upgrades identified by
ENSG can be progressed as the renewables fleet builds up. Similarly,
we believe that the feasible sites for new nuclear development
are well known and that integration of the necessary grid upgrades
into the process should not be difficult.
2.2 A supportive regulatory regime, aligned to
Government's ambition in meeting EU targets and security of supply
objectives, is paramount. Network operators have a central role
to play in the delivery of energy policy objectives. However,
it must be recognised that the regulatory body also bears a responsibility
in delivering energy policy and it is not sufficient to simply
place all responsibility for delivery with industry. Ofgem need
to become an important facilitator in the process by developing
a balanced, supportive and forward-looking regulatory framework.
2.3 A key requirement of any regulatory
framework is to ensure that the confidence of the financial market
is retained, particularly during the current economic climate.
Increasing network investment will require the provision of significant
amounts of finance from the investment market and should current
circumstances persist, this will mean higher financing costs and
more restrictive debt covenants. Prospective investors must therefore
be re-assured that all efficient expenditure by network owners
is recoverable and that the rewards available to them are commensurate
with the risks they are faced with in transforming their networks.
3. 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 nuclear build
in the future? For example issues may include the use of locational
pricing or the availability of skills.
3.1 The ENSG final report highlighted that
the UK will need to incorporate the use of technologies that have
yet to be employed in the UK energy network that include HVDC
and Series Compensation. Coupled with the expected volume of renewable
generation, these could present a number of technical challenges
for the operation of the network.
3.2 Under capacity of the supply chain places
a significant risk to timely delivery of sufficient network capacity.
A consequence of the volume of activity being undertaken in the
replacement and assembly of new network assets is the ability
of suppliers to deliver to short timescales. Currently forecast
lead times for delivery of equipment is prohibitive in completing
projects on a timely basis. In addition, the UK is now heavily
reliant on sourcing equipment from oversees suppliers leaving
it exposed to global markets and volatility when placing procurement
contracts.
3.3 To deliver the combined DNO investment
plans in respect of DPCR5, will require approximately 9000 new
posts in engineering and crafts across the industry. The unavailability
of suitably skilled individuals needed to deliver the required
investment represents a major risk. The industry faces a dilemma
as many of the people with the necessary skills are approaching
the end of their careers. This combined with the average lead-time
to fully train suitable replacements in the order of 5 years,
represents a significant barrier. The industry needs to be able
to attract new people that have the necessary skills, education
and training.
3.4 Planning remains a significant barrier
to the development of the necessary infrastructure required to
accommodate new forms of generation. In order to meet the 2020
target, investment in infrastructure must take place ahead of
construction of new generation. Historically, the timeline for
constructing new transmission network has taken longer than for
that of the new generation.
3.4 The key to connection of a large volume
of renewable and nuclear generation is the provision of infrastructure
within timescales aligned with the development programmes of those
generators. Short-term measures such as the rationing of capacity
through an auction process or the introduction of locational charging
will deter potential developers from investing in areas rich in
renewable resource but lacking in transmission infrastructure.
Developers require certainty over connection dates and predictability
and stability of transmission costs before funding can be secured
in an increasingly difficult economic climate.
3.5 Moreover, developing these measures,
which will inevitably lead to winners and losers, will inevitably
distract all parties as they seek to protect their commercial
interests. But, as the location of the wind resource is known,
and (in our judgement) so are the locations of new nuclear power
stations, these measures will not actually help get the necessary
infrastructure built or lead to more efficient location of generation.
Instead, Ofgem should focus on efficiently funding the delivery
of the ENSG recommendations and the necessary upgrades for nuclear
development.
4. What are the issues the Government and
regulator must address to establish a cost-effective offshore
transmission regime?
4.1 The successful development of offshore
wind and fulfilling the potential of wave and tidal stream generation
as well as the associated network infrastructure is essential
if the UK is to meet its EU 2020 targets.
4.2 The proposed offshore licensing regime gives
rise to individual licences for connecting offshore wind farms
to the onshore grid. This will promote a `radial connection' approach
and raises questions as to whether such an arrangement is sustainable
or whether instead (or in addition) an offshore interconnected
transmission system might be desirable from both a technical and
economic perspective to fully realise the potential offshore resource.
It should also be noted that significant investment in the onshore
network would also be required. It will be necessary to consider
an integrated approach towards the planning and design of both
the onshore and offshore system.
4.3 There needs to be acknowledgment of
the importance of a coordinated approach for the development of
infrastructure for Round 3 offshore projects, as opposed to the
current piecemeal approach promoted through the regulatory framework
for Rounds 1 & 2.
4.4 To achieve the very significant export
capacities proposed in Round 3, a strategic view of the overall
infrastructure must be established which concludes, that by reacting
to individual requests for connections, even when grouped together
within a framework of an annual window, this will inevitably lead
to an inefficient design and ultimately increase the cost to consumers.
We therefore believe that there is now an opportunity to progress
the Round 3 offshore transmission networks by identifying a single
OFTO for each geographical area.
4.5 As a consequence consideration of the
regulatory regime needs to take place of how it can effectively
deal with Round 3 connections and allow infrastructure associated
with an entire development zone to be constructed by a single
OFTO. Such infrastructure could be strategically developed in
an economic and efficient manner with a mechanism allowing for
adjustments to the revenue stream that reflect the extent of investment
efficiently completed.
4.6 The final regulatory regime is key to
ensuring that potential OFTOs are attracted into the offshore
arena and are able to attract the required investment from the
financial markets.
5. What are the benefits and risks associated
with greater interconnection with other countries, and the proposed
"supergrid"?
5.1 Any proposal to increase the interconnection
between Europe's electricity networks will require national regulators
to adopt a consistent approach in performing and executing their
duties. Another key consideration will be the harmonisation of
the various industry codes and planning standards that governs
the development of infrastructure within each country.
5.2 The financial capacity of network operators
will be an obstacle for building new network against the backdrop
of the current financial crisis. However, this should not detract
from the fact that investment in network infrastructure is critical
that further emphasises the importance of ensuring that network
operators are adequately funded.
5.3 It is widely recognised that the commercial
and regulatory issues surrounding the construction and use of
any proposed "supergrid" would be complex, however if
EU objectives are to be met, the proposed supergrid could be an
important enabler, particularly in relation to security of supply.
A valuable first step would be for a cost and benefit analysis
to be completed; as well as the cost of the project and the benefits
in terms of security of supply, promotion of competition and greater
access to energy storage, this could also consider risks such
as increased exposure to power outages in other EU member states.
6. What challenges will higher levels of
embedded and distributed generation create for Britain's electricity
networks?
6.1 We are answering this question in terms
of multi-megawatt connections such as distribution-connected wind
farms. Different issues arise in relation to micro generation,
which we will address in question 9 (innovation).
6.2 The current rate of connection for new generation
is limited by the complexities of obtaining planning consents
and land rights. It is also held back by the structure of incentives
faced by the Great Britain Transmission System Operator (GBSO)
under the current regulatory regime, whereby the GBSO is incentivised
to reduce constraint payments received by generators whose energy
production is restricted.
6.3 Whilst planning remains key, it is a
concern that NGET's CAP167 proposals seek to further restrict
future generation connecting to the networks of distribution operators
that, whilst they do not trigger any local transmission works
are seen to be a contributing factor to the rising cost of constraints
on the wider transmission network. This proposal, should it be
implemented, would severely limit the level distributed generation
connecting in Scotland. We acknowledge, however, the lack of support
for its implementation from the industry as a whole. The CAP167
amendment currently sits with Ofgem for approval and it is critical
to the future of distributed generation in Scotland that Ofgem
do not approve the NGET proposal.
6.4 National Grid recently issued an updated
GB Queue Management methodology that now gives embedded generators
the ability and right to request advancement to connection, if
contingent upon future transmission upgrades. The work carried
out to date by the three transmission companies has been encouraging,
and has seen the advancement of connection dates of a number of
projects.
6.5 There is however a concern as to how
distributed generator schemes will be treated under the enduring
Transmission Access Reform (TAR) arrangements. The TAR amendments
to the Grid's Connection and Use of System Codes (CUSC) focus
on generators who have access rights to the transmission system,
and while it is assumed that arrangements for smaller embedded
generators will continue to be managed by the Statement of Works
process, it may lead to small generators having to apply for explicit
rights that will place more onerous obligations upon them as a
consequence.
6.6 It appears that Ofgem would prefer not
to see renewable generation connected in Scotland at the present
time because of the additional constraint costs that arise due
to the connection. While we accept there will inevitably be short-term
issues around constraints, these should be resolved by the steady
progress of the infrastructure upgrades that are taking place
and are planned to take place across the GB grid.
6.7 Also, in areas where natural renewable
resources are plentiful, for example wind, the distribution system
if often sparse. This results in new generation triggering significant
infrastructure, and in many cases will involve the construction
of overhead lines. A very good example of this exists in Wales
where the Welsh Assembly has laid out its TAN 8 proposals. Whilst
we believe that the existing distributed generation incentive
mechanism (DGIM) provides and effective framework that enables
Distribution Network Owners (DNOs) to coordinate with multiple
generator parties in providing efficient and timely connections,
there remains a case for augmenting the DGIM to deal with very
high cost strategic infrastructure projects.
6.9 With regard to the technical challenges
faced by DNOs in accommodating large volumes of distributed generation,
as more distributed generation connects, it will initially displace
local demand, however it will ultimately result in "export"
onto the transmission system. This will have implications both
for the transmission system which will need to accept power import
at times from the distribution system, and for the distribution
system itself which will need to be more "active" to
handle the resulting power flows. This is further considered in
response to question 9 ("Innovation").
7. What are the estimated costs of upgrading
our electricity networks and how will they be met?
7.1 We agree with the estimate of £4.7bn
cited by the Energy Networks Strategy Group (ENSG), to facilitate
necessary GB reinforcement following studies completed by the
three transmission owners based upon a range of scenarios taking
into account the significant changes anticipated in the generation
mix between now and 2020, in particular the large volume of onshore
and offshore generation and the connection of new nuclear generation
within GB.
7.2 This figure is however a relatively small
proportion of the total amount that needs to be invested in the
electricity network over the next few years as part of the normal
investment cycle. We estimate the total investment required between
now and 2020 (including the ENSG work) to be approximately £37
billion. This figure takes account of both transmission and distribution
investment. It is based upon the investment levels assumed in
the current transmission price controls and in the industry's
submissions for the current distribution price control review,
and assumes that these levels are maintained through to 2020.
7.3 We would highlight that the current
transmission price control arrangements have been, and continue
to be, a successful mechanism for delivering optimal and cost-efficient
investment for all forms of grid investment. In out view it is
important that the present price control arrangements should continue
in order to allow companies to progress existing connection and
infrastructure upgrades with relative certainty over the regulatory
arrangements. However given the potential scale of future grid
investment beyond 2012, and the urgency to deliver this investment
timeously, we would agree that there is a need to look at the
process for authorising major infrastructure projects and whether
this should remove the need for specific advance commitments to
be made by users when the strategic requirements are already clear.
8. How can the regulatory framework ensure
adequate network investment in light of current credit crunch
and recession?
8.1 The combined DNO investment plans submitted
to Ofgem in respect of Distribution Price Control Review 5, will
not only be about maintaining the integrity of the UK Distribution
system, but will now represent a significant opportunity to help
underpin the UK's economic recovery with the opportunity to create
a further 9,000 new posts in engineering and crafts across the
industry.
8.2 We would highlight that the current price
control arrangements have been and continue to be a successful
mechanism for delivering optimal and cost-efficient investment
for all forms of grid investment and are of fundamental importance
to our energy future.
8.3 Price controls have an important role
in ensuring that electricity network companies are able to continue
to attract investment, however successive price reviews have significantly
increased the risk borne by network operators. The importance
of implementing a workable and balanced set of incentives aligned
with energy policy objectives needs to be recognised.
9. How can the regulatory framework encourage
network operators to innovate, and what is the potential of smart
grid technologies?
9.1 Network operators have a critical role
in facilitation of a low carbon future. We have already mentioned
above the fact that increasing levels of distribution connected
generation will require networks to be more "active"
in their operation and the possibility that this may require export
on to the transmission system. In anticipation of this future,
ScottishPower is involved in a range of industry-leading projects.
DNOs will need to consider solutions such as voltage control,
power flow management, dynamic circuit ratings and potentially
energy storage technologies to deliver a better and more efficient
electricity transport.
9.2 In this context, it will be important that
GB network operators are able to innovate. The regulatory framework
must be such that it does not create barriers to development through
complex and uncertain economic schemes that are based around subjective
reviews. We remain concerned at Ofgem's apparent reluctance to
reintroduce the Technical Director's role within its operation.
The previous incumbent in the role was a key enabler to the UK
DNOs establishing the IFI scheme. This type of engineering leadership
will be key in enabling network operators to meet future challenges.
9.3 There is a need for a much closer degree
of coordination between the Regulator and network operators in
future, this will require an active and participating Regulator
that signs onto a shared vision of the UK's energy future that
network operators can deliver against. This will in all likelihood
involve revisiting some decisions previously taken by Ofgem that
may seem politically difficult to them at this time.
9.4 Distribution networks will also facilitate
smarter behaviour by consumers and by their appliances. Smart
metering will be a key enabler of this and we welcome the Government's
decision to proceed with this project; it will be important to
take a decision as soon as possible on the market model for the
roll-out. Demand side management by consumers will help mitigate
some of the variability of wind generation; the scale of this
will depend on the speed of adoption and therefore the development
of appliance solutions that are attractive to consumers. Plug-in
hybrid vehicles look to be a promising option. However, it must
be recognised that this will not avoid the need for large scale
fossil fuelled back-up, for example to deal with the possibility
of calm conditions lasting for a period of several days in the
winter.
9.5 Similar considerations apply to micro
generation. This provides slightly different challenges for DNOs
than larger scale distribution connected generation, for example
as a result of being connected at the low voltage level. Our present
judgement is that this sector will remain relatively small because
the underlying economics appear to be significantly worse than
larger scale renewables. We would note that gas fired micro CHP
is a technology that is unlikely to be a viable part of the mix
as the 2050 target approaches, as its residual carbon looks too
high.
10. Is there sufficient investment in R&D
and innovation for transmission and distribution technologies?
10.1 The Innovative Funding Incentive (IFI)
mechanism introduced as part of the DPCR4 has been a resounding
success against which companies such as ScottishPower have levered
further funding to develop and implement technologies with mid
range Technology Readiness Levels (TRLs).
10.2 It is widely recognised that the facilitation
of a low carbon electricity system will require changes on both
the supply (high penetration of variable renewable generation
resources) and the demand side (energy efficiency and the potential
electrification of transport). As the network operator is the
common link between these changing inputs/outputs it is recognised
that these developments could lead to evolutionary change in both
network topology and network operation from the largely passive
system of today.
10.3 There remains uncertainty about the
choice and costs of the solutions that will be used to make the
network more flexible and controllable, this being related to
the availability of solutions and their positioning in the R&D
lifecycle. It must be recognised that all DNOs have effectively
ramped up R&D from a point of almost zero in 2005 to today's
level (leveraged programme in excess of £35 million). It
is an accepted fact that network related R&D has longer timescales
in comparison to many other sectors.
10.4 We recognise, through projects in our
own IFI portfolio, that many of the concepts and technologies
underpinning a change to a more flexible network are still very
much at an embryonic stage, with little or no firm commercial
offerings in the marketplace. Examples include, Active Network
Management (ANM) functions such as dynamic load management, multi-generation
constraint management, fault current limitation etc. However,
uncertainty around the costs and choices of solutions and the
inability to benchmark against other schemes in detail should
not, in itself, become a reason for delaying investment in these
enabling technologies. In order to avoid such behaviour a `no
regrets' approach to specific and targeted expenditure to such
projects would be of benefit.
10.5 It is increasingly apparent that a
wider form of cross sector participation is required to facilitate
the paradigm shift to a low carbon energy system. We would acknowledge
that working as an individual DNO, or even a body of network operators
is insufficient to develop a future network in the most economic
and "future-proofed" manner.
10.6 Feedback from recent stakeholder events
highlighted the need for active engagement of network operators
with suppliers (smart metering), generators (energy mix), planning
authorities (geographical issues) and other key stakeholders (eg
car manufacturers—relating to "plug-in" hybrid
vehicles) in order to fully understand the risks and opportunities
presented by changes outside of the current networks arena.
10.7 It is fundamental that in order to
meet these challenges, network operators need to be appropriately
resourced.
11. What can the UK learn from the experience
of other countries' management of their electricity networks?
11.1 We would observe that the UK has a
tradition of investing the minimum in infrastructure and utilising
assets for as long as possible. While this does indeed save money
in the short term, there is a risk that it builds up a bow wave
of under-investment that is expensive, both for consumers and
utilities. We believe that continental utilities have generally
adopted a more regular asset replacement programme that has led
to a lower average age of the assets and avoided the replacement
build-up that we currently face.
11.2 A number of other countries have also pressed
ahead with the introduction of smart metering as a DNO led activity.
While the market model is open to debate, it is instructive to
learn that some others are ahead of us in this field, and have
succeeded through an organised programme.
March 2009
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