Memorandum submitted by the Sussex Energy
Group
ABOUT THE
SUSSEX ENERGY
GROUP
There is growing awareness that a transition
to a sustainable energy economy is one of the main challenges
facing us in the 21st Century. Although climate change is a central
factor, there are several other reasons why we need to address
the energy transition, including security of supply, fuel poverty
and the attractions of innovations such as renewable energy resources,
distributed generation and combined heat and power.
Critically, the energy transition needs to be
designed in such a way that maximises economic efficiency. An
effective response requires technical ingenuity, behavioural change
and virtually unprecedented political commitment. The complexities
and uncertainties involved are similarly great.
These are the challenges that the Sussex Energy
Group is addressing. We undertake academically excellent and inter-disciplinary
research that is also centrally relevant to the needs of policy-makers
and practitioners. We pursue these questions in close interaction
with a diverse group of those who will need to make the changes
happen. We are supported through a five-year award from the Economic
and Social Research Council but also have funding from a diverse
array of other sources.
OUTLINE OF
THIS RESPONSE
This response has been written and edited jointly
by Professor Gordon Mackerron, Dr Jim Watson, Dr Alister Scott
and Dr Shimon Awerbuch, all of the Sussex Energy Group.
In this response, we cover all the main areas
set out in the inquiry announcement: A) The extent of the generation
gap; B) Financial cost and investment considerations and C) Strategic
benefits. We do not wish to include any "other issues"
under D.
Within A, we question the usefulness of the
idea of a "generation gap", particularly since the time
required to build new electricity supply based on gas or renewable
technologies has decreased dramatically in recent years.
Within B, two important themes we emphasise
are: the impact of much greater uncertainty than commonly admitted
on the reliability of generating cost estimates as the basis for
major policy departures; and the role and needs of potential micro-generation
innovations.
Within C, we comment on: security of supply
arguments and the different dimensions of security of supply;
and the value of taking a portfolio approach to investment decision-making.
A. THE EXTENT
OF THE
GENERATION GAP
What are the latest estimates of the likely shortfall
in electricity generating capacity caused by the phase-out of
existing nuclear power stations and some older coal plant? How
do these relate to electricity demand forecasts and to the effectiveness
of energy efficiency policies?
We would question whether the idea of a "generation
gap" is useful in analysing energy and security problems.
Whilst it is important that public policy makers be aware of the
balance between probable demand and supply for power several years
ahead, expressing this in terms of a "gap" pre-judges
the existence of a problem and can give rise to a false sense
of urgency. It also lends itself to a "predict and provide"
approach to generation investment, which has demonstrably failed
in the past. For example, in the early 1980s a programme of 10
Pressurised Water Reactors was thought to be necessary to fulfil
UK electricity demand. In the event, only one (Sizewell B) was
built.
The rise of gas-fired and renewable energy generation,
with their short construction times relative to coal and nuclear
power plants, also means that the period over which it is important
to forecast the balance between demand and supply has drastically
decreased. While National Grid still makes such projections seven
years into the future, supply response times are now dramatically
shorter than this—usually 2-3 years.
B. FINANCIAL
COST AND
INVESTMENT CONSIDERATIONS
In this section we dwell particularly on the
potential for nuclear and micro-generation, both being areas where
the Sussex Energy Group has conducted substantial research.
Nuclear1[1]
With regard to nuclear new build, how realistic
and robust are cost estimates in the light of past experience?
What impact would a major programme of investment in nuclear have
on investment in renewables and energy efficiency?
The shape of the current UK debate about new
nuclear build is familiar. Climate change is serious; the UK wants
to reduce carbon emissions substantially as a result; the scope
for doing so via renewable energy, energy efficiency and carbon
capture has limits; UK nuclear capacity will keep falling; and
nuclear technology offers an established form of low-carbon energy.
Therefore, the argument runs, we need to re-invest in nuclear,
preferably soon.
There may be some economic problems to overcome
but decisive action on the part of Government could remove the
obstacles to a new "programme". Setting aside issues
of nuclear waste, the argument is a serious one and needs proper
scrutiny[2].
How serious are the economic and commercial obstacles to new build,
how might they be overcome and—often overlooked—what
would be the wider consequences?
Many commentators are now putting forward analyses
of the economic status of new nuclear build, usually with a comparison
of the status of alternatives, mainly gas-fired power and/or renewable
energy. The majority suggest that the generating cost of nuclear
power is similar to, or not much higher than, these alternatives.
This is new: when Government declared in its February 2003 White
Paper[3]
that nuclear was currently an uneconomic choice, no-one seriously
demurred. What has changed?
There have been two major changes in the last
two years. The first is that oil and gas prices have risen and
stayed high. If these price levels were to persist over the next
10-20 years, nuclear economics would clearly improve. The problem
for nuclear is that potential private investors in nuclear power
are unlikely to take a bet on oil and gas prices falling. So the
case for nuclear needs to rest primarily on the technology itself.
This is where the second change comes in. After deadlock for a
decade, a European country (Finland) has at last placed a real
order for a nuclear plant, and France has decided that it will
follow. Nuclear power now becomes a real prospect in Europe: if
Finland, why not the UK?
Uncertain economics
The most important single economic obstacle
to nuclear power is that no-one really knows what a new nuclear
plant would cost to build, and it will be impossible to know for
some time. Bearing in mind that the construction cost and time
of a nuclear plant are the single most important determinant of
the economics, this is a serious obstacle.
Most of the recent UK economic analyses—mainly
from nuclear vendors, financial institutions and consultants—start
by assuming a given construction cost for a plant. The numbers
range from a frankly optimistic figure of £850/kW (vendors'
estimate) to £1,625/kW from the consultants Oxera. [4]This
is quite an alarming range: at £850/kW nuclear is close to
economic; at £1,625/kW it is highly problematic. Some of
the differences between numbers are easily explained: the Oxera
number includes a range of real costs that are often ignored (eg
planning, licensing and first-of-a-kind costs). It also explicitly
refers to the first reactor that might be built; the vendor estimates
are commonly the expected cost of the eighth or tenth reactor,
or a "settled-down" cost, to which we return below.
But there are still serious differences in cost
estimates even after these factors are taken into account. These
represent the serious uncertainties that remain at the heart of
the economics of nuclear power.
There are perhaps two main contending designs
for new plant: the EPR from Areva in France and the AP1000 Westinghouse/BNFL
design. The EPR is the plant just starting to be built in Finland,
but neither design has yet been completed anywhere in the world.
This creates an immediate uncertainty. Further, neither design
has yet started to go through the UK safety licensing system,
and different licensing requirements in different countries lead
to different costs. UK history at Sizewell B is that UK licensing
requirements tend to be more onerous and costly than those of
other countries. This could be different in future, but again
no-one would expect an investor to risk much money on it. The
conclusion is clear: no single-number estimate of nuclear construction
cost in UK conditions has any real meaning.
The conventional answer to this uncertainty
is that big vendors or consortia are willing to take on these
financial risks of construction and—as is the case in Finland—offer
a fixed price, turnkey construction contract. This certainly transfers
the risk from the consumer back to the vendor, but it does not
remove it. If costs turn out to be higher than the fixed price
agreed, then vendors will not keep offering low, fixed prices.
In the late 1960s, GE and Westinghouse signed similar fixed price
deals on nuclear plant to US utilities for nuclear plant, only
to retreat into cost-plus contracts when they made big losses.
The same may not happen this time round—but it is possible.
Scale and scope of new nuclear
The other major issue in construction costs
is around scale and scope. Vendors argue, as they have for three
decades, that bigger is better in two senses. First, to minimise
cost, reactors have to be as big as possible—the EPR represents
1,600MW of power per unit, substantially bigger than any in the
UK. Second, a series of identical reactors needs to be built,
usually eight or 10. A first reactor, alone, will be seriously
uneconomic, on almost all analyses. The decision then is not whether
or not to try building a more or less novel reactor; it is whether
to commit to a programme of around a minimum of 10GW (representing
the capacity needed to meet around 20% of current UK maximum demand).
This is a game with high stakes.
Subsidy and competition
How could such a 10GW programme be delivered?
This is a large subject in itself but most commentators agree
that substantial Government intervention would be needed—to
underwrite construction costs, to ensure long-term electricity
sales contracts, and to cap long-term liabilities. These are all
technically feasible operations, but they would entirely undermine
the painfully constructed, and broadly competitive, wholesale
market for electricity.
This might be acceptable if climate change is
thought to be serious, but it throws up another potentially serious
obstacle. Non-nuclear electricity generators would be unlikely
to sit back and accept as reasonable the "state aid"
that Government support of this kind would involve. If BNFL and
the new Nuclear Decommissioning Authority can be subject to an
18-month European Commission inquiry when the potential threat
to fair competition is marginal, it is easy to imagine the scale
of an inquiry if 10GW of nuclear capacity were to be favoured
by Government on the scale needed. Such a state-aid case might
well be resolved in favour of the UK Government—state aid
is allowable if there are powerful reasons to do so—but
it represents another obstacle.
Impacts on other options
Further, and to finish, a large programme of
nuclear power would have other consequences, especially for other
means of reducing carbon emissions. The prime effect would be
"crowding out" other low-carbon investments, especially
renewable energy. There are at least three aspects to this. First,
there would be an opportunity cost in allocating public money
to nuclear at the expense of other options. Second, there would
need to be some restructuring of market and regulatory rules,
which might make it more difficult for decentralised options such
as renewables and CHP. Third, government intervention to support
nuclear would send a mixed signal, and would damage fragile investor
confidence with respect to renewables.
The nuclear choice, as currently presented,
is therefore of an essentially "all-or-nothing" character,
carrying large risks. The prospects for a real nuclear contribution
to reducing carbon emissions would be helped if a more flexible
and incremental case for nuclear investment could be plausibly
constructed.
We discuss the question of portfolios of generating
technologies in more detail below under "strategic aspects".
MICRO-GENERATION
What contribution can micro-generation make, and
how would it affect investment in large-scale generating capacity?
The following comments draw on our recent response
to the DTI's consultation on its micro-generation strategy[5].
The full consultation response is given at Annex A [not printed].
The DTI's decision to develop a micro-generation
strategy is welcome. The UK is in a strong position to become
a world leader in micro-generation technologies. Our research
shows that power exports to the grid from some technologies can
be significant. If these technologies are deployed in large numbers,
they could make substantial contributions to the supply mix. For
example, over a million household heating boilers are replaced
each year, representing a sizeable opportunity for the introduction
of micro-CHP: if 50% were replaced as micro-CHP units, this would
displace several hundred megawatts of central generation[6].
However, since many of these technologies are
at an early stage of development, a supportive policy framework
is essential to give micro-generation the opportunity to grow.
At the moment, the DTI bases its approach to micro-generation
on three types of barrier: cost, information and technical. While
these are important, this characterisation obscures some other
important barriers, particularly those that relate to: consumer
decision-making, current policies and regulations, and the fiscal
regime.
By way of illustration, there are fundamental
differences between the fiscal treatment of investments in energy
supply and investments on the customer's side of the meter—particularly
in domestic households[7].
Consumers have no access to tax or depreciation allowances for
investments in micro-generation, whilst companies investing in
central generation are able to take advantage of capital allowances.
Furthermore, consumers pay VAT (albeit at a reduced rate) for
their investments, whilst energy supply companies are able to
pass VAT on to consumers.
In brief, our research on the economics and
regulation of micro-generation raises the following implications
for policy:
— the government should consider setting
informed targets for the expansion of micro-generation, which
should be backed up by a package of policies to support deployment;
— creative approaches to technology
support should be considered including enhanced capital allowances
and the extension of the settlement system so that micro-generation
is given similar treatment to centralised energy investments and
business energy efficiency (see below for further discussion of
the settlement system issue);
— there is a need for schemes to provide
households with easy access to impartial information and skilled
installers to minimise the risks they perceive;
— energy service contracts could help
to expand the micro-generation market by providing access to capital.
The 28-day rule, which means that consumers can switch their energy
supplier every four weeks, should be abolished to enable this;
and
— metering should be upgraded when
micro-generation is installed to help provide consumers with access
to a range of energy services.
It is too early to say whether—and to
what extent—micro-generation will help to deliver all of
the four goals of UK energy policy as set out in the 2003 White
Paper: reducing carbon emissions, improving electricity reliability
and security, enhancing choice for consumers and reducing fuel
poverty. For example, there is not enough evidence to show that
some technologies (particularly micro-CHP) can deliver significant
carbon reductions when installed in an average household. This
evidence will not be available until the Carbon Trust field trials
have been concluded. It is also unclear whether micro-generation
will reduce the load on distribution networks. If most households
with micro-generation export some of their electricity, this might
make distribution network management more challenging, as discussed
next.
Impacts on the energy network
The impacts of micro-generation on energy networks—particularly
electricity distribution networks are contentious. A report for
the government by Mott MacDonald[8]
came to the broad conclusion that these impacts would be minimal
in the short-to-medium term except for a few exceptional geographical
areas. However, this conclusion is not shared by some distribution
network companies, who are predicting that integration might be
more problematic once micro-generation has grown beyond a certain
threshold.
The process of changing incentives for distribution
network companies so that they find it easier to integrate distributed
electricity generation sources has started, albeit slowly. The
recent implementation of the 2005 price control review includes
extra measures so that these companies can recoup some of the
additional investment associated with this. For micro-generation
however, the issues are different to larger distributed sources
such as wind farms and industrial CHP. The most important is the
need for simplicity. Whilst there are now connection standards
for micro-generation (which mean that electricity companies do
not have to inspect every installation), the process of registering
new installations is overly-complex (see Annex A for more on this
[not printed]).
Another important issue that will hamper the
future deployment of micro-generation is metering. Thoughts about
future metering arrangements for households should not only focus
on the requirements of micro-generation units. They should also
consider future consumer demands for broader energy services,
better pricing and more transparent bills. It is possible to install
micro-generation with a standard one-way meter, and Ofgem has
indicated support for this option since it can be implemented
at little or no cost (Ofgem, 2005)[9].
Despite this advantage, we believe that such a minimal approach
would represent a missed opportunity. The deployment of micro-generation
should be seen as an opportunity to kick-start the upgrade of
the UK's outdated stock of domestic meters.
As the government noted in their recent consultation
document, an import-export meter has the potential to allow consumers
a fair reward for the power they export to the grid. This is especially
the case if the meter can collect half-hourly data that can be
fed into a modified settlement system. This would mean that for
any power sold to the grid at peak times—when power is most
in demand and therefore most valuable—micro-generators would
receive substantially more than under a flat-rate scheme. This
obviously helps with the economics of micro-generation, and therefore
its likely uptake.
Going one step further, the installation of
a third meter, to measure generation, would also allow those with
renewable micro-generation units to claim renewable obligation
certificates (ROCs). The upgrade of metering so that it has these
capabilities should be mandatory when a micro-generation unit
is installed. Whilst this approach is more expensive than requiring
a simple one-way meter, the cost differential is likely to fall
as micro-generation deployment increases. In general the additional
up-front costs for import-export meters and even import-export-generation
meters are very small in relation to the total investment costs.
The changes suggested here would introduce greater
transparency and fairness into the rewards given to micro-generators
and, combined with the measures suggested earlier, would help
to level a playing field that is currently heavily slanted against
micro-generation and in favour of centralised large-scale power
production. If government is serious about micro-generation it
needs to implement these sorts of measures; only then will it
given the opportunity to make a substantial contribution to UK
energy supplies.
C. STRATEGIC
ASPECTS
In this section we will discuss two strategic
aspects: security of supply, and the need for a portfolio approach
to investments in the power sector.
Security of energy supply
Perhaps surprisingly, security of energy supply
has not received much robust analytical attention. It has many
dimensions, including timescale, various sources of insecurity
and then some wider dimensions of security. Although it is a vitally
important issue, the label "security of supply" is often
appropriated by those with a particular vested interest, often
in a supply technology or fuel whose costs are too high for the
private market to support.
Timescales
In terms of timescale, there are short-term
concerns (will we get through next winter without power cuts?)
and long-term (will we have supplies of fossil fuels at affordable
prices?), as well as the question of the lead times required for
infrastructure investment, as discussed above. The economic, social
and environmental characteristics of the energy system we are
putting in place now clearly also have substantial implications
for future generations' choices.
Sources of insecurity
Then there are concerns around various sources
of insecurity. The principal ones are around: supply; technology;
and networks.
Concerns around supply include: interruptions
to the supply of individual primary fuels (gas, oil etc.); the
range of fuels; and securing appropriately diverse sources of
these fuels.
Too much public debate reduces security to the
issue of reliance on imports, and poses an apparently stark choice
between indigenous energy (secure) and imported energy (insecure).
Imported energy may be more or less secure than indigenous energy,
but in the face of declining domestic availability of gas and
oil, imports are as likely to be a part of the solution as a cause
of problems. [10]
All else equal, a diversity of supply sources
will lead to greater security, not less. And trade, normally a
major objective of economic policy, usually benefits both parties,
rather than one. Policy still needs to pay attention to the security
of individual supply sources, and heavy reliance on one distant
source of natural gas may increase insecurity. But every other
major European country imports substantial quantities of its primary
energy and while this does raise security issues, it does not
dominate their energy policy agenda. Potential problems of energy
insecurity need to be analysed across all possible sources and
need an empirical answer, not pre-judgement.
Concerns around technology and networks include:
lack of integrity of infrastructures (eg gas terminals, electricity
wires), and common-mode failures in energy technologies (eg in
nuclear power). As demonstrated by the fuel protests several years
ago, our reliance on the efficient, "just-in-time" working
of the fuel infrastructure and the relative lack of redundancy
in the system mean that security of supply could be at least as
threatened by the shutting of, for example, a major gas terminal
as any of the other potential problems identified here. And all
the major electricity supply interruptions in recent years in
industrial countries (eg California, New York, Italy and, on a
smaller scale, London) originated in faults in the transmission
or distribution systems (wires). Inadequate investment in and—especially—maintenance
of electricity transmission and distribution systems are potentially
major sources of serious insecurity. Bearing in mind that gas
and electricity transportation are natural monopolies and therefore
subject to economic regulation, regulatory practice needs to pay
close attention to the incentives it gives for adequate investment
and maintenance.
Similarly, should a widely used technology develop
a generic fault, it could cause significant problems for security
of supply. France's reliance on one design of nuclear power plant
is a case in point, although we should stress that no problems
have emerged yet.
Wider dimensions of security
Finally, some wider dimensions of security are
increasingly significant, including concerns around terrorism,
vulnerability, health and environment.
Terrorism—now a major part of Government's
overall policy agenda—could have an impact through several
of the above processes, especially perhaps by attacking infrastructures.
These could be overseas infrastructures but insofar as terrorism
may target particular countries, indigenous infrastructures could
also be a target. Certain supply technologies are potentially
particularly attractive as a target of terrorist action while
others are innately less vulnerable. These are dimensions of security
that are rarely considered in the context of energy policy.
http://politics.guardian.co.uk/green/story/0,9061,1576317,00.html
and on BBC online see
http://news.bbc.co.uk/1/hi/sci/tech/4284502.stm
PORTFOLIO PERSPECTIVES
The second strategic aspect of energy policy
that we address here is the need for policy-makers to adopt a
portfolio perspective in decisions around the mix of energy supply[11].
The need for this perspective can be illustrated
through the following example from another field: why do investors
often hold forms of investment, such as government bonds, that
apparently offer lower rates of return than other investments
such as shares? The answer can be found in finance theory, specifically
portfolio theory. These well-founded and widely used ideas and
associated techniques show that for any given level of risk, a
diverse portfolio will be lower cost (or more profitable) than
a portfolio that is dominated by one sort of investment. Financial
investors deal with market risk by holding efficient, diversified
portfolios.
Unfortunately, electricity planning has long
relied on the stand-alone generating costs of various technologies;
this measure is inadequate. This is because these cost estimates
focus on the engineering/construction aspects and fail to analyse
their market risk over the life cycle. In this way, they
lack economic interpretation.
Instead, we suggest that policy towards electricity
investment should take account of modern portfolio theory concepts,
which reflect costs but also the risk contribution a given
generating technology makes to the generating mix. Our application
of portfolio techniques to the energy system consistently shows
that when added to a conventional generating mix, wind and other
renewables serve to lower overall generating costs. This outcome,
which is predicted by finance theory, holds even if it is assumed
that the stand-alone costs of wind exceed those of gas-based generation.
Why should this be so?
The explanation starts from the fact that the
costs of wind and other renewables technologies are largely fixed
and predictable, so they add an element of stability to the portfolio.
Even more important, the costs of these technologies are also
independent of (technically "uncorrelated with") fossil
fuel costs, further reinforcing their stabilising effects by reducing
the risk and expected cost of the overall portfolio. This result
is exactly analogous to diversifying financial portfolios. Similar
effects would apply to nuclear investment, but—as argued
earlier—there are sizeable and nuclear-specific barriers
to new nuclear investment in the UK.
We also question the idea that gas-based generation
is, on a stand-alone basis, cheaper than, for example, wind. Finance
theory shows that when fuel price volatility of eg gas-based electricity
generation is taken into account, the overall risk-adjusted cost
of these technologies is much more than suggested by the standard
engineering-based estimates. Only by making such risk adjustments
can one arrive at a meaningful estimate of overall costs.
In the annex, we show that using portfolio techniques,
and based on the DTI's target 2010 overall generating cost, it
would be possible in principle to increase wind's share of the
total from the DTI's aspiration of 11% to as much as 54%. Similarly,
holding the risk profile constant, it would be possible to increase
the share of wind to 31% while decreasing the overall generating
cost from 2.96p/kwh to 2.49p/kwh. These are of course modelling
results and wind investment is constrained by many other factors,
but they strikingly illustrate the very different results, compared
to stand-alone analyses, that portfolio approaches yield.
Energy security—the oil-GDP effect
The "oil-GDP effect" provides a further
reason to wish to invest in fixed-cost renewables. Our analysis
shows that fuel price volatility, and over-reliance on fossil
fuels, imposes costs not just on generating technologies but on
society more generally.
This is because oil price increases and volatility
dampen macroeconomic growth by raising inflation and unemployment
and by depressing the value of financial and other assets. This
oil-GDP effect has been reported in the academic literature for
a quarter of a century, although it received little attention
from the media and energy policy makers prior to the recent oil
price spikes. The Oil-GDP effect is sizeable. In a recent paper,
members of the Sussex Energy Group[12]
estimated that a 10% increase in the global share of wind (or
other renewables) could help to avoid GDP losses of $95-$176 billion
as a result of lower fossil fuel costs.
Annex A
SUSSEX ENERGY GROUP RESPONSE TO GOVERNMENT
CONSULTATION ON MICRO-GENERATION
See separate file. [not printed]
Annex B
VALUING GENERATING ASSETS IN AN ENVIRONMENT
OF UNCERTAINTY AND TECHNOLOGICAL CHANGE
Shimon Awerbuch, PhD, Senior Fellow,SPRU Energy Group,
University of Sussex,Brighton, UK
www.awerbuch.com, s.awerbuch@sussex.ac.uk
Electricity capacity expansion questions currently
focus on two principal issues:
(i) The kilowatt-hour cost of renewables
such as wind, relative to the cost of gas turbines and, potentially,
nuclear power; [13]and
(ii) How our century-old electricity grid
might be contorted into dealing with the so-called intermittency
of wind and other renewable technologies.
In this submission I argue two principal points.
First, that while electricity planning has long relied on the
stand-alone generating costs of various technologies, this
measure is no longer relevant. In its place, I suggest that electricity
policy be based on modern portfolio theory concepts, which
reflect the cost as well as the risk contribution a given generating
technology makes to the generating mix. Financial investors routinely
use portfolio optimisation techniques to value stocks and other
additions to their holdings. These techniques consistently show
that when added to a conventional generating mix, wind and other
fixed-cost renewables serve to lower overall generating costs.
This outcome, which is predicted by finance theory, holds even
if it is assumed that the stand-alone costs of wind exceed those
of gas.
Second, I argue that the current debate about
the system integration costs of wind and other variable output
renewables is largely misplaced. This debate conceives of wind
as a direct substitute for dispatchable fossil technologies, which
it is not. As a consequence, the debate needlessly dwells on such
issues as the cost of additional backup generating capacity. In
my opinion, efficiently integrating wind and other new, passive,
variable-output renewables will ultimately require changes our
current electricity production-delivery paradigms and protocols.
This is a tall order. At the very least, integration will require
new parallel in-formation networks for the electricity
grid and most likely new ways of charging for grid services. These
must allow wind-based electricity products such as space
and water heating, which naturally match this "intermittent"
technology with so-called "dispatchable" load applications.
The century-old concept of the grid as a system for transporting
commodity electrons becomes obsolete in an environment characterised
by many distributed generating sources and a diversity of load
applications.
1. THE COST
OF RENEWABLE
AND CONVENTIONAL
TECHNOLOGIES
Electricity policy and planning decisions should
not be made on the basis of traditional engineering kilowatt-hour
(kWh) cost models. Such models, developed around the time of the
Model-T Ford, have been widely discarded in most industries in
favour of modern asset valuation concepts.
My own stand-alone kWh cost estimate, which
have remained quite constant over the last decade, use a standard
(CAPM) finance-oriented approach that reflects the cost of risk.
Through periods of both low and high fossil prices and money-market
rates, [14]these
estimates have consistently suggested that gas generation costs
more than wind and many other renewables (eg Awerbuch June 2004,
June 2003, May 2003, February 2003, November 2000, April 1995,
1993). This is in stark contrast to estimates prepared by the
DTI (2003), the Royal Academy of Engineering, the IEA (2005) and
other national and international agencies, which generally find
that gas costs less than wind. These agencies however, use calculative
procedures that produce cost results with no economic interpretation;
they should not be given any weight in policy-making.
Fossil fuel prices have risen significantly
over the last two years and some predict oil-price spikes in excess
of $100/bbl (Reuters, 2005). Finance theory tells us that future
cost streams can be meaningfully expressed only in terms of their
market risk. When fuel price volatility is considered, gas-based
generation is noticeably more costly than standard engineering-based
estimates indicate. For example, conventional estimates such as
those produced by DTI and IEA suggest that gas-based electricity
costs in the range of
0.03-
0.05/kWh. The true, risk-adjusted cost is quite likely
in excess of
0.06-
0.07/kWh, making many renewables generally competitive.
[15]
2. EXTERNALITY
BENEFITS OF
WIND: ENHANCING
COST AND
ENERGY SECURITY
Risk-adjusted CAPM procedures more reliably
estimate the cost of gas and wind. But even CAPM results are only
as good as the underlying gas price forecasts, which could dramatically
change even before this inquiry is concluded. Meaningful kWh cost
estimates require unbiased gas price forecasts. But history
provides little comfort that today's fossil price forecasts will
be any more reliable than those of the past. Nonetheless, suppose
we assume for the moment that the conventional analyses—which
predict that gas generation costs less—are correct. Does
this imply that we should abandon wind and other options and invest
only in gas? This is the traditional "least-cost" approach
to energy investment decision-making. It makes little sense in
today's highly uncertain energy environment.
Energy planners need follow financial investors,
who are used to dealing with risk. No one can predict the performance
of a corporate share of stock over 20 years just as no one can
predict the price of gas. Financial investors deal with market
risk by holding efficient, diversified portfolios. These offer
the best hedge against an uncertain future. Prudent investors
do not try to chase today's best performing securities; these
may be the laggards of tomorrow. Rather, they balance their portfolios
with a mixture of potentially high yielding securities along with
low-yielding government obligations and similar "safe"
investments. Policy makers must take note of this important idea.
It matters little that gas might appear to be the lowest cost
alternative (on the basis of conventional costing models). Even
if correct today, that picture could change dramatically, suggesting
that electricity planning and energy policy making in general
must abandon its fixation with identifying alternatives with the
lowest stand-alone cost and focus instead on developing optimal
generating portfolios and strategies.
When added to a risky, fossil-dominated generating
mix, wind and other fixed-cost renewables reduce generating cost
and risk, as long as the mix can be altered over time [Awerbuch
2005, February 2000, 1995, Awerbuch and Berger 2003]. This so-called
portfolio effect, (eg see Brealey and Myers, 2003) holds even
if wind costs more on a stand-alone basis. Wind's generating costs
are uncorrelated to fossil costs which means that it diversifies
the mix and reduces expected overall cost and risk the same way
diversification improves the expected performance of financial
portfolios.
For example, DTI's Year-2010 target generating
mix (DTI, 2004, 2003) has an overall cost of 2.96 p/kWh (Table
1). It consists of 71% fossil generation and 11% wind. By contrast,
applying the same generating costs, it is possible to identify
a number of optimised UK portfolios[16]
which cost no more, but have wind shares of 31% to as much as
54%—three to five times as much wind as the DTI target mix.
The "Equal Cost" portfolio, (Table 1) has the same cost
but lower risk than the DTI target mix, yet contains 31% offshore
wind, in spite of the fact that this technology is assumed to
cost 75% more than gas. [17]
Table 1
DTI TARGETS VERSUS OPTIMISED GENERATING PORTFOLIOS
(UK 2010)
| DTI 2000-2010 Technology Generating Costs (p/kWh): Coal: 4.0/3.6—Gas: 2.0/1.9—Wind: 2.7/2.0—Offshore: ¸/3.6 |
| | |
|
|
Typical Optimised Portfolios |
|
DTI 2010 |
|
|
Target Portfolio |
"Equal Cost" | "Equal Risk" |
| Portfolio Cost | 2.96 p/kWh
| 2.96 p/kWh | 2.49 p/kWh
|
| Portfolio Risk |
.08 |
.04 |
.08 |
| Fossil Share |
71% |
32% |
52% |
| Nuclear Share |
16% |
12% |
14% |
| Wind Share |
On-shore: 11% Offshore: 0% |
On-shore: 25% Offshore: 31% |
On-shore: 31% Offshore: 0% |
| Source: Awerbuch Airtricity (2005) |
| | |
| |
| |
These results are not meant to suggest that 50% wind shares
are feasible given today's network architecture, or even that
such a target cold be attained in five years. The results are
presented to illustrate that stand-alone costs, even if adjusted
for risk, are not necessarily a meaningful metric for evaluating
energy options. Because various technology costs move in unison,
(eg are correlated), intelligent energy strategy, by necessity,
requires that cost interrelationships be considered. Electricity
capacity planning must reflect the cost and risk of the overall
portfolio.
The UK results shown above are representative of similar,
and in some ways even stronger results I have obtained for the
US, the EU, as well as Mexico, Morocco, and other nations (Awerbuch,
2005, Awerbuch, Jansen and Beurskens, 2003). The portfolio approach
illustrates the idea that increasing the deployment of wind, even
if it is assumed to cost more, does not necessarily raise overall
generating cost, as long as the generating mix can be re-optimized
over time. Wind production costs are relatively fixed. This creates
important cost-risk benefits for generating portfolios.
Energy Security—The Oil-GDP Effect
Oil price increases and volatility dampen macroeconomic growth
by raising inflation and unemployment and by depressing the value
of financial and other assets. This so-called Oil-GDP effect
has been reported in the academic literature for a quarter
of a century, although it received little attention from the media
and energy policy makers prior to the recent oil price spikes.
The Oil-GDP effect is sizeable. In a recent paper Raphael Sauter
and I (2005) estimate that a 10 percentage-point increase in the
global share of wind (or other renewables) can help avoid GDP
losses of $95-$176 billion (Table 2).
Table 2
WIND DEPLOYMENT OFFSETS SIZEABLE MACROECONOMIC OIL-GDP
LOSSES
AVOIDED GDP LOSSES FOR 10-PERCENTAGE-POINT INCREASE IN
THE WIND GENERATION SHARE (USD $BILLIONS)
| | US | EU-15
| OECD | World
|
| 2003 GDP | $10,882 |
$10,970 | $18,659 | $36,356
|
| Avoided GDP Losses
| | |
High Estimate | $53 |
$53 | $90 | $176
|
| Low Estimate | $29 | $29
| $49 | $95 |
| Source: Awerbuch and Sauter, 2005
| | |
| |
| | |
These avoided losses offset 20% of the renewables investment
needed to meet 2020 EU RES-E targets and 40% the OECD requirements.
Our analysis suggests that each additional kW of wind helps society
avoid $250 in GDP losses. Stated differently, avoided GDP losses
offset 20-25% of today's investments in wind and other renewables.
Energy security is enhanced when nations hold optimal generating
mixes that minimize exposure to fossil volatility. As the last
two sections have described, wind and other renewables provide
a joint set of benefits: they enhance energy diversity/security
while they reduce overall generating costs (Awerbuch, Stirling,
Jansen and Beurskens 2006).
3. MODERNISING POWER
NETWORKS TO
ACCOMMODATE 21ST
CENTURY NEEDS
Widespread debate prevails about how to manage wind's variable-output[18]
and how to make it fit into today's electricity production-delivery
system, designed over a century ago for dispatchable, fossil-fired
central station generation. Had a different generating technology
emerged in the 1890's, it would have no doubt given rise to a
different set of network system architecture and protocols. But
we are stuck with our system—at least for time being. System
engineers have been weaned on dispatchable technologies with central
control. It is difficult for them to imagine anything else: they
see the challenge as making wind fit into the system. I see the
challenge as rearranging the electricity production-delivery paradigm
to accommodate a variety of 21st Century needs, including the
integration of wind and other variable-output sources.
Many new process technologies have faced significant impediments
to their integration and were fully exploited only after underlying
systems and infrastructures were extensively modified. We tend
to conceptualise new technologies in terms of the capabilities
and functionalities of the previous vintages that we better understand.
This was true for word processing, which was initially conceived
merely as a replacement for the typewriter, and is true for wind.
How do engineers want to integrate wind? By making it act like
a gas turbine (as much as possible) so it can be centrally dispatched
by the control room operator, just the way it has been done for
a nearly a century. Fully integrating wind will likely require
new approaches, including different system architecture and protocols
and powerful parallel information networks to manage electricity
grids in a decentralized, market-responsive manner.
We need to alter the electricity production-delivery system
to better accommodate 21st century needs and capabilities. This
involves adopting mass-customisation concepts from manufacturing
and moving decision making to loads, which have better information
about their hour-to-hour requirements than a central dispatcher.
At any moment, the system's total load consists of thousands of
transactions, each with a different value. Electricity to power
water pumping or heating likely does not have the same value as
electricity required for microchip processing (Awerbuch, March
2004, July-August 2004). Adapting to these realities will yield
a more efficient, more market-oriented production-delivery paradigm
under which the network operator becomes the electricity market
enabler. The traditional transportation function of the network
becomes obsolete in an environment characterized by a large number
of distributed resources.
Today's network is based on outmoded mass-production concepts.
Electricity mass customisation will allow users to take
power in the forms that best match their various applications.
Implementing these ideas requires new strategies for regulating
network system operators, who hold a key position in an electricity
system that has been partially deregulated in the belief that
markets, not regulation, produce the greatest efficiency (Awerbuch,
Hyman, Vesey, 1999, Chap 3). Yet the system operator continues
as a monopoly entity with no incentives to create new market-driven
products or to diversify the mix to broaden consumer access to
competitively priced supply markets that include traditional generation
along with wind and other renewables.
Policy-makers correctly focused on deregulating generation
first. Much of the potential benefit of those policies however
is lost because the essential market facilitator, the transmission
operator, is naively conceived as a caretaker of the wires with
no incentive to enhance overall system performance. Efficient
integration and exploitation of wind may have to wait until policy-makers
focus on the governance, organization, regulation and pricing
structures of electricity networks.
4. CONCLUSIONS
CAPM-based risk-adjusted procedures suggest that at currently
projected gas prices, wind and other fixed cost renewables are
likely to provide electricity at lower cost. Moreover, when added
to fossil-dominated generating mixes, fixed-cost renewable technologies
reduce cost at any level of risk by virtue of the portfolio-effect.
This holds even if they are assumed to cost more on a stand-alone
basis.
Wind and similar fixed-cost technologies enhance energy security
and their deployment will help the UK avoid costly macroeconomic
(GDP) consequences induced by oil price volatility. Every kW investment
in wind offsets $250 USD in oil-induced GDP losses. The benefits
of wind and other renewables are strong, verifiable and highly
certain. Our challenge is to re-engineer the electricity production-delivery
paradigm so it efficiently integrates variable-output renewables
and meets other 21st century requirements.
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3 October 2005
1 This section is largely based on G MacKerron "What
price another?" Parliamentary Brief Energy Special
Report, September-October 2005, pp 11-12. Back
2
G MacKerron "Nuclear power and the characteristics of `ordinariness':
the case of UK energy policy" Energy Policy, 32:17,
November 2004, pp 1957-1966. Back
3
DTI Our Energy Future: Creating a Low-Carbon Economy February
2003. Back
4
Oxera Financing the nuclear option: modelling the costs of
new build Agenda, June 2005, Table 1. Back
5
For coverage of these ideas in the Guardian see Back
6
The precise "capacity credit" of micro-generation would
depend on the technology and the operating regime. Some initial
estimates can be found in Hawkes, A and Leach, M (2005) The
Capacity Credit of Micro Combined Heat and Power in the UK Proceedings
of the BIEE Academic Conference, Oxford 22-23 September. Back
7
Chesshire, J (2003) Energy Efficiency Projects and Policies
for Step Changes in the Energy System: Developing an Agenda for
Social Science Research, ESRC Seminar, Policy Studies Institute,
March. Back
8
Mott MacDonald (2004) System Integration of Additional Micro-generation
Report to the DTI. Back
9
Ofgem (2005) The regulatory implications of domestic-scale micro-generation-a
consultation document Ofgem, April. Back
10
A very good exposition of this and other views of the security
debate with respect to gas is J Stern "UK gas security: time
to get serious" Energy Policy 32:17, November 2004,
pp 1967-1979. Back
11
This section is a summary of fuller arguments made in Annex B. Back
12
Awerbuch, S and Sauter, R. (2005), "Exploiting the oil-GDP
Effect to support Renewables Deployment," Energy Policy,
articles in press, 21 June. Back
13
This is not to say that other issues, such nuclear waste are
not also prominent. Back
14
Inflation expectations and money-market rates underlie CAPM-based
discount rates. Back
15
The cost advantage of wind survives when system integration charges
are added, eg per Dale, et al (2004) or the DENA Grid Study
(2005). Back
16
An infinite number of such portfolios exist, all with different
cost-risk and different technology shares. Back
17
This study focuses on wind. Nuclear output is constrained so
it does not exceed 2004 levels. Back
18
The concept of wind intermittency is misleading. Wind
blows a high percentage of the year, at least at better sites,
although its force varies so that output is variable. There are
very few days when wind ceases entirely implying that variable-output
is a better concept. Back
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