Memorandum by Dr Karsten Neuhoff
i. How achievable
are both the EU's general 20% and the UK's national 15% renewable
energies target?
Several studies have demonstrated the available
potential and technology to deliver the target. Delivering the
target will imply that power companies have to shift their focus
to renewable energy rather than continuing to use their current
business-as-usual approach where the majority of attention is
given to then next wave of mergers.
Only an ambitious target can actually be achieved—the
experience of the UK in recent years demonstrates that without
commitment a far less ambitious target is easily be missed—despite
the excellent resource base in the UK. A step-change by both companies
and government will therefore be required.
ii. How coherent are these proposals in the
context of the EU's energy policies in general and the Third Energy
Package in particular?
iii. To what extent
are these targets capable of improving the EU's security of energy
supplies?
Renewable energy has the potential to increase
production of domestic energy and thus reduce the needs for imports
of coal, gas, and, if many cars shift to electricity, oil. With
appropriate power market design this can reduce the long-term
price volatility for final consumers. While intermittent generation
will increase the hour to hour volatility of wholesale prices—it
is the longer-term price volatility (eg year to year) that matters
most for final consumers. This would also shift funds that are
currently directed to oil exporting countries to renewable energy
provision in European countries.
This does not imply that countries and security
of supply suffers from closer trade relationships. Renewable energy
might well be imported from other regions of the world, eg large
scale solar concentration in North Africa. The challenge for national
and energy security is to ensure that this shift is supported
by good governance frameworks.
GRID ACCESS
iv. How effective has the existing legislation
(2001/77/EC) been in encouraging grid access for renewable energy
generators?
v. To what extent
does grid access remain a significant barrier to increased consumption
of renewable energies? Is it consistently a problem across all
Member States?
Management and regulation of grid access remains
an important constraint for increased renewables deployment. In
the UK, like in much of Europe, most of the technical grid expertise
and information about the network is located with the network/system
operator and owner NGT. In contrast to the US, detailed network
operation and technical characteristics are not public, and no
process exists that allows market participants to challenge decisions
on delayed grid connections. Also, the regulator and government
often rely on information, expertise and interpretation provided
by NGT.
Grid access can be split up into two components.
First, the connection of a renewable generator to the grid and
second, accepting the power delivered from the generator.
In many Member States, grid operators and owners
are vertically integrated with existing generators. As new renewable
power sources create competition for their existing assets, network
owners have an incentive to delay connection of these assets.
In the UK distribution networks owners also hold generation assets.
In an efficient power market, all generators
that apply are connected to the grid. Not necessarily all generators
can deliver power at the same time. If at one location, or in
one region, too many generators aim to deliver power to the system,
then an efficient market design ensures that the generator with
the lowest marginal costs is dispatched before more expensive
generator operates.
In most Member Stats, including the UK, connection
to the network entitles a generator to nominate and deliver power
flows to any location within the country—without consideration
of potential congestion in the network. If the nominated flows
exceed the network capacity, then the transmission network operator
(NGT) is charged to resolve the constraint. NGT has to use the
balancing mechanism, or contract with some generators, to reduce
generation in parts of the country that are export constraint,
and increase generation in parts of the country that are import
constraint.
NGT bears the costs it incurs when contracting
with the generators as part of an incentive scheme to minimise
congestion costs. This is inefficient, because the market design
does not signal to generators the cost they are imposing on the
system. The simplified market design was chosen at a time when
stable flow patterns in a conventional power system with strong
transmission capacity created very limited congestion.
With increasing shares of renewables, flow patterns
will be more volatile and will result in some congestion. Some
congestion is efficient—an electricity network that is never
congested is over-dimensioned. The difficulty is that NGT bears
the cost of the congestion and thus has an incentive to limit
the connection of renewable generation capacity so as to limit
congestion costs.
Various fixes have been discussed, but I do
not see how they will offer long-term solutions and therefore
market stability. I anticipate that the UK will eventually move
to an efficient scheme—nodal pricing. The price in every
area is set at the value electricity offers to the system at a
specific location. Where there is too much supply, a lower price
is set, and expensive fossil generation reduces output, or storage
hydro plants shift production. Generators can receive financial
transmission contracts to hedge against the locational price risk
they face under such a scheme. The states in the North-East of
the USA have moved to nodal pricing—and it works very effectively.
Priority access for grid connection is across
Europe the policy response to a market structure and market design
that is inefficient and artificially hinders the investment in
renewable generation. It typically sets a clear time frame within
which new projects have to be connected and requires that generators
power can be inserted into the system.
Implementing priority access in the UK would
create a challenge for NGT, given the long list of projects waiting
for connection. This could encourage NGT and Ofgem to implement
a market design that allows for efficient investment and operational
decisions, eg nodal pricing with a centralised dispatch and financial
transmission contracts. Once a clear, transparent, and efficient
way for grid connection, congestion management and dispatch has
been implemented, priority access provisions are no longer required.
This does not imply that there might not be
the need for grid expansion. But it will be important to evaluate
the need for transmission expansion assuming an effective market
design that allows for efficient network operation. This could
reduce the need for transmission expansion relative to current
estimates, and allows for a decoupling of grid connection of new
projects from some of the transmission grid expansion (at the
expense of temporarily higher congestion in the system).
vi. How does Use of System charging affect
grid access for renewable energy generators? How far can the different
levels of renewable energies take-up in different Member States
be attributed to Use of System charging and cost sharing rules?
European countries differ in the way they allocate
grid costs. In the UK grid costs are shared between generators
and consumers, but many other countries impose virtually no charge
on generators and require the consumers to pay all the costs.
As this was an established principle for conventional generation
it is also applied to new generation, and therefore varies widely.
The UK is one of the countries where generation
has to pay connection charges. The methodology was developed for
conventional generation capacity and the implied simplifications
create a bias against intermittent generation technology. The
TNUoS system of charges (based on ICRP) does not differentiate
by technology despite large variations of capacity factors.
vii. What impact do the various systems of
reinforcement planning and work have on encouraging renewable
generation? How important is the issue of constraint in increasing
Member States" renewable generation?
Physical transmission constraints currently
only create a constraint for renewables at very distant sites,
eg in the North of Scotland. The inappropriate power market design
results in the UK, like in many European countries, in inefficient
use of transmission capacity and therefore induces network operators
to delay the connection of new assets.
A change of congestion management can thus allow
for better use of the network and allow for connection of more
renewable generation assets. This creates the time window to expand
the network where this will still be required to deliver the larger
shares of renewables.
viii. To what extent is further co-ordination
of National Regulatory Authorities needed?
ix. How far do current
regulations inhibit access to the grid?
SUPPORT SCHEMES
x. At what level should the EU be involved
in harmonising or regulating support schemes offered by Member
States to encourage renewable energy generation?
If the 15% renewables target is to be achieved,
a significant investment from private sector actors into the supply
chain will be required; from cables to turbine manufacturing plants,
and from tailored ships to new marine energy devices. The challenge
for national policy makers has always been their inability to
credibly commit to future targets—and therefore investment
in the supply chain always was slower then the subsequent market
growth. As is now observed, this resulted in bottlenecks with
higher scarcity prices for several renewable technologies.
The EU Renewables Directive offers national
governments a unique opportunity to commit to targets and to trajectories
on the way to these targets. It will be important to implement
a stringent compliance mechanism and to turn the indicative trajectory
into mandatory milestones. Credibility of the growing market enhanced
by the commitment and scale provided with the EU Renewables Directive
can trigger a step change of investment across the industry.
Implementing renewables requires a multitude
of activities, ranging from planning to grid access, from encouraging
local participation to ensuring effective national balancing and
congestion management schemes. These are responsibilities that
can only be pursued at the national level. Therefore delivery
responsibility and flexibility to choose the most suitable instruments
must rest at the national level.
xi. What impact have the various schemes
in operation across the Member States had on encouraging renewable
energy? How have these schemes affected take-up both by producers
and commercial and domestic consumers?
In principle feed-in type schemes have been
most successful. They provide a simple and transparent remuneration,
in most cases with a 20 year price guarantee. This has allowed
a multitude of project developers to pursue projects. The most
successful developers were often the ones that managed to engage
best with local communities to obtain support and subsequent planning
consent. The clear revenue streams also facilitated investment
by private investors in projects, thus increased local ownership,
and allowed local banks to provide large shares of debt (70-80%)
to reduce financing costs. The result has been significantly lower
costs per turbine and larger deployment levels.
In contrast, trading based schemes create significant
policy risk associated with future target levels, qualifying resources
and other design components. Also changes to grid charging methodology
as well as balancing and congestion management have disproportional
impacts on intermittent generation technologies and therefore
increase policy risk for investors in renewables projects. As
a result project developers required long-term contractual arrangements
with vertically integrated incumbents to off-load policy and other
risk components. The experience across Europe is that incumbents
are reluctant to encourage large scale investment in renewables
where these create competition for and reduce the profitability
of their existing assets. Only Spain witnessed an incumbent utility,
Iberdrola, taking forward large shares of renewables—because
they satisfied rapidly growing electricity demand rather then
replaced output from their existing power stations.
Given the limited interest most UK power companies
have so far expressed for large scale investment in renewable
energy, as for example illustrated by ongoing delays with off-shore
wind parks, it will be important to provide a market structure
that allows for new entrants. The threat of entry is increased
with long-term price guarantees that facilitate investment. It
can either shift the focus of incumbent power companies to a renewable
strategy, or might allow new entrants to take forward the renewable
energy projects.
xii. Will cross-border renewables markets
be genuinely affected by the existence of a variety of support
schemes? Is necessary investment hampered by lack of market harmonisation?
I appreciated the value of the initial ideas
of the Commission to pursue a European-wide trading scheme for
Guarantees of Origin—effectively a European market for green
certificates. This would have offered the framework for a strong
compliance mechanism. It also addresses the concern that renewable
resources are not always located where demand and economic activity
is highest. Thus with trading, countries can commit to renewable
targets that are not necessarily linked to their renewable resource
but to their economic strength.
The approach, however, had serious draw-backs,
including the replacement of existing support schemes in countries
where feed-in tariffs were successful. Also, a common "renewables
currency" does not differentiate across technologies at a
time when even the UK government had acknowledged the drawbacks
of an undifferentiated scheme, and introduced banding to access
a set of technologies including off-shore wind. Finally, renewable
trading is nice in theory, but has so far not shown to be effective
in supporting the level of investment required. Most importantly,
the approach would have removed national targets and responsibility
to implement the necessary framework by Member States, including
grid access, expansion, market design, and planning.
In response to these concerns, the Draft Directive
published by the Commission in January allowed Member States to
opt out of installation based trade with Guarantee of Origin (GoO)
and to pursue domestic schemes. Member States opting out of installation
based trade could still cooperate and transfer GoOs at country
level.
There was subsequently a vivid debate on the
extent to which the opt-out provisions from installation based
trading are legally robust. Also, few countries envisaged participation
in the GoO trading approach as this would require significant
changes to domestic changes—and would have prevented the
UK from implementing banding or the ROC scheme. This might well
result in a shift away from installation based trading of GoOs
towards transfers between Member States.
Renewable targets for Member States are set
based on their economic activity, not their renewables resource
base. Without any type of trading it would be costly, and for
some countries probably impossible, to deliver their targets.
The Directive therefore envisages that Member States can transfer
some of their targets. This approach offers the opportunity for
effective cooperation to deliver the EU renewables targets by
Member States. It allows for example Belgium and Bulgaria to work
together to define how many TWh of renewable energy will be produced
in Bulgaria and counted against the Belgium target. Both countries
would announace this cooperation in their National Action Plans.
Such bilateral cooperation provides a robust
framework and a reasonable time-frame to implement policies that
facilitate the renewables investment. They can involve cooperation
across many institutions, (including TSOs, regulators, local and
national administrations), and thus follow the successful experience
of country twinning ensures cooperation among equals, usually
an important basis for effective work.
The Directive implies that Member States are
only allowed to export their renewable targets, if they satisfy
their domestic objectives. Thus bilateral cooperations can increase
the focus on delivering domestic targets.
So far the Directive is not specific on how
such cooperation has to be pursued, and according to the subsidiarity
principle, it might be best to leave it to the Member States to
define their cooperation. However, it might be worthwhile to actively
discuss guidelines among Member States for such cooperation, to
accelerate the process, facilitate some harmonisation and transparency,
and give smaller Member States the comfort that the framework
agreements they will be using are fair and effective.
xiii. To what extent would the enhanced use
of Guarantees of Origin certificates require the harmonisation
of support schemes?
A GoO trading scheme, as described in the Draft
Directive of January, would likely require abandoning the buy-out
price under the ROC scheme, and would prevent the introduction
of head-room, ski-slope, and more importantly the banding envisaged
for the ROC scheme.
8 July 2008
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