Memorandum by Dr Karsten Neuhoff, University
of Cambridge
1. Does renewable energy deserve any support,
in your view, beyond that given by setting a price for carbon?
Would carbon reductions be achieved more economically by setting
a carbon emissions target rather than a renewable energy target?
If we follow the IPCC recommendations and UK
and European government policy—UK emissions have to be reduced
to 20-30% of today's level by 2050. If we want to allow at the
same time for economic growth a shift to zero or low-carbon energy
technologies is required. Three non-renewable energy sources are
being discussed:
— If we continue to support nuclear
fusion programs in 30 years it could provide large scale commercial
energy.
— If desired, nuclear energy can provide
some additional low-carbon energy. Large-scale global contributions
require closed fuel cycles and would probably increase the number
of countries with access to plutonium. I am concerned about non-civil
use of this material should any of the countries face social instability
or war. This risk is likely to increase with climate change impacts
and scarcity of food, fossil fuels, and other commodities.
— Carbon capture and sequestration
might reduce emissions from fossil fuel use in large scale installations
by 80% (85% captured, but 20% increase of energy consumption for
capture). Large scale availability is expected post 2020—with
major uncertainties associated with storage sites. Because of
this and constraints on future availability of oil and gas the
technology is frequently labelled as bridging technology. A shift
from gas based CCGTs to coal based CCS will only reduce emissions
by 60% (carbon intensity of coal is higher, and efficiency of
coal powered stations is lower). This does not reduce emissions
to 20-30% of today's levels, especially not with economic growth.
All three options might have a role to play
for energy and climate policy over the next decades, but it is
difficult to see how they can replace the need for large scale
use of renewables.
This brings me to the second part of your question—will
imposing a carbon constraint be an effective mechanism to deliver
the timely investment in a portfolio of renewable energy technologies
in order to:
— develop and improve the technologies
with regard to cost, scale and quality factors;
— increase production scale along the
supply chain to serve a UK and global market;
— aid diffusion of technology, including
the training, experience and organisation of UK based staff and
firms for their deployment; and
— achieve system integration—including
transport chains for bio-mass, network structure and management
for power generation, and possible alternative transport infrastructure
with electricity/batteries as energy carrier.
This is a complex set of changes and I doubt
that the UK or any European government has the ability to micro-manage
them. So incentives are required to ensure that market participants
deliver the different components—after all most of the R&D,
production and organisational skills and scale are already in
place.
I do not think that the carbon price signal
alone will provide this incentive for three reasons:
First, many of the renewable technologies are
at an early stage, and will have to be built and installed much
more often in order to allow cost reductions from learning-by-doing.
Very few consumers are prepared to pay the necessary premium for
renewable energy to finance this investment. So the learning investment
will either have to subsidised by firms or by governments.
Firms will only sell products below costs in
the expectation of future profits from a competitive product.
But, in this case, the time scales are too long, the investment
volumes are too large, the technology spill over is too quick,
and too many firms have to be involved for private investors to
believe that they will capture this future benefit. This investment
environment is in contrast to mobile phone markets, where product
differentiation allows firms to capture their investment, or the
pharmaceutical industry where patent protection is viable.
Hence targeted deployment programs are required
to create initial markets for different renewable technologies.
Even large venture capital firms only invest in new renewable
technologies if they see the possibility of supplying markets
created by government renewable policy.
Some policy analysts are concerned about targeted
technology policies by governments—arguing governments are
bad at picking winners. Strategic deployment programs, eg feed-in
systems or banded ROCs, create a market interface between governments
and technology firms, allow for continuous transparent evaluation
of the programs, and limit regulatory capture. In addition, the
output, energy, is clearly defined and can therefore be targeted
with the deployment programs (in contrast to fashion, IT, or other
consumer products). Hence I feel more comfortable with targeted
technology policy for renewables than for other technologies.
Second, the transition to a low-carbon economy
creates technological, resource and political uncertainty that
needs to be managed. Especially when the exact timing of the use
of new technologies is uncertain. In the absence of targeted programs,
it is difficult to predict costs and regulatory regimes in order
to anticipate whether the second wave of renewable technologies
will involve tidal stream energy or expand use of dedicated bio-mass.
For most technologies a change in timing of a few years makes
the difference between a profitable marketing strategy and bankruptcy.
However, in the bigger picture of emissions reductions to 2050
or considering the overall social cost benefit analysis, the exact
timing does not matter. Hence it is desirable for governments
to commit to a timing and market volumes even at the risk of getting
it slightly wrong, thus creating a stable framework to facilitate
private sector investment.
Third, the successful use of new energy technologies
requires new infrastructure and regulatory frameworks and action
across a multitude of policy areas of government. Any one delay
can derail investment strategies of companies. Unless there is
a clear commitment of governments to create the framework for
a specific technology it is difficult to see how investment will
be pursued at the relevant scale.
2. Less than half of the UK's greenhouse gas
emissions from heat are covered by the EU Emissions Trading Scheme.
Could the ETS be extended, or some other scheme brought in, to
spur the deployment of renewable heat sources?
The ETS could in principle be extended. However,
as all the other emissions sources are small in scale, to limit
transaction costs the ETS would have to move upstream, eg to the
fuel input. This was not desired with the ETS so far, because
direct exposure of emitters to the carbon price signal creates
more management attention and is therefore more effective in changing
operational and investment decisions.
The focus of the ETS is on energy and carbon
intensive industries, where competition between Member States
has so far resulted in very low energy tax levels. Such competition
is not an issue for small scale heat sources—and therefore
also allows for national policies. As the politics of fuel poverty
differs across Member States, and it is important to have complementing
regulation and information provision, it might be desirable to
pursue these policies at national level against emissions reduction
targets defined for the non-covered sector at the national level.
In the UK aligning energy tax levels and abandoning
VAT rebates for heating fuel and starting to imposing taxes that
reflect carbon costs would be important for both supporting renewable
heat and energy efficiency. This should be accompanied with some
redistribution of additional tax income towards low income households
and a continued focus on energy efficiency measures for these
income groups. But no government will pursue such changes unless
the fuel poverty index is redefined, from the share of household
expenditure spent on fuel towards the household expenditure minus
direct support for energy services of total income.
Biomass might prove to be very valuable for
decentralised provision of renewable heat. Decentralised biomass
generation avoids long transport chains, energy losses in transformation,
and offers the opportunity to store energy for cold winter periods
when UK energy demand is peaking. I do not know what support scheme,
including investment and operation divides, is most suitable—particularly
given the characteristics of its application by private households.
3. What expectations do you have for the level
of the carbon price in future years? Is anyone currently trading
carbon permits for the period after 2012?
Current prices are 28 Euro/t CO2 and forward
prices for 2012 are traded at 32 Euro/t CO2. Trading beyond 2012
is—to my understanding—very limited. I think prices
for 2020 are around 40 Euro/t CO2 and at a recent PointCarbon
conference several traders gave presentations suggesting that
prices would be around 50 Euro/t CO2 by 2020.
Looking at the overall European Climate Package,
I can easily imagine that prices could fall bellow 20 Euro/t CO2,
if the emissions reduction target is not increased to 30% by 2020.
Obviously, if oil, gas and coal prices stay as high as currently,
they will drive far more demand response than anticipated from
current carbon pricing (complementing regulation and information
will be in place in both cases). This suggests a perspective with
potentially rather low-carbon prices. But then again, the global
resources for coal are excellent and therefore coal prices are
likely to revert to lower levels. In this case even with lower
energy demand, a shift to coal would increase carbon emissions
and would therefore push up the carbon price.
You notice lots of uncertainties. But given
that the UK does not control global oil, gas and coal prices,
it would make little sense to fix a carbon price for 2020—the
carbon price has to be able to respond to fossil fuel prices and
technology costs. Therefore a strong commitment to an emissions
cap will be far more important including limited inflows of CDM
credits. The firm cap gives some certainty about the market shares
for different fuels in 2020 and the market opportunities for energy
efficiency and low-carbon technologies. A reserve price in auctions
can then ensure that the price does not drop below, for example
20 Euro/t CO2—thus providing a parameter that banks and
project investors for low-carbon projects can confidently use
as their worst case scenario, and avoiding emissions that are
far below the social cost of carbon.
4. Do you think the UK should be allowed to
count renewable energy in other countries towards its national
targets? Would it be possible to trade renewable energy (or just
green certificates) across borders in a manner that guaranteed
that additional supplies were being produced as a result?
The main argument in favour is that it this
captures least cost potentials. But this obvious advantage must
be balanced by the objective to create a framework and pressure
to develop a portfolio of renewable technologies that can deliver
the necessary scale. Also if trading results in the majority of
skills for installation being cultivated abroad, it does not prepare
the UK for emissions reductions of 70-80% relative to today's
levels. Finally, if the majority of deployment of renewables happens
abroad, additional benefits for security of supply and some domestic
jobs, profits and tax revenues are not captured. An additional
factor that is even more difficult to quantify is the sense of
shared ownership. By creating financial frameworks that allow
people across the UK to install and participate in renewable projects,
they are more likely to appreciate and support the technology
and policy.
The EU Renewable Directive will allow countries
to cooperate bilaterally to deliver against their shared renewable
target. For example the UK can cooperate with Poland and subsequently
count some of the renewables deployed against the UK renewable
target, and not the Polish quota. This approach allows for long-term
cooperation across different institutional levels and can thus
benefit both countries. The payment may be negotiated but could
be linked to an average European support level. The Directive
ensures that Poland could only export renewables once the domestic
target is met—thus ensuring additionality and creating a
strong incentive for both countries to make the cooperation work.
Renewables investments outside the EU can, according
to the Directive, only be counted, if they are delivered physically
(eg solar concentration in North-Africa with a DC link to Italy
or Spain). Not allowing other projects sounds reasonable to me,
because of the largely differing marginal resource costs of renewables.
Otherwise globally all good on-shore wind resources would be counted
against the EU scheme, even though many might be viable without
additional support. Renewable investment in developing countries
should be supported—but in a more targeted manner so as
to ensure technology transfer. This could include using EU ETS
auction revenues to support developing countries in implementing
domestic policies in order to accelerate the use of renewables.
5. Through Clean Development Mechanism projects,
rich countries can partly meet their carbon emission targets by
investing in "green" projects in poor countries. Does
your experience of such projects offer any lessons about the scope
for international trading in renewable energy?
I think CDM projects are very effective in creating
private sector incentives to pursue new project and technology
types and to offer profits as incentives to pursue difficult first
of kind projects in a new country so as to create effective demonstration
projects. But all projects receive the same carbon price—with
only small risk adjustments—even though the additional cost
for emissions reductions are vary widely. This creates significant
rent transfers to private sector investors, which would be of
concern if the mechanism was scaled up. Also, CDM subsidises projects
often against prevailing energy subsidies and regulation. Hence
we might contemplate moving towards cooperation with developing
countries on implementing domestic climate policies.
The experience of CDM type trading—and
the limited success of ROC trading in the UK—was my main
concern when arguing against an installation based trading scheme
at the EU level as initially proposed by the EU Commission. It
would have created large rents, and significant regulatory risk
that increases costs of capital for investors and the subsidies
paid by electricity consumers. The approach would also not have
created clear targets for national governments to implement the
necessary market design, grid framework and investment and planning
regimes.
It seems that the EU Directive will use country
level transfer of renewables. This allows countries to agree early
on the volume of renewables they want to transfer—and thus
creates clear targets for national and regional administration
to ensure the necessary framework is in place. This will have
to be reported in national action plans. I think this kind of
approach learns from positive experience that was internationally
collected with Poverty Reduction Strategy Papers of the Worldbank
and the (L)PSAs in the UK.
It will be important to create a robust non-compliance
mechanism at the EU level. My sense is that various administrations
of Member States are reluctant to fully commit to action and will
try to impose a lax compliance mechanism in the EU Directive.
But only a strong compliance mechanism at the EU level will make
the renewable targets defined in the Directive credible. Only
credible targets will enable the level of investment required
into the supply chain—including cables and turbine production
and ships for off-shore installation.
6. What are the key considerations for UK
energy policy? How do and should renewables fit into Britain's
energy policy? How far is their role likely to change between
the medium term (to 2020) and the long term (to 2050 and beyond)?
I think a secure, affordable and sustainable
energy supply is typically the key consideration. For reasons
of simplicity most analysis is usually focused on a static short-term
perspective.
It would be important to reflect on uncertain
and volatile energy prices. This would create more of a focus
on the value of long-term energy contracting to hedge against
high prices and provide stable revenue streams for investment
through low price periods. Unfortunately policy makers (like consumers)
are only looking at long-term contracting at times of high energy
prices, and then lock themselves into high prices (see California
example in power market). At times of low prices, there is a reluctance
to look long-term. In addition, Ofgem's focus on retail competition
implies a focus on switching of retail consumers and therefore
limits the ability of supply companies to sign long-term contracts
with generators. Vertically integrated companies bet on the limited
scale of retail competition and invest against their customer
base which is assumed to be rather stable.
It would also be important to develop a more
dynamic perspective on the energy system. Sustainability looks
at the long-term carbon emissions, but in the day-to-day business
is translated into a shadow price of carbon. As mentioned above,
taking climate change policy serious will require an transition
towards a low-carbon economy and can not be achieved by only capturing
low hanging fruits (least cost carbon reductions). The Climate
Change Bill with carbon budgets, the renewables consultation and
this committee allows for a focus on the trajectory for different
renewable technologies. I think it would be valuable to judge
energy policies not only by the cost born in 2008, but also by
the outcome of the system in 2030—where does the UK population
want the energy to come from?
7. How do the costs of generating electricity
from renewables compare to fossil fuel and nuclear generation?
How likely, in your view, are these relative costs to change in
the future, and how robust are the estimates? What are the main
cost drivers for renewable energy?
For onshore wind, the German feed-in tariff
generated 22 GW of investment with current tariffs between 49£/MWh
at sites with high wind speeds and 63£/MWh for sides with
lower wind speeds. Capacity shortages in production and high commodity
prices however resulted in recent costs increases. To ensure continued
high investment volumes, the German government increased the tariff
for installations commissioned in 2009 by about 10%. I think this
is a temporary cost increase that will be resolved as production
capacity increases. Production scale and learning-by-doing is
likely to reduce costs after that—I would assume towards
£40/MWh in 2020.
For off-shore wind, a new publication by the
IEA—Energy Technology Perspectives—lists the costs
of past off-shore wind parks at 80-100$/MWh—at historic
exchange rates around 45-55£/MWh. Some of the projects might
have been underpriced at the time and most sites were close to
the shore in shallow water. To accelerate deployment in deep water,
the new German feed law offers 97£/MWh support level for
off-shore wind parks, that will decline in 2015 to 79£/MWh.
Power prices have dramatically increased and
are now at 95£/MWh. The increases are driven by higher gas
prices that follow the oil price increase, but also coal prices
have within the last year increased from 80$/tonne to 210$/tonne.
At least according to forward markets covering the next few years,
fossil fuel prices are expected to stay high and therefore forward
electricity prices for 2009 and 2010 are 90£/MWh and 85£/MWh.
At such prices even off-shore wind is at the
edge of breaking even. So why do we need any support policy at
all?
First, it is uncertain whether coal and oil
prices stay at their current extremely high levels. Particularly
for the coal price it seems more like a production constraint
if not exercise of market power. But also for oil, and therefore
gas, the high prices will trigger demand reduction, or if not
new production. Given this uncertainty, risk averse private investors
are use far lower numbers when valuing investment projects. Even
the adventurous oil industry had—when oil prices already
had moved into the 50 and 70 $/barrel range—only pursued
investment projects that could break even at 30$/barrel. Feed-in
tariff offer typically a twenty year revenue guarantee for investors.
This reduces the risk and therefore financing costs by about 20%.
Second, so far incumbent utilities make large
profits with their conventional generation asserts. Investment
in renewables creates competition for conventional assets and
reduces their value. Iberdrola is the only large Utility that
had focused on investment in renewables—because in Spain
electricity demand increased and therefore new investment was
required rather than competing with existing assets. The UK also
needs to create a policy environment that allows new entrants
to take forward renewable projects independent of long-term projects
with incumbent utilities—if only as a credible threat to
ensure incumbent utilities focus on renewables. This approach
has succeeded once before in the UK—with the dash for gas.
New entrants in generation signed long-term power purchasing agreements.
A feed-in tariff would again offer such a price guarantee.
Finally, most renewable energy technologies
do not provide base load power but intermittent output. This reduces
the value they can contribute to the system and creates two uncertainties
for renewable investors: First, will the UK government implement
an efficient market design that allows for optimal integration
of dispatch and congestion management and limits the additional
cost. Second, who will bear the cost of intermittency under the
new market design—and will incumbent conventional generators
be able to exercise market power in the design of, and operation
under, such a design at the cost of intermittent generation technologies.
With an efficient market design, using nodal pricing, centralised
unit dispatch and careful market monitoring, the cost could be
a few £/MWh. But the experience during the initial months
of the balancing market under NETA, when balancing costs exceeded
energy revenue for some generators, illustrates how important
it is that the power market design evolves to reflect the requirements
of the generation mix.
8. How likely are there to be technological
advances that would make renewable energy cheaper and viable without
Government support in the future? Should policy be designed to
promote such technological advances, and if so how?
Learning-by-doing suggests that technologies
exhibit cost reductions usually between 10% and 20% with doubling
of global installed capacity. We have confirmed this with an extensive
literature survey. Separate studies were pursued for on-shore
wind with Luis Olmos, photo voltaics with Gregory Nemet, Misato
Sato and Katja Keller, and marine energy technologies with Jason
Hayman.
For on-shore wind we found that cost reductions
per delivered MWh declined between 2000 and 2003, because cost
reductions were partially compensated by diseconomies of scale
as turbines increased beyond 1MW. A larger scale is still a good
idea, because it allows better harvesting of wind resources. In
the subsequent years global demand for turbines grew faster than
predicted, resulting in continuous production scarcity and therefore
higher prices.
This example was paralleled in photovoltaics.
After three decades of successful learning-by-doing when the cost
was reduced by the factor 100, the price suddenly stalled in the
last four years. A global interest of policy makers to support
deployment programs multiplied demand. This resulted in scarcity
rents captured in a capacity constrained supply chain, particularly
for silicon and prevented price reductions for several years.
The constant price, however, masks the significant cost reductions
that will now be harvested—the German feed-in tariff for
roof top installations will be reduced by 9-10% annually staring
in 2010.
One important lesson from both technologies
is the importance of long-term signals about the market size.
The European Renewables Directive offers countries the opportunity
to credibly to commit to renewable targets up to 2020. It will
be important to formulate the indicative trajectory that is part
of the Directive as a mandatory trajectory with compliance mechanism
to increase the credibility and visibility of the signal for investors
in the supply chain.
With the work on photo voltaics we also wanted
to address a long-standing question—should we invest in
R&D or subsidise the deployment of the technology? Deployment
is crucial for cost reductions. Profitable opportunities have
attracted companies from many sectors of our economies to apply
their specific skills and technologies to the PV production line—a
result that was crucial for their success and almost impossible
to deliver with R&D subsidies. Also, many of the new ideas
can only be explored on real production lines, which offer the
precision and allow for an optimisation of processes. But subsidy
costs for strategic deployment are a multiple of R&D expenditure—governments
could explore how to better target R&D funds to companies
to give incentives to be more adventurous in trying out new technology
and manufacturing ideas.
Wave and tidal stream costs are difficult to
predict. But if they are to be taken seriously, they will require
real focus from government. So far the companies pursuing demonstration
projects are very small start-ups, focussed on getting the next
round of funding for their first large-scale demonstration plant
to simply prove that their concept has merit. This distracts the
focus from the use of more sophisticated materials and designs
that would enable the mass production required to reduce costs
and deliver the scale. The companies involved in the industry
currently don't have the capacity to pursue a more sophisticated
design approach and there is insufficient incentive for larger
engineering firms to engage.
The Marine Energy challenge of Carbon Trust
initially approached this challenge, but again the level of investment
was not in line with the scale of the engineering challenge. Rather
than building individual demonstration projects at a few million
pounds each, one might consider working in parallel to really
get things moving. I don't think we can guarantee success, but
I would feel uncomfortable if this option is not really explored.
Also, it is the one renewable technology where the UK has competitive
advantages and could be a successful global leader with large
export potential.
All marine energy technologies, including off-shore
wind, are currently desperately competing with the offshore oil
and gas industry for engineering resource and physical resources
such as installation vessels and equipment. It is not practical
for companies to ignore the current demand created by high oil
prices and it will require very strong government policy to give
credible signals that it will be profitable to shift this attention.
9. Does the fact that the running cost of
renewable energy is likely to be less volatile than that of fossil
fuels give it a competitive advantage in the market?
The example of power systems with large shares
of hydro power shows that the opposite is the case. The marginal
power price is still set by fossil fuel generation, and therefore
revenue streams are volatile. I think for many years we will remain
with power systems where the marginal generation is based on fossil
fuels, and therefore private investors in conventional, not renewable,
generation technologies have more stable revenue streams.
The risk to which renewables are exposed in
the current market design is in marked contrast to the benefits
they would offer to final consumers. Final consumers suffer from
price volatility of global oil, therefore gas prices and now also
from volatile coal prices and would benefit from more stable prices
if they could sign long-term contracts for the energy from renewables.
This is, however, difficult under the current design of the power
market—which focuses on allowing retail competition, rather
than on long-term investment frameworks. Long-term contracts signed
by retail franchises or under feed-in tariffs would offer an alternative.
The current market design for congestion management
and balancing has been designed for conventional technologies
and is not suitable for large shares of renewables. Significant
changes will eventually be implemented. Renewable energy technologies
are most exposed to network congestion and balancing markets,
because they have volatile or intermittent output and usually
lower numbers of full load hours. It is difficult to predict when
exactly this change will occur, but renewables face the biggest
uncertainty from the outcome of such a change.
10. There have been suggestions that the Renewables
Obligation should be replaced with a Feed-in Tariff system, as
used (for example) in Spain and Germany. Would a Feed-in Tariff
be more effective at deploying renewables?
I think the UK would benefit from a shift to
a feed-in system for all investment combined with a tender for
off-shore wind parks. This approach has been successful in deploying
renewables across Europe and exhibits significantly lower costs
per turbine than the UK ROC scheme. Cost reductions of about 20%
can be achieved by reducing financing costs. The feed-in tariff
gives long-term price guarantees, thus reducing exposure to regulator
risk about the future ROC design, future congestion management
and future balancing market design.
The feed-in tariff can also be cheaper for consumers—as
the tariff can be set to reflect the costs of different resource
location. With certificate schemes all projects in one technology
band receive the same payment, irrespective of the depth of water
or wind speed. If only a limited number of projects are to be
implemented, this allows the certificate mechanism to target the
best resource location. But many projects are required to deliver
the UK renewable target, and therefore many inhomogeneous sites
have to be developed. Therefore the certificate price has to rise
to finance projects at somewhat lower wind speed or deeper water.
The projects at better sites will also benefit, and receive higher
rents at the cost of consumers.
The feed-in tariff also offers a clear and transparent
payment scheme that allows both large scale and small scale market
participants to pursue investment. This opens the market for local
and specialised project developers that might be better positioned
to engage with local communities and gain support for projects,
as experience in other countries has demonstrated. Also, the threat
of entry of new firms is likely to be required to ensure incumbent
utilities shift their efforts towards renewable projects.
The UK government suggests adjusting the ROC
scheme to address some of these concerns. Using adjustment mechanisms
(ski-slope and head-room) the ROC price is stabilised and gradually
transformed into a premium scheme. The Spanish example shows that
a premium scheme alone is not acceptable if wholesale prices rise.
Therefore, in Spain the scheme was subsequently adjusted to implement
a price floor and ceiling for the sum of wholesale price and premium.
Judging by current UK wholesale prices the next round of changes
is probably already on the table.
A further change that will be implemented to
the ROC scheme is, that it will provide different bands for different
technologies—eg off-shore wind receiving more than one ROC,
while co-firing bi-mass only receives a fraction of a ROC. These
technology bands can be reviewed in five year review periods.
Given the uncertainties about the costs off-shore wind and marine
energy projects, this is likely to be a bit slow.
Anticipating forthcoming changes, the renwables
review suggests implementing some grandfathering of provisions—such
that future changes of the scheme will not change the revenues
of current projects. I guess with careful formulation the ROC
scheme can eventually be translated into a feed-in system—albeit
with a few drawbacks. For example, a feed-in approach allows governments
to sign explicit long-term contracts with investors. Thus renewable
projects that want to be supported have to promise to deliver
their energy at a fixed price. At times when wholesale prices
exceed the feed-in tariff for wind power this reduces the electricity
bill for consumers.
The main concern expressed in the renewable
consultation document by BERR about a change to a feed-in system
is a potential investment hiatus—if the government changes
the investment framework again. Perhaps I am an optimist—but
I think the transition can be managed without detrimental impacts
on investment. European human rights law ensures property rights
and protects the existing investment from expropriation, and therefore
ensures that it will receive fair treatment under the new scheme.
Even more importantly, if the UK parliament expresses a shared
interest in delivering the renewable target and the EU Renewable
Directive makes this obligatory, then it is clear that project
investors will require cash and goodwill to develop the necessary
projects—and will therefore be treated with generous transition
provisions. This can makes it more attractive to invest during
the transition and will possibly contribute to an accelerated
deployment.
July 2008
| 
