SUMMARY
AND CONCLUSIONS
i) UK energy markets are beset by a number of
actual and potential market failures. This submission tries to focus on those
that are most relevant to institutional questions, including regulation, and
issues for infrastructure investment and for wholesale and retail markets. It
also concentrates on power as the sector critical to low carbon transitions,
although some of the issues for power will have implications for, or a read
across to, other sectors.
ii) Stemming from the
objective of controlling CO2 emissions, the biggest single market failure is
the absence of adequate carbon pricing. This failure can be addressed through
carbon taxes or more effective and flexible emissions trading schemes, and the
main obstacles are well known. But with or without resolution of carbon pricing
questions, there are several less familiar sources of market failure within the
sector. These stem from:
·
General features common to much if not all
infrastructure investment, and the level of reassurance required by
infrastructure investors for large long life projects.
·
Complex nature of the industry requiring real
time command and control, as well as coordination between generation and
transmission (and increasingly distribution).
·
Multiple interactions with the technical
characteristics of low carbon generation, very different from those of the
fossil plant for which existing structures were designed.
·
Weaknesses already embedded in existing
conventions and assumptions underpinning both wholesale and retail market
arrangements.
iii) Resolution of these questions, in the context
of wholesale transformation of the energy sector, will depend on finding a
“system architecture” – combining technical, markets, regulatory and
institutional features to accommodate a sector undergoing major changes in its
mode of operation. Particular resolutions suggested here indicate some
combination of a central purchasing function, use of properly structured
contracts under which the system operator would schedule and dispatch plant,
and use of sophisticated metering to permit abolition of the load profiling and
averaging that characterises the current retail market.
iv) The government has de facto become a central
purchaser in the power sector. A central purchaser is almost certainly part of
the answer, but the priority should be to ensure the role is performed well. A
technically and commercially competent agency at arm’s length from government,
with a degree of regulatory oversight, should be considered as an option. Inter
alia this agency would conduct capacity auctions and define the nature of the
contractual obligations for generation and storage facilities and some elements
of consumer load.
v) The technical and economic characteristics of
low carbon (and storage) technologies are fundamentally different from those of
fossil generation, notably in terms of zero marginal cost, inflexibility and
intermittency. Current wholesale markets were conceived and designed for fossil
generation (by and for fossil generators) and will increasingly cease to be fit
for purpose in a low carbon power sector. These market arrangements are likely
to need review in the next few years, and we should anticipate a larger role
for any system operator(s).
vi) Current market arrangements and conventions
that govern the onward sale of electricity to retail consumers have had the
effect of inhibiting innovation in retail supply, eg in the provision of more
cost reflective tariffs and different definitions of the services provided to
consumers. They will also inhibit trends towards more decentralised generation
and storage. Given the technical possibilities in metering and control, these
obstacles can be removed.
vii) This submission also
considers the Committee’s specific questions from this perspective.
DEFINING
THE KEY CHALLENGES
The Committee’s first specific
question defines the context for this submission. What are the key economic challenges for the energy market which the
Government must address over the next decade?
The fundamental challenge for
the energy sector is that low carbon objectives require transformative change
across several sub-sectors of energy production and use. The largest in scale
are the power sector, transport (notably via electric vehicles or hydrogen),
and the heat sector. This submission focuses on power partly because it has the
most immediate challenges and partly because its transformation is also
critical to the other two. Large increases in generation output and capacity
are likely to be required for future transport (eg battery charging) and for
heat (heat pumps or district heating).
The role of the power sector
is therefore central in the short, medium and long term. Early decarbonisation
is a precondition for successful later decarbonisation of transport and
heating. But although the power sector
is the main concern of this submission, we should note that there are also
major challenges particular to transport and heating.
Transport. This
is still dominated by road transport. However motor manufacture is an
international or global industry, so that the pace and detail of technical
change will be determined on an international stage. The immediate challenge
for the UK government and industry may therefore be mainly about influence on
international market and regulatory developments. Most recently it is European
regulation that has been of the most immediate concern to the British motor
industry, whether from an export or import perspective. Maintaining UK
influence is therefore a significant challenge both for the UK motor industry
and in terms of low carbon objectives.
Heating.
Heating poses particular technical challenges for the power sector, given its
scale and the seasonal, temperature dependent nature of heat load. But it has
its own regulatory and institutional challenges. Many of the scenarios that
describe how low carbon targets might be met depend on widespread introduction
of district heating schemes, typically with combined heat/power generation.
This is not only a major infrastructure investment in local pipe networks (to
carry hot water), of which the UK has very limited experience. It also implies
a degree of collective choice over heating method for a large part of the
population. Institutional questions will arise for the ownership, management
and regulation of municipal district heat networks – local monopolies outside
the OFGEM framework. Although the decarbonisation of heat will not be achieved
quickly, it has been widely assumed that the foundations will need to be laid
in the next decade.
The
Investment Challenge
The investment requirements
for transformative change across the sector are very large, but scale per se is
not the main problem. French experience of very successfully decarbonising
power in the 1980s and 1990s tends to support this assertion, although clearly
the challenges in achieving this through private sector investment will be
different from those of a state corporation.
However it is already clear
that future energy systems will be dominated by capital costs to an extent even
higher than for existing energy systems. In consequence the cost of capital
becomes a factor of absolutely fundamental importance in making the necessary
transition affordable. One key economic challenge is therefore creating market,
regulatory and institutional arrangements that provide confidence to
infrastructure investors (eg pension and sovereign wealth funds), by
eliminating regulatory and policy uncertainties. This should result in a relatively
modest cost of capital for what are essentially “low beta” utility
businesses.
Market
Failure and “System Architecture”.
The overarching challenge is
to find the right combination of regulated monopoly or public guarantee (to
achieve a lower “utility” cost of capital), competitive markets and incentives
(to promote efficiency and innovation), policy intervention (to meet climate or
other social and political objectives), and technically competent institutions
(to manage complex interdependencies). A major part of this, though not the
only part, is devising means to overcome the several sources of actual or
potential market failure that are present for the sector.
MARKET
FAILURE. A KEY THEME.
The Committee has identified
market failure as a key theme for its investigation. This submission begins
with some of the main sources of actual or potential failure for the sector.
These can also interact and be mutually reinforcing. They are:
·
The nature of the CO2 externality, the “social
cost of carbon”, and the problem of incentivising low carbon objectives through
current market mechanisms. This is the biggest single market failure.
·
Familiar issues of infrastructure investment:
of providing private investors with sufficient policy and regulatory certainty
on their future revenue streams.
·
Technical features peculiar to the power sector
that depend on real time command and control functions to maintain secure and
stable power to consumers; the interaction of these with the newer generation
technologies.
·
Weaknesses in existing electricity market
structures (particularly post 2000) with inadequate incentives for capacity,
even for fossil-based systems.
·
A general problem of coordinating investment,
and deciding the right mix of assets and other features, both for the power
system itself and across the energy sector as a whole. This feature is
reinforced by the more complex technical constraints pertaining to low carbon
generation.
·
Features of current market structures and
conventions that fail to translate underlying cost structures into consumer
tariffs that will encourage “efficient” modes of consumption. Current
arrangements have inhibited innovation in, for example, smart metering and novel
approaches to supply.
The author has addressed some
of these topics in more depth elsewhere, most recently in a piece recently
published by the Energy Technologies Institute[1], but the main points of
analysis and conclusions can be summarised as follows.
Point
I. Putting a price on carbon emissions,
consistent with the policy imperative to mitigate climate change, ought to be a
priority. Inter alia it can improve the “carbon efficiency” of existing assets,
help incentivise research and investment, and reduce energy consumption. The
difficulties are also well known, and what ought to be an important mechanism,
the EU ETS, has so far failed to deliver prices adequate to incentivise the
transformative changes that are required. The government, like others in
Europe, has resorted to more direct interventions. However with or without
satisfactory resolution of carbon pricing questions, the government will still
face several other sources of market failure within the sector, which would not
be removed even with a realistic carbon price
Point
II.
Obtaining investment in new capacity at an acceptable cost of capital,
appropriate to what is in capital market terms a “low beta” utility sector with
low market correlated risk, depends on providing infrastructure investors with
assurance on a number of uncertainties that are outside their control,
including policy, regulatory and market structure uncertainties. Historically
this has normally been achieved through measures that involve strong components
of vertical integration into relatively stable downstream markets, regulated
monopoly, long term contracts with secure counterparties, government guarantee,
public ownership or some combination of some of all these. This traditional
analysis of the economics of the power sector continues to be true. It is
however reinforced by the uncertainties around policies for the sector,
including those that relate to carbon prices.
This implies a continuing
important role for government in the sector, and it will almost inevitably
continue to get drawn into questions of technology choice and support for major
investments. There is a strong case for an arms-length agency with professional
sector expertise to deliver this role.
Point
III. There are specific features of wholesale
power markets that mean they fail to deliver a set of price signals that works
both to deliver efficient operation of existing assets (“sweating the assets”
through the merit order) and to provide signals to incentivise investment in
new capacity. Technical and economic features of the various forms of low
carbon generation, including zero short run marginal cost, inflexibility
constraints, multi-period storage, intermittency, and changes in scale, will
all reinforce and accentuate these problems. It is likely that existing
wholesale markets will increasingly cease to be “fit for purpose”, and subject
to ad hoc fixes that further undermine their position as a basis for an
efficient sector.
Wholesale and spot prices are
likely in a low carbon system to have a much smaller role in delivering
efficient and secure operation of the current stock of sector assets. The role
of the system operator, in dispatching plant and making operational choices, within
a set of available options that includes demand side response and the
contractual commitments of the existing stock of plant, is likely to expand.
Point
IV. Capacity markets are widely seen as part of
the answer to the issue of securing new investment and adequate capacity on a
competitive basis. This immediately raises the question of exactly who (and
with what expertise) determines the parameters for any capacity auction, and
how that auction is conducted. This requires decisions on who decides how much
capacity is required, when it is needed, what constitutes capacity, how it is
measured and monitored, how it is remunerated (eg under long term contracts)
and so on.
Capacity markets in the UK
have the government acting as a central purchaser, a role already implicit in
its support for renewables and nuclear investment. This suggests formal
recognition of the need for a central purchasing agency, with a strong case to
make it at arms length from government, with at least some degree of insulation
from political interventions and interest group lobbying.
Point
V. Engagement of the consumer in demand
response programmes is widely anticipated as part of the future power sector,
and along with storage, one of the necessary responses to intermittent or
inflexible sources of generation. Current arrangements, which average
consumption load profiles across categories of consumer, do not allow for the
exploitation of advances in metering, communications and control technologies
which could transform the “consumer offering”, the way in which consumers buy
and use power. They will need re-design as part of a new architecture for the
sector.
Point
VI.
Decentralisation of significant and increasing parts of generation and storage
facilities for the sector also raises related issues. Inter alia this will put
a much larger onus on the operators of local distribution networks to balance
local loads and local generation, without necessarily reducing the importance
of the national system, which will continue to be an essential back-up and a
means of exploiting diversity between different sources of intermittent power.
This changes in fundamental ways the business model of conventional (local)
network utilities, inter alia placing a big emphasis on the structure of
network charges. This represents a major change from the status quo, not least
because it undermines the traditional practices of basing network tariffs
mainly on simple averaging of costs over all kWh.
These points add up to the
need for a comprehensive re-thinking of the “system architecture” for the power
sector and most likely for the energy sector more widely. System architecture
in this context means the totality of arrangements for the sector that
determine where technical and operating decisions are made, which parts of the
sector are primarily based on competitive markets or on coordination and policy
intervention, and the details of regulatory and market structures.
This submission remains
neutral on questions of technology choice, and is consistent with “consensus”
views of a balance between nuclear, CCS and renewables. It is also neutral on
the issue of public vs private ownership. The key issues are apportioning and
reconciling the roles of competition, coordination and command and control
elements required for the sector, and necessary policy interventions required
for ambitious emissions targets.
ADDRESSING
SPECIFIC QUESTIONS OF THE INQUIRY
Has
the market and the Government responded effectively to changes in external
circumstances, such as significant shifts in technology and prices?
De facto very significant
areas of decision making have moved from notional reliance on market forces to
actual dependence on government decisions. Little or no major generation
investment is anticipated without some form of direct government support or
guarantee, either through feed-in tariffs or long term contracts. Moreover the
introduction of capacity auctions, prima facie a market mechanism, is itself no
more than the institution of a form of central purchasing arrangement, since a
central body has to specify how much capacity is required and to define its
technical requirements. A competitive market to supply capacity will still
operate of course, but it will operate within parameters laid down by a central
agency.
A positive perspective on this
is that the government has clearly recognised the need to intervene, in order
to deal with some of the market failures identified above, including weaknesses
in current market structure. A more critical perspective is that it may lack
the technical and institutional competences to intervene effectively and
efficiently, and that this not a suitable role for a government department. In
my view there is a strong case for this role to be carried out by an
arms-length agency. This could take various forms, including that of a central
purchasing agency or augmenting the responsibilities of a body such as the
National Grid.
Markets themselves, in the
context of the power sector, are unlikely to be able to adapt to changing
external circumstances of the kind we are observing, and it will rarely be in
the interest of incumbent participants to change the rules. Previous changes to
market structure and design, including the 1990 structure and the 2000 NETA
reforms, have been the result of major policy and regulatory interventions.
Meanwhile other issues are
surfacing. These include the increasing failure of conventional wholesale
markets to deliver wholesale prices that can reward capacity, and concern that
these prices may not even be compatible with efficient operations. There is a
risk that these problems will provoke a series of ad hoc interventions, special
one-off rules, and “patch-ups” that fail to address the underlying issues.
Finally there is a strong body
of opinion (not just in the UK) that the future of the power sector, and the
energy sector as a whole, involves a bigger role for decentralised power
generation, more decentralised decision making within local and regional
distribution networks, and more emphasis on consumers as active market
participants. This would have a profound impact on the location of decision
making and what constitute appropriate or viable structures for the future, but
change is only likely to occur as the result of regulatory or other
intervention, preferably based on a clear vision of the “system architecture” –
the mix of technical features, competitive market content and regulation – that
is most appropriate to UK energy needs.
What
are the emerging technologies which could materially change the energy market
over the next decade and beyond?
Virtually all the low carbon
generation technologies have characteristics that will materially change the
energy market, most obviously because the technical and economic
characteristics of low carbon generation undermine the assumptions on which the
conventional wholesale markets are predicated.
Zero or negative marginal costs, the dominance of capital costs, and
different operating constraints, are all relevant examples.
Storage is also rapidly
emerging as a key factor in analysis of viable energy futures. This includes
but is not confined to developments in battery technology. In a power system
context, storage of power, even for relatively short periods, has obvious
implications for the ways in which current wholesale markets operate.
Looking further ahead we
should also anticipate the possible effects of two particular possibilities. It
may be premature to describe them even as emerging technologies, but both are
of huge potential significance, both as technical solutions and in their impact
on our conceptions of the energy market.
One is a solution (at
acceptable cost) to the problem of seasonal storage, a role which batteries and
hydro storage currently seem unlikely to fulfil. The most likely answer is
chemical storage of energy, eg conversion of electrical power to hydrogen, or
better still further conversion to a liquid fuel or a more amenable gas. This
could in principle transform the market by resolving many of the real time
balancing, seasonal and security problems, including the intermittency problem
(for renewables), and make energy conform more closely to the model of
conventional commodity markets.
The other is a solution for
carbon sequestration. The “zero carbon” future implied by the Paris agreement
almost certainly implies net extraction of CO2 from the atmosphere. The only
currently viable technology for this is carbon capture and storage (CCS)
although other more esoteric ideas have been put forward. The potential
importance attaching to zero carbon, however, suggests that the cost of carbon
sequestration technologies might ultimately attach a much more well-defined
cost/value to CO2 emissions.
How
should the Government promote research and development- could any shift in
public funding improve the efficiency of the energy market?
Prima facie the efficiency of
the energy market per se depends not on funding but on regulation, structure
and governance, ie system architecture.
However if one were to look for areas where technical advance could have
the biggest impact on market efficiency per se then it is the consumer related
area – metering, automated control of consumer loads, etc – that is likely to
be the most significant.
How
long might it take for new technologies to displace the established capital
stock?
French experience demonstrates
there can sometimes be very few barriers to a comparatively rapid
transformation of the capital stock, even in power generation. France moved
from high dependence on oil-fired and fossil generation to a near-zero carbon
power sector over a period of less than two decades (1977-1995). And the UK’s
movement from coal to gas has also been quite rapid.
What
should the future balance between the roles of the public and the private
sector be?
Overall the future will almost
certainly require higher levels of government involvement in setting policy
objectives for the energy sector, in defining new institutional architectures
for the operation of markets, and to some degree in underwriting key
infrastructure developments.
However the balance between
public and private, at least in terms of ownership and management, is not the
most important question. The key question for system architecture is the
balance between traditional “command and control” functions for the sector
(many still retained by the system operator), regulated monopoly, and segments
of the sector open to various forms of competition.
Another major factor is the
growth in decentralised generation and storage. This has been widely perceived
as a significant threat to the business model, regulated monopoly with
guaranteed cost recovery from a secure customer base, of local distribution
networks.
The preferred direction of
travel should probably be towards more explicit policy intervention in relation
to generation investment, system operation based on a combination of command
and control and contractual commitments made by
generators (who may have competed for their long term contracts in the
first instance), and much more effective competition in retail supply where
existing market arrangements have largely stifled the incentives for innovation
in more sophisticated metering and “consumer offerings”.
Similar issues arise for the
heat sector in the context of this and the next question. The nature of
district heating suggests that actual ownership and control should be at local
or municipal level, but the scale of development needed and the low level of
current UK expertise in this field suggests that there is a case for a national
body, again at arms length from government, to provide a kick-start for
district heating programmes.
Is
further expertise needed within Government to understand the issues and to
negotiate with external investors and suppliers?
Yes. The government has taken
on a de facto role as the main planner of the power system and as the main
decision maker on choice of generation technology. But, while it may be well
equipped in strategic terms, it is not clear that it has been able to develop
the necessary technical competence that would allow it to perform the purchasing
role effectively and to deliver the best outcomes. This is in any case not a
role well suited to a government department and should ideally be assumed by an
arms-length agency, which might for example act as the main purchaser for new
capacity.
National Grid is the entity
that currently comes closest to having the responsibilities and expertise
appropriate to this task, given its position as system and transmission
operator, but there are other options.
Are
returns for private investment in the sector adequate or excessive? How should
the Government attract sufficient investment?
The market failure arguments
above suggest that current returns will tend to be quite poor for new
investment in generation (other than under long term contracts secured at the
outset). This reflects the tendency of the wholesale market price to be
dominated by short run marginal costs, providing inadequate incentives for
capacity. At the same time margins and returns appear rather large in the
retail supply businesses[2], which requires little or
no capital investment. Unsurprisingly this can be viewed both as a prime
motivation for the vertical integration, or re-integration, of the industry
that has occurred since privatisation in 1990, and as an explanation of it.
There is also a significant
part of the sector that remains as regulated monopoly, notably the network
businesses of pipes and wires. Getting the balance right is the responsibility
of the regulatory body OFGEM, and there is no reason to suppose that the
balance between adequate incentives for investment and a fair deal for
consumers is not, in broad terms, being achieved, at least as measured by
returns on capital.
In aggregate, observed rates
of return on existing assets may therefore be reasonable (although I hesitate
to pass judgment on this), but the more substantial issue is financing new
investment. Investors require confidence in the anticipated revenue stream. New
generation investment no longer happens except in response to schemes that provide
some form of long term contractual protection. This takes us back to a
traditional view of dependence on some combination of regulated monopoly,
government guarantee, vertical integration and long term contracts.
What
is the relationship between high energy costs and the loss of industrial
capacity in the UK? What measures should be taken to address this?
It would be wrong to dismiss
the importance of energy costs for particular industries but it is also
difficult to argue that there is a strong relationship between high energy
costs and the loss of industrial capacity in the UK. The following points tend
to support this sceptical perspective.
The Committee on Climate
Change analysis[3]
suggests that the proportion of industry and GDP for which energy costs are a
significant influence on a firm’s price competitiveness is quite small. [c 2.6%
of GDP]. If analysis is confined to
goods in extra-EU trade the proportion will be smaller.
Exchange rate movements are
substantially more significant in their impact on cost competitiveness. The
recent depreciation of sterling will have substantially improved the UK
position in an international energy price comparison (except to the extent that
domestic prices embody international fuel prices). But the same exchange rate
depreciation will also have a much bigger and generally more important
competitive impact on firms through making their comparative labour costs, and
other domestically incurred costs, more favourable (since these are a bigger
proportion of total costs even for most energy intensive industry),.
The loss of UK industrial
capacity in the 1980s and 1990s has been strongly associated with the advent of
North Sea oil, sometimes known as the “Dutch disease”, and strongly associated
with the exchange rate impacts of North Sea oil as well as of economic policy
during that period. It had little to do with energy prices per se.
In general the association of
energy prices with measures of competitiveness looks weak. Many of our Asian competitors have faced
higher energy costs than the UK or EU. Germany, widely regarded as the most
“competitive” of the EU economies, also has among the higher levels of energy
costs, in spite of what is sometimes seen as an artificially competitive
exchange rate position[4] within the euro.
There are likely to be some
“carbon leakage”[5]
issues for particular energy intensive and internationally traded products and
industries. This should not in principle
be a problem in relation to EU competition, assuming the UK were to continue to
participate in a reformed EU ETS[6], but may be a problem in relation
to other countries, eg Chinese steel.
However the appropriate
response may be to consider remedies for each of the small number of affected
sectors on its merits, rather than to distort the general pattern of UK energy
policy. The political and economic
issues are very much akin to those of general trade policy, antidumping etc.
Anticipation of a changing post-EU trade environment obviously adds to the
potential complexity of this particular issue.
What
preparations could be made to cope with the risk of a shortfall in energy
supply?
The most critical area is
again the power sector. A lot depends on
the nature and extent of the type of shortfall that is anticipated as a risk.
Historically shortfalls have been perceived as events of relatively short
duration (a few hours at a time), linked to cold weather conditions and
reflecting insufficient capacity to meet the strongly seasonal and temperature
related nature of aggregate load. This is a failure to meet “needle peaks”.
Planning to reduce the
incidence or impact of this kind of failure ought to be relatively
straightforward, at least in principle, and the most obvious strategies to
adopt, apart from trying to avoid crisis in the first place, would be some
combination of measures already available to the Grid:
·
Using the capacity market or other means to
increase the amount of low cost incremental capacity available to meet peak
loads; this might include enhancement to existing interconnector capacity,
measures to encourage more use of existing sources of emergency back-up, and so
on.
·
Developing load management/ consumer response
techniques to allow for switching off loads that have lower priority in real
time, eg water heating for domestic consumers.
·
To cover worst case scenarios, prioritisation
of particular loads on the system.
·
The above all being additional to any legally
permissible measures of power system control, such as voltage reduction within
statutory limits.
It is possible (but not likely
in the near term) that future systems could face different kinds of supply
shortfall crises. For example a system heavily dependent on renewables with a
large weather related output (eg wind) could face longer periods (of a week or
more) of sustained shortage, less amenable to the solutions available for
“needle peaks”. Possible remedies and mitigations in this case might include:
·
Much more emphasis on international
interconnections, since this improves diversity of supply for weather related
generation.
·
Reinforcement of the economic case to find
large scale storage solutions.
·
Possibility of much stronger short term price
signals to encourage some temporary reduction in the activity of energy
intensive industry.
·
Administrative measures to reduce “low
priority” use of power (office lighting at night).
·
Redefinition of what constitutes an acceptable
standard of security. In part this merely reflects the increasing number of
technical options to differentiate between different categories of load.
Intermittent sources also tend to accentuate the trade-off between cost and
reliability, so may provoke some re-evaluation of the right balance.
What
would be the cost to the economy of the breakdown of the existing system?
It is difficult to answer this
question without a more explicit picture of what form a breakdown might take.
Historical experience of short term supply crises in the UK has been largely
confined to the immediate postwar period, including some exceptionally cold
winters, and supply disruptions associated with industrial action in the coal
industry (the 3-day week). These were associated with rota disconnections of
whole towns or districts, causing great inconvenience and significant lost
output.
It should be possible to
mitigate the worst effects of a supply crisis of the “needle peak” variety with
improved load management and demand response, in which case the economic impact
would be relatively much smaller than in the past.
However the effect of
sustained (“no wind”) supply shortages could be much harder to manage, and the
costs correspondingly higher. This would obviously be of the greatest concern
to sectors that place the highest value on supply reliability, including all
sectors that depend heavily on reliable IT and communications. The impact would
clearly depend in large measure on the way the previous question was addressed.
What
alternative ways of pricing energy should be considered to reduce the burden of
high energy bills, in particular on less well-off consumers?
There are some well-rehearsed
arguments around domestic tariff structures that aim to alleviate fuel prices
for poorer households. The most familiar is the concept of lifeline tariffs, in
which the first “block” of energy is provided either free or at a heavily
discounted rate, but with a premium rate attaching to higher levels of
consumption.
Although this is superficially
attractive there are some practical problems. One is that poorer consumers are
not necessarily low volume consumers, depending on family size, fuel choice,
nature of property, etc. As an
illustration of the imperfections of such a scheme, a lifeline tariff will
typically also benefit second home owners.
Moreover the capital intensive
nature of low carbon generation may also predispose to a higher element of
fixed charge in fuel tariffs, ie counter to the notion of an initial free
allowance. This would tend to increase the role of the state in determining
“social” tariffs, ie in determining who should pay what fixed charges.
However there are two
developments that may suggest new approaches. One is the medium term prospect
of more district heating schemes. It seems quite possible that these will tend
to incorporate a higher proportion of high density social or affordable housing,
and this may provide new opportunities to provide relatively low cost heating,
depending on how the initial infrastructure cost is funded. We should also look
at this in the context of a simultaneous rolling out future schemes for energy
efficiency, which may have an at least equal potential to reduce costs to
poorer consumers.
Second, new technologies at
the interface with consumer metering and load control may also be helpful. For
example it is quite feasible that the new “consumer offering” will differentiate
between different types of load, eg between lighting, battery charging (for
EVs), and other domestic circuits. It also makes it possible in principle for
consumers to choose between different standards of reliability, at different
prices, rather than having a single reliability standard across the board.
But there is no simple answer
to this problem. At root it is a problem of poverty rather than a problem of
energy per se, and we have to accept the fact that the costs of energy
(ignoring for the moment health and climate “costs”) are likely to rise above
current levels (which in some senses may still be at an unsustainable historic
low). The direct consequences can be alleviated to a degree by efficiency
programmes (insulation), an approach sometimes evident in policy discussions,
or by other dimensions of social policy.
23 September 2016
[1]
Markets, Policy and Regulation in a Low Carbon Future. Policy and
Regulatory Frameworks to Enable Network Infrastructure Investment for a Low
Carbon Future. John Rhys. January 2016.
[2] Energy Market Investigation. Final Report
June 2016. Competition and Markets Authority.
[3] Reducing
the UK’s carbon footprint and managing competitiveness risks, Committee on Climate
Change April 2013.
[4] In
the sense that reversion to the DM would make Germany much less competitive.
But it should be noted that Germany has also been accused of crosssubsidising
parts of its heavy industrial sector.
[5] Carbon
leakage occurs if a country exports its own industry emissions to another
country solely as a result of having a more stringent policy on CO2 reduction,
possibly resulting in the unintended consequence of higher global CO2 emissions,
especially if competitors are subject to less stringent emissions targets.
[6] This
point, and that the bulk of this trade is intra-EU, is made in the 2013
Committee on Climate Change report.
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