Memorandum submitted by E.ON
EXECUTIVE SUMMARY
— Britain's electricity networks are key
to the successful achievement of government energy policy objectives.
— Long term regulatory stability is essential to give confidence
to and ensure investment in networks. — The success of the
new planning process under the Planning Act 2008 will be key to
the delivery of major energy network projects in future.
— Distribution network operators (DNOs)
have a more active role to play in the facilitation of a low carbon
economy, and we look forward to engaging with Ofgem, government
and other stakeholders to develop robust, long term solutions.
— The regulatory framework must be aligned
with government energy policy goals. We welcome Ofgem's and DECC's
support for a strategic approach for transmission network investment,
and for greater innovation in network design and investment incentives,
which will help facilitate this.
— We believe that the strategic transmission
investment incentive mechanism should allow the transmission companies
greater flexibility in making their investment decisions. The
transmission companies must start developing their planned investment
now to give the best chance of providing a network that will be
sufficient for the UK's requirements by 2020 and beyond.
— We recommend the consideration of a similar
strategic approach for distribution, which is at the beginning
of a prolonged period of asset replacement. A clearer vision of
the future energy network landscape of the UK, associated with
a shared range of assumptions, will provide companies with the
clarity they need to develop the network.
— E.ON believes that smart networks can
bring opportunities to networks businesses, but DNOs now need
to build up their capabilities, test potential solutions and understand
the benefits and risks. RPI-X has been successful at driving costs
down, but now needs to be broadened to allow DNOs to develop ready
for the challenges they now face.
— The network businesses have in recent
years introduced a very effective programme of innovation, but
there is a need for ongoing development of the framework to encourage
project replication and acknowledge the inherent risks associated
with emerging technology application.
1. INTRODUCTION
1.1 E.ON UK is one of the UK's largest retailers
of electricity and gas, one of the UK's largest electricity generators
by output, and owns Central Networks, the distribution network
which covers the east and west midlands. We welcome the select
committee's consideration of Britain's future energy network needs,
as E.ON UK has a key role to play.
2. GENERAL REMARKS
2.1 E.ON UK believes that robust networks
are key to the delivery of energy policy objectives. However,
Britain's network businesses face significant challenges which
must be met if the government's energy policy objectives are to
be achieved.
2.2 We welcome the opportunity for distribution
network operators (DNOs) to take a more active role in the facilitation
of a low carbon economy, and are keen to help develop a robust
framework which enables a more proactive approach by DNOs and
provides appropriate funding, as well as taking account of the
risks and uncertainties that networks businesses face in the DPCR5
period and beyond. Aligned with this, we welcome Ofgem's and DECC's
agreement with the industry that a strategic approach is required
for transmission network investment, along with greater innovation
in network design and investment incentives.
3. ANSWERS TO
SPECIFIC QUESTIONS
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?
3.1 Effective electricity networks will
be key facilitators in the delivery of our energy policy goals.
The priority should be to ensure there is sufficient investment
to maintain secure supplies to consumers, that networks are capable
of incorporating low carbon technologies at all scales, and that
the investment required is delivered efficiently and does not
impose excessive costs on customers. The expectations of Britain's
energy networks will be very different, and they must be able
to accommodate distributed generation, to work in a more flexible
way and to play their role in the reduction of the UK's carbon
footprint.
3.2 Where there are clear targets and reasonable
certainty where investment will be located (as with on and offshore
wind and nuclear), the regulatory framework needs to support the
required investment and its delivery in good time. However, in
other areas, where there is more uncertainty (for example in respect
of the extent of distributed and microgeneration), the regulatory
framework needs to allow companies to commit investment to create
options for the future.
3.3 Many network assets were installed in the
1950s and 1960s and are now reaching the end of their lives, and
the cost of replacing them and of recruiting and training the
skilled workforce that will be needed to carry out this work over
the next 15 or 20 years are considerable. Companies must be appropriately
rewarded for this massive investment programme, within a stable
regulatory framework that will enable them to attract equity funding
in today's less favourable economic climate.
3.4 The role of the electricity distribution
companies could help with the integration of low carbon activities,
potentially combining smart network features that could help facilitate
generation connection and network diagnostics, with additional
energy management requirements.
3.5 The degree of flexibility suggested
by the range of scenarios under consideration is too great for
effective engagement. In order to deliver the desired UK outputs
within the required timescale, the vision of the future energy
network landscape for the UK requires association with a set of
common assumptions, including for example:
— A narrower range of outcomes for likely
generation mix (central vs. distributed, level intermittency,
geographic dispersal etc).
— A consistent view of customer demand
developments, particularly electric vehicles and electric heat
pump adoption.
— A clearer view of "end to end"
energy delivery roles and responsibilities, dealing with, for
example the application of demand side management technologies.
3.6 The Department for Energy and Climate
Change (DECC) reconstituted the Electricity Networks Strategy
Group (ENSG) in 2008 to consider the transmission network requirements
for 2015, 2020 and 2030. The ENSG has reported its recommendations
for least regret and low regret investments required to provide
the necessary transmission system to facilitate the 2020 renewables
target. We supported this work and participated in the Transmission
Project Working Group that prepared the report to the ENSG. We
agree with the recommendations contained in the report. In particular
we believe that transmission companies should be permitted to
commence immediately with pre-construction work on the investment
projects identified, in order to provide the opportunity to meet
2020 targets.
How do we ensure the regulatory framework is flexible
enough to cope with uncertainty over the future generation mix?
3.7 Given the complexity of the issues discussed
above and the urgency of action to meet 2020 targets, there may
not be a single "ideal" solution in the form of a regulatory
mechanism or incentive. The framework will however need to accommodate
three key mechanisms:
— To grow capabilities in relatively short
timescales, resource also needs to be funded via the price control
for engagement and development with developers and local authorities,
similar to "incubation" funding provided to start-up
companies. This should encapsulate a more proactive stance from
networks in supporting future projects but also working with them
to innovate in new commercial and technical solutions for future
energy policy. This should be shielded from the RPI-X cost control
framework to actively encourage development.
— To encourage the construction of demonstration
projects and key partnerships early in the DPCR5 period, supported
by an innovation incentive mechanism and the DG incentive.
— To support the transposition to business
as usual, minimising the unit cost of application, but recognising
that this will add to the levels of business risk within the network
companies. This "risk premium" may be best recognised
as an explicit element of the company's financing costs.
3.8 A fundamental point that must be recognised
is that as DNOs will face increased risk in a number of ways,
including financing capacity for smart schemes that fail, interaction
with regulatory incentives—losses, Customer Interruptions
(CIs) or Customer Minutes Lost (CMLs). DPCR5 is making steps in
the right direction, and is likely to deliver a more flexible
treatment of costs, although the treatment of losses needs more
consideration, particularly since in the current form it would
penalise "smart" networks where capacity utilisation
is increased.
3.9 There will be additional risk to companies
(for example, additional capacity may be required on top of "smart"
solutions), and the framework must recognise this and find a pragmatic
way to assign this risk between companies and customers, recognising
the longer term benefits to the UK as a whole. Ultimately, the
framework has to ensure investors stand a reasonable chance of
making a return from investing in new approaches and technologies—"a
fair bet" as some commentators have observed.
3.10 Proposed changes by Ofgem to remove
cost-incentives that dissuade companies from pursuing operating
cost solutions vs. capital investment programmes will also help
significantly.
3.11 The framework must also recognise the
need to provide for network developments for both known connection
projects, and also the expected large number of unknown connection
and development requirements.
3.12 The regulatory framework for transmission
should also be aligned with government energy policy goals. Ofgem
has recently consulted on transmission owner (TO) investment incentives
to provide a funding mechanism for the necessary transmission
network reinforcement to facilitate transmission capacity requirements
for the 2020 renewables targets. The mechanism relates to the
low and least regret investments identified in the ENSG transmission
project working group report. The investment incentive mechanism
in principle should allow the TOs greater flexibility in making
their investment decisions, alongside the price control review
process. Consequently Ofgem's role in approving investment in
the transmission system could be reduced.
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
3.13 The barriers relate to the points discussed
above, most importantly the high level of uncertainty and the
ability of the regulatory framework to handle this whilst incentivising
investment and keeping prices at efficient levels. For example,
there is no common commercial framework to handle interactions
between customers and DNOs for control of generation and demand
side management, and indeed no clarity on whether there should
be direct contact or via an intermediary. Likewise, there is little
experience in the UK of operating "smart" electricity
distribution technologies on a wide scale whilst meeting existing
security standards.
3.14 The development of an industry wide common
set of assumptions for use by the distribution companies would
certainly reduce the degree of uncertainty, and consequently encourage
earlier physical engagement.
3.15 As for transmission, this would need
acceptance by Ofgem of some investment ahead of need, which the
current framework fails to accommodate.
3.16 The success of the new IPC planning
process under the Planning Act 2008 will be key to the delivery
of major energy infrastructure projects. The national policy statements
for energy infrastructure are therefore important documents to
get right to enable the investment needed.
3.17 Locational pricing is a prerequisite
for the long term efficient economic development of the transmission
network because it incentivises generation and demand to be located
near to each other thus reducing transmission losses and CO2 emissions,
and is therefore in the interests of the consumer and the environment.
Optimising the use of the transmission system, through a form
of "connect and manage" being considered under the transmission
access review, is important to the connection of new renewables
in the short to medium term. Long term regulatory certainty however
is essential to give confidence to and ensure investment in the
network and generation with longer lead times, such as nuclear.
Regulatory certainty will provide the investment needed in the
supply chain and increases in the skilled resource that will be
required for delivery of the network infrastructure and new generation.
3.18 Proving new technology for the deployment
in the UK will be an important technical assurance to provide
greater network capacity, the use of series reactors and high
voltage direct current (HVDC) cable onshore in the UK for the
first time are examples of this. Whilst this technology is used
internationally it needs to be proven for successful deployment
in the UK transmission network.
What are the issues the Government and regulator
must address to establish a cost-effective offshore transmission
regime?
3.19 The need for regulatory clarity and
stability is key. The introduction of the proposed offshore transmission
regime should therefore not be delayed. Whilst it can be implemented
for transitional projects, DECC and Ofgem have yet to demonstrate
that the regime will work as hoped to provide offshore strategic
network investment. A route map of the application of the competitive
tender process for the delivery of round three projects and later
round one and two projects that do not qualify for transitional
status would be an important step to providing industry confidence.
If this can be proven the benefits of competition should help
to deliver cost effective investment, much needed sources of capital
and delivery capability to meet the scale of investment predicted
for the network and generation offshore.
What are the benefits and risks associated with
greater interconnection with other countries, and the proposed
"supergrid"?
3.20 The main benefit of greater interconnection
is that the increased trading between the two connected systems
will allow generation to be used more efficiently and reduce the
total volume of capacity required to meet demand if peaks are
at different times. A potential benefit of greater interconnection
is the access to additional reserve generation would help to offset
increased volumes of intermittent generation, although our studies
suggest this effect is limited as large volumes of wind generation
also occur in north western Europe which is often subject to similar
weather conditions. Interconnectors are expensive and the trading
benefits have to provide through usage charges an adequate return
on the investment.
3.21 A super grid connecting offshore wind farms
to adjacent countries is an exciting proposal but it is unclear
whether this is the most cost effective route for connecting new
offshore wind. Timely delivery of the supergrid will be an issue.
For example, round three offshore windfarms should not be delayed
because the connection of a zone is dependent upon a wider interconnection
project.
What challenges will higher levels of embedded
and distributed generation create for Britain's electricity networks?
3.22 The electricity network has in general
been designed to transport power from large central generators
through the transmission and distribution grids to the end customers.
Investment in the distribution network will be important as networks
move from this passive, one directional design to more active
networks, with the interaction between embedded generation and
potential growth in demand side management.
3.23 Technical challenges include voltage control,
the management of thermal limits of lines and cables and the operation
within plant fault level ratings, whilst optimising to ensure
demands such as vehicle charging, and DG inputs are all integrated
into the distribution network. The extensive development and integration
of control and telecommunications systems will become increasingly
important.
3.24 Contractual challenges include risk
allocation, where for example a local generator is relied upon
in preference to the investment in additional network capacity.
What are the estimated costs of upgrading our
electricity networks, and how will these be met?
3.25 For transmission, the ENSG 2020 transmission
network report indicates capital expenditure of £4.7 billion,
but that savings of £850 million can be made by commencing
the pre-engineering work now to enable timely delivery. This will
reduce the amount of more expensive offshore network investment
that may otherwise be required.
3.26 We are still assessing the cost impact for
distribution networks within E.ON UK. Although early costs may
be small (£10s-£100s millions over the next few years
for small scale "dg-ready" capacity increases and systems
development) longer term costs may be more substantial. For context,
Central Networks' investment requirement for 2010-15 is approximately
£2 billion.[65]
This is for two distribution networks and is part of a replacement
programme likely to last for another 15 to 20 years.
How can the regulatory framework ensure adequate
network investment in light of the current credit crunch and recession?
3.27 The regulatory framework must allow
adequate cost of capital to attract the substantial funding required
and must recognise the long term nature of network investments.
In the face of increasing capital requirements, companies need
to be able to maintain a stable financial position and credit
rating, and not be forced into "novel" debt-base financial
engineering by an inadequate recognition of the cost and value
of equity in the allowed regulatory return. In addition, as innovation
is increased, the risk taken by businesses will increase, and
this must be reflected in the return, with an emphasis again on
the importance of equity. Finally, the framework must recognise
that new ideas by their nature sometimes fail and not unduly penalise
companies which are trying to innovate.
How can the regulatory framework encourage network
operators to innovate, and what is the potential of smart grid
technologies?
3.28 The existing regulatory framework has been
very effective in encouraging research and development activity
amongst the network companies, and has in parallel provided some
stimulus for network related programmes within our universities.
This approach should certainly be continued, but supported by
a regulatory framework that encourages not just the initial innovation,
which is beneficial, but importantly the replication of innovative
developments in pursuit of a lower carbon model. Please see paragraph
3.7 and following paragraphs for more specific proposals for electricity
distribution regulation.
3.29 Whilst TO investment incentives should facilitate
the necessary investment, this will be underpinned by the price
control arrangements on transmission and distribution companies
as well as the competitive tender process for awarding 20 year
offshore transmission licences. Long term regulatory certainty
will give added confidence and minimise the risk relative to other
investment opportunities, so that the UK is seen as attractive
to the level of capital debt/equity funding that will be needed.
3.30 The potential for "smartgrid"
technologies is considerable and the benefits could span distributed
generation facilitation through active controls, network security
improvements through automation and diagnostics, and network utilisation
through the application of demand side management techniques.
Is there sufficient investment in R&D and
innovation for transmission and distribution technologies?
3.31 We believe there is, at least in the
early stages of development, sufficient investment and the Innovation
Funding Incentive has been very successful.
3.32 Whilst there is an R&D allowance under
the transmission price controls, the ENSG transmission report
suggests using HVDC technology and series reactors, which are
new technology for deployment onshore in the UK. Early signals
to the supply chain for the need for these technologies will facilitate
the specialist supply chain to invest in enhanced capacity and
capability for the UK market. Again, long term regulatory stability
will help to ensure the necessary investment is made by the specialist
supply chain.
What can the UK learn from the experience of other
countries' management of their electricity networks?
3.33 Experience from the feed in tariff
in Germany gave rise to a growth in renewable generation in Germany.
This was ahead of the capability of the network to meet the fluctuations
in generation and demand to cope with the increased penetration
of wind in its generation mix. To some extent this was offset
by the level of interconnection on the continent, which gives
more options to balance generation and demand than the British
island network. Development of the British security and quality
of supply standard is seeking to address these issues prior to
the anticipated increase in wind generation as part of the UK`s
generation mix. It will be important to ensure that there is adequate
network investment and back up generation available to accommodate
the expected growth in wind generation to ensure network stability
and security of supply.
3.34 German offshore wind deployment has progressed
but is limited by the level of technology currently available
to facilitate deployment of large scale offshore wind in deep
waters.
3.35 Some countries are less focussed on
ensuring that network investment has a clearly demonstrable economic
justification. They may take a more probabilistic attitude to
planning and allow or even incentivise investment in strategic
infrastructure projects ahead of need. Ofgem is starting to do
this, but its approach is to develop a carefully calibrated incentive.
This may be appropriate, as it leaves some risk with the network
company and provides an incentive for National Grid to engage
with developers. However, it may also mean capacity will not be
built as quickly.
3.36 A roadmap for how to achieve a vision
could be useful if Ofgem then had to take this into account when
assessing efficiency of investment. This approach is, for example,
now being actively considered by the Californian legislature.[66]
March 2009
65 Regulatory capex based on DPCR4 cost allocation
methodology. Back
66
Californian Senate Bill 17 (Padilla); "Electricity: smart
grid systems." Back
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