This paper builds on analysis of some
fundamental issues, for the future of a low carbon power sector, carried out by
the author in the course of work within the Oxford Martin Programme on Integrating
Renewable Energy, and also in work for the Energy Technologies Institute (ETI),
due to be published by the ETI in the near future. My current intention is to develop some of these ideas further, with recommendations, in the context of the Oxford Martin School programme.
POLICY, MARKET AND REGULATORY FRAMEWORKS FOR A LOW CARBON POWER SECTOR.
System Economics Questions In Future Power Systems.
1. INTRODUCTION
This paper tries to provide a
high level perspective on challenges for the integration of renewable energy
sources within a low carbon electricity sector. The conceptual approach is to
start from a perspective of the system economics for the power sector as a
whole, and several clear sources of market failure in three main domains of
investment, operations and allocative efficiency. This last is the consumer and
behavioural dimension, and included issues of tariffs and demand management. This approach leads to numerous implications
for markets, governance and regulation. These reflect practical commercial,
market and organisational questions, and will suggest corresponding structural,
institutional and regulatory changes of a wide ranging nature.
Interactions
Analysis of the systems
economics of the renewable energy challenges is essentially about interactions
and complementarities within the power system. This covers other sources of
generation, including residual fossil fuel generation (at least in a period of
transition), nuclear, and carbon capture and storage (CCS), storage and demand
side measures. It also needs to take
account of how future use of power is expected to develop in energy economies
that are intended to become wholly low or zero carbon. This implies looking at
future electricity penetration in transport and heat, and the particular
challenges posed in additionally meeting these kinds of demand.
The Grubb Paradigm.
Investment, Operations and Consumption.
Michael Grubb’s analysis[1] of climate issues uses a
categorisation of climate mitigation and energy policy options within three
domains, loosely summarised as:
·
transformative, strongly
linked to all the major issues of technology policy and strategic investment,
and generally linked to timescales measured in decades. This domain is
fundamentally strategic and policy driven.
·
optimising, strongly
associated with the operation of the major energy industries, with markets and
prices, and the assumptions and methods of neoclassical economics as a major
pillar of policy; and both short and medium term timescales.
·
consuming, or part of the “satisficing”
domain within the Grubb paradigm, with a focus on day to day consumer behaviour
and choices rather than energy industry operations. Relevant policy in this
domain has often focused much more on regulatory solutions, through building
standards and appliance labelling for example. The targeted time dimension is the
more immediate, including behaviours relating to the ways consumers buy and use
energy.
In this context our analysis
also distinguish three domains. These
correspond to the Grubb paradigm, at least superficially, but will be described
more simply as the investment domain
governing the way investments are chosen and made, the operations domain covering how the energy industry capital stock is
utilised, and the consumption domain
dealing with consumers and their choices. In each of these domains there is
likely to be some combination of market driven choices and decisions, policy
intervention or formal coordination, and regulation. Investment tends to be a dominant concern but cannot be isolated
from the matter of confidence in the future arrangements governing both
operation and consumption.
The basic economic and
practical objective, in responding to several substantial market challenges
(and potential market failures) is efficiency and effectiveness, in investment,
operation and consumption. This means
considering how to:
·
finance and deliver an efficient mix of
investment, in the quantity needed, and without incurring excessive capital
costs.
·
incentivise and deliver efficient and secure
operation of those investments once made, together with operation of the
existing capital stock.
·
achieve allocative efficiency by ensuring
consumers can respond to cost reflective pricing, with appropriate technical
and commercial options, to allow a potentially large contribution to getting an
efficient low carbon economy.
2. MARKET FAILURES/ MARKET CHALLENGES.
We can define six challenges to a low carbon
objective that stem from the system economics of the power sector.
2.1
Failure to internalise the CO2 externality.
An annoying and inconvenient
truth: “If damaging externalities are not internalised in prices, there is no
basis to assume that free markets and free trade will improve human welfare”.[2] In the absence of adequate
carbon pricing a purely market-based approach is unable to deliver low carbon
investment or even to ensure the most carbon-efficient operation of an existing
stock of plant. Nor, in systems with significant fossil fuel content, can the
market be relied on to provide the right signals to consumers for efficient use
of energy or the optimal choices between alternative energy vectors. The carbon
pricing issue, whether it is treated as explicit or implicit, impacts
on all three domains - investment, operations and allocative efficiency.
SOCIAL COST OF EMISSIONS AND THE PRICE OF CARBON
The notion of a generally
agreed measure of these externalities as a social cost, and its application to
the pricing of carbon, may be illusory.
Policy makers are increasingly influenced by an appreciation of the potentially
catastrophic scale of failure to address climate issues, and it is global risk
management concerns, rather than the arguably inadequate and incomplete tools
of cost benefit analysis, that drive policy. Moreover cap and trade schemes
have hitherto been of very little significance. Nevertheless measures do exist,
have been embodied for example in UK Treasury guidelines and do serve a useful
purpose as a very loose benchmark against which to evaluate, at least
superficially, costs of failure to deal with the externalities.
The largest adverse
consequence of this failure may be the effect on low carbon investment
incentives, the most notable being failures to incentivise the carbon capture
investments widely recognised (not least by ETI) as key to a least cost
decarbonisation of the power sector .
But it can also lead to perverse operational choices, an obvious recent
anomaly (in Northern Europe) being the closure of highly efficient gas power
stations, while coal stations continue to operate baseload due to cheap coal.
In climate terms this is an expensive anomaly, even though the immediate
financial implications for the utilities were relatively trivial.
It is easier to attach a
value to current operational anomalies than to investments foregone. Recent UK
experience is an illustration of the scale of the issue at the operational
level. Between 2009 and 2012 the substitution of coal for gas, induced by
changes in gas/coal price relativities, increased UK coal consumption by about
15 million tonnes. This increased CO2 emissions by around 20 million tonnes, to
which past Treasury guidelines might have attached a notional “social cost of
carbon” value of around £ 1.2 billion. Actual fuel savings to generators are
likely to have been at most 10% of this amount.
In other words this single failure to price carbon will have generated,
notionally, a long term “social cost” of around £ 1 billion.
If investment choices were
also to be based on a projection of very low carbon costs, corresponding
measures of welfare loss would be of a much larger magnitude, even on the basis
of these very conservative measures of social cost. The real cost however would
be comprehensive failure to meet emissions targets, and consequences of that.
The inability of existing market structures to incentivise and bring forward
low carbon investment provides a primary justification for intervention.
Consistency between vectors is
particularly important in contexts of consumer choice. A UK inconsistency has
been Treasury guidance, for public sector projects or public policy purposes,
which differentiates between “market” and “non-market” sectors. Inclusion of
aviation in the carbon traded sector attaches a lower value to CO2
in aviation than in road transport. So hypothetical schemes to promote biofuels
would show a higher return if they displaced diesel as a road fuel (excluded)
rather than aviation fuel (included), even though, ceteris paribus, the
opposite might prima facie be better policy.
A number of points can be
made in the context of low carbon policies.
i.
Even modest carbon prices may
assist attainment of low carbon objectives, even if they remain insufficient to
incentivise investment.[3]
ii.
An important role for carbon
prices is to counteract “rebound effects”, where energy efficiency induces lower costs to the
consumer and additional use.
iii.
Consistency matters.
Inconsistent or incomplete coverage can lead to “leakage” between sectors or
geographies[4],
with perverse effects.
Implications for a low carbon power sector. This is a major issue for
the system economics calculations around finding the best or even the (most)
feasible choices for combinations of renewables, other low carbon sources, and
residual fossil plant. There may be fundamental differences between systems and
policies that work well for (say) an 80% emissions target, with a substantial
but still modest implicit cost of carbon, and those for a 100% target with a
very high implicit cost. In the first instance analysis can start just by
exploring how sensitive results are to the target or to the carbon price, but
conclusions may well remain very sensitive to this parameter.
2.2
The investment problem for
infrastructure assets.
This relates primarily to the
investment domain, as a problem of infrastructure,
policy, regulation and risk. Economists
describe it as a “time inconsistency” problem. Ex ante, policy makers want to
make sure an investment is made. Ex post, with investments made and costs sunk,
political, regulatory and consumer priorities turn rapidly towards demand for
lower prices. This applies to energy and other infrastructure investments where
costs of fixed assets are recovered directly through charges to consumers.
Conceptually at least, low
carbon technologies do not alter the problem. However the possible scale and
extent of policy interventions, observed policy changes or reversals[5], higher costs of low
carbon alternatives, and controversy over climate change or energy policy
generally, all tend to increase policy, regulatory and market uncertainty. Renewables
have been particularly dependent on policy interventions and also vulnerable to
market rules. It will also be a near universal issue, except perhaps for the
smallest systems. In less developed economies it will be closely bound up with
more general social conditions and the strength of institutions.
The solution for developed
economies, history suggests, requires a selection from, or some combination of,
vertically integrated monopoly, long term contracts for generators with secure
counterparties, and Government guarantees. All of these possibilities will have
strong implications of a legal and regulatory character, particularly in
systems which have moved towards unfettered free market approaches. They pose
questions for competition law, “state aids”, regulation, and the construction
of workable contracts with reliable counterparties.
COST
OF CAPITAL.
It is
worth reiterating some of the principles of capital theory as commonly
deployed. The conventional CAPM model equates the cost of capital (CoC) to a
risk-free rate plus a risk premium. In this context CAPM ignores project
specific risk and defines a “beta” risk premium in terms of correlation with
the movement of the market as a whole. Since investments in mitigating or
adapting to climate change can be deemed to be essential there is no reason to
suppose any market correlation. As with public
utilities, which also have a very low correlation with the market, and hence a
low beta and cost of capital, the CoC should be close to the risk-free rate.
The
discrepancy arises from confusions between how to treat risks attaching to
construction and commissioning, often of untested technologies with difficult
site conditions, which are likely to be high but project specific, on the one
hand, and how to treat the risk to the value of the investment once in place.
In a regulated context the latter should be very low. Project specific risks,
in principle, are diversifiable and so do not add to the cost of capital. They
may affect the cost of the project through the incorporation of a contingency
allowance in cost estimates.
The
answer is financing structures that separate the two dimensions of risk. Risk in the pre-commissioning phase may well
need to allow for contingencies and appraisal optimism, not relevant to use of
a discount rate per se, and this is reflected in the capital value at
commissioning. But return on that capital needs to be much closer to the
risk-free rate and, on the assumption that regulatory and policy risks can be
eliminated, will be much closer to any social cost of capital used in policy
appraisals.
But the biggest source of risk for potential investors remains
policy and regulatory uncertainty. The cost of this risk is borne by consumers,
under any market or regulatory structure; if imposed on investors it will be
reflected, if investment is forthcoming at all, in a much higher cost of
capital. As this risk sits almost
entirely within the control of governments and regulators, its imposition on
infrastructure investors is entirely self-defeating in terms of efficiency or
value for money.
Analogies. Pension funds, who diversify their “person
specific” risk across millions of individuals, are often required to value
future liabilities at a risk-free rate, ie government bonds. Similar practice
is often applied to nuclear liabilities, which are emphatically not discounted
at 10% over 100 years. The reason in each case is that the liabilities are “certain”
rather than market correlated risks.
Implications for a low carbon power sector. Responses to infrastructure
investment questions define the
institutional and governance context for the power sector as a whole. Low carbon policies generally will accentuate
moves away from liberalised market regimes, towards more public involvement,
government guarantees, long term contracts and regulated monopoly approaches.
Law and governance issues may be particularly important in developing country
contexts.
This is also critical for the
cost of capital (CoC), another key parameter in any technical economic appraisal
of the system economics. Appraisals should be based primarily on low discount
rates, although we can show the effect of varying CoC assumptions on policy and
investment choices.
2.3
Paying for capacity. Zero or negative
system SRMC.
This is a very specific problem for generation or capacity investment. Not
covering capital costs is a major, intrinsic and largely unresolved problem for
SRMC-based wholesale markets, sometimes known as “energy only” markets. The
typical question is how to recover the capital cost of fossil peaking plant
that operates for a few hours a year, during which it earns an SRMC based
wholesale price that is set by its own fuel cost. There is clearly no profit
even in the few hours for which it operates.
It is a major issue even in fossil-based systems, but it will be
accentuated dramatically in low carbon systems; many renewables have zero
marginal cost and are often “at the margin”, setting SRMC and hence the
wholesale price at zero.[6] Resolution of this issue by external
intervention in the market, eg by subsidising additional capacity, further distorts
the market, possibly in unpredictable ways, and further undermines the
confidence of investors in market based price signals.
“Market” solutions are often assumed. The simplest is assumption of reliance
on “scarcity pricing”, sometimes combined with the assumption of a degree of
market power by generators. Scarcities produce “price spikes”, attracting
instant political and regulatory attention. This reinforces the “time
inconsistency” problem, and undermines confidence that investors might
otherwise place in a “market price”.
Market interventions to ensure adequate capacity most commonly involve
the introduction of a capacity payment. However capacity payments and capacity
auctions are emphatically not a pure “market” solution. They are themselves the product of a central
intervention, and pose questions of what entity is responsible for making the
capacity payments, how much capacity is required, who is to conduct the
auction, how is it to be conducted, what should be the contract lengths, how to
define and monitor what is being supplied, and a host of questions on how to
measure and compare capacity from very different sources (eg wind, nuclear or
fossil). In other words this implies
that some agent is necessarily required to make a large number of important
decisions on generation investment, inter alia bearing on technology choice,
and to make substantial financial commitments.
Introduction of capacity markets can therefore be seen, correctly, as a
substantial first step towards central direction of investment in generation[7],
and towards the installation of a “single buyer” or central purchasing agency.
Capacity choices determine standards for security of supply
Decisions on how much capacity are closely tied to any setting of standards
for generation security (capacity adequacy), by governments and/or regulators. A
particular form of intervention, adopted in the UK in 1990, was to set a
penalty charge for failure to supply, constructed around a value of lost load
(VOLL). This was intended as a minimal intervention, and to mimic how a market
might operate under conditions of capacity shortage, with VOLL as the critical
parameter in setting the security standard expected by consumers. It was a
clever administrative device. Relating capacity to VOLL makes it explicit that
decisions on capacity represent a balance between cost and capacity adequacy,
with a higher VOLL leading to a higher standard and conversely. In other words
the whole issue can also be described in terms of setting standards for
generation security.
Implications for a low carbon power sector. “Energy only” or SRMC based
markets, cannot properly reward future investment. This is a problem not just
for generation per se but for any facility that provides additional capacity or
its equivalent. This includes storage, transmission, interconnection and load
management, all of which are relevant to the question of integrating renewables.
This problem of wholesale
markets also reinforces the general infrastructure investment problem, and
provides another more technical argument on the need for market reform, and for
institutional structures that do not rely only on market solutions.
However the discussion also shows
decisions on capacity adequacy are inextricably linked to the choice of what
constitutes the right level of security across the system. This will become a
much more complex question with sophisticated technologies for load management,
and may reflect much more differentiated levels of capacity adequacy for
different applications and different consumers.
But chosen levels of security,
or capacity adequacy, will also have a large effect on total electricity costs
and hence consumer prices, and on the optimum mix of plant. A higher proportion of capital cost makes this
an issue for low carbon systems, and intermittent renewables, that is much
bigger than for conventional systems.
2.4 Optimising or coordinating generation under
complex constraints.
This is primarily an
operational issue, although operational issues can feed back into strategic
investment choices, and it has implications for prices and tariffs, and hence
for allocative efficiency. Conventional
wholesale markets applied to low carbon systems will not deliver either
efficient system operations or meaningful price signals. The reason is that most low carbon
technologies have cost and operating characteristics that are very different
from fossil generation and are incompatible with the assumptions behind current
wholesale markets. It may be possible to
remedy this problem in certain well-defined conditions, but theoretical
considerations suggest it will often not be possible.
This is a novel and largely
unexplored problem for the power sector, and deserves analysis and explanation in
more depth. The issue is also important because it has the potential to
invalidate much of the conventional wisdom on how to organise market structures
across the board. It is an issue separate from but additional to that of zero
marginal cost and “missing money”, and a deeper and possibly more intractable
problem. A short further exposition is provided in the Annex.
Merit order operation is
unlikely to be an adequate approximation for efficient operation of future low
carbon systems, which incorporate substantial inflexibilities (eg nuclear plant
and possibly CCS[8]),
substantial storage or time shifting options (including the demand side), and
stochastic supply (eg wind power). These are new
issues in that they are accentuated in systems that do not have the flexibility
of fossil plant, where both storage and demand shifting play a large role, and
where there is an increasingly important stochastic element. It is often
claimed for example that the UK’s BETTA market has penalised less flexible
plant, not necessarily fairly.
These complications predispose
to a contract based command and control system in which a system operator (SO)
seeks to optimise and balance choices, including those related to system
security. A later section argues that
there is a counterpoint to the strengthening of existing real time “command and
control” by the SO, in the form of much more consumer involvement through
innovative approaches to competitive supply, and a larger role for retail
competition.
Merit order type wholesale markets have been the intellectual and
practical lynchpin of liberalised electricity markets as a whole. Loss of easy
to understand wholesale markets will make it much harder for generators to
anticipate the likely operating regimes for their plant or to have confidence
in its fairness. Combined with the zero wholesale price issue, this will make
generators much more likely to rely on contract terms both to cover capital
costs and to govern their operating requirements.
Implications for a low carbon power sector. This issue is sufficiently
important to the operations of a low carbon system with renewables that it
deserves more analysis both at a theoretical level and empirically. One large
unknown is exactly how operational choices will be determined in complex low
carbon systems, and what role might be played by different markets. Loss of
confidence in conventional wholesale markets as the lynchpin of commercial
structures will also have significant regulatory and wider implications.
2.5 Coordination of the investment mix.
This relates primarily to the investment
domain but in a context that has to take into account future balancing and
compatibility problems in system operations.
In a fossil fuel dominated
generation sector, all plant is, at least in the essential respects of how it
responds to being part of a complex power system, very similar. Even so, and
even within market driven systems, some limited coordination, often in relation
to transmission, has been implicit, eg in regular forward looking statements
from the UK’s National Grid.
However whether markets can in
future sort out coordination issues to provide workable combinations of technically
very different forms of generation is a more open question. There is for
example substantial debate over practical problems in managing systems with
substantial volumes of intermittent wind and/or inflexible nuclear.
Moreover potential new or greatly increasing loads, like battery
charging or storage heating, also transform the possible choices, but their
impact depends heavily on exactly how these demand side options themselves are developed.
These issues are widely recognised, for example in a recent call by the
Institution of Engineering and Technology (IET) for a “system architect”. Choice is not just about comparing costs, but
about technically feasible and economic combinations.
Implications for a low carbon power sector. From a system economics perspective the general task of finding the
right balance of investments, including those necessary for the future
penetration of electricity in new applications, is the central problem. The box
below describes some typical questions.
Low
carbon power systems raise new coordination issues. Items on the agenda are:
Siting
of wind turbines. Geography has a major effect on the economics of a wind
facility, most obviously in the quantity and reliability of the wind and in the
cost of construction, particularly offshore with different depths and sea
conditions. However “firm” wind capacity in aggregate, and hence reliability,
is improved through geographical diversity, so that concentration in a few
favoured locations is not necessarily the best choice.
Question. What can we say about the parameters on
diversity, in relation to costs, feasibility, etc, and how much does this
depend on the load characteristics?
Question. What percentages of intermittent
generation are consistent with workable power systems, and how does this relate
to differing combinations of other plant, load management, storage, etc.
Solutions,
in terms of demand management, storage and generation, need to bridge both
diurnal and seasonal variations.
Question. Are different forms of storage better
located locally or even with individual consumers, or centrally to capture
economies of scale with a grid location and under direct system operator (SO)
control?
Question. What are the desirable characteristics, in
technical and economic terms, of storage options for different applications?
Electric
(or hydrogen) vehicle development will have a profound influence on storage
needs and the potential for load management through possible battery charging
regimes. The extent to which re-charging is on domestic premises, or “rapid
re-charging” at service stations, will have major implications for load
balancing, the mix of generation, and reinforcement of local distribution
networks. In either instance there is a potential requirement to “manage” load
by some combination of price or administrative means (advance booking).
Question. What are the potential profiles of this
transport load, and how should they be managed or influenced?
Very
similar issues will arise for electricity used to heat buildings, with heat
pumps and storage heaters posing new questions.
Question. What
will the profiles look like in
cold countries? And what does this tell us about the economics of seasonal
storage?
Question. Is there a rationing or compulsion element
in the heat sector, eg how many households can be allowed access to “off-peak”
night storage tariffs, and will there be local distribution network limitations
on heat pumps?
2.6
Communicating cost structures as tariffs and incentives for consumers.
This starts as an issue of allocative
and operational efficiency. Market structures in general do not provide for
complex interactions between choices on supply and storage, and demand side
options open to smaller consumers. In the
UK this arose from adoption of load profiling. With load profiling, all
consumers of a particular type are assumed to have the same time profile in
their consumption pattern, implying a homogenous mix of peak/ non-peak,
day/night and winter/summer loads. The supply business is then essentially
commoditised. All suppliers provide the
same product, with differentiation only on price. This undermines, or rather
excludes from the market, any competitive benefit from offering consumers a
truly differentiated service. Profiling inhibited UK development of
sophisticated metering and control systems and tariffs, arguably for a
generation[9].
Nor are these features of
future low carbon systems currently accommodated in conventional vertically
integrated utilities, still constructed mainly around the technical features of
fossil generation and a “predict and provide” approach to determining capacity
needs. Future low carbon scenarios will require cost and price signals to be consistent,
cost reflective and supportive of demand side management. This will be true both in terms of aggregate
supply and demand in national systems and, increasingly also at smaller scales,
eg within local distribution networks (LV for the power sector).
If markets are to produce
efficient outcomes then they must contain the means for complex cost structures
and network/ system characteristics, in production and distribution, to be
combined and integrated with the right incentives for the many forms of
decentralised contribution to balancing and stabilising the system. This
includes appropriate tariffs for consumers engaged in demand management, for
“prosumers” (who both produce and consume), and “prostumers” (who produce,
consume and store). However even simple versions of “real time pricing” face
major practical obstacles, mainly because consumers generally show little
appetite for time or effort intensive economic calculations in relation to what
they will continue to regard as an “on demand” utility service. There is also
potential dynamic instability if simple peak load pricing just shifts peak to
another period rather than managing and shaping load. A more sophisticated and
radical approach may be required.
Developments in communication
and control technology have created an explosion of possibilities in metering
and service provision. They allow for the application of sophisticated TOD
metering – even real time pricing – previously seen as impractical or
impossibly expensive, as well as sophisticated approaches to remote control of
individual appliances. Given the
interactive nature of these possibilities, utilities need to consider how end
use should be incorporated into processes for the secure and efficient
operation of the system.
Distribution engineers have
identified further questions for the medium and low voltage distribution
networks, if they have to handle substantially greater volumes of electrical
throughput, with new types of load, and possibly with very different dynamic
characteristics. So there are likely to be future problems of local load
balancing, as well as aggregate demand/ supply management at higher or national
system levels. These too may need to be reflected in the design of network use
of system charges and in control measures to manage local stability. Network
tariffs are another major area where cost recovery may have to be done
differently in future, and not simply by averaging total costs over total units
sold.
There are happily many
technical and other options for managing these interactions more effectively while
at the same time moving towards a “service” rather than a commodity approach. These
include the automation of responses within individual appliances on the consumer
premises, to respond either to price signals or to remote control by a supplier/provider.
These are discussed in more depth below.
New Models for Retail Supply
to Consumers
The
conventional utility model has consumers able to treat electrical energy supply
as “on tap”, with limited or no differentiation between applications (e.g. as
between lighting, heating or mechanical power). Tariffs and prices for the most
part approximate to an averaging of the costs of supplying electricity, with
limited ability to differentiate on grounds of differing incremental
costs.
One
means to meet the challenges above is to redefine the “consumer offering”,
defining electricity as a set of services, rather than a homogeneous commodity.
This requires starting with a clean sheet in defining the nature of the
services that consumers will want, and the basis on which they pay. So, for example, a consumer wanting to charge
electric vehicle batteries might request 75 kWh to be delivered in a specified
period, over several hours or even several days (eg a weekend), and the
consumer’s contract might specify that this requirement will be met in full but
with timing that is “at the supplier’s discretion”. Corresponding but different arrangements
could apply to the purchase of power for heat, for refrigeration, and some
other uses, reflecting in each case the nature of the load. Commitments to individual consumers would be
made by energy service companies who would be able to aggregate consumer
requests and feed them in as part of the SO’s system optimization routines.
Such services might even be packaged with the provision of appropriate
equipment (eg storage heaters).
The
role of suppliers is then to act as aggregators, and their essential function
will be to manage the complex interaction between consumer loads and system
balancing requirements, including shaping and managing the pattern of
consumption. This provides a major opportunity for a much more innovative
approach to all aspects of metering and for the terms on which consumers
purchase power. Suppliers could at the same time enter into individual
contracts with generators, or a system operator
or other central agency, which would reflect the economic benefits of
their ability to shape consumer loads. They would also take responsibility for
managing loads within network constraints at lower voltages, ie within local
distribution networks.
This
would have some powerful advantages.
First it would allow consumers to purchase power for particular usages
in ways more akin to their purchase of other goods and services, as opposed to
perpetuating the “instantaneous commodity” characteristics that have hitherto
been a unique and constraining feature of the power sector. This would also
correspond to what consumers actually want and need from the utility. At the same time it would help make the
services more affordable. Consumers
could still choose to take some power “on tap” and would normally pay a higher
price for this.[1] But many of the issues
associated with administrative setting of security standards would become much
less significant. To a much greater extent security levels would be chosen in a
market.
This
change is enabled by one set of technologies – those that surround metering,
separate identification of different loads within each consumer household or
business, and remote control. But it
also helps to resolve the problems posed by another set of technologies, those
linked to intermittent or inflexible sources of non-fossil and distributed
generation.
New Loads
The major new loads of
particular interest in this context are transport and heating, since each may
pose particular, but different, sets of problems. In the UK, the ETI has
suggested that there may be a need to add a hydrogen economy to this list.
Penetration of electricity
into the transport sector has been widely assumed to be a means of flattening
load shapes and managing intermittency, but a
Norwegian experience illustrates that it may create some new questions of
its own, both locally and nationally.
Heating loads may be generally
assumed to be manageable in a relatively straightforward way in terms of a
diurnal load shape, if one assumes significant on premises potential for short
term heat storage, but have additional characteristics that deserve
attention. These include the sheer scale
of potential heat load, its strongly seasonal character, and the potential for
a big accentuation of the peak in response to cold weather, a problem that is
particularly acute for heat pumps.
This raises questions about
the appropriate level of supply security for heat load (with possibly a very high
cost attaching to sufficient capacity margins of low carbon plant), and also of
possible needs to determine quotas of different types of heating at local
level, in order to manage load on local networks.
Implications for a low carbon power sector. The most significant relate to
the nature of the “deal” for consumers, and how this can be made consistent or compatible
with the need to balance the system as a whole, whether this is at an aggregate
grid level or at much lower voltages.
New approaches are likely to reflect
the many developing options for real time metering, automated controls, and
remote control over loads, pointing towards a “service provision” approach
rather than current models for delivery of a commodity. But this leaves many
questions and options.
1. The basis for sale to
consumers may reflect some combination of:
·
more sophisticated time of day tariffs
·
different tariffs/ contract terms for different
loads/ household circuits
·
automated responses for particular appliances
·
remote control by an aggregator or system
operator
·
“administrative rationing” for certain loads,
eg booking a time slot for battery charging
·
different guarantees of reliability of supply
for different loads
2. Suppliers may have
“aggregation” of loads as an important function, or there may be a reversal of 21st
century trends, with the supply function returning to local distribution
companies.
3. The basis of network (use
of system) tariffs need to change. Traditional averaging of total costs over
all kWh will need to give way to a much more cost reflective approach, in which
retail consumers pay for the actual service that they value from the network
(local or grid), ie as back-up or for peak loading.
[2] The
quote is attributed to
Michael Grubb, but is no more than a simple re-statement of a fundamental idea
in economics.
[3] €15/ tonne may be
sufficient to induce early gas for coal substitution in existing plant, for
example. One claim made for the EU ETS
is that companies are now basing their planning on an expectation of much
higher carbon prices, eg. €40/ tonne, even if these are not sufficient to
induce the major generation investments. Both these numbers were quoted in a recent
address by the Director of the Commission’s Directorate for Climate Change
Action
[4] In relation to
industrial energy prices, this is often expressed as concern over international competitiveness
[6] For various reasons,
such as perverse incentives for renewables or actual costs of reducing output
for nuclear, prices in these markets can even be negative.
[7] Indeed this has often
been expressed as a serious criticism of such proposals by proponents of fully
liberalised markets. It is an issue at EU level where the Commission has
generally supported “energy only” markets, which of course avoid the issue of
setting a Community wide security standard.
[8] It has been suggested
that this is also a factor that should influence choice of CCS technology. Post
consumption capture has been claimed to allow for more flexible operation of
plant. Operating inflexibilities will tend to be associated with the chemical
process aspect of CCS rather than combustion/ generation per se.
[9]
The CALMU credit and load management unit was pioneered by Fielden and Peddie
(then an Area Board Chairman) in the 1980s, and has enjoyed worldwide success.
It died in the UK with privatisation and the adoption of profiling.
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