Memorandum submitted by Dr Michael Pollitt,
ESRC Electricity Policy Research Group, Judge Business School
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?
How do we ensure the regulatory framework is flexible
enough to cope with uncertainty over the future generation mix?
A useful starting point for a discussion of
the future of GB's electricity networks is Ofgem's LENS report
which outlines five scenarios for the future of the UK electricity
network.[90]
The LENS scenarios from Ofgem describe five very different electricity
networks in 2050, ranging from a heavily reinforced scenario with
"bigger" transmission and distribution networks (Big
T&D) than at present sized to cope with the variability of
large renewable plant, particularly wind farms to a micro-grid
based scenario (micro-grids) with lots of local generation and
less strongly inter-connected local grids, based on local biomass,
wind and solar.
Another important starting point is the idea that
when it comes to electricity policy we should be thinking in terms
of the efficient delivery of energy services (heating, lighting,
power etc) rather than in terms of vertical structure of the current
electricity supply industry (generation, transmission, distribution
and supply). The question is not how best to configure the electricity
network, but how best to ensure reasonable demands for energy
services are met most efficiently. This encourages to think in
terms of appropriate organisational forms for such delivery and
to be open to potentially radically different combinations of
assets which might best deliver services (e.g. heat networks,
local generation etc).
It is worthwhile starting with a number of basic
principles for the future regulation of networks.[91]
First, there should be a presumption that regulation
in the future will involve more deliberate engagement between
buyers and sellers of network services (or their representatives).
Stephen Littlechild has discussed the success of such policies
in the electricity systems in North and South America (so called
negotiated settlements).[92]
The UK has been experimenting with this in airports with some
success (where it is known as constructive engagement). Given
the uncertainty about the future, creating appropriate fora for
negotiation between the parties is crucial as a way of handling
this uncertainty and managing the complexity of the task of approving
investment plans faced by the regulator.
Second, regulation should remain committed to
making good use of competitive mechanisms wherever possible and
to facilitating innovative entry into the sector. In electricity
generation and supply we expect large amounts of innovation to
help us to meet our ambitious climate change targets. Electricity
networks involve substantial investments by themselves, but even
more importantly can influence (via their flexibility/inflexibility)
the generation/supply investments that they support. They need
to be incentivised to encourage new entrants and be open to the
possibility that the current natural monopoly model of networks
may not be optimal by 2050.
Third, the academic literature and practical
experience has already established that differentiated pricing
has a key role to play. The arrival of smart metering throughout
the distribution system will offer significant potential for demand
response both in the short and long run at the household and commercial
levels. Such demand response requires the use of differentiated
pricing in space and through time for all electricity customers.
Customers may, of course, choose not to be exposed to such variations
directly (by choosing time invariant contracts) but the incentives
for energy service providers to match load to intermittent (or
indeed inflexible) generation should exist.
Fourth, keeping technological options (and hence
all the scenarios) open has a lot of value initially. We just
don't know at this stage what the best network configuration is
for 2020 or 2050, not least because of price, policy and technological
uncertainty. Different configurations have strengths and weaknesses.
However to begin with we can achieve demand reduction and increases
in renewable generation without radical changes to energy networks.
This gives us space to experiment with different technological
options and organisational forms. We should take this opportunity
because it has a high initial option value.
Fifth, the climate change agenda needs to be
consistently pursued through all aspects of regulation. It is
important to stress that rational consistency of policy is key
to delivering energy services at least cost. This requires a single
price of carbon and a consistent subsidy framework delivered with
commitment over the life of investments. We are some way from
achieving this difficult policy aim. At the moment planned network
investment is being made in an environment of high uncertainty
about the future financial incentives that will be available.
As with generation investments it is important that network investments
face a more consistent policy framework going forward than at
present.
An additional starting point, is to point out
that it is possible to imagine linear combinations of the scenarios
(this is different from the multi-purpose networks scenario in
LENS). Thus different distribution network areas might follow
different paths towards achieving our overall climate targets
and this might be a desirable outcome given their different electricity
generation and demand characteristics.
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.
An increase in large scale inflexible central
generation (over the current level) would mean a need for either
more flexible demand or more storage. Flexible demand is helped
by clear price signals to loads. It seems clear that nodal pricing
throughout the transmission system (like in the PJM market in
the US) and additionally nodal pricing within the distribution
system (as is being partially implemented in the south west (WPD))
would seem to be important to provide finely differentiated incentives
which could help manage demand and incentivise least system cost
location of distributed and micro-generation.
Consideration might also need to be given to storage
technology which might complement extra wind on the system. It
would be possible to invest in a significant amount more pumped
storage hydro. Careful evaluation of the value of such water (which
may not be privately economic if it reduces the price differentials
across time and hence the arbitrage opportunity) would need to
be made. David MacKay[93]
notes that several good sites are already identified for this
capacity. Similarly there are possibilities for dumping excess
wind power into heat (via electrical elements in hot water tanks)
which are being investigated in Scotland (and happens in Denmark)
but would require appropriate connections and incentives. However
this might be a cheap alternative to building new storage capacity.
What are the issues the Government and regulator
must address to establish a cost-effective offshore transmission
regime?
Ofgem are making substantial progress with this.
The move to have auctions for transmission capacity is a positive
one, which should ensure least cost new build of plant. Littlechild
notes the success of auctions for new transmission wires in Argentina[94]
and Pollitt noted the cost-reducing value of contestability in
transmission wire building in Chile.[95]
This process should cause significant new entry into the transmission
market in the UK. Care must be taken on where transmission links
are connected into the existing grid as this generation will be
intermittent and large scale. It is also important that auctions
are monitored to ensure competitiveness and that bidders deliver
on their winning bids. Clearly lessons from the private finance
initiative need to be learnt to avoid only one effective bidder
at the final stage. However given the standard nature of investment
in each case, the prospects for this form of competitive process
would seem to be good.
What are the benefits and risks associated with
greater interconnection with other countries, and the proposed
"supergrid"?
These need to be carefully evaluated. The tentative
evidence would seem to be that greater interconnection between
power control areas does increase the risk of large—multi-national—blackouts.[96]
There is also a problem of paying for international transmission
links where the costs are socialized within average tariffs. This
can either lead to incentives to oversize the grid (because the
costs are shared among average transmission charges) or to undersize
because merchant transmission cannot be justified. There is also
an interaction between the gas and electricity markets which suggests
that it might be more efficient to trade the gas rather than the
electricity internationally. Therefore it may be more cost-effective
at the European level to work on improving the gas market in Europe
and efficiently arbitrage this, rather than trade the electricity.
What challenges will higher levels of embedded
and distributed generation create for Britain's electricity networks?
This requires distribution networks to become active
rather than passive networks. Serious consideration needs to be
given to network regulation which encourages local generation.
Ofgem have begun thinking about this in the context of how electricity
regulation can learn from telecoms.[97]
The argument here is that we need to encourage more contestability
in local wires, with the threat of purchase by local generators
of sections of the existing networks or the creation of private
(duplicate) wires and the leasing of wires on fair terms. New
forms of ownership of local distribution assets, as say part of
Local Authority Energy Service Companies or Customer Cooperatives
might also be necessary to cope with lock-in of customers to local
supply and to encourage local political support.
It is possible that the creation of a more active
distribution network requires a significant reorganisation of
the electricity sector. In particular consideration should be
given to ownership unbundling distribution wire businesses from
the rest of the electricity system (similar to the position of
National Grid in transmission) in order to avoid incentives to
discriminate in favour of own generation or supply in an active
distribution system. This has occurred in New Zealand already.[98]
It might also involve the creation of new kinds of licences for
local electricity companies (e.g. for a local authority led ESCO
in each municipal area) who would have specific responsibilities
to deliver locally generated power and heat and in return receive
regulatory or fiscal support/exemptions.[99]
An important part of the mix is customer engagement.
It will be increasingly important that individual customers respond
to financial incentive to economise on carbon and energy. It is
also important that they embrace new technology such as smart
meters and the intensive use of data that they will eventually
facilitate. Thus individual consumers will need to welcome own
and local generation and to voluntarily submit to demand response
measures either directly or via energy service companies. This
will be key to the successful uptake of much more local generation.
An important part of the policy to get right will be that towards
the fuel poor. Customer engagement offers the prospect of initially
targeting the fuel poor for energy efficiency measures and subsidy
support. This has high potential as popular policy if implemented
sensitively.
What are the estimated costs of upgrading our
electricity networks, and how will these be met?
Network costs cannot be separated from power
costs and must be looked at in the round. It is very important
to only upgrade networks when this is necessary. If we can reduce
electricity demand it may be possible to slow the rate of replacement
of electricity network assets and this may be a significant saving.
Regulated companies need to be given strong incentives to prolong
the life of assets where there is no technical reason to replace
them.
How can the regulatory framework ensure adequate
network investment in light of the current credit crunch and recession?
In my view the existing system is capable of adjusting
to the credit crunch. Revenue will adjust marginally in line with
falls in demand which is appropriate. The calculation of the regulatory
weighted average cost of capital—WACC—will also adjust
at the time the prices are reset. Regulated network companies
remain relatively attractive investments to the credit market.
The credit crunch will offer strong incentives to regulators and
government more generally to clarify the investment regime and
reassure investors that the government is committed to a stable
investment environment.
How can the regulatory framework encourage network
operators to innovate, and what is the potential of smart grid
technologies?
The Innovation Funding Incentive (IFI) run by Ofgem
which encourages companies to spend up to 0.5% of their revenue
on R&D is important. This is a good scheme because it creates
extra revenue for R&D expenditure and it involves an element
of co-funding and competition. It is important that incentives
exist to undertake larger scale trails, as the town/city level.
In my view the IFI should be evaluated with a view to expanding
it (say to 2% of revenue) with the money being put into a pot
which not only network companies but other players (e.g. generators,
suppliers and local councils) could bid to conduct large town
level demonstration scheme (e.g. to promote a local smart grid/energy
service company).
Is there sufficient investment in R&D and
innovation for transmission and distribution technologies?
Almost certainly there is not enough R&D being
done given the scale of the future investments expected. The IFI
scheme for electricity transmission and distribution currently
only raises around £20 million per year. This would not be
sufficient to support a set of large scale demonstration projects
suggested above.
What can the UK learn from the experience of other
countries' management of their electricity networks?
In England and Wales National Grid have an on-shore
monopoly of new build of transmission assets and are integrated
with system operation. It is not clear that this is desirable
especially in a world where grid investments should compete directly
with generation and where local and remote generation should also
compete (and hence distribution and transmission system investments
are substitutes). We should therefore consider the creation of
a separate GB wide system operator operated on a not-for-profit
basis (similar to the situation in US jurisdictions, Chile and
Argentina etc). It would also be desirable if large new on-shore
investments were made under competitive tender and decided on
via a process of negotiated settlements. Serious consideration
should be given to the lessons from overseas experiences of separate
independent transmission operator(s) (ITO) and independent system
operators (ISO). These systems can operate as well as the England
and Wales system of a single independent transmission system operator
(ITSO).[100]
The UK has a largely monochrome approach to the delivery
of energy services via electricity and gas networks. Other countries
have traditionally had a more diverse approach with a combination
of heat networks as well as gas and electricity (e.g. Denmark,
Germany etc). This has involved a significant role for district
heating and increasingly own generation (e.g. Germany's support
for residential solar power). In other countries also make much
more use of smaller more local energy utilities and customer cooperatives
which might be capable of fulfilling an important role in showcasing
innovative approaches to energy service management (e.g. rural
electric cooperatives in the US and local electricity distribution
companies in Norway and Sweden). We in the UK need to consider
whether a more localized approach is part of the solution in the
future. This plays to the need to engage individuals and local
communities in tackling climate change and to encourage the use
of local resources as opposed to relying on big national level
projects. Such a local approach—reflecting the ESCO and
Micro-grids scenarios in the LENS report—would require significant
regulatory support and government subsidy particularly at the
beginning to trial new business models in the UK energy sector.
Thus while the UK electricity market liberalisation has been very
successful, it is also the case that Scandinavian countries have
followed a very different path at the local level and seem to
have also had successful energy market liberalisations. A closer
look at what lessons can be learned from these countries would
seem to be appropriate.
March 2009
90 See Ault, G, Frame, D and Hughes, N (2008), Electricity
Network Scenarios in Great Britain for 2050, Final Report for
Ofgem's LENS project, London: Ofgem. Back
91
Here we draw on Pollitt, M (2008a), "The Future of Electricity
(and Gas) Regulation in a Low-carbon Policy World", The Energy
Journal, Special Issue on "The Future of Electricity: Papers
in Honor of David Newbery", pp 63-94 and Grubb M, Jamasb,
T and Pollitt, M (2008) (Eds), Delivering a Low-Carbon Electricity
System, Cambridge: Cambridge University Press, pp 487-495. Back
92
For a summary see Littlechild, S (2008) "Some applied economics
of electricity regulation". The Energy Journal, 29(S2):
43-62. Back
93
MacKay, D (2008), Sustainable Energy-Without the Hot Air,
Cambridge: UIT. Back
94
See Littlechild (2008) op cit. Back
95
See Pollitt, M (2004) "Electricity reform in Chile: lessons
for developing countries". Journal of Network Industries,
5(3-4): 221-262. Back
96
Yu, W and Pollitt, M (2009) "Does liberalisation cause more
electricity blackouts? Evidence from a global study of newspaper
reports". Electricity Policy Research Group Working Papers,
No EPRG0902. Cambridge: University of Cambridge. Back
97
See Pollitt, M (2009, forthcoming), Does Electricity (and Heat)
Network Regulation have anything to learn from Fixed Line Telecoms
Regulation?, Mimeo. Referred to in Ofgem (2009), Regulating
energy networks for the future: RPI-X@20 Principles, Process and
Issues, Ref 13/09, London: Ofgem. Back
98
See Nillesen, P and Pollitt, M G (2008) "Ownership unbundling
in electricity distribution: empirical evidence from New Zealand".
Electricity Policy Research Group Working Papers, No EPRG0820.
Cambridge: University of Cambridge. Back
99
For a review of existing local authority ESCOs in the UK see Kelly,
S (2008), Economic competitiveness of combined heat and power
district heating networks in the UK, M.Phil.Engineering for
Sustainable Development, Thesis, University of Cambridge. Back
100
Pollitt, M (2008b) "The arguments for and against ownership
unbundling of energy transmission networks". Energy Policy,
36(2): 704-713. Back
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