by Professor Michael Grubb, Faculty of Economics / Electricity
Policy Research Group, Cambridge University|
Moving to a very low carbon electricity system is
central to meeting the goals of UK energy policy, and indeed to
the wider global challenge of tackling climate change. This will
require massive investment in low carbon electricity sources.
Part 1 of this submission summarises briefly four of the difficulties
facing the current mainstream approach of relying on the impact
of the EU ETS in the present liberalised electricity market, supplemented
with additional incentive mechanisms like renewable obligation
certificates and feed-in tariffs.
Part 2 offers some observations on some of the alternative
or complementary approaches set out in the EMR Consultation document,
with a brief look at strategic dimensions of a carbon floor price,
and then a more detailed look at the design of long-term contracts.
In this, I outline a case for a distinct approach to long term
low-carbon contracts, which focuses upon engaging a diversity
of potential buyers. The aim would be to retain a greater role
for competition on demand as well as supply side, in the form
of long-term "Green Power" contracts that operate in
a separate, differentiated contract market. It could thereby harness
the potential interest and capital of electricity consumers, large
and small, directly in funding low carbon electricity investments.
The UK has been amongst Europe's leaders on both
electricity liberalisation and climate change. In electricity
regulation, the UK blazed a trail in unbundling previously centralised
systems to inject competition wherever it seemed viable. The short
term result was a radical reduction in costs (including unfortunately
R&D), a surge of investment in combined cycle gas turbines,
and a proliferation of suppliers competing for customers followed
by consolidation. Reduction in CO2, driven by the displacement
of old coal plants and some increased plant efficiency, was a
significant side benefit. The basic idea of liberalisation and
competition has spread more widely across the EU, albeit with
The UK also aspired to be among Europe's leaders
on climate change, pushing to strengthen the EU ETS, together
with its ROC scheme to support renewable generation and a strengthening
range of demand-side policies. This would seem to a good environmental
combination. It is, however, now recognised to be inadequate,
for a combination of technical issues in design and implementationand
for more fundamental reasons.
PART I: PRESENT
The situation we now find ourselves in, the UK and
Continental Europe, is a mix of carbon pricing, technology-specific
support mechanisms and targets for renewable power. The interaction
between these instruments and electricity market design can be
troublesome, and there are at least four specific challenges associated
that arise with this policy mix.
1. Reprise: low-carbon
electricity and investment
Creating a low-carbon electricity system requires
a huge capital investment over the coming decades. The liberalisation
of electricity systems has been very effective in driving down
the costs and prices associated with operating existing systems,
but less effective in attracting new investment, except into low
Zero carbon sources are very different: most renewables,
and nuclear power, are very capital intensive, with relatively
low operating costs. The scale of the different shares of investment,
O&M and fuel costs between fossil-fuel based generation and
some low-carbon options are shown in 1: capital accounts for more
than half the levelised costs for nuclear, wind and solar alike,
in sharp contrast to conventional options. A move toward any of
these low-carbon generation options implies a radically greater
COMPOSITION OF LEVELISED GENERATION COSTS
AT 5% DISCOUNT RATE SOURCE: (IEA 2005)
At the risk of repeating now well-known issues, this
has two crucial implications:
- Zero carbon sources will tend to operate as baseload,
ahead of fossil fuel sources, because they are cheaper to run
and need to run as much as possible to recover the cost of capital;
- The cost of capital is all-important to developers
and is crucial to determining the cost of, and our ability to
move towards, a low-carbon electricity system.
Returns to investment in low-carbon electricity generation
at present depend upon the electricity price, along with any additional
support policies. In competitive wholesale electricity markets,
such as that that exists in the UK, the price is set mainly by
the marginal unit of generation. In the UK this is predominantly
gas or coal-fired generation, as determined by the combination
of fuel and carbon prices. Crucially, this means that in the mainstream
market the price at which a low-carbon investor can sell
its product bears little or no relation to its own costs.
It depends instead upon the volatile prices of coal, gas and
carbon faced by the fossil fuels generators.
In the absence of other targeted support, this amplifies
risks to investors in low carbon plant and raises the cost of
capitalincreasing overall costs and reducing incentives
to invest, for the very sources that are central to low-carbon
futures. Doubling the cost of capital (effective discount rate)
from 5 to 10% can increase the cost of nuclear and wind by around
50%, with far less impact on the cost of fossil fuel generation.
At 5% discount rate, nuclear and (onshore) wind can compete comfortably;
at 10%, they are uncompetitiveand the cost of transforming
to a low carbon electricity system would itself be about 50% higher.
An investment environment that minimises the cost of capital will
be crucial; the current structure does not do this.
UK scenarios for decarbonising the power sector imply
that the UK system should get about 90% of its electricity from
zero carbon sources within 20 years, from a massive investment
programme mainly in renewable and nuclear costing potentially
over £100 billion. This is a staggering scale of investment,
and yet the existing approach implies that this should be financed
on the basis of future electricity sales at a price that has little
to do with the cost of all that investment, but is a function
of gas, coal and carbon priceswith added incentives eg
for renewables over which the investors limited foresight or control.
This is likely to prove a very expensive way of funding £100
billion of investment, if indeed it delivers at all, which is
clearly in doubt.
Acceptance of this basic insight underlies the EMR.
It bears repeating, simply to underline not only the scale of
the challenges, but its two distinct components: capital intensity,
and the fact that the investments sought would be "price
takers", from fossil fuel and carbon markets. A structure
to provide greater stability and security for the long-term infrastructure-type
investments required might need to look very different from the
spot market system we have today. The main solutions considered
to date largely take the incentives out of the hands of any market.
Whilst this forms the central challenge, there are
three other difficulties that also inform the reasoning behind
this submission's approach to long term contracts.
2. Innovation in electricity
We require innovation across a range of technologies,
yet private R&D expenditure in electricity (per unit turnover)
has been just a tiny fraction of that in the most innovative sector
of pharmaceuticals and software and computer services (Figure
Much of the current technology embodied in generation, transmission
and distribution is based upon the technology used a century ago.
The reasons for this are still inadequately appreciated,
but comprise several mutually reinforcing explanations. One is
the sheer scale and technological risk associated with the heavy
engineering implied in converting large amounts of power. Another
plausible factor is that for most of last century, power systems
were run as regulated monopolies. It was hoped that liberalisation
would inject more innovation. In terms of operating practices,
it has; and yet liberalisation has been accompanied by further
collapse of R&D expenditure, as investors sought quick returns.
Overlaying these is the fact that electricity is
the ultimate homogenous good. At the point of consumption, all
electricity is the same. This means that there is little product
differentiation in electricity: the only differentiator is price.
This greatly reduces the incentive to innovate. A new way of generating
electricity has to compete purely on price against incumbent technologies
that have benefited from decades of development, economies-of-scale,
and regulatory adaptation. They might be aided by a carbon price,
but thata price differential, driven and constrained by
politicsis the sole basis on which low carbon innovation
has to recover all of the costs and risks of its R&D. Thus
new innovations in electricity can't command a large economic
margin by offering consumers products with unique characteristics,
protected by the monopoly guaranteed by patents (as with pharmaceutical),
and/or consumers chasing the latest gadget (as with IT).
R&D INTENSITY PER SECTOR (DEPARTMENT
OF INNOVATION, UNIVERSITIES AND SKILLS 2008)
Ofgem's low carbon network fund is an ambitious effort
to fill the gap, but cannot wholly compensate for the weak market
incentives for innovation. Yet innovation on the scale of IT or
pharmaceuticals is what we really want for the challenges ahead.
The suggestion in this submission offers an attempt to strengthen
the potential for consumer-driven innovation for low carbon electricity.
3. Consumer interest
in low carbon electricity
Some consumers, groups, and companies would value
the potential to use low-carbon electricity. Finding ways to harness
consumer purchasing power more directly in the transition to a
low-carbon electricity system could help drive the innovation
required and raise the political acceptability of the undertaking.
In the UK consumers have a range of "green tariffs,"
but as noted below these are somewhat problematic and uptake has
been modest, just 319,000 in 2009 (OfGem 2009). Empirical evidence
of the willingness of individual consumers to pay for green energy
Interest in purchasing "green energy" is
however not confined to households. Several major UK companies,
accounting for a significant fraction of UK electricity demand,
have pursued a strategy of wanting to buy green power often for
CSR reasons. However in June 2008, DEFRA prohibited companies
from claiming credit for purchasing electricity through the present
green tariffs in carbon accounting or environmental reporting,
due to problems with double-counting given the regulatory structure.
This extends to companies under the UK's Carbon Reduction Commitment
(CRC) which have to count all their electricity purchased from
the grid at a single emissions grid average. Only on-site renewable
generation can avoid this, creating an obvious distortion.
The reality is not that all customers treat all electricity
the same. There is a diversity of electricity customers, with
varied willingness-to-pay for a product they believe to be "environmentally
clean". The present market structure makes it hard and/or
unnecessarily expensive for them to exercise that preference.
4. Electricity prices,
carbon leakage and carbon attribution
Carbon prices increase the cost of fossil-fuel based
generation and in competitive markets this passes through to wholesale
electricity prices, increasing tariffs for both households and
industries. In terms of economic incentives the pass-through of
carbon prices is desirable, but gives rise to two kinds of problems.
One obviously is the distributional impact on consumersindividual,
and corporateand the political resistance this creates.
The resistance may be magnified if they do not have a clear alternative
to consider of buying low carbon power that is free from the carbon
The other is the concern about "carbon leakage"
from impact on industrial costs. The most extreme case is aluminium.
Over 80% of emissions from aluminium are from electricity, and
they represent about 4% of total emissions from the EU ETS. Aluminium
firms could relocate if the indirect cost they face from carbon
pricing is high enough. For many energy-intensive industries,
these indirect costs from electricity prices are small relative
to the direct costs from emitting CO2, but are not
insignificant: the electricity-related costs associated with paying
30/tCO2 would add more than 4% of Value Added to the cost
of industrial gases, inorganic basic chemicals, paper and paperboard,
and steel electric arc furnaces.
Free allocation is being used to "protect"
most energy intensive industries in the EU. This in itself a highly
imperfect approach. Border-levelling of carbon costs (charging
embodied carbon on imports, and repaying carbon costs on export)
would, from an economic and environmental perspective, be far
better. For compensating direct emissions, numerous analysts (including
by the present author) have argued that border levelling can be
implemented in ways compatible with WTO rules; the WTO itself
emphasises that various forms of border levelling can meet criteria
to ensure they are compatible with world trade law.
However this requires attributing emissions to products,
which is much more difficultto the point of almost impossiblefor
electricity-related costs. Trying to attribute to a specific product
the carbon intensity of electricity drawn from a power grid would
be replete with scope for dispute.
No amount of supply-side incentivescarbon prices, feed-in
tariffs, etccan overcome this problem, they just add to
These four factorsstructures that seem inadequate
in terms of investment incentives, innovation incentives, consumer
engagement or carbon attribution to industrial productsadd
up to a powerful and difficult set of challenges. A key point
of this submission is that alternatives should be evaluated not
only with respect to the first, which is driving force behind
the EMR, but in relation to all.
PART II: ON
5. Overview: the recentralisation
of electricity policy?
Part II of the submission considers the challenge
of developing investment incentive structures that could rise
to the considerable challenges identified in Part I. The EMR identifies
several options, and this submission does not attempt to cover
the span. It touches briefly upon the role of, and architectures
for, a carbon floor price; and then concentrates on the case for
a specific approach to long-term contracts.
First an important word of context. One effect of
the developments during the 2000s is an apparent emerging conflict
between the agendas of liberalisation, and the environmental agenda.
Fundamentally, it seems the government needs increasingly to try
and engineer investment that would not otherwise happen in the
short-run, competitive market that it has created, by adding more
rules, special incentives, and constraints. There seems to be
an increasing risk of the environmental agenda unrolling the liberalisation
agenda and pushing us back towards centrally planned power systems
(a concern articulated for example by Malcolm Keay among others).
When we reflect on the nature of the UK electricity marketaimed
to minimise costs and risks on short term financial perspective,
driven by shareholder interests, and with rules designed to force
competition through regulatory oversight and limiting the scope
for long-term consumer commitments (eg through switching provisions)this
is not so surprising. It suggests a deeper level of challenge
that needs to be considered.
Some, pointing to the environmental and other inadequacies
of the current system, welcome this. I "cut my research teeth"
in the days of the Central Electricity Generating Board, which
clung to coal and nuclear generation as the only serious options.
One does not need an ideological approach to free markets to be
uneasy about a trend towards greater State determination of energy
To date, UK efforts to promote environmental goals
in the market framework have led to growing complexity, and/or
reduced flexibility. The ROCs scheme has evolved closer to central
direction, set to operate at the "capped" price and
with technology-based banding to support the growth of diverse
technologies. "Green power" tariffs have to pass a complex
set of assessment criteria to try and avoid double counting of
renewable energy with the ROCs support and Levy Exemption Certificates.
Obviously, their "additionality" could be ensured if
suppliers of green tariffs had to retire ROCs, but the price of
ROCs reflects the cap price including the many elements of market
risk premium that others have noted, not the actual cost of most
renewablesthereby making this approach to "green tariffs"
An important option in the debate is to set a floor
price to carbon. This submission does not address this in detail,
but in my view much depends upon the form a price floor might
take. A floor price set by an EU-wide reserve price on allowance
auctions is not in itself an interference in the market.
In principle, it is a simple mechanism that can reduce the cost
of capital, by reducing downside risks in the face of inherent
economic uncertainties: it offers an automatic self-correction
of the target if events prove the initial level of ambition to
have been weaker than expected. However this is different from
a floor price that takes the place of an inadequate level
of ambition in the EU wide emissions cap.
In turn, achieving an EU floor pricewhether
a genuine hedge against uncertainty or a substitute for an inadequate
capwould be preferable to a UK-alone solution. The current
focus on a UK-specific floor price is second-best: it reflects
the relatively weak nature of the EU's current 2020 ambition,
the related lack of serious EU debate on a floor priceand
the now-limited timespan of EU ETS Phase III. It may be useful
for specific UK investment purposes, but will in turn face limitations
on the level that may be contemplated, not least arising from
concerns about inta-European competitiveness impacts on
Against that background a carbon floor price may
be useful but does not in itself address all the obstacles to
capital-intensive, low carbon investment noted in Part 1 above.
Another option set out in the EMR is for long term
contracts. Carbon Contracts have been proposed separately for
example by both Newbery and by Helm. As initially conceived these
would be project-specific contracts in which the Treasury would
sign a contracts-for-differences on the carbon price, in effect
guaranteeing a minimum carbon price to project investors. The
economic logic is impeccable: carbon price risk is driven by politics,
it makes sense for the political system to underwrite the risks
if it wants private sector investors to assume a particular level
An extension, which would further reduce market risks,
is for direct long-term power contracts. These could take the
form of mandated feed-in tariffs, or could be established between
the government and investors through some kind of auction mechanism.
Such approaches could address many of the obstacles to capital-intensive
investment and are rightly now the topic of extensive debate around
There are implementation challenges arising from
the project-specific nature of the "contract-for-difference"
proposals, concentration in the power market undermining auctions,
and the understandable reluctance of the UK Treasury to take on
the liabilities or costs that most contract proposals would imply.
The Treasury may desire an adequate price for investors, but not
to the extent of being keen to underwrite a price largely outside
its control using UK taxpayers money.
Moreover, most of these proposals place the government
in a much more central position in the power markets. The fundamental
tension is that the government would berightly in my viewtrying
to facilitate long-term, low carbon investment by reducing the
political risks, for which it seems that placing the government
as determining or underwriting the price is the only option.
6. Transferrable long-term,
low-carbon electricity contracts
Most of these improvementscarbon floor prices
/ FITs / auctioned contracts, are targeted at the first of four
issues surveyed in Part 1: investment. Differentiation between
technologies may support "learning by doing" but they
do little for innovation per sea lack of which has
resulted in the UK and EU launching major publicly-funded innovation
programmes to try and compensate for the lack of private R&D.
And they do nothing for the accounting of carbon or carbon costs
in industrial products, or engagement of consumers. Indeed, on
the last of these most policies have achieve exactly the opposite,
leaving the consumer faced with one metrica cost per kWh
- in which suppliers, in their different ways, subsume together
all the different kinds of support and incentive costs.
This submission, based on a Working Paper published
last year with the Cambridge Electricity Policy Research Group,
offers a case for a different way of conceiving long-term contracts.
The basic proposal is that the emphasis should be on facilitating
long-term, low-carbon electricity contracts between private sector
producers and consumers. The government's role would be to create
the market structure, which would have to operate alongside
the existing (or altered) structure of electricity generation
and supplier markets, and to the extent necessary underwrite
contracts. One way into this could indeed be for the government
to be an initial purchaser, but with the aim of selling contracts
on to third party buyers.
Specifically, this would require the government to
facilitate the development of a market for long-term, zero-carbon
power contractsa specific, regulated contracted "green
power" market, which could operate alongside the mainstream
conventional power market. A core feature would be to allow final
consumers to associate in consistent ways with zero carbon electricity
production, from sources that their contracts would help to fund.
This would require active regulatory and policy decisions
in several dimensions. To secure investment, such contracts would
have to be long term; current regulations at the consumer end
seek the opposite. However, a long-term contract on the generator
side does not necessarily preclude the ability to trade contracts
(which might be particularly relevant as an option on the consumer
side). Over time, driven in part by a rising carbon price, more
investment might be contracted through what might best be termed
a "Green Power (GP) Contracts Market".
To be clean, the entire accounting framework would
need to clearly delineate such GP contracts from the rest of the
power system, including in terms of its carbon intensity. Such
a differentiation would allow holders of such GP contracts to
claim credit for purchasing low-carbon power in calculating their
carbon emissions, either for regulatory (eg CRC) or voluntary
purposes. This would increase the incentive for firms to purchase
and invest in low-carbon power, and allow those who would like
to, to purchase and claim credit for it. It could provide a means
for those consumers who wish to pay extra for renewable power
to make the purchases they desire. It is thus an extension of
market principlesnot the reverse.
In some respects this has much in common with established
contract proposals: unless and until an adequate carbon price
is attained, the government would probably still need to underwrite
the contracts. In other respects it is a radical proposal: it
would in effect imply creating a separate kind of electricity
at point of consumptionone directly associated with zero
emissions, high capital and low operating cost plantand
designing contract structures accordingly. The structure might
have more in common with mortgages, than with the current spot
price, and would not necessarily be per kWh: it could be a fixed
payment charge, conferring entitlement to a maximum kW, or a total
Some consumers might wish to purchase both "kinds"
of electricitya GP contract for a basic level of use, topped
up with purchases per kWh (maybe from another supplier) that would
reflect the marginal operating cost of the system. The combined
economic structure would then be akin to a fixed + variable charge,
or other "rising block" tariffexcept that the
size of the "base" component (if any) would be entirely
in the hands of the purchaser.
Note that the carbon market remains central to the
economics of this approach. As the carbon price rises, the relative
value of GP contracts would correspondingly increase. It is
this that makes a growing non-governmental role in a GP contract
market economically plausible. But the financing of the power
investments would not be at the mercy of the fluctuating markets
in coal, gas and carbon; they would be securitised through long
term contracts that reflect the cost structure of the generating
sources in that GP contract market, not the fluctuating spot price
determined by current fossil fuel and carbon prices.
Thus, in terms of the four challenges discussed in
- Establishing such a GP contract market would
reduce the financing costs, and thereby reduce the cost of investment
in low-carbon electricity. To use Walt Patterson's term, this
parallel market would be better suited to the "infrastructure
electricity" that new green power will supply. Long-term
contracts for green power could be based on their own costs, and
allow more certainty in repayment of the large initial capital
costs, reducing the cost of capital. From a Treasury standpoint,
it would presumably be welcome to bring new sources of private
capital to help finance the UK electricity sectors' transition.
- The product differentiation from such a division
could create extra incentives for innovation into low-carbon
power, and help to create the missing demand-pull for low-carbon
technologies from consumers, both large and small.
- Such differentiation could also help create a
system in which major industrial consumers, such as Aluminium,
could accurately and legitimately establish a basis for avoiding
carbon costs. Adopted more widely, this might provide a way for
any border attribution to legitimately focus on carbon-related
costs: charging imports, unless producers could produce evidence
that they were drawing power from zero carbon electricity contracts,
in which case they could be exempt.
- Finally, this would provide a way in which diverse,
large-scale electricity consumers could express their potential
preference for low carbon power in the marketwithout the
extraordinary and unsatisfactory hoops that have emerged to avoid
double counting for existing schemes to small consumers, and the
de facto ban on large consumers entering at all. It would thus
provide a ready alternative to the bizarre situation in which
the UK, whilst extolling the need for a rapid and costly transition
to zero carbon sources, specifically prevents the major companies
participating in the Carbon Reduction Commitment from claiming
any credit for investing in zero carbon generation.
7. Challenges and
Given these potential advantages, is it possible
to create such a structure, and could this be done in the context
of our current regulatory regimes?
There are a number of hurdles that would need to
"Green power" contracts would need to ensure
that low-carbon power sold is matched by low-carbon generation
average over a suitable time period, to account for variability.
The UK already has models for this, in terms of rules around Levy
Exemption Certificates. The creation of a separate low-carbon
product alongside standard grid electricity would require the
carbon intensity of the mainstream electricity market to be calculated
separately for use in regulatory instruments like the CRC, or
in voluntary carbon footprintingwith separate accounting
for the electricity denominated in GP contracts.
Of course, long-term contracts are nothing new. Indeed,
they already exist in the electricity arena. The Finnish contract
under which pulp & paper industry contracted to a new nuclear
power plant, underwritten by AREVA, is the most famous recent
examplethough not an encouraging one, given the scale of
delays and cost overruns. This reflects one reason why such arrangements
are rare. A contract between an individual buyer (or a fixed consortium)
and a single power plant poses big risks for both sides. A generating
company that builds and operates the plant faces the risk of having
a single purchaser, while the counterparty is dependent on one
single power source, with the inherent risks involved:
- If the buyer goes bust, the power plant is exposedthis
has been a major reason cited why most generators have not pursued
long term contracts with some of Europe's major industrial consumers.
In a globalising world, and witnessing the struggles of European
heavy industry, the longevity of a specific industrial plant is
just considered too risky to finance a major power plant construction;
- If the contract is focused on a single huge new
power plant, the buyer is exposed if that goes wrongas
with the Finnish reactor.
That is why transferability, and government underwriting,
would be important to lower the risks.
There is at least one other major example in Europe,
which seems more relevant, namely the French Exeltium contract
(see box). However, even this reflects rather special circumstances
and it may be neither feasible, nor necessarily desirable, for
this exact model to be more widely replicated.
In this contract, a consortium of electricity intensive
industries combined to structure a long-term partnership with
energy producers. The total value is 4 billion, funding
a 24-year contract with EdF. Four French banks led a consortium
of ten banks to provide a 1.7 billion loan, supplying electricity
to the syndicated consortium of about three dozen heavy electricity
consuming industries. The deal reached financial closure in April
The cost to the consuming industries are differentiated
between a fixed part at the start of the contract reflecting the
investment cost, and a variable part in line with operating costs
of the plant. Thus, the cost structure of the Exeltium contract
broadly matches that of the generating plant, considerably reducing
the cost of capital.
By some pooling of demand (with a consortium of consumers),
some of these risks are reduced; the electricity supply risk is
underwritten through EdF.
However, there seem to be major obstacles to the
wider use of such contracts.
One relates to political and legal acceptability.
The Exeltium contract required approval from the European Commission,
which was granted after considerable negotiation. However there
was strong indication that this was considered to be an exception
(presumably aided by strong support from the French government)
and that in general such contracts would face difficulties as
they are perceived as potentially anti-competitive.
Another obstacle is that the conditions themselves
are not so easily replicable, reflecting as it does the nature
of the relationship between French industry, banks, and EdF, mediated
to a large degree by the French government.
The proposal in this paper is not that the Exeltium
experience should itself be replicated, but rather that the underlying
objectivelong term contracts between suppliers and consumers
of electricityhas potentially multiple benefits. Policy
can learn from such experience, and rather than impede should
facilitate more generic tradeable long-term contractual structures,
and engage a wider group of electricity consuming organisations,
more explicitly linked to the huge task of decarbonising European
*Sources: Reuters, 13 Apr 2010; Simon Cotterill,
Presentation to CBI Energy Conference, 2009.
The core argument of this paper is that long-term
contracts are desirable, but that they need to be embedded in
a structure that would facilitate transfer of such contracts.
Structured in the right way, making long-term contracts transferrable
can reduce risk to both generators and consuming parties.
Creating a transferrable contractual structure would
be crucial to such arrangements, allowing aggregation of buyers
to finance large investments, for example, and allowing firms
to acquire or divest such contracts as their financial situation
(and CSR policy) dictates, within prescribed rules that protect
the underlying financing commitments. The great difficulty with
such an idea is the potential diversity of such contractshow
would one trade a 15-year contract with one finance and risk structure
with another of 20 years and a completely different finance and
risk structure? This is why it cannot emerge on its own. Some
degree of diversity is probably necessary and healthy, but the
need for some liquidity in such a contract market would imply
two things: a need for a publicly defined framework for a limited
number of "qualifying" contract types; and as wide a
market as possible. More specifically, there needs to be a government-led
process that establishes a basic structure of such contracts,
and that facilitates competition between those entities that
are interested in securing stable, zero carbon long term power
Why link the long-term contract market to zero carbon
power? Fundamentally, because of all the reasons set out earlier
in this paper:
- decarbonising power generation is one of the
major public policy challenges of our times, and low carbon generation
is almost all very capital intensive and infra-marginal;
- the electricity system suffers from insufficient
innovation in general, and specifically in relation to low carbon
innovation given the industrial discounting of political uncertainties
around the carbon market; a market for long term contracts could
widen the space and incentives for innovative approaches,
- the ability to demonstrate zero carbon generation
in legally secure, verifiable and trackable ways is crucial to
attributable power-related emissions in any system of border leveling;
- there are a substantial body of electricity consumers
whose interest might be driven partly by the desire for low carbon
power and/or long term stability separate from the fluctuations
of fossil fuel and carbon pricesconsidered further below.
One open question is how to design such a market
interface in open competition with standard grid electricity,
where consumer switching of suppliers is strongly encouraged.
Individual consumers seem unlikely to be the main participants
in long term contracts anyway, but there may need to be some re-examination
of the rules if consumers were interested in long-term contracts.
At some scale, preventing or impeding mutually assenting parties
from entering long-term contracts can no longer be presented as
a way of preventing market abuse, but risks instead impeding another
sort of competitionone which might be far better suited
to fostering the investments required. These are big questions
and I do not pretend to have all the answers, but the issues need
Another key question is how such a GP contract market
would relate to existing support structures, notably for renewable
electricity. Clearly, if a country has a mandated renewable energy
cap (as in theory does the UK) that it is set to achieve, then
GP contracts could only increase the renewable energy investment
if they retire credits (ROCs in the UK case). However even in
the UK the system is subject to a "cap price". With
feed-in tariffs, the question is whether any investor would wish
to sign such a contract, compared to the returns available under
a feed-in tariff. This is an empirical question, not a fundamental
Moreover, a key goal of GP contracts would be to
provide a more secure "convergence point" for a sector
if and as technology-specific supports phase down. At present,
the proposition appears to be that low carbon technologies will
benefit from an extended period of support, whilst there is an
"industry-building" case for supporting the implicit
innovation, or compensating for an inadequate carbon pricebut
will then have to fend for themselves on the basis of a market
determined entirely by short-run marginal prices of fossil fuels
and carbon. After supports expire, leaving many GW of capital-intensive
plant, this is a recipe either for windfall profits or eternal
financial restructuring of bankrupt projects that cannot cover
GP contracts could offer a much more robust answer
to the question of whether and how we could ultimately move beyond
current technology-specific supports. The carbon price would still
be crucialbut alongside it, there would be a market structure
more appropriate for existing "infrastructure" generationand
for supporting continued investment in low carbon technologies
if and as other supports expire.
8. Potential purchasers
A key question is who might want to buy such long-term,
zero-carbon power contracts. There are three broad approaches
to answering this question.
One is to speculate, based on current indications
and possibilities. Many consumer-facing companies already have
clear environmental goals, and have expressed frustration at the
current rules that make it so difficult for them to purchase genuinely
low carbon electricity. Examples exist in telecoms, supermarket
chains, and financial services; companies like TESCOs and Marks
& Spencer are also starting to market electricity to consumers
under their own brand, and might prefer to be able to offer genuinely
zero-carbon electricity. CRC participants, that currently have
to pay for carbon in their electricity even if they might pay
for zero carbon electricity, is an obvious place to look. Depending
on cost differentials, some electricity-intensive industries might
welcome the certainty of moving to such contracts as their current
contracts expire. In addition, the recent government move to allow
local councils to sell electricity might open up a whole new kind
of purchaser, more closely aligned to domestic markets, that might
sell "clean power" on to local consumers.
Each of these might inject preferences for different
kinds of zero carbon power; several might also help to engage
citizens more in the choices about low carbon investment, reducing
some of the political obstacles that emerge (eg opposition to
onshore wind energy, despite its cheapness) when the incentives
for investment become too disconnected from civil society. Indeed,
underlying the thinking there lies a strong element of organisational
and behavioural economics, in which the degree of control that
people have over their choices is an important motivating factor.
There are obvious parallels with the various proposals for "green
bonds", and buyers could of course include pension companies,
for example. However its distinctive feature is its potential
to help electricity consumers of different sorts connect withand
help to fundelectricity sources of their choice, through
the electricity they purchase.
A second approach is simply to wait and see: to argue
that one never knows, until one tries, what the demand for a new
product might be. "Green tariffs" to date have been
presented as a green version of conventional energy, set purely
at a price per kWhnot presented in the form of a long-term
offering more akin to a mortgage. Discovering the scale of demand
could itself be valuable.
The third approach notes that ultimately, the leverage
of carbon price remains in State hands. If there is insufficient
investment in low carbon electricity sources, in addition to contracting
more itself, the government could increase the carbon price, to
improve the competitiveness of the "GP contracts market".
And that, indeed, is one additional advantage. Many of the proposals
for support mechanisms, including long-term contracts with government
as the purchaser, marginalise the role of the carbon price. Having
put huge political effort into creating a carbon price, for sound
reasons, it would seem very strange to then sideline its role
in long-term electricity investments. By creating zero-carbon
electricity contracts as a separate commodity, in competition
with "normal", high carbon electricity at the point
of end users, the carbon price would remain a key driver of a
market-based switch to low carbon investment.
Creating a low-carbon power system is a cornerstone
of the move towards a low-carbon economy. This requires huge investment
and extensive innovation. Our current electricity market structures
create large uncertainties for investors, and have incentivised
little private innovation and R&D. We have put in place policy
instruments to try and address these problems. ROCs and feed-in-tariffs
create greater certainty over returns to investment, and boost
demand for renewable power. Both of these policies have had their
successes, but also face long-term limitations.
Harnessing consumer, business and industry demand
for zero-carbon electricity can help raise investment in low-carbon
power, and also increase the political acceptability of the endeavour.
Our current market structures do not harness this demand, and
the systems we currently have in place struggle to provide clearly
additional zero-carbon electricity to consumers. Creating a clearly
defined separate low-carbon electricity product could help to
harness this demand and capital, and could carry a number of other
benefits as indicated.
The idea is only presented for consideration: it
is not a proposal that has been rigorously explored and debated.
Closer examination might reveal insuperable obstacles, or show
advantages to be less than they seem. With the EMR process, however,
the UK is at a major juncture, and has the kind of opportunity
for major reform that only arises every couple of decades. Whether
and how to create a separate contractual market that allows end-user
competition between zero-carbon electricity and the rest of the
system requires more research and analysis, but it is surely an
option that should be seriously debated in the EMR process
This submission is drawn from a published working
paper: Tim Laing and Michael Grubb, "Low-Carbon electricity
investment: The limitations of traditional approaches and a radical
alternative", Electricity Policy Research Group, Cambridge
University, September 2010 (www.eprg.cam.ac.uk). References are
contained in that working paper.
29 See also various reports by UKERC for cost structures
of different specific UK generating options Back
In economic terms, zero carbon sources are all infra-marginal,
but in the absence of other measures will receive a price set
at the margin over which they have no control-and limited capacity
to predict. In practice, most renewables are covered by other
support schemes, reducing the role of the electricity market itself.
This submission does not address directly the pros and cons of
the UK ROC scheme vs feed-in tariffs, but does argue the
need for some vision of when and how to integrate renewables investment
into mainstream electricity regulation in the long term. Back
Although it depends on the definition of the electricity sector,
for example Siemens are classified in the Electronics sector,
yet some of their products may be applicable to the electricity
The most inherently WTO-compatible approach to border levelling
suggests starting with a fixed "benchmark" based on
the carbon intensity of the best available technology. However
for electricity-intensive products, the best available technology
from a carbon emissions perspective would involve zero carbon
power, with no carbon costs-negating the point of the border levelling.
And for export adjustments, it would be similarly hard or impossible
to get consensus on the level of adjustment, unless a producer
could plausibly demonstrate direct association with a specific
power source and a trail of the carbon costs incurred. This is
impossible under our current regulatory structures, because it
is impossible to associate a given power source with a given electricity
This would also facilitate (though not resolve entirely) the dilemma
that any cap on generator emissions "disenfranchises"
consumers from claiming any carbon reductions from reducing their
electricity consumption. The EU ETS cap for post 2020, for example,
could be explicitly debated in terms of electricity sector emissions
net of the volume of GP contracts; such contracts could
thus legitimately claim to be contributing to ongoing carbon emissions,
by reducing the demand for carbon-based generation and thus facilitating
tougher carbon caps on the rest of the system over time. Back