Renewable energy: the key to ensuring energy security in Harare

SAMANTHA ÖLZ, RALPH SIMS
AND NICOLAI KIRCHNER
INTERNATIONAL ENERGY AGENCY
© OECD/IEA, April 2007
CONTRIBUTION OF
RENEWABLES TO
ENERGY SECURITY
INTERNATIONAL ENERGY AGENCY
AGENCE INTERNATIONALE DE L’ENERGIE
IEA INFORMATION PAPER

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Table of contents
Acknowledgements………………………………………………………………………………………………… 3
Foreword ……………………………………………………………………………………………………………… 5
Executive Summary……………………………………………………………………………………………….. 7
1. Risks to energy security ………………………………………………………………………………….. 13
1.1 Risks for developing countries………………………………………………………………….. 15
1.2 Policy responses to energy security risks …………………………………………………… 15
1.3 Energy security implications of renewable energy technologies……………………… 16
2. Current energy use by market segment……………………………………………………………… 19
2.1. Electricity production ………………………………………………………………………………. 19
2.2. Heat …………………………………………………………………………………………………….. 21
2.3. Transport………………………………………………………………………………………………. 22
3. Renewable energy technologies in the energy mix and effects on energy security……. 23
3.1. Electricity production and the impact of variability………………………………………… 23
3.1.1 Contribution of renewable energy technologies to electricity production ………. 26
3.1.2 Security effects of grid integration of renewables……………………………………… 28
3.1.3 The physical security advantages of renewable electricity generation …………. 33
3.1.4 Summary…………………………………………………………………………………………… 35
3.2. Heat production……………………………………………………………………………………… 36
3.2.1. Contribution of renewable energy technologies to heat production in OECD
countries……………………………………………………………………………………………………….. 37
3.2.3 Regional dimension of renewable heating – energy security implications …….. 46
3.2.4 Local resources and global trade – implications for energy security…………….. 47
3.2.5 Effects of renewable heating on fossil fuel demand ………………………………….. 48
3.2.6. Challenges and barriers……………………………………………………………………….. 49
3.2.7. Summary…………………………………………………………………………………………… 50
3.3 Biofuel production for transport……………………………………………………………………. 51
3.3.1 Current role of biofuels worldwide………………………………………………………….. 54
3.3.2 Fuel standards and engines………………………………………………………………….. 58
3.3.3 Economic feasibility …………………………………………………………………………….. 58
3.3.5 Summary…………………………………………………………………………………………… 63
4 Conclusions…………………………………………………………………………………………………… 64
5 References……………………………………………………………………………………………………. 66
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Acknowledgements
The main author of this paper is Samantha Ölz, Policy Analyst with the Renewable Energy
Unit (REU) of the IEA. The contributing authors are Ralph Sims, Senior Analyst with the
REU and Nicolai Kirchner, formerly with the REU. Antonio Pflüger, Head of the Energy
Technology Collaboration Division of the IEA, and Piotr Tulej, former Head of the REU,
provided valuable guidance on the structure of the paper. The authors would also like to
thank Hugo Chandler, Frieder Frasch, Nobuyuki Hara, Neil Hirst, Cédric Philibert, Antonio
Pflüger, Daniel Simmons, Ulrik Stridbaek, Noé van Hulst (IEA) and Piotr Tulej for their
incisive comments and suggestions throughout the drafting of the paper.
IEA Renewable Energy Working Party delegates and Implementing Agreement Executive
Committee members provided invaluable input with substantial technical advice and market
data. Helpful suggestions from the REN21 (Renewable Energy Policy Network for the 21st
Century) Secretariat and REN21 Steering Committee members are also much appreciated.
This paper was prepared for the Renewable Energy Working Party in March 2007. It was drafted by
the Renewable Energy Unit within the Energy Technology Collaboration Division. This paper reflects
the views of the IEA Secretariat and may or may not reflect the views of the individual IEA Member
countries. For further information on this document, please contact Samantha Ölz of the Energy
Technology Collaboration Division at: Samantha.Olz@iea.org
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Foreword
The environmental benefits of renewable energy are well known. But the contribution that
they can make to energy security is less widely recognised. This report aims to redress the
balance, showing how in electricity generation, heat supply, and transport, renewables can
enhance energy security and suggesting policies that can optimise this contribution.
For those countries where growing dependence on imported gas is a significant energy
security issue, renewables can provide alternative, and usually indigenous, sources of
electric power as well as displacing electricity demand through direct heat production.
Renewables also, usually, increase the diversity of electricity sources, and through local
generation, contribute to the flexibility of the system and its resistance to central shocks.
This makes it all the more important to pursue policies for research, development and
deployment (RD&D) that can progressively reduce the costs of renewables so that, with
appropriate credit for carbon saving, they can be established as technologies of choice.
Attention has focused disproportionately on the issue of the variability of renewable
electricity production. This only applies to certain renewables, mainly wind and solar
photovoltaics, and its significance depends on a range of factors – the penetration of the
renewables concerned, the balance of plant on the system, the wider connectivity of the
system, and the flexibility of the demand side. Variability will rarely be a bar to increased
renewables deployment. But at high levels of penetration it requires careful analysis and
management, and any additional costs that may be required for back-up or system
modification must be taken into account.
The direct contribution that renewables can make to domestic or commercial space heating
and industrial process heat deserves much more attention than it has so far received. Heat
from solar, and geothermal sources, as well as heat pumps, is increasingly cost effective but
often falls through the gap between government programmes that promote public awareness
and provide incentives for renewable electricity and energy efficiency. We urge that greater
focus be given to this topic.
The IEA’s World Energy Outlook 2006 concludes that rising oil demand, if left unchecked,
would accentuate the consuming countries’ vulnerability to a severe supply disruption and
resulting price shock. Biofuels for transport represent a key source of diversification from
petroleum. Biofuels from grain and beet in temperate regions have a part to play, but they
are relatively expensive and their benefits, in terms of energy efficiency and CO2 savings,
are variable. Biofuels from sugar cane and other highly productive tropical crops are
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substantially more competitive and beneficial. But all first generation biofuels ultimately
compete with food production for land, water, and other resources. Greater efforts are
required to develop and deploy second generation biofuel technologies, such as biorefineries and ligno-cellulosics, enabling the flexible production of biofuels and other
products from non-edible plant materials.
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Executive Summary
“Ministers and Government Representatives from 154 countries gathered in Bonn,
Germany, June 1-4, 2004, for the International Conference for Renewable Energies,
acknowledge that renewable energies combined with enhanced energy efficiency, can
significantly contribute to sustainable development […] creating new economic
opportunities, and enhancing energy security through cooperation and
collaboration.”
Political Declaration, renewables2004 – International Conference for Renewable
Energies Bonn 2004
Providing energy services from a range of sources to meet society’s needs should ideally
provide secure supplies, be affordable and have minimal impact on the environment.
However these three government goals often compete.
Security of energy supply is a major challenge facing both developed and developing
economies since prolonged disruptions would cause major economic upheaval. Security
risks include the incapacity of an electricity infrastructure system to meet growing load
demand; the threat of an attack on centralised power production structures, transmission
and distribution grids or gas pipelines; or global oil supply restrictions resulting from political
actions. Extreme volatility in oil and gas markets can present a security risk. Overall, the
picture is complex: In many circumstances diversifying supply, increasing domestic supply
capacity using local energy sources to meet future energy demand growth, and demand
reduction can all make positive contributions to energy security.
This paper focuses on the contribution of renewable energy technologies to energy security.
It does not consider other options relating to energy security and the environment, such as
nuclear energy, coal, including carbon dioxide capture and storage, oil supply and cost
predictions, or natural gas distribution. It assesses opportunities presented by renewable
energy technologies (RETs)1
to mitigate risks to energy supply, such as:
• market instabilities;
• Technical system failures; and
• Physical security threats including terrorism and extreme weather events.
The paper recognises that some features of renewable energy systems can, however, also
carry security risks if not adequately addressed.

1
The IEA’s definition of renewable energy sources includes energy generated from solar, wind, biomass, the
renewable fraction of municipal waste, geothermal sources, hydropower, ocean, tidal and wave resources, and
biofuels.
Energy
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Energy supply and environmental impacts
Widely fluctuating oil and gas commodity prices have impacts on world economies,
particularly developing countries. Low-income economies that import fossil fuels are
particularly vulnerable to price increases which can badly affect their balance of payments
and increase their vulnerability (ESMAP, 2005b).
Electricity accounts for around 17% of global final energy demand, low temperature heat
44% (of which traditional biomass used for heating and cooking in developing countries has
a significant share), high temperature industrial process heat 10%, and transport fuels 29%
(IPCC, 2007).
Renewable energy can contribute to the security of supply of all these energy forms and in
addition reduce greenhouse gas (GHG) emissions when displacing fossil fuels. This makes it
all the more important to pursue policies for research, development and deployment (RD&D)
that can progressively reduce the costs of renewables so that, with appropriate credit for
carbon saving, they can be established as technologies of choice (Figure 1).
Figure 1: Cost-competitiveness of selected renewable power technologies, before
credit for carbon savings Wholesale Power Price Retail Consumer Power Price
10 20 30 40 50 Power Generation Costs
in USD cents / kWh
Small Hydro
Solar Photovoltaics
Concentrating Solar
Biomass
Geothermal
Wind
Source: IEA, 2006f

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Nevertheless, the implications of renewables for energy supply security differ between the
electricity, heat and transport sectors.
Electricity: Introducing a broad portfolio of renewable energy – hydro, geothermal,
bioenergy, solar and wind energy – generating plants into the system, and establishing a
decentralised power generation system can provide more security, especially where many
small to medium generating plants can be located close to the load.
Renewables can reduce geopolitical security risks by contributing to fuel mix diversification.
Their risks are different from those of fossil fuel supply risks, and they can reduce the
variability of generation costs. In addition, indigenous renewables reduce import dependency.
Biomass can be an exception although imported bioenergy feedstocks usually diversify import
portfolios.
Some renewable energy technologies (RETs) such as hydro, wind, solar photovoltaics (PV),
tidal depend on different natural cycles and are therefore subject to variability on differing
timescales. This has to be taken into account in considering security. While large hydro,
bioenergy, geothermal resources and concentrating solar power (CSP) plant offer
comparable levels of firm capacities to conventional fossil fuel based plant, solar PV
applications, wind and possibly small hydro resources (and wave energy resources in the
future) are more variable. These characteristics may affect the degree to which some RETs
will be able to displace fossil fuel and nuclear generating capacity. At high penetrations
these characteristics will pose new challenges in the stability, reliability and operation of
electricity grids. The direct effects of an increasing share of variable RETs depend on the
balancing options. Options sometimes exist to balance the grid using a mix of RETs with
different natural cycles, reducing the need for back-up capacity. For instance, large hydro
can complement wind power. In such circumstances, RET installations can therefore be built
to meet increasing power demand or replace existing power plants at the end of their life,
reducing investment in fossil-fuelled power plants and possibly also in the distribution
infrastructure. Nevertheless, appropriate grid management strategies and investments in
back-up capacity and demand-side management may be necessary to absorb the largescale grid integration of variable renewables. The additional costs for grid back-up and/or
electricity storage and spinning reserve have to be taken into account (Swider et al., 2006;
Meibom et al., 2005)2
.

2
Flexible measures to absorb the fluctuations in wind power production are required as the grid penetration of
wind power increases. Recommended integration measures include the use of electrically operated heat pumps
in CHP systems which can provide relatively cheap optional demand (Holttinen et al., 2005; Meibom et al., 2005).
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RET installations have the advantage of being flexible with regard to the scale of plant size
and to the possibility of integrating them either into the transmission or the distribution
systems. These characteristics yield positive effects for physical aspects of energy security.
Heat: Deploying renewable heating and cooling technologies can reduce energy security
supply risks for the same reasons as in the electricity sector. Many biomass, solar thermal
and geothermal heat applications have already reached or are close to competitiveness with
heat production from fossil fuels. A major barrier to their market is consumers’ lack of
awareness of the range of available heating options. Nevertheless, renewable heating (and
to a lesser extent cooling) provide energy security benefits as a result of distributed supply
and also reduce greenhouse gas (GHG) emissions, and can reduce pressure on electricity
transmission systems.
The energy security advantages of renewable heat production can be substantial when
large-scale market deployment is achieved. Governments should develop and implement a
support framework of enabling policy measures, including market-based financial incentives.
These could build upon the lessons learned from support policies for renewable electricity
production. Extensive information dissemination programmes to inform the public about
viable alternative heating technologies could be beneficial.
Biofuels: The production of liquid transport fuels from a range of biomass resources is
growing. Many governments perceive biofuels as a part solution to the high dependence on
imported oil, the need for GHG mitigation and clean air targets, and the increasing costs of
foreign exchange expenditure from relatively high gas and oil prices. Biofuels can help
reduce supply risks for several reasons. They can be produced at both the large scale
(limited by local feedstock resource availability) and small scale (limited by maintaining fuel
quality standards and higher costs).
The commercial viability of biofuels depends on future oil and feedstock prices, land use
change, and possible technological breakthroughs. Production of bioethanol from sugarcane
crops is already commercially viable with oil prices around USD50/bbl. At this price biodiesel
from waste oils and animal fats is also competitive but limited in supply volumes. Other
biofuels are more costly to produce and cannot compete when oil is below USD70/bbl
without some form of support such as agricultural subsidies or excise tax exemption. To
maximize the potential for biofuels, RD&D investments should aim to drive down costs. The
production of biofuels should be further encouraged in tropical and sub-tropical countries,
but only where sustainable land use is practiced without the clearing of forests, stripping of
soil nutrients or the contamination and depletion of local water supplies. Competition for
biomass feedstock for different uses presents a significant challenge for large-scale
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expansion of “first generation” biofuel production although growing momentum for the
integrated production of food, fibre and energy co-products in “biorefineries” and the
development of advanced ligno-cellulosic technologies will likely reduce this concern.
In summary: RETs have the potential to contribute to energy security as well as
environmental objectives on the national, regional and global levels. While, in many cases,
the environmental objectives will be uppermost, governments and industry should also take
into account the security benefits of renewables (and occasionally dis-benefits) in framing
their policies. In order to bring down costs and achieve market penetration these policies will
need to include support funding, incentives to stimulate private investment, government
procurement and buy-down actions, facilitation of international collaboration, and removal of
barriers to technology use. Providing better access to modern energy services for the poor in
non-OECD countries will enhance investor confidence in the sustainability of energy demand
growth.
Greater investment in RD&D for renewable energy systems, both by the public and private
sectors, will enhance energy security at affordable costs with minimal environmental impact3
.
Good progress in bringing down the cost of energy technologies has been made in recent
years but there is a further need to make markets work better, improve technology
performance and provide coherent support for renewable energy technologies in ways that
safeguard health, safety and the environment.

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The IEA has recently published “Renewable Energy: RD&D Priorities – Insights from IEA Technology
Programmes” (IEA, 2006f).
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1. Risks to energy security
The IEA defines energy supply to be “secure” if it is adequate, affordable and reliable.
Consumers expect the lights to always come on at the flick of a switch, their buildings to be
maintained at a comfortable temperature all year round, and to be able to purchase vehicle
fuel or public transport tickets whenever they wish to travel. Electricity, heat, and mobility are
usually considered to be amongst the basic necessities of life and therefore should be
affordable to all at any time.
The European Commission defines energy security in its Green Paper (EC, 2000) as the
“uninterrupted physical availability of energy products on the market, at a price which is
affordable for all consumers (private and industrial)”.
This study defines energy security risk as being the degree of probability of disruption to
energy supply occurring. A forthcoming IEA report on the interactions between energy
security and climate change policy uses an analogous definition of energy insecurity as “the
loss of economic welfare that may occur as a result of a change in the price and availability
of energy” (Bohi and Toman, 1996 cited in: IEA, 2007).
Energy security risks can be categorised as:
a) Energy market instabilities caused by unforeseen changes in geopolitical or other
external factors, or compounded by fossil fuel resource concentration;
b) Technical failures such as power “outages” (blackouts and brownouts) caused by grid or
generation plant malfunction; and
c) Physical security threats such as terrorists, sabotage, theft or piracy, as well as natural
disasters (earthquakes, hurricanes, volcanic eruptions, the effects of climate change etc.).
a) Energy market instability. Energy supply constraints may occur due to political unrest,
conflict, trade embargoes or other countries successfully negotiating for unilateral supply
deals. Such supply constraints rarely result in physical supply interruptions thanks to the
flexibility of the energy transport, storage, transformation and distribution systems as well as
international mechanisms. Nonetheless, they do have consequences for price developments
in fossil energy markets – immediately in the case of oil, with a time lag also in natural gas
and coal markets.
The impact on energy market volatility of such geopolitical threats is heightened by the
uneven global distribution of fossil fuel resources. The world’s proven conventional oil and
gas reserves are concentrated in a small number of countries. Taken together, members of
the Organisation for the Petroleum Exporting Countries (OPEC) countries account for 75%
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of global conventional oil reserves. OECD countries only account for 7% while they consume
close to 60% of the world total.
Similarly, over half of global proven gas reserves are found in three countries: the Russian
Federation (27%), Iran (15%), and Qatar (14%). OECD member countries account for only
8% of the total reserves but consume over 50% of the world total (BP, 2005). The
concentration of fossil fuel resources is the most enduring energy security risk (IEA, 2007).
The 2006 World Energy Outlook (WEO) business as usual Reference Scenario projected
that oil demand will become increasingly insensitive to price, which reinforces the potential
impact of a supply disruption on international oil prices. Transport demand is price-inelastic
relative to other energy services. Since its heavy dependence on global oil consumption is
projected to rise, oil demand will become less responsive to movements in international oil
prices. Thus, prices are expected to fluctuate more than previously in response to short-term
demand and supply shifts (IEA, 2006h). The relative weight of the impact of price
fluctuations varies according to the robustness of economies and businesses (see section
1.1).
b) Technical failure. Faults in energy supply systems caused by accidents or human error
may cause a temporary supply interruption. Due to network complexity and the immediate
loss in network stability which has to be established system-wide, such failures have
particularly sharp and wide-ranging effects if they occur in large interconnected systems as
observed during the recent power outages in California, Italy, Germany and elsewhere. The
probability and impacts of such events can be reduced by investment and control measures.
c) Physical actions. Acts of terrorism, sabotage or piracy – which occur relatively rarely- and
natural disasters can affect any part of the energy supply chain including:
• Power stations, sub-stations and transmission lines;
• Oil and gas exploration, extraction and refining installations as well as oil and gasfired plants, pipelines and storage facilities; and
• Rail or road networks; stations, terminals and ports; or individual planes, shipping
tankers, trains or road vehicles.
The effects may be similar to that of technical failures. Large scale actions may cause longer
outages, take longer and have deeper impacts and longer-lasting effects on energy markets.
The costs of security measures needed to prevent or mitigate them can affect prices,
network stability and provision of energy services and may have significant effects over the
long term. Oil platform and refinery closures off the south coast of the USA following
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Hurricane Katrina in 2005 exemplify the threat to energy supply infrastructure posed by
extreme weather events, which climate change models expect to increase.
Highlighting the significance of physical threats to energy security, the G8 stated in its 2006
St. Petersburg Plan of Action that “[r]ecognizing the shared interest of energy producing and
consuming countries in promoting global energy security, we, the Leaders of the G8, commit
to […] safeguarding critical energy infrastructure […]” (G8, 2006).
1.1 Risks for developing countries
The impact and perception of energy security risks differ across countries. Widely fluctuating
oil and gas prices have an impact on world economies, particularly those of developing
countries. In many developing countries, consumers’ expectations of reliable energy
services are often low and disruptions to energy supply are sometimes considered to be
normal. Nonetheless, increasing short term oil and gas price fluctuations are a major threat
to meeting the United Nations’ Millennium Development Goals for sustainable development
(ESMAP, 2005a and 2005b). Oil importing, low-income economies are particularly
vulnerable to price increases which badly affect their balance of payments (ESMAP, 2005b).
One and a half billion people in developing countries have no access to electricity; two and a
half billion rely only on biomass for cooking and heating fuels. For them, ensuring continuous
energy access is necessary before the security of their energy supplies can be discussed.
Energy access and environmental sustainability are inextricably linked – without access to
modern energy services, the unsustainable use of indigenous energy sources in developing
countries, such as traditional biomass, often leads to environmental degradation and
resource scarcity, which place further pressure on energy supply (Saghir, 2006; Bugaje,
2006; Plas & Abdel-Hamid, 2005). The populations of many, especially small, oil-importing
developing economies are faced with insecure, inadequate, barely affordable and unreliable
energy supplies that undermine economic development (Saghir, 2006).
1.2 Policy responses to energy security risks
In order to prevent significant impacts from energy insecurity, governments can diversify
their energy sources. Of course renewables are not the only option for such diversification.
For instance, coal supply has a wide geographic spread. However, coal without carbon
capture and storage, is a major CO2 emitter and countries have to take account of the
environmental, as well as the security impacts of their policies. The advantage of renewables
is that they can address environmental as well as security objectives.
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Energy efficiency improvements through demand side management and technological
innovation can cost-effectively mitigate the large-scale impact of energy supply disruptions in
the electricity and heat sectors, and to a limited degree in the transport sector too. Demand
side management and energy efficiency measures can reduce dependence on conventional
fuels for the production of electricity, heat and transport fuels. Long-term IEA scenarios to
2050 based on existing and near-commercial technologies (the ETP Accelerated
Technology Scenarios) indicate that energy efficiency in the transport, industry and buildings
sectors plays a crucial role in significantly reducing oil demand growth as well as CO2
emissions (IEA, 2006e).
As the following analysis shows, increasing the deployment of RETs in the energy mix can
help reduce the impact of supply variations and disruptions. For example, in the buildings
sector, introducing renewable heating and cooling and distributed power generation should
be considered in tandem with energy efficiency measures, as combining both options
creates synergies in terms of energy security.
1.3 Energy security implications of renewable energy
technologies
Renewable energy sources (RES) are typically indigenous resources and can reduce
dependence on energy imports. RES are widely (though unevenly) distributed and their use
for electricity generation can minimise both transmission losses and costs when they are
located close to the demand load of end-users: so called “distributed” generation4
. Although
relatively high capital costs per unit of capacity installed remain for many RETs – in spite of
significant cost reductions as a result of learning experience (IEA, 2006f) – this is offset to
some extent by a zero fuel cost over the life of the system so the cost per energy unit
generated can be competitive for instance for wind generation on good sites. Bioenergy is
the exception, since the biomass fuel cost may represent a significant share of total
production cost. However, this varies with the feedstock which can even have a negative
cost where disposal of the biomass as a waste product is avoided. The corollary is that
electricity or heat supplied using renewable energy is less prone to fuel cost fluctuations than
is the case with fossil fuel plants (Janssen, 2002).
With bioenergy applications, over the longer term, feedstock supply itself represents a risk
and securing biomass supplies over the longer term poses a challenge. Where the feedstock
is produced as a by-product of a process with another primary objective, such as food or
fibre production, it will only be available as long as the processing plant continues to operate.

4
Distributed generation refers both to off-grid and on-grid applications which differ in their capacity requirements
due to different load patterns.
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Alternatively, in the case of a bioenergy plant that relies on bringing in the feedstock from
outside sources, be it local forest residues or foreign imports, a similar supply and price risk
will emerge as for purchasing fossil fuels. Negotiating long term contracts for biomass
feedstock with suppliers in advance of building the energy conversion plant is one option to
reduce feedstock price and supply risks, although few long-term biomass supply contracts
exist. Developing a diverse portfolio of feedstock suppliers is a viable risk mitigating
alternative. The associated level of risk depends on the distance travelled, the choice of
supply chain, such as the Middle East – Europe route, as well as on the biomass feedstock
itself. Differing fuel characteristics also engender different levels of transport risk, e.g. a
tanker transporting oil or gas constitutes a higher risk (to the environment) than woody
biomass transported to biomass plants.
A significant supply risk is the competition for the biomass resource – for energy uses, such
as electricity, heat and transport, and for food, fibre and chemical production. Biomass
suppliers will sell to the highest bidder. However, bioenergy is unique amongst RETs in that
is the only renewable source of hydrocarbon fuel for transport and feedstock for many
petrochemicals. Diversifying import origins thanks to biofuels which could be produced from
countries that are not oil exporters may still reduce energy security risks.
Similarly, in the medium-term future, imports of renewable electricity, e.g. generated from
wind power or CSP, through high-voltage direct current (HDVC)5
lines could help diversify
the origins of energy supply. A recent study shows that, in the case of Europe, the key for
increasing the share of renewable energy supply in the European electricity mix is the
development of strong interconnection within the EU and its neighbouring countries,
including North African and Middle Eastern countries (Czisch, 2004). Interconnection would
spread the geographic area of variable electricity sources, thus contributing to smoothing
variability. More importantly, it enables European countries to access additional and good
quality renewables energy resources from its margins.

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This technology is already in place in various applications worldwide in order to either to save power losses on
long transmission lines, reduce environmental impacts or connect asynchronous grid areas.
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2. Current energy use by market segment
Renewable energy systems are diverse, widely available and, in some cases, close to being
cost competitive. RET applications based on wind, solar, geothermal and tidal grew 8%
annually on average from 1971 to 2004 (IEA, 2006g). Appropriate deployment of renewable
energy systems can thus help improve the security of energy supply for electricity,
heating/cooling and transport fuels.
The IEA projected in its WEO 2006 Reference Scenario that renewables (including hydro,
biomass and waste and other renewables) will only constitute 13.8% of world primary energy
demand by 2030. In contrast, in its Alternative Policy Scenario, which assumes the
implementation of energy-related policies and measures currently being considered by
governments to ensure energy security and reduce energy sector CO2 emissions, this share
rises to 16.2% (IEA, 2006h) (though in both instances most of the biomass is traditional
supplies).
Large-scale displacement of fossil fuels and traditional biomass by renewable energy is
theoretically possible as the resource potential is huge. Nevertheless, the evolution of the
economic potential of RETs over the coming decades will depend both on their technological
development and on cost in relation to competing conventional energy technologies.
Appropriately targeted and stable research, development and demonstration (RD&D),
together with incentives for market deployment and climate change policies may influence
both factors.
Electricity accounts for around 17% of global final energy demand, low temperature heat
44% (of which traditional biomass used for heating and cooking in developing countries has
a significant share), high temperature industrial process heat 10%, and transport fuels 29%
(IPCC, 2007).
2.1. Electricity production
In 2004, the share of coal6
used as fuel for electricity generation in OECD countries was
around 38%, natural gas 18%, nuclear 23% and oil 5%, with large hydro representing 13%,
combustible renewables and waste 1.4% and other renewables7
1.1% (IEA, 2006b). The
share of oil-fired plants ranges from less than 5% in OECD Europe and North America
(though for individual countries it reached up to 16% as in Italy) up to nearly 10% in the
OECD Pacific region where small diesel gensets are more common (ibid.).

6
Includes hard coal, brown coal, peat and coal gases
7
Other renewables include wind, geothermal, solar, tidal and wave energy.
20
As oil no longer plays a major role in electricity production in most OECD countries, the
security of natural gas supply has gained in significance. The shares of gas-fired power
generation were 17% in OECD Europe, 19% in North America and 19% in OECD Asia (ibid.).
OECD Europe imported 54.8% of its gas in 2004 mainly from the former USSR and Middle
East/North Africa (MENA) countries. For the OECD Pacific region import dependence is
even more pronounced, with 87.1% of its gas imported from non-OECD countries. OECD
North America imported only 13.1%, mainly from Trinidad and Tobago.
Dependence on a small number of gas supplier countries can be an indication of fossil fuel
resource concentration which can affect energy security (IEA, 2007). However, as energy
markets become liberalised and the distinction between domestic and foreign resources
becomes more fluid, import dependence may become a less significant factor (ibid.).
The IEA has developed an energy security indicator which complements a physical
availability component derived from the notion of import dependence, with a price
component based on calculations of market power and concentration (ibid.). Modelling
results suggest that increasing the role of renewables in electricity generation, which will
most likely displace fossil fuel fired generation, reduces both the price and volume (physical
availability) components of the energy security index – in other words, an increase in energy
security (ibid.).
The impact of a disruption in the supply of gas to a power plant depends on its source. Gaspipeline infrastructure is inflexible, so that a loss of supply through a particular pipeline
system cannot always be made good by supplies from other sources (IEA, 2006h).
LNG supply shipped into ports is more flexible in principle as the loss of supply from one
producer may be replaced by imports from another. The growing share of LNG in world gas
trade should therefore contribute to more flexibility in gas supply. That said, in practice there
may be insufficient liquefaction and shipping capacity available to compensate for a large
supply disruption. Increasingly, a shortage of gas in one region may therefore affect global
gas prices. To mitigate such a supply risk, most LNG is sold under long-term contracts, with
rigid clauses, e.g. “take or pay”, covering delivery (ibid.). This underlines the special risk
structure of gas supplies in comparison to coal where a world market exists in combination
with a more flexible transport system on both land and sea.
The current trends in electricity production and the assumptions about the future generation
mix are reflected in the WEO Reference Scenario (IEA, 2006h) which assumed a decline of
the market share of coal in the OECD, an increase of the market share of gas, and an
increase of non-hydro renewables until 2030 (Table 1).
21
Table 1: Current market shares and trends in OECD electricity generation for 2004
and WEO Reference Scenario projection for 2030
2004
Generation Share
(TWh) (%)
2030
Generation Share
(TWh) (%)
Growth rates
(% p.a.)
2004-2030
Coal 3842 38 5391 37 1.3
Oil 527 5 297 2 -2.2
Gas 1854 18 3345 23 2.3
Nuclear 2319 23 2382 16 0.1
Hydro 1267 13 1519 11 0.7
Combustible
renewables
and waste
196 2 485 3 3.6
Other
renewables
115 1 1049 8 8.9
Source: IEA, 2006b and IEA, 2006h
2.2. Heat
Heat production has grown steadily in OECD countries in recent years. In 2004, OECD total
gross heat production8
was approximately 2,721 PJ9
with direct use of heat from geothermal
an additional 160 PJ and solar thermal applications a further 126 PJ10. The OECD Europe
region represented 82% of OECD gross heat production in 2004, while the OECD North
America and OECD Pacific regions supplied 10 and 8% respectively. In comparison, total
non-OECD gross heat production amounted to 9,691 PJ. Natural gas contributed the bulk of
2004 gross heat production both in OECD and in non-OECD countries, namely 44% and
57% respectively (IEA, 2006b).
A large amount of waste heat (approximately 75,000 PJ/ year or 1,791 Mtoe/ year) from
power plants is not utilised and is dumped as it is either not close to demand or timing of
heat demand requirements do not match power generation requirements. Industrial waste

8
An important caveat is that the IEA statistics include heat sold to third parties only. Auto-production by industry
is not included, nor is residential transformation of electricity, natural gas and fuel oil for space heating and other
heat uses. The amount of total heat produced is at least two orders of magnitude above commercially sold heat.
9
IEA, 2006a
22
heat recovery offers a significant opportunity to reduce energy consumption and emissions
and increase productivity. There are several techniques for heat recovery, all based on
intercepting the waste gases before they leave the process, extracting some of the heat they
contain, and recycling that heat.
2.3. Transport
Biofuels have been identified as a part solution for transport fuels but this may be limited by
competing requirements for (mainly land and water) resources. This is particularly the case
with first generation technologies based around several existing crops more commonly
grown for food. Second generation systems under development using crop and forest
residues and non-food crops hold greater promise in terms of scale, but cost reductions
remain to be made. Even with aggressive support policies to account for carbon benefits,
improved vehicle consumption rates, integrated cropping, uptake of new crop varieties
(possibly genetically modified) and more efficient process production processes, biofuels are
unlikely to meet more than 4-7% of global transport fuel demand by 2030 (IEA, 2006h). This
share depends on future oil prices and availability as well as the rate of uptake of liquid fuels
from unconventional oils.
10 Nevertheless, non-OECD countries, such as China, Israel, Brazil, India, Cyprus and South Africa, constituted
over 50% of global direct use of solar thermal systems in 2004 (IEA SHC, 2006). This figure only includes “active”
solar systems; “passive” solar architecture is not accounted for.
23
3. Renewable energy technologies in the energy mix and
effects on energy security
The following sections assess the impacts of the different categories of risks for disruption to
energy supply security in the electricity, heating and transport sectors. An indicative
overview of the relative significance of these risks is presented in Table 2.
3.1. Electricity production and the impact of variability
Renewable energy technologies used to generate electricity are flexible in scale and type of
use. They can be exploited locally, used both for centralised and dispersed power
generation, and the energy sources used are indigenous. Regional variations in both
capacity factors and variability of the available resource exist so that security of renewable
energy supply is site specific. The output variability of individual renewable energy sources
can be a constraint to reliable and secure supplies but can be minimised by demand
variability, especially where this correlates with times of high energy output by RETs; better
predictability of their generation output; and the complementarities of different power sources
to overall supply .
Hydropower is a highly flexible technology from the perspective of power grid operation as
the fast response time of hydro reservoirs can meet sudden fluctuations in demand or help
compensate for the loss of other power supply options. Hydro reservoirs provide built-in
energy storage which assists in the stability of electricity production across the entire power
grid. In the case of run-of-river systems with limited storage, hydropower may show strong
seasonal variability; prolonged periods of low rainfall in regions where insufficient reservoir
capacity exists can have significant effects on power supply predictability.
Solar photovoltaics (PV), whether grid connected, stand alone or building integrated, are
exposed to variability as a result of seasonal variation from winter to summer, diurnal
variation from dawn to dusk and short-term fluctuations from varying cloud cover. At
significant grid penetrations, such possible variations in electricity production have to be
compensated for by flexible grids and/or energy storage. Solar PV is not dispatchable in a
traditional sense, meaning its output cannot be controlled and scheduled to respond to the
variable consumer demand for electricity. However, solar PV electricity supply fits well with
demand wherever peak demand occurs during daylight hours and especially where a large
part of demand is for air-conditioning.
24
Table 2: Relative significance of supply disruption risks from a national and business perspective
***
High risk
** Medium risk
* Low risk
No star No perceived risk
Electricity system and
infrastructure
Low temperature heating
and cooling
High temperature heat Transport and
infrastructure
Nature of risk National Business National Business National Business National Business
Energy market
instability * * * * * ** *** **
Technical
failure *** *** * ** * *** * *
Physical
security threat
(including
natural
disasters)
*** ** * ** **
25
Concentrating Solar Power (CSP) plants can provide electricity especially in areas with
long and reliable hours of direct sunshine. In these areas peak demand is usually driven by
air-conditioning systems and the availability of CSP matches peak and mid-peak demand
well – although heat storage and/or fossil fuel back-up may help fully cover the mid-peak
demand during a few hours after sunset. Because insolation is available only in the day,
CSP can provide base load only if heat storage technologies are integrated. While roundthe-clock operation is technically possible industrial heat storage options are currently not
economically feasible.
Wind power is directly dependent on the cube of the wind speed within the operating range.
The wind speeds, at which wind turbines commonly operate, are between 2.5 to 25 m/s.
Thus, wind power can become unavailable at times of low wind speeds, but also at times of
very high wind speeds when wind turbines need to be shut down in order to avoid damage to
equipment. Thus, for entire grid system control areas, power generation will gradually
decrease at mean wind speeds higher than 25 m/s. The annual power output of a given
turbine varies greatly with location and capacity factors of over 45% are rare11. Wind energy
is typically variable on time-scales from minutes to hours but can also be seasonal.
Geographical distribution across a grid partly compensates for short term fluctuations as is
also the case for solar.
Biomass combustion, used widely for heat as well as power generation using feedstocks
usually from organic waste products, depends on reliable supplies. Seasonal cycles of
energy crops or crop residues used for biomass can have effects on the availability of
feedstock and thereby affect supply security. Cogeneration plants using sugar bagasse for
example often only operate for 6-7 months of the year during the sugar harvesting season.
The possibility of storing biomass, however, such as straw bales or wood chips can help to
offset other variable power production systems. Using a bioenergy system as back-up to a
solar thermal power plant is one example, although mainly for nights as the bioenergy plant
response time is not fast. The co-firing of biomass with coal can also partly reduce the risk of
supply. Common designs of handling and combustion systems often restrict biomass to less
than a 15% share.
Where available, geothermal power plants can provide base load capacity as variability is
not an issue. Geothermal energy is largely untapped in many areas of the world and is
available in many developing economies of South and Central America, Africa and SouthEast Asia. Near surface geothermal heat is only accessible in limited regions worldwide.

11 Wind turbines are designed to minimise cost per unit of electricity generated in the wind conditions where the
wind turbines are placed. Least cost per generated unit of energy is usually obtained with capacity factors of 25-
35%.
26
Geothermal heat from deeper hot rocks is more widely available but also more costly to
extract.
Ocean energy is at the development stage and has considerable potential. Tidal power is
variable but predictable as are ocean currents. Similarly, wave power outputs are variable,
but with non-random patterns; this permits output predictions, albeit with varying degrees of
accuracy. The energy available through ocean thermal energy conversion (OTEC) is one or
two orders of magnitude higher than other ocean energy options such as wave power, but
current systems have very low efficiency.
3.1.1 Contribution of renewable energy technologies to electricity
production
Electricity demand has grown in most OECD member and non OECD countries over the
past decades. However, the generation mixes and the corresponding growth of underlying
primary fuel use have varied across regions. In the USA and China for example a huge
growth of coal-fired power generation has occurred, whereas in Europe the main growth has
been from the use of gas. Wind energy generates a significant share of electricity in some
European countries and regions, such as Denmark, northern Germany and Spain.
Geothermal energy makes a significant contribution to electricity generation in some OECD
countries – Iceland and New Zealand – as well as in several non-OECD countries, for
example Kenya, Philippines, Indonesia and El Salvador 12 . Overall however, renewable
energy has not contributed to a large extent to this growth and its share has remained
secondary.
In 2004, 15.1% of total electricity in OECD countries was produced from renewables
(excluding generation from pumped storage plants): 12.5% from large hydro, 1.4% from
renewable combustibles and waste13 and 1.1% wind, solar, geothermal etc. (IEA, 2006g)
(Figure 2). These shares differ by country depending on the local renewable energy
resources, current energy prices and policy support mechanisms in place.
A large increase of non-hydro renewables especially in Europe is expected to achieve a
market share of 11% by 2030. This is based on official targets and strong government
support policies and measures (IEA, 2006h). In 2005, annual investment in new renewable
power capacity increased to USD 38 billion (REN21, 2006), representing about 20% of total
additional worldwide investment in power generation14.

12 Personal communication, IEA Geothermal Implementing Agreement 13 This includes solid biomass, renewable municipal waste, biogas and liquid biofuels. 14 Figures of global power generation investment exclude transmission and distribution investment and fossil fuel
supply chains, which might mean the comparison is too favourable to renewable energy.
27
Figure 2: Renewable shares in OECD electricity production, 2004
Renew ables
15.1%
Gas
18.3%
Coal
38.0%
Oil
5.2%
Non-Renew . Waste
0.5%
Other**
1.1%
Hydro
12.5%
Renew able
Combustibles
and Waste
1.4%
Nuclear
22.9%
** Other renewables include geothermal, wind and solar. Source: IEA, 2006b
Investment as well as generation costs vary greatly among RETs, with several technologies
already approaching competitiveness with conventional power generation technologies at
the midpoint of their respective cost ranges. The IEA projects that by 2030 learning effects
will have pushed investment and generation costs further down (Figure 3 and Table 3). In a
few countries, some prime locations for the deployment of RETs, especially for electricity
generation, are already used which may affect the potential for future cost reductions.
However, in most countries, renewables offer a large unexploited potential.
Figure 3: Capital costs for renewables-based technologies, 2004 and projected for
2030
0 1 000 2 000 3 000 4 000 5 000 6 000
Co-firing
Wind onshore
Wind offshore
Geothermal
Solar thermal
Medium-scale CHP plant
Tide and wave
Solar photovoltaic
Biowaste
dollars (2005) per kW
2004
2030
0 1 000 2 000 3 000 4 000 5 000 6 000
Co-firing
Wind onshore
Wind offshore
Geothermal
Solar thermal
Medium-scale CHP plant
Tide and wave
Solar photovoltaic
Biowaste
dollars (2005) per kW
2004
2030
Source: IEA, 2006h
28
Table 3: Costs of electricity generation technologies in OECD countries, 2005 and
projected for 203015
Technologies
based on:
Investment
costs (USD per
kW), 2005
Investment
costs (USD
per kW), 2030
Typical
electricity
generation
costs16 , 2005
(USD per
MWh)
Typical
electricity
generation
costs, 2030
(USD per
MWh)
Large hydro 1,500 – 5,500 1,500 – 5,500 30 – 120 30 – 115
Small hydro <10 MW 1,800 – 6,800 1000 – 300017 60 – 150 50
Wind onshore 900 – 1,100 800 – 900 30 – 8010 30 – 70
Wind offshore 1,500 – 2,500 1,500 – 1,900 70 – 220 60 – 180
Geothermal 1,700 – 5,700 1,000 – 2,000 30 – 90 30 – 80
Solar PV 5,000 – 8,00018 1,200 – 1,800 180 – 540 70 – 325
Solar thermal 2,000 – 2,300 1,700 – 1,900 105 – 230 90 – 190
Biomass 1,000 – 2,500 400 – 1200 30 – 100 30 – 100
Ocean (current, tidal,
wave) 55 – 160
Coal 1,000 – 1,200 1,000 – 1,25019 20 – 60 35 – 40
Coal with CCS20 1,850 – 2,100 1,400 – 2,10012 40 – 90 45 – 60
Natural gas 450 – 600 400 – 500 40 – 60 35 – 45
Nuclear 2,000 – 2,500 1,500 – 3,000 25 – 75 47 – 6221
Source: IEA, 2006e; IEA/NEA, 2005
3.1.2 Security effects of grid integration of renewables
Generation mix
Given increasing environmental and climate change concerns and efforts to reflect the cost
of CO2 emissions in energy markets, renewables are gaining increasing attention. They are
increasingly substituting other conventional generation technologies.
This substitution process can be made by dispatching renewable energy plants from the grid
or by modifying the load. As an example, in Germany, electricity production from gas is
limited to peak load and spinning reserve power. Hence, the displacement of gas out of the

15 Using 10% discount rate. The actual global range is wider as discount rates, investment cost and fuel prices
vary. Wind and solar include grid connection costs, where appropriate.
16 Total costs include investment, operation and maintenance and fuel costs. For wind and solar PV, the cost also
encompasses grid connection costs.
17 Johanssen et al. (2004), Fisher (2006), IEA/NEA (2005), MIT (2003), WEC (2004a, 2004b) 18 Personal communication, IEA PVPS Implementing Agreement 19 Projected investment costs for 2030 relate to advanced coal conversion technologies (advanced steam cycles,
FBC, IGCC).
20 CCS stands for carbon dioxide capture and storage 21 These costs relate to Generation III (advanced boiling water reactor, advanced pressurised water reactor,
European pressurised water reactor) and Generation III+ (pebble bed modular reactor and AP1000 a thirdgeneration light water reactor) nuclear reactor types. Generation IV reactors are not expected to be available until
around 2030.
29
generation mix by wind energy is almost negligible to date. This indicates a small
improvement in energy security in terms of decreasing gas import dependency.
In the UK, natural gas-fired electricity contributed 40% of total gross electricity production in
2004, so the effect of introducing renewables is very different (IEA, 2006b). Meeting load
demand by following the least-cost merit order based on marginal pricing means that the
capacity which is more expensive to generate is not dispatched. Gas fired plants manifest a
higher share of fuel as part of total in generation costs (USD/GJ) than coal, nuclear or
renewables (IEA/NEA, 2005). Consequently, gas plants can be assumed to be the fossil fuel
plants with higher marginal costs (although oil-fired plants would be even higher). Switching
gas for renewable energy would therefore likely affect gas consumption in the UK more than
in Germany. Thus, the effect of RETs on energy security in a mainly gas-fuelled electricity
system can be significantly higher.
Management strategies for variable power generation
Downstream security refers to the probability of interruptions to the energy supply from the
electricity system. Most renewable energy technologies such as hydro, wind, solar, tidal and
wave depend on different natural cycles and therefore vary on different time scales. At high
levels of grid penetration by RETs the consequences of unmatched demand and supply can
pose challenges for grid management. This characteristic may affect how, and the degree to
which, RETs can displace fossil fuels and nuclear capacities in power generation. The
additional costs for grid back-up and/or electricity storage and spinning reserve have to be
taken into account (Swider et al., 2006; Meibom et al., 2005)22.
Large shares of a single variable resource, such as wind energy, require means to balance
the supply with the load. In many countries existing control methods together with back-up
capacity available can deal with the ever-changing power demand at penetration levels up to
around 20% (GWEC and Greenpeace, 2006). Western Denmark already successfully
integrates a 20% share of wind energy into the electricity system, but this ability relies on
good inter-connection to the German and Nordic grids for back-up and export. Above this
level, some changes may be needed in power systems and their method of operation to
ensure system reliability.
In countries with high penetration levels of wind power but few flexible power stations and
little hydropower storage for back-up, the question of sufficient operational reserve is critical.
Less flexible conventional power stations can be costly back-up as changing their load may

22 Flexible measures to absorb the fluctuations in wind power production are required as the grid penetration of
wind power increases. Recommended integration measures include the use of electrically operated heat pumps
in CHP systems which can provide relatively cheap optional demand (Holttinen et al., 2005; Meibom et al., 2005).
30
reduce efficiency and thereby raise costs. Improved wind prediction methods have lowered
these risks.
High-impact, low frequency weather events, such as long periods of low wind speeds, need
to be evaluated. Statistically, these ‘outlier events’ (see box) are at the edge of the
probability distribution. Experience suggests that capacity reserves will be needed as a
consequence of low wind speed events23. Such rare events are manageable, although they
may affect the installation of large wind capacities disproportionally.
Improved control technologies, more accurate forecasting techniques and increased
geographical dispersion of wind farms – ensuring that the wind will generally be harvested
somewhere in the network – will all help their effective integration. A balanced portfolio of
RES with different natural cycles may also reduce the need for back-up capacity. A good
example is a combination of solar and wind energy to satisfy peak demand (the former being
more productive during summer, the latter often more productive during winter) with base
load provided by geothermal or biomass.
The direct effects in quantitative terms of an increasing share of variable renewables depend
on the balancing options and demand-side response techniques. If the possibility exists to

23 Low wind speed events are defined as average hourly wind speed measurements of less than 4 m/s (the
minimum wind speed for electricity generation for many modern wind turbines).
Example of an “outlier event”
Hourly wind data collected over a 23 year period (1970-2003) from 66 different
locations in the United Kingdom showed that low wind speed events affecting more
than half of the UK are present for less than 10% of all hours. The data did not indicate
any hours where wind speeds were below 4 m/s throughout the UK. The UK
experiences far fewer high speed wind events (average hourly wind speeds above 25
m/s) than low wind speed events, with the UK not having any high speed wind events
for over 96% of all hours over the 23 year period (Sinden, 2007). Three year data
(2000-2002) in Denmark identified that the longest duration of calm weather with wind
generation below 1% of capacity was 58 hours in 2002 and 35 hours in 2000. For
Finland and Sweden it was 19 hours and for Norway 9 hours. However, if the wind
power production of these four neighbouring countries were combined, there were no
totally calm periods in the data (Nørgård et al., 2004).
Besides the occurrence of extreme wind conditions, the availability of wind power at
different times of the year and different demand levels is a critical aspect. Over the long
term, low wind speed events are less likely during periods of high electricity demand
than during periods of low electricity demand. The relationship between the extent of
high wind speed events – although extremely rare – and electricity demand is more
complex. While the impact of high speed wind events is greatest during periods of high
electricity demand, such wind events on average affect less than 0.2% of the UK at
such times. Moreover, the extent of such events is at its greatest during periods of
relatively low electricity demand (Sinden, 2007).
31
balance the grid using other RETs, these installations can effectively replace existing power
plants and consequently reduce investment needs in fossil-fuelled power plants.
Geothermal is not a variable power source, nor is biomass except where the latter depends
on seasonal cycles and harvesting periods of dedicated energy crops. These cycles affect
biomass production on larger time-scales and, since many forms of biomass can be stored
for short to medium time periods, it is therefore more manageable than other renewables.
Competing uses of land for energy, food and fibre production can also put constraints on the
availability of biomass. The low density of several forms of biomass exposes them to high
transportation costs limiting some resources to on-site use for heat and power or distributed
generation, resulting, in some cases, in reduced use of power transmission grids.
Hydropower is exposed to generation variability depending on the hydrological cycle which
provides seasonal rain and runoff from snow melt.
Within the aforementioned characteristics of their natural cycles, then, hydro, biomass, CSP
(with heat storage or fossil fuel back-up) and geothermal power technologies can be used for
base and peak load production. Consequently, their capacity value is close to one. In the
case of CSP, this is due to the matching of its availability with summer peak demand.
Bioenergy can also be used for mid load production. Geothermal technology applications are
able to operate in a load-following manner, although this is not the optimum operating mode.
Therefore, CSP, geothermal and biomass can have direct fuel substitution effects at the mid
load level, and thus a high net effect on capacities. This results from the absence of the
need for further balancing of capacities. Consequently, bioenergy installations can affect the
need for new investments or the use of current power plants. Under the assumption of
complete market integration of bioenergy technologies, the effect on other power plants is
determined by their marginal costs.
Therefore, geothermal and biomass plants can displace new investments in nuclear, coal or
gas plants depending on their various deployments in different countries. Depending on the
growth of variable RETs’ share in power production, renewables are most likely to displace
conventional technologies used for base load generation, namely coal, nuclear and natural
gas (IEA, 2007).
Associated costs for variable renewables can be divided into additional balancing costs,
requirements for operational and capacity reserves as well as adaptation of transmission
and distribution grids.
Energy technology portfolios
Adding RETs to the portfolio can reduce the risks of generation failure by adding to the
portfolio of technologies in the energy supply mix. In general terms, portfolio theory aims to
32
determine the mix of different financial assets which is the most desirable to hold. In energy
terms this seeks to secure a combination of generation plants that reflects the risks and
corresponding prices under pre-defined goals and risk targets. In the context of electricity or
heat generating options, expected portfolio cost is used, rather than the expected return.
Optimisation seeks to minimise the expected portfolio cost (Awerbuch and Berger, 2003). A
diversified portfolio of energy supply options reduces energy security risks, such as fuel price
volatility due to resource concentration. It can offer a hedge against future uncertainties –
population growth, rate of energy demand growth, speed of new technology development
and technology performance.
The drawback of utilising the concept of fuel mix diversity as an indicator of energy security
is that it cannot be easily measured or quantified. Basing a portfolio’s composition on past
price correlations does not adequately reflect energy security concerns, especially where
prices are regulated and in the event of price shocks.
Individual energy technologies face different risk structures as a result of differences in
capital intensity, fuel dependency and fuels used. Consequently, disruptions in energy
markets affect energy sources differently. Energy security risks may show up as physical
interruptions that can seriously harm supply of energy services or as sudden price shocks
reflecting rising demands, falling supplies or several other factors like political risks. The risk
structures of some power generation technologies depend on their degree of variability
(Table 4).
Gas-fired power generation is exposed to high fuel cost risk. This implies that a further
expansion of gas-based electricity production of 2.5% per year from 2004 to 2030, as
assumed in the WEO 2006 Reference Scenario (IEA, 2006h), will probably result in a higher
price risk for the generating portfolio. Geothermal, wind and PV do not face a similar risk as
they do not rely on a commodity feedstock. Hence, their risk structure is not correlated with
the risk of gas or other fossil fuels whose fuel costs depend on overall energy demand.
Under the assumption that variable renewable energy technologies can be geographically
dispersed and considered as part of a diverse RET portfolio, the costs of these variable
technologies are quite stable. Consequently, following the portfolio approach, to deploy
renewable energies can result in a reduction of the volatility of generation costs and
therefore in a risk reduction to a portfolio of generation technologies.
The problematic definition of an optimal portfolio is determined by the degree of risk aversion, the
effect of variability on the economy, and the extent to which mechanisms exist to mitigate risk
efficiently. Several factors including demand response, fuel flexibility determine the final value of
a risk reduction measure to a portfolio. What value a risk reduction measure can have in
monetary terms goes beyond the scope of this study. Nevertheless, the assumption is supported
33
that those renewables not exposed to fuel costs have a positive effect on the risk profile of
generation portfolios by reducing the risk of rising fuel costs. This shows the benefits from
increased diversification through the inclusion of renewables.
Projections of future electricity market structures
The World Energy Outlook 2006 Reference Scenario projected a total investment in global
electricity markets of USD 11.3 trillion by 2030, of which USD 6.1 trillion will go to new and
upgraded transmission and distribution assets (IEA, 2006h). As RETs gain more significant
market shares, some of this investment will benefit the integration of these technologies. Six
main areas of structural change directly benefit renewables:
• Increased grid capacity and cross-boarder connections, corresponding to the WEO
2006 projections;
• Balancing/regulating markets that are cost-reflective, transparent and interconnected
with gate closure times reflecting the technical and economic needs of the system;
• Enhanced uptake of efficient demand-side response mechanisms.
• Installation of more flexible generating capacity, including hydro-power and biomass,
as capacity reserves and increased efforts to reduce costs of novel storage solutions
to widen the number of strategic options;
• A mix of different renewable energy technologies, taking advantage of different
natural cycles and thus reducing volatility and uncertainty; and
• Improved forecasting and modelling of natural fluctuations and increased utilisation of
communication technologies to disseminate this information between grid operators
and markets.
The first four are likely to occur as a consequence of continued evolution of electricity
markets and electricity grids. Other options might require further policy guidance. Overall,
variability should not be regarded as a risk to energy security (dena, 2005). However, the
issue needs to be carefully analysed and managed.
3.1.3 The physical security advantages of renewable electricity
generation
Renewable energy installations vary greatly with regard to the scale of plant size and to the
possibility of integrating them either into the transmission or the distribution systems. For
example, large hydro plants and the majority of large-scale wind farms (up to 300MW) feed
in to the high voltage transmission system, in the same way as conventional power plants.
34
Table 4: Qualitative comparison of risks of electricity generation technologies
Technology Plant capacity
ranges (MW)
Lead
time
Fuel cost
as % of total
generation
costs24
Risk of fuel
cost
fluctuation
Variability Rapid response rate use to
level out peak demand for
generation
Regulatory
risk
Hydro 14 – 32000 Long Nil Nil Low Yes High
Wind power 0.5 – 300 Short Nil Nil High No Medium
Photovoltaics 0.01 – 10 Very short Nil Nil High No, except in hybrid systems and
systems with expensive storage
components
Low
Geothermal 0.1 – 200 Long Nil Nil No No Low
Biomass
including CHP
10 – 240 Medium 60% Medium25 No No Low
Fuel cells 0.1 – 10 Very short 40% Low No Yes Low
Coal 150 – 900 Long 35% Medium No Yes High
CCGT 100 – 500 Short 75% High No Yes Low
Nuclear 700 – 1600 Long 10% Low No No High
Internal
combustion
engines
0.1 – 60 Very short 70% Medium No Yes Low
24 At 10% discount rate – IEA/NEA (2005) 25 A significant supply risk is the competition for the biomass resource – for energy uses, such as electricity, heat and transport, and for food, fibre and chemical production.
35
On the other hand, small hydro applications and small wind turbines for self-production are
decentralised and much smaller in capacity when compared to traditional power stations.
Biomass and geothermal installations typically are 20-100 MW capacities, although plants
can be larger with combined heat and power (CHP) opportunities. These smaller
installations tend to be widely dispersed and do not show a major security risk in terms of
exposure to sabotage or terror attacks. Plant outages for any reason would only affect a
small portion of electricity supply. Consequently, there is no need for costly precautionary
measures with regard to specific or common security risks.
Centralised power generation is exposed to a larger set of supply security risks relative to
distributed generation. An outage of one of these power stations could have significant
impacts on the electricity supply in absence of reserve capacities and may therefore imply
major costs for society. However, the probability of this risk is limited as electricity systems
normally rely on a large number of units and are designed to cope with unplanned outages
at individual stations due to technical problems as well as planned outages for maintenance.
Besides the protection of central power stations another burden is the protection of transport
infrastructure and storage capacities like pipelines, ships as well as gas terminals etc.
Although difficult to assess, the costs involved in securing such infrastructure against piracy
and attacks can be substantial. Where these costs are at least partly borne by public funds
the security requirements are not internalised in the costs of fossil fuel based electricity
production. The risk of physical security risks, such as sabotage, faced by high voltage
transmission systems is moderate, as overhead transmission lines are vulnerable to possible
attacks. While the short-term economic impacts of power outages would be significant, the
attacks would not have long-term effects as the affected high-voltage transmission lines
could normally be reinstalled in a fairly short period of time. The extent to which renewables
can be regarded as reducing the exposure of an electricity network to terrorist attacks or
natural disasters will vary greatly depending on the nature and penetration of the renewables
as well as the extent of the system and the characteristics of the other generation sources.
However, in some circumstances, the deployment of renewable energies can have a positive
effect in reducing the amounts of transported and used fuels as well as on the need for
securing power stations.
3.1.4 Summary
1. Depending on electricity market conditions, the effects of a country’s renewable energy
generation facilities on fossil fuel consumption are determined by the infrastructure and
the characteristics of the generation technologies. Consequently, the impacts relating to
energy security have to be assessed by technology and by country.
36
2. Electricity generation from renewables is, in the case of hydro, wind, biomass and
geothermal, often already competitive with generation from conventional power
stations to the midpoint of the RET cost ranges at current fossil fuel prices. Targeted
and adequate RD&D investments can help reduce technology costs by facilitating
collective market learning.
3. Renewables can reduce the exposure of power generation to price risk. Price
volatility due to fuel cost variations can be reduced which affects the risk structure of
generation portfolios. This effect favours renewables and enhances their
competitiveness.
4. Renewable electricity systems can contribute to security against terror, sabotage and
localised natural disasters as a result of their dispersed structure.
5. Careful analysis is required of the impact of large scale penetration of variable
renewables in a power grid. Depending on the balance of capacity available and
wider connectivity of the system, investment may be needed in back-up capacity and
in policies to enhance demand side response.
6. Depending on the extent to which variable RETs dominate a power network, they are
most likely to displace conventional generation technologies used for base load,
namely coal, nuclear and natural gas (IEA, 2007).
7. Positive effects of renewables on selected indicators for energy security may include:
– Diversification of energy sources in energy supply: renewables can contribute to
diversification of the portfolio, especially as their risk structure is not related to fossil
fuel supply risks, they can reduce the variability of generation costs.
– Diversification of imports with respect to imported energy sources: as most renewables
do not need imported fuels, they can contribute to reduced import dependency. Biomass
can be an exception. However, in some countries, using bioenergy provides opportunities
for diversifying import portfolios.
3.2. Heat production
Globally, heat is the largest energy end use. Nevertheless, because of the relative absence
of policy interest to date compared with electricity and transport fuels and its distributed
nature, the energy security implications of heating have not received much attention.
Similar to electricity generation, heat can be provided both through grid- and non-grid
connected systems though the transport distance is short. Official government statistics only
capture the commercially traded fuel inputs to heat production as well as the commercial
sale of heat by contract to a third party use (e.g. residential, commercial or industrial
37
consumers). Thus, while the data on grid-connected and centralised systems, such as
district heating, CHP plants and industrial process heating, will be more reliable, heat
production in non-grid connected and decentralised systems, such as ground-source heat
pumps and domestic solar thermal26, is not included in official statistics. Therefore, the actual
contribution of renewables to heating is understated in official statistics.
3.2.1. Contribution of renewable energy technologies to heat production
in OECD countries
About 22% of reported world heat production in 2004 was in OECD member countries (IEA,
2006b). Renewables as defined by the IEA represented approximately 18.4% of total gross
heat production27 (including direct use of geothermal and solar heat) in 2004 among OECD
countries (IEA, 2006b, 2006f). The deployment of renewable heat production technologies
differs among OECD regions. OECD Europe, and the EU-15 in particular, occupies the
dominant position in the deployment of commercially available renewable heat, with the
region representing all listed commercially traded geothermal and solar heat, 94% of heat
from solid biomass and 92.4% of heat from renewable municipal waste.
Among OECD countries, heat derived from biomass technologies overshadows geothermal
and solar thermal technologies and represents 65.8% of commercially traded heat produced
from renewable sources (IEA, 2006g).
In its WEO 2006 Alternative Policy Scenario (APS), which assumes the implementation of all
policies currently under consideration by governments driven by concerns for climate change
mitigation and energy supply security, the IEA projected that by 2030 global renewable heat
production in the building and industry sectors will have grown by 43% from 2003 (IEA,
2006h). The most substantial growth is projected to derive from commercial biomass
followed by solar thermal, while traditional biomass supply stagnates and its relative share in
renewable heat production declines.
3.2.1.1 Bioenergy
Biomass, including traditional fuelwood and dung, is the largest contributor to renewable
energy heat worldwide. In 2004, biomass supply was 7,034 PJ and represented a 10.4%
share of global primary energy supply but only 3% of total OECD primary energy supply
based on IEA, 2006g).

26 i.e. for direct use of RES for heating 27 An important caveat is that the IEA statistics include heat sold to third parties only. Auto-production by industry
is not included, nor is residential transformation of electricity, natural gas and fuel oil for space heating and other
heat uses. The amount of total heat produced is at least two orders of magnitude above commercially sold heat.
38
Figure 4: Worldwide renewable heat production in industry and buildings in 2004 and
projected by 2030
0
200
400
600
800
1 000
1 200
1 400
1 600
2004 RS 2030 APS 2030
Mtoe
Traditional Biomass Commercial Biomass Solar Geothermal
Note: RS = Reference Scenario; APS = Alternative Policy Scenario
Source: IEA, 2006h
Gross heat production in OECD countries from solid biomass was 164 PJ in 2004, which is
30% of total renewable heat production; 52% was from direct use of solar and geothermal
heat. Heat production from renewable municipal waste28 was 29%.
In 2004, the largest producer of heat from solid biomass in the OECD was Sweden (85 PJ),
representing 52% of total OECD heat production from solid biomass (Figure 5). Favourable
policy instruments and the dominance of biomass feedstock for district heating systems are
major drivers underlying Sweden’s significant development of biomass. Other major
producers were Finland (26 PJ), Denmark (18 PJ) and Austria (14 PJ).
In Sweden, solid biomass – mainly forest products and residues – met 49% of the supply for
district heating systems in 2003, a three times increase since 1990. In Finland, gross heat
production from solid biomass increased from 6 PJ in 1995 to 26 PJ in 2004, an average
annual growth of more than 17% per year. Heat generation is not taxed in Finland and plants
are eligible for investment credits.

28 Renewable municipal waste excludes the non-renewable waste fraction.
39
Figure 5: Solid biomass share in OECD heat production, 2004
0
10
20
30
40
50
60
Sweden
Finland
Denmark
OECD Average
Austria
United States
Czech Republic
Poland
Slovak Republic
Norway
Netherlands
Hungary
0
20000
40000
60000
80000
100000
Share in OECD total Heat output(TJ)
% of Total Heat Production (TJ)
Source: IEA, 2006g
In 2004, heat production from solid biomass in Austria was 14 PJ, up from 1 PJ in 1990.
Federal and state policies have been instrumental in stimulating the market for biomass
district heating plants for villages since the mid-1980s. These policies have primarily taken
the form of implementation management and, as a financial incentive, investment grants.
Installation of biomass district heating plants has increased steadily.
The share of commercial heat in total final energy consumption is also relatively high in
Denmark at 16% due to Denmark’s extensive use of district heating, which was promoted
after 1979 through the National Heat Supply Act. It included a national heat plan and the
possibility for local governments to mandate connection to the district heat network for new
and existing buildings.
In the EC’s 1997 White Paper on Renewable Energy Sources biomass represented 68% of
the EU’s indicative target of doubling its share of renewable energy sources from 6% of
gross domestic energy consumption in 1998 to 12% in 2010 (EC, 1997). However, in its
more recent Biomass Action Plan, the EC highlighted that despite the existence of mature,
straightforward and commercially viable technologies for renewable heating for residential
and industrial purposes, the consumption of biomass is growing slowest in the heating sector
40
(EC, 2005). In its Roadmap for Renewable Energy the European Commission emphasises
that biomass is projected to contribute significantly to the suggested target of 20% of primary
energy supply by 2020 in all three end-use sectors – power, heating and cooling and
transport (EC, 2007b). In the heating and cooling sector, biomass could contribute the bulk
of growth towards the doubling of renewable heating and cooling sources’ current market
share by 2020 through the deployment of high efficiency biomass-fired CHP and efficient
residential heating systems (ibid.). In order to achieve it is assumed that renewable heating
policies are implemented across EU member States, providing sufficient incentives for the
deployment of all relevant renewable heating technologies (EC, 2007c).
The IEA Bioenergy Implementing Agreement29 identifies a lack of demand as the main
barrier to a significant growth in the uptake of heat from bioenergy sources (or “bio-heat”).
The main reason for the lack of demand is argued to be an absence of targeted policy
instruments for renewable heating which would in turn create an enabling market
environment and stimulate R&D investment.
3.2.1.2 Geothermal heat
According to the IEA Geothermal Implementing Agreement30 geothermal resources have
been identified in more than 80 countries, with recorded geothermal utilisation in 72
countries to date. At the end of 2004, total geothermal heating in OECD countries was 175
PJ/year including the direct use of geothermal energy.
It was reported at the World Geothermal Congress 2005 that total annual worldwide direct
use was 273 PJ, which represents an almost 45% increase over 2000 and a compound
growth rate of 7.5% per annum. The numbers include all direct uses, for agriculture, industry,
and space heating. The growth rate has increased in recent years, despite economic downturns and other factors. In space heating there are centralised systems like district heating
networks (in Iceland, a non-IEA member participant in the GIA, geothermal heat supplies
88% of all buildings), and smaller, decentralised ground-source heat pump (GHP) systems.
GHP supplied 79 PJ in 2004 (Figure 6) being the greatest contributor to geothermal heating
and cooling. They contributed decisively to the growth over time due to the growing
awareness of their capabilities, popularity and ability to use them anywhere in the world.
Sweden and the USA contributed 73.4% of total IEA heat production from GHP, with China,
Denmark, Switzerland and Norway also major users. Japan has a strong heat pump
manufacturing industry but GHPs have still not established a market. In general, there are
large discrepancies in GHP usage from country to country; major reasons include the lack of

29 The website link of the IEA Bioenergy Implementing Agreement is: http://www.ieabioenergy.com 30 The website link of the IEA Geothermal Implementing Agreement is: http://www.iea-gia.org/
41
awareness among end users about this relatively new technology as well as the high upfront
equipment and drilling/ installation costs relative to other conventional heating applications,
which commonly deter domestic users with high implicit discount rates.
Figure 6: Geothermal heat pump use for heating and cooling in IEA countries, 2004
0
10
20
30
40
50
Sweden
United States
Denmark
IEA Average
Norway
Switzerland
Germany
Canada
Finland
Austria
Czech Republic
Netherlands
Italy
France
Belgium
Ireland
United Kingdom
Greece
Australia
Hungary
Japan
S.Korea
Portugal**
Luxembourg
New Zealand
Spain
Turkey
0
5
10
15
20
25
30
35
40
Share of IEA total annual heat pump use (%) Annual energy use(PJ/yr)
% of IEA total annual heat pump use (PJ/yr)
Source: Data from Lund et al. (2005)
3.2.1.3 Solar thermal
Low temperature solar heating covers a broad spectrum of technologies, including solar
water heating, active solar space heating, and passive solar heating, all of which have been
commercially available for more than 30 years. Medium to high temperature heat for industry
is also feasible.
The worldwide contribution of solar heat to the overall energy supply is significant. At the end
of 2004 a total of 141 million square meters of collector area, corresponding to an installed
capacity of 98.4 GWth, had been installed in the 41 recorded countries (Weiss et al., 2006)31.
OECD member countries represented 50% of worldwide installed capacity. Of the total

31 The 41 countries (all OECD countries except Korea and Iceland plus – in descending order of total installed
capacity – China, Israel, Brazil, Taiwan, India, Cyprus, South Africa, Barbados, Slovenia, Malta, Latvia, Lithuania,
Estonia) included in this report represent 3.8 billion people or about 58% of the world’s population. The collector
area installed in these countries is estimated to represent 90% of the solar thermal market worldwide.
42
worldwide installed capacity, 34 GWth were accounted for by flat-plate and 40.3 GWth for
evacuated tube collectors, used to heat water and for space heating and 23.1 GWth for
unglazed plastic collectors, used mainly to heat swimming pools. Unglazed air collector
capacity was 1.2 GWth installed. This collector type is used for drying agricultural products
and to a lesser extent for space heating of houses and other buildings (ibid.). In 2004, the
highest collector surface area per 1,000 inhabitants was Cyprus with 582 m2
, followed by
Austria 297 m2
, far above the EU average of 33.7 m2
(EurObserv’ER, 2005b).
The worldwide market for glazed solar collectors has greatly increased over the last decade
to approximately 10 million m2
installed per year – in 2004, 72% of the growth in new
capacity installed occurred in China which represented 45% of the world’s total capacity in
operation in 2004 (Weiss et al., 2006). The largest users of solar water systems among
OECD countries were the United States, Japan and Turkey which account for 74% of direct
use (Figure 7).
Figure 7: Direct use of solar heat in OECD countries, 2004
0
10
20
30
40
50
United
States
Japan Turkey Germany Greece Austria Mexico Australia Other
OECD
0
10
20
30
40
50
60
Share in OECD total Final Consumption
% of Total Direct Use of Solar Heat (PJ/ year)
Source: IEA, 2006g
If one observes the use of solar thermal energy it becomes clear that it greatly varies
between the different countries and economic regions. In North America (USA and Canada)
swimming pool heating is dominant with an installed capacity of 18.8 GWth of unglazed
plastic collectors while in China and Taiwan (44.4 GWth), Europe (10.8 GWth) and Japan
(5.4 GWth) plants with flat-plate and evacuated tube collectors mainly used to prepare hot
water and for space heating are dominant.
43
3.2.2 The security advantages of renewable heat production
The benefits of heat production based on RES with regard to energy security are similar to
those of renewable electricity production (section 3.1.3). The main difference between
electricity and heat markets is the lack of tradability for heat as a commodity. Like electricity,
heating (services) are required at all scales of consumption. Industrial process heating
requires larger-scale equipment, whereas space heating and hot water production in
commercial and especially residential buildings can be achieved both with small-scale
applications as well as with medium- and large-scale technologies.
3.2.2.1 Technical security advantages
Bio-heat, geothermal and solar thermal applications can satisfy the diverse scales of heating
demand due to the modular characteristics of these systems which are based on mature
technologies. Bio-heat technologies can be used for medium- and large-scale heating
purposes, such as to supply district heating systems in metropolitan areas, as in Sweden,
Finland and Denmark, as well as for the small scale space heating of individual buildings,
using wood stoves and pellet burners. Geothermal heat is also a significant provider of heat
on the small scale of individual homes and buildings via GHPs and on the larger scales
through district heating schemes, such as those in Iceland, Turkey, China and France.
In contrast, solar thermal applications are generally used at the domestic level. Most high
temperature solar applications for industrial processes have been on a relatively small scale
and are mostly experimental in nature. Solar Heating Industrial Processes (SHIP), a new
joint task of the IEA SolarPACES and Solar Heating and Cooling Implementing Agreements,
is investigating the potential for solar heat in industry.
Domestic solar water heating has energy security benefits in that it reduces households’
exposure to risk of supply disruption and any sudden increase in fossil fuel prices as heat is
produced on-site. Small-scale domestic renewable heat applications run a lower risk of
technical system failures (although in the case of solar thermal not completely eliminated) as
they reduce requirements for transmission, distribution and service equipment and are not
affected by power losses in transmission lines which can be up to 10% of total generation.
District heating systems based on RES combine both efficiency gains of the economies of
scale with the environmental benefits of using renewable heat sources. District heating pipe
networks allow end users to consume renewable heat without shouldering the installation
cost of individual single building units. Given the more common distributed location of such
installations, the risk of physical security threats is low.
44
Implementation of renewable heating should be considered in tandem with energy efficiency
measures since combining both options creates synergies in terms of energy security. The
buildings sector represents 40% of the EU’s energy requirements. Therefore,
environmentally friendly options for decentralised renewable heating options are encouraged
alongside a push to improve the energy efficiency of buildings in the EC’s Buildings Directive
(EC, 2002). Another pertinent EC directive relating to the promotion of end-use efficiency
and energy services was promulgated in early 2006 (EC, 2006a), which could also further
the diffusion of renewable energy service companies (RESCOs) for both electricity and heat
production.
3.2.2.2 Resource potentials
In terms of resource adequacy, the resource potentials for both geothermal and solar
thermal technologies are virtually unlimited. Unlike the other energy sources, GHPs can be
installed practically everywhere is not restricted by location. In contrast, biomass resources
for heat production are limited and compete with both electricity and transport fuel production
for feedstock supplies. Biomass supply is considered to be variable to the extent that it
depends on climatic conditions and the seasonal cycle of dedicated energy crops.
There are broad ranges for estimated resource potentials for all renewable heat sources.
Geothermal enjoys the advantage of being a non-variable resource, as opposed to solar
energy. As a consequence of the reduced availability of solar energy during peak heating
load times, such as at night and during winter, solar heating systems require either an inbuilt storage system or a back-up heating system often fuelled by natural gas. This reduces
the energy security benefits of solar thermal technologies, relative to geothermal.
Due in part to the relative ease of transporting and storing biomass resources, biomass is
the only one of the three renewable heat sources whose diverse feedstock options have
market prices.
Table 5: Key factors in the availability of biomass waste and energy crops
Biomass residues and wastes Dedicated energy crop production
Demand for alternative uses, e.g. as
fertilisers or as input for recycled paper
Alternative uses of agricultural land,
primarily food production
Climate conditions Climate conditions
Legislation concerning waste Agricultural policy (at the EU level
especially the Common Agricultural Policy)
(Faaij, 2006; Ericsson & Nilsson, 2006)
45
Disruption may interrupt the supply of biomass feedstocks to CHP and heat-only plants or to
wholesalers and retailers of biomass, such as wood chips or pellets, who supply domestic
households. Adequate and affordable storage of biomass feedstocks represent a possible
physical security target. However, this risk can be assumed to be low as storage facilities are
likely to generally be decentralised and reasonably small in size, corresponding to the scale
of heat generation. A discussion of the impact of international trade in biomass resources on
energy security follows in section 3.2.4.
Heating is currently already the cheapest energy conversion mode for biomass with average
costs ranging between USD 0.01-0.05/ kWh (ICEPT, 2002). The dedicated production of
energy crops is generally more expensive at least in IEA Europe, than the use of available
residues and waste, as land and labour are relatively expensive in developed economies
(Faaij, 2006). Upward price pressures due to the increasing influence of international market
demand may threaten the future affordability of biomass resources. This would be especially
so if dedicated energy crops, which compete with different uses for limited agricultural land,
play a dominant role in biomass supply.
3.2.2.3 Affordability
In terms of affordability, solar heat is expected to be cost-competitive with conventional heat
technologies (oil, gas and electricity) across Europe by 2015 due to reduced system costs,
and sooner if fossil fuel prices remain high. In 2000, the cost of solar thermal heat production
was close to EUR130 (USD170)/ MWh for domestic solar hot water systems (Rantil, 2006).
Recent IEA research indicates that this is cheaper than electricity in Denmark and the
Netherlands, comparable to the cost of electricity in Austria, Germany and Italy, but more
expensive than electricity in other OECD countries. It is also more expensive than heat from
natural gas in urban areas (Philibert, 2006). By 2030, solar heating is projected to cost USD
65-105/ MWh for solar hot water systems and EUR50-80 (USD130-180)/ MWh for solar
combisystems. Large-scale solar thermal applications (above 1 MWth), such as district
heating and industrial systems, are projected to cost EUR30-50 (USD40-65)/ MWh (Rantil,
2006).
Geothermal heat applications are generally already cost-competitive in terms of investment
and heat production costs with most conventional fossil fuel heat technologies, both for lowto-medium temperature applications, including district heating, and for very low temperature
applications.
A discussion of the affordability of renewable heat production needs also to consider the
costs of externalities, such as supply disruptions, which market prices for energy sources do
not yet reflect.
46
3.2.3 Regional dimension of renewable heating – energy security
implications
In 2004, fossil fuels accounted for 78.8% of heat production among OECD countries (IEA,
2006b)32. Natural gas represented over 50%, with two thirds of natural gas for heat being
supplied in OECD Europe where it is the most significant energy source for heat production
and accounts for 39.5% of gross heat production (including direct use of geothermal and
solar heat) (ibid.).
The significance of natural gas in the general energy matrix is growing across developed
economies, and especially in Europe. The EU Green Paper on energy security predicts that
by 2030 demand for natural gas will have more than doubled since 1990 and will be set to
overtake oil as the leading energy source (EC, 2000). Its growing importance means that
natural gas presents a significant potential energy security risk due to single source
dependence, transit dependence, facility dependence and structural risks (IEA, 2006h).
Europe’s reliance on natural gas imports is forecast to rise rapidly (by 2030 the dimension of
gas imports will represent between two to three times the current volume up to a maximum
volume of 500 billion m³).
The WEO 2006 scenarios forecast that the share of gas imports in the region’s total gas
supply will also increase substantially (IEA, 2006h). The majority of OECD member countries
import natural gas supplies via pipelines from a limited number of supplier regions. For
OECD Europe it is predominantly Russia, North Africa and the Middle East (Weisser, 2006),
so thus becoming increasingly source dependent.
In contrast, the Netherlands, which is the second-largest producer of heat from natural gas
after Germany, is currently a major exporter of domestic natural gas reserves. In 2002, 66%
of final gas consumption (22.8 Mtoe) was used in the residential and service sectors.

32 This figure takes into account gross heat production both from combustible fuels as well as direct use of
geothermal & solar heat.
47
3.2.4 Local resources and global trade – implications for energy security
Although heat can not be easily traded or transported beyond short distances, biomass can
be. Biomass is the only one of the three renewable heat sources with a fuel input, and
consequently has a market price.
In 2003, trade in primary solid biomass contributed only 0.9% of the solid biomass share of
TPES while for liquid biofuel trade contributed 3.4% of total consumption (IEA, 2006d).
These figures only reflect trade in biomass produced in centralised plants whereas the
majority of biomass resources such as biomass residues and their secondary products, e.g.
wood pellets and energy crops, are produced in decentralised plants so cross-border trade
originating in decentralised plants may not be captured in official government statistics.
The distributed nature of biomass harvesting and production of secondary fuels and the
large number of potential trading partners reduces the structural risks that exist in the supply
Dominance of natural gas for heating in the Netherlands
Natural gas has evolved to be the major fuel source in the Netherlands since the 1970s
with the discovery and development of domestic natural gas reserves. Natural gas now
dominates the heating market with a near-95% market share (IEA, 2004a), and, in
2004, represented 45% of the country’s TPES compared to the IEA average of 22%
(IEA, 2006d). This is the largest penetration of natural gas among IEA countries. Selfsufficiency is facilitated by large domestic gas reserves (the second largest in IEA
Europe) and by the balancing capacity of the large Groningen field which is
complemented by the development and exploitation of small fields under the
Netherlands’ “small fields policy”. In 2004, the Dutch government implemented a
specific production cap on the Groningen field – replacing the previous indirect cap on
national gas production – which should help secure production from smaller fields (IEA,
2006a). In 2005, exports represented 66% of domestic gas production (IEA, 2006d).
However, gas imports are rapidly increasing, transported via pipelines (IEA, 2004a) and
four planned LNG terminals.
In the medium term, the limited gas import capacity of the Netherlands is likely to
become a concern. At present, available contractual capacity at pipeline
interconnections is very small. There is a need to expand capacity for imports by new
entrants as domestic production declines.
Although residential gas consumption has declined following a national drive for
improved domestic energy efficiency (including improved insulation and boiler
efficiency), the decline has been hampered in recent years by an increased use of gas
for hot water production (ibid.).
With the ongoing liberalisation of the Dutch gas market towards the creation of a
Northwest European gas market, the explicit link of natural gas prices with oil prices will
break down, enabling gas prices to full reflect gas scarcity. Together with concerns
about the supply stability of imports, this trend will likely lead to substitution efforts,
particularly towards biomass which enjoys an inherent resilience against supply
disturbances (Jansen et al., 2004). While large industrial users may be able to switch
easily to alternative auto-production capacity, e.g. biomass-fired CHP, most residential
and commercial customers will be less able to do so in the short term.
48
chain for many fossil fuel sources, such as natural gas, which rely on large and inflexible
transport infrastructure, such as pipelines. Flexibility of supply, in terms of diversity of
suppliers and origin and duration of contract, provides biomass for heat with a distinct
security advantage over fossil fuel alternatives.
However, regional and international trade flows and the associated cost and distance of
transport also bring negative implications for energy security including potential domestic
disruption (short-term logistical or longer-term political) in the exporting country’s supply
system which may interrupt cross-border trade flows and thus threaten stability of supply.
However, this risk can be mitigated by establishing a wide and varied group of suppliers
producing a variety of substitutable biomass fuels. A further negative impact is increasing
GHG emissions due to longer transport distances as a proportion of life-cycle emissions of
biomass. Depending on the future scale of international trade in biofuels, the transport
modes used, and on future policy measures to restrict GHG emissions of mobile sources,
this may inhibit the growth of biomass resources for heat (and electricity) relative to the use
of geothermal and solar energy resources which do not require transportation.
The development of internationally standardised certification for biomass, which is still in its
infancy, although national criteria already exist, will support a growth in sustainable biomass
imports.
3.2.5 Effects of renewable heating on fossil fuel demand
Renewable energy provides a direct hedge against volatile and escalating natural gas prices
and it reduces the need to purchase fossil fuels as heat sources, replacing it with fixed-price
renewable energy. Diversification of energy sources for heating, in particular increased
investments in renewable energy, could help alleviate the threat of high gas prices over the
short and long term. By displacing gas-fired generation, increased deployment of renewable
energy is expected to reduce demand for fossil fuel energy sources, such as natural gas, for
heating and consequently put downward pressure on natural gas prices (Wiser & Bolinger,
2006).
Oil as an industrial and residential heating fuel has been increasingly substituted by gas (and
electricity) since the high oil prices of the mid 1970s and early 1980s. In 2004, oil
represented 17% of OECD total final consumption in the residential sector and 19% in
commercial and public services (IEA, 2006d).
49
3.2.6. Challenges and barriers
3.2.6.1 Biomass: uncertainties regarding future supplies
Among IEA countries, European members are currently the major producers of renewable
heat and are likely to remain so up to 2030. The largest biomass potential in the EU-25 (plus
Ukraine and Russia) region resides in energy crops, forest residues and industry byproducts with crop residues, such as from straw and maize, occupying a secondary role
(Ericsson & Nilsson, 2006).
Difficulties exist in forecasting future areas of agricultural land available for energy-crop
production over a time frame of several decades (ibid.) as other land uses compete with
energy-crop cultivation, such as food, fibre and chemical production, environmental
protection concerns etc. Factors influencing the future availability of land include food
demand, farming practices and agro-climate trends. In general, regional variations are likely
to arise or be exacerbated, even if total agricultural production may increase.
Similarly, the future availability of forestry residues and by-products is also difficult to predict
as it is a complex function of the implementation of sustainable forest management
guidelines combined with climate change effects and rising GHG atmosphere concentrations
which are likely to lead to regional variations in forest productivity (ibid.).
The EC asserts in its Biomass Action Plan that at least in the short-term (to 2010) there will
be no major competition for feedstock as electricity and heating rely mainly on wood and
wastes while biofuels rely mainly on agricultural crops (EC, 2005). Furthermore, competition
for feedstock may be restrained, as the optimum efficiency of the conversion technologies
for electricity, heat and transport fuel production rely on different characteristics of biomass
feedstocks.
However, in the medium term, competition for feedstock supply may occur between
electricity and heat production; the IEA’s 2006 Alternative Policy Scenario projects that by
2030 power generation from bioenergy will more than quadruple to 983 TWh (IEA, 2006h)
and, at the same time, it is expected that the majority of bio-heat will continue to be
generated in co-generation plants. Demand for bioenergy supplies for transport fuels may
also precipitate competition, if biofuel production for transport grows as rapidly as forecast
(section 3.3).
3.2.6.2 Balancing electricity & heat production
CHP technologies offer significant advantages with regard to primary energy savings and
avoided network losses by using both electricity and heat generated from a single source.
These systems recover heat that normally would be wasted in an electricity generator, and
50
utilise it to produce steam, hot water, heating, desiccant dehumidification or cooling. Through
the use of CHP systems, the fuel that would otherwise be used to produce heat or steam in
a separate unit is saved. However, as the following example highlights, operational decisions
can be skewed away from the optimal production choice due to an unfavourable policy
framework.
While electricity generation from renewable energy sources is supported in the United
Kingdom under the Renewables Obligation (RO), heating from such sources is not. The UK
Renewable Energy Association argues that the lack of incentives for renewable heating
systems disadvantages biomass which can be used effectively for both electricity and
heating production. Despite enjoying the advantage of being non-variable, the use of the
UK’s biomass resource has not expanded much under the RO because of cheaper, albeit
variable, on-shore wind power generation. A study commissioned by the Department of
Trade and Industry (DTI) calculated that generation costs in 2004 for stand-alone biomass
plant stood at an average of EUR 0.096/ kWh compared to an average EUR 0.058/ kWh for
on-shore wind. Biomass co-firing is a lower cost renewable energy technology with average
generation costs of EUR 0.039/ kWh (Enviros, 2005). However, financial support for biomass
co-firing under the RO is limited and will cease completely by 2016.
If the heat element of biomass output, such as reusing steam in a CHP plant, was valued as
the power element is, then the economic feasibility of biomass would change significantly.
Without a financial incentive for renewable heat a CHP plant operator’s choice between
producing electricity and heat will be oriented towards the electricity portion because of the
associated revenue from the sale of Renewable Obligation Certificates (ROCs), as well as
Climate Change Levy certificates (LECs) in addition to the electricity’s wholesale market
value. This may lead to non-optimal production choices with respect to efficiency, as steam
production with higher process efficiency is neglected.
The demand for renewable heating technologies, such as biomass, geothermal, ground
source heating and solar thermal, could be boosted by the introduction of a market-based
support mechanism modelled on the Renewables Obligation, such as a Renewable Heat
Obligation (RHO), where a quota obligation relative to their fossil fuel sales could be placed
on fossil fuel suppliers of heat, which could be met through the surrendering of Heat
Obligation Certificates (HOCs) from eligible renewable heat producers.
3.2.7. Summary
The technical potential for heat from renewable biomass, geothermal and solar resources is
large. The costs of these heat sources vary. Some are already competitive with fossil fuels
51
and others have the potential to become so. However, in many cases, renewable heat
generation suffers from not receiving comparable support to renewable electricity or energy
efficiency measures. There are also barriers due to lack of awareness of the potential and
the lack of trained professionals to tailor installations. Effective political instruments are
needed to promote the use of renewables in the heating and cooling sector when it can
substitute for the most critical fossil energy resources of oil and gas. Renewable heat
production provides the energy security benefits of distributed supply and production and of
non-dependence on fossil fuel imports.
In order to utilise and benefit from the energy security advantages of renewable heat
sources, renewable heat production must be brought to large-scale market deployment,
which it is capable of in terms of resource potential and technological maturity. Therefore, to
achieve this, governments should develop and implement a support framework of enabling
policy measures, including market-based financial incentives, building on the lessons
learned from support policies for renewable electricity production.
3.3 Biofuel production for transport
Today’s transport infrastructure is vulnerable due to its major dependence on a single fuel
source – oil. Petroleum products provide around 96% of transport fuels and much of the
supply is concentrated in a few countries with economic and political problems threatening
their stability. Liquefied petroleum gas (LPG), compressed natural gas (CNG), biofuels and
electricity provide the remainder.
Trade between oil exporters and highly dependent nations is vulnerable to supply disruptions
for a variety of reasons. Many consumers of petroleum and natural gas resources depend to
varying but significant degrees on fuels imported from distant, often politically-unstable
regions of the world. A disruption in supply could have a severe impact on global oil markets.
When in the foreseeable future international shipping trade in oil and LNG expand, the risks
of supply disruption may increase (IEA, 2006h; CIEP, 2004).
The size of the global problem is easily expressed. In 2005 around 1215 billion litres (Gl) of
gasoline and 1207 Gl of diesel were consumed as transport fuels, equating to 84 Mb of oil
equivalent each day. IEA projections in the 2006 WEO Reference Scenario (IEA, 2006h) are
for 6.3% per year production growth from 20 Mtoe in 2005 to 54 Mtoe in 2015 and 92 Mtoe
by 2030. Growth in the Alternative Policy Scenario would be 8.3% per year, reaching 147
Mtoe in 2030 giving 7% of road transport fuel use (IEA, 2006h).
This understanding of the global position has already led many countries to support the
development of their own biofuels industry with supporting policies, regulations and tariffs.
52
There is now a need for clear government initiatives aimed at fostering the development of
an international biofuels industry to begin to meet the growing demands.
Biofuels are defined as liquid and gaseous fuels produced from various forms of biomass
and used to displace conventional petroleum fuels used for transport (mainly on land but
also for sea and air). Bioethanol, biodiesel, biogas, dimethyl esters and synthetic fuels are
included, but fossil fuel derived liquid fuels produced from oil shales, tar sands, coal-toliquids and gas-to-liquids are not.
The growing oil demand and resultant price increases have led to a sudden worldwide
interest in biofuels not seen since the oil price shocks and severe supply disruptions of 1973
and 1979 caused transport fuel prices to rise rapidly. At that time considerable progress was
made as a result of large RD&D investments to produce bioethanol and biodiesel. Since
then the oil price declined as did interest and R&D funding in biofuels. In the past five years
biofuels have gained renewed momentum, partly due to the goal of reducing carbon
emissions from transport fuels and more recently due to the drive for energy security and the
assumption of higher oil prices. In addition, agricultural policies, and new and improved
processing technologies are propelling many governments to enact powerful incentives for
the use of biofuels. This in turn is encouraging private investment in numerous biofuel
production and processing plants and a growing interest in biomass refineries of the future to
produce a number of chemical products, biomaterials as well as biofuels (OECD, 2004).
The implications of the use of biofuels for global security as well as for economic,
environmental, and public health need to be further evaluated. Biofuels are relatively
convenient to use as low blends in the existing fuels used for the transport vehicle fleet and
can be easily integrated into the infrastructure designed for petroleum fuels. Government
decisions made in the near future will help determine whether the use of biofuels will have a
largely positive impact in the future or not.
As conventional oil prices rise and concerns about long term supplies gain greater traction,
the interest in unconventional oils has also risen (see box). There are large quantities of
these to be extracted. Canada already supplies 15% of its transport fuels (around 1.6 EJ /yr)
from oil sands in Alberta. Heavy oils (orimulsion) mainly in Venezuela and oil shales mainly
in the USA are starting to be utilised and even sub-marine methane clathrates are being
considered at the R&D stage. In all cases, however, they are more difficult and costly to
extract and refine than conventional petroleum products. They also require significant inputs
of energy and/or water, and hence have higher GHG intensities in terms of g CO2 emitted
per person-km travelled (or per tonne-km for freight).
53
Oil reserves and alternatives
Oil accounted for 34.3% of total primary energy supply in 2004 (IEA, 2006b), consumed
in 220 countries. More than 50 countries produce it and 35 are exporters, and it is
consumed in 220. The assessment of the volume used to date, remaining reserves, and
the amount economically available for extraction has been controversial. Oil data is poor
due to non-disclosure of all relevant information by oil producing nations and oil
companies. The uncertainties are poorly understood and there is lively debate about the
issue of “peak oil” which commonly denotes the point of maximum production worldwide
(IEA, 2005).
The IEA’s study on “Resources to Reserves” emphasises that the moment of “peak oil” is
difficult to forecast because of uncertainties over the respective amounts of resources
and reserves (IEA, 2005d), as well as uncertainties about future consumption rates.
Estimates of the time of peak conventional oil range from today to 2050 or beyond. The
IEA stresses that pinpointing when conventional oil production will peak is less significant
than assessing the cost involved (not forgetting to include the cost of CO2 emissions)
when making unconventional fossil fuels available or increasing the recovery rates of
conventional fossil fuels, as well as the impact of energy efficiency gains. Such mitigation
efforts will need a lead time of more than a decade. Therefore, attention to supply,
demand and risk management is warranted.
Conventional oil refers to crude oil produced from well bores by primary, secondary or
tertiary methods. The known reserves, based on geological and engineering information,
can be recovered with reasonable certainty from reservoirs under existing economic and
operating conditions. Additional “probable” and “possible” resources do not yet meet the
criteria for proven reserves but may do so in future with improved knowledge and
extraction techniques, but only if demand exists and market conditions allow. Resource
estimates are therefore difficult to make. Unconventional oil shales, tar sands, heavy oils,
coal to liquids, coal bed methane (and methane clathrates) require different and more
complex extraction and upgrading methods (ibid.).
IEA analysis has indicated that 20 trillion barrels of oil equivalent (boe) (115,000 EJ) of
the world’s endowment of oil and gas remain in the form of both conventional and nonconventional sources (IEA, 2005a). Up to half could be technically recovered, but not
necessarily economically depending on the rate of extraction and long term price
assumptions. To date around 1.5 trillion boe (8,500 EJ) have been consumed. So the
volume of geological resources is not the issue with regard to supply security. More
relevant is the rate of development of new extraction and process technologies, future
prices, supporting policies, investment levels, and mitigation of the increased carbon
emissions.
54
3.3.1 Current role of biofuels worldwide
IEA member countries value biofuels as a means of reducing greenhouse gases, meeting
clean air policies and achieving greater energy supply security by reducing foreign oil
dependence. Developing countries, on the other hand, also consider biofuels to be a means
of stimulating rural development, creating jobs, and saving foreign exchange.
The global production of all types of biofuels for 2005 was estimated to be over 40 billion
litres (or 40 Gl). Combined exports were less than 4 Gl, while Brazil already exports over
10% of its production.
Biofuels can be produced at both the large scale (limited by local feedstock resource
availability) and small scale (limited by maintaining fuel quality standards and higher costs).
In 2005 the world produced 38 Gl of bioethanol (3% of the gasoline volume of 1215 Gl or 2%
on an energy basis) and 3.84 Gl of biodiesel (0.3% of the diesel market of 1207 Gl).
If 2005 total transport fuel demand remained static, and the world were to move towards an
E10 target blend (10% ethanol/90% gasoline by volume) for gasoline alone, some 120 Gl of
bioethanol would be required annually. For an E3 blend, this would be closer to 40 Gl
annually. For biodiesel B10 and B3 blends the volumes of biodiesel required would be
approximately 130 Gl and 40 Gl33.
Brazil, the largest global producer of ethanol (Figure 8), processed around 15 Gl from sugar
cane feedstock in 2005 which met 44% of its total national automobile fuel demand. A further
2.5 Gl were exported, being half of the world ethanol trade (although this is mainly for
beverages and industrial uses). Production figures for 2006 are expected to be
approximately 16 Gl but this depends in part on the competing sugar price as bioethanol
competes for the same feedstock. The Brazilian government has mandated for 23%
anhydrous ethanol content in gasoline and 40% of all vehicles to utilise high ethanol blends
or hydrous E100 by manufacturing more vehicles with flexi-fuel engines (see section 3.3.2).
In the USA, bioethanol production from subsidised corn (maize) crops increased from 4 Gl in
1996 to over 7 Gl in 2002, then doubled again to 15 Gl in 2005 giving overall recent growth
at 15-20% per year (Figure 9). It now accounts for 3% of the total US gasoline market due to
its high octane value and suitability as a substitute oxygenate replacing methyl tertiary butyl
ether (MTBE), which negatively affects the taste and odour of drinking water and may pose
health risks, entering US water supplies from road vehicle exhausts. Ethanol is blended into
30% of all retail gasoline.

33 Biodiesel (33.0 MJ/l) has a higher net energy value than ethanol (21.2 MJ/l) on a volume basis, but both are
lower than diesel (36.1 MJ/l) and gasoline (33.5 MJ/l).
55
Figure 8: Fuel ethanol production, 2000 and 2005 (billion litres/ year)
Source: REN21, 2006
Figure 9: Growth of US bioethanol industry from 1980 to 2004
US Ethanol Production
In billions of gallons
0.1750.215 0.350.375 0.43
0.61 0.71 0.830.845 0.87 0.9 0.95
1.1 1.2
1.35 1.4
1.1
1.3 1.4 1.47
1.63 1.77
2.12
2.81
3.4
4
0
0.5
1
1.5
2
2.5
3
3.5
4
4.5
*Projected *
Source: ACE, 2006a
56
The US Clean Air Act (1990) has driven industrial growth and, amongst other initiatives,
banned the use of MTBE and other toxic and carcinogenic additives into transport fuels. In
August 2005, President Bush signed a comprehensive energy bill 34 which included a
requirement to nearly double the production of bioethanol from 15 to 28 Gl by 2012.
Between 2005 and 2012 this will displace 338 Gl of crude oil and reduce the outflow of US
currency largely to foreign oil producers by around USD64 billion (2005 dollars).
In many US states, ethanol use in transport fuel is mandated at 10% (E10). During the past
two years in California, major fuel companies have switched to ethanol prior to the 2004
deadline for the phase out of the MTBE additives (ACE, 2006b).
The third highest bioethanol producer is China which produced 5 Gl in 2005 mainly from
corn, sugarcane and inedible agricultural products. Growth is reported at 8-10% a year. The
Japanese government supported E3 in 2003 and is currently considering 5% biodiesel (B5)
and trialling E10 but has no local production. The Ministry of Environment has indicated the
possibility of a mandate for 10% in petrol and 15% in diesel for transport use in the longer
term. Demand at these levels will result in ethanol usage of approximately 5-7 Gl per year.
The Canadian government has stated a plan for 35% of petrol to contain 10% ethanol by
2010. This level would reflect a usage of approximately 1 Gl/year. India has approved an E5
blend with an increase to 10% ethanol anticipated by 2010. Indonesia’s current palm oil
production is reported at 4 Gl/ year from 17 production facilities with plans to add biodiesel
processing plants. Plans are in place to increase the level of production by 5 times to 20 Gl/
year over the next five years. Australia has no mandated consumption at present but major
government investments in R&D includes AUD500 million in the Low Emissions Technology
Development Fund, which includes biofuel pilot and demonstration plants, and AUD100m in
the Renewable Fuels Development Fund. Production subsidies of AUD0.30 per litre are in
place for bioethanol and development of a biodiesel plant based on animal fats has just been
announced. Import tariffs on ethanol are AUD0.38 per litre which is a deterrent to Brazilian
imports (AEL, 2006). Germany was the largest producer of biodiesel in 2005, with 1.92 Gl
from oilseed rape being almost half of the world’s supply. France, Italy and the USA are
other leading producers.
In the short term sugar cane is the most economic source and also most efficient in
achieving carbon reductions. Brazil has shown that bioethanol from sugar cane is already
competitive with imported transport fuels and also suitable to become a widely tradable
commodity.

34 Energy Policy Act of 2005
57
Policies and measures
National target levels for biofuels total around 2.8% of the 2006 total worldwide transport fuel
demand. For example the US aims for 10% growth/year of bioethanol (to 28 Gl) by 2012 and
the EU aimed for a 2% market share of motor fuel by 2005 (but only 1.4% was reached by
February 2006) and now aims for 5.75% (12 Gl) by 2010 with 10% by 2020 the long term
goal. This will require a 35%/ year increase in process plant capacity. Mandatory biofuels
targets placed on oil companies exist in 11 countries and other common support policies
include excise tax incentives.
Biofuels have recently received considerable publicity due to increased world oil prices,
energy security concerns and the drive for GHG emission reductions. However, based on
current technologies, costs and policies, only a small proportion of future transport fuel
demand during the next 2-3 decades will be met by biofuels. A 5% displacement of gasoline
and diesel by biofuels as suggested by various policy debates would reduce global oil
consumption of transport by around 1.8 Mbbl/ day (2%) but this would require the current
biofuels market to increase 2.4 times. Hence, policies need to focus on market deployment.
This could be considered as a possible task by the new IEA Implementing Agreement on
Renewable Energy Technology Deployment.
Biofuels can only be fully developed by expanding the range of feedstocks and
commercialising any breakthroughs in advanced conversion technologies including
bioethanol from ligno-cellulosic feedstocks, Fischer Tropsch synthesis, biotechnical solutions
to produce novel biofuels, and development of multi-product bio-refineries. Policies need to
speed the transition to second generation technologies which have a high potential but
currently cost over USD 0.8/ l, when produced in small scale pilot plants.
The land and water resource bases necessary for biomass production need protecting.
Biofuels produced from crops grown in temperate climates remain more expensive, are less
effective at reducing emissions, and hence continue to require financial support policies.
Land use subsidies need reviewing, possibly transferring support from food and fibre to
energy products.
Quota policies that incentivise biofuel production in OECD countries can under some
circumstances have limited value, can be costly in terms of carbon emissions avoided, and
do not necessarily lead to the development of new and improved technologies. Bioethanol
from sugarcane and biodiesel from waste fats and oils remain cost competitive in a high oil
price environment in spite of feedstock price increases. Production of these biofuels should
be encouraged in countries able to provide economic feedstocks, not only for their own
transport fuel supplies but, if in excess, also for export.
58
3.3.2 Fuel standards and engines
Fuel specification standards have been produced in Europe, USA and elsewhere to ensure
only biofuels with pre-determined properties are used and hence warranties by vehicle
engine manufacturers can be maintained. E85 blends (85% bioethanol, 15% gasoline) can
be used to fuel specialist “flex-fuel” engines millions of which already exist, whereas E10
“gasohol” is suitable for most spark ignition engines, though older vehicles may experience
minor problems if seals and plastic fuel pipes are not compatible.
Most compression ignition engines will run satisfactorily on 100% biodiesel (B100) or any
lower blends with minimal modifications. Exhaust emissions are mostly reduced by using
biofuels resulting in improved local air quality particularly in cities. Biodiesel reduces both
SOx and particulates although NOx can increase by 5-30%. Engine life using biodiesel is
increased due to lubricity and low sulphur content. Using gaseous fuels in vehicles is well
understood for CNG and LPG fuels but biogas and producer gas are more challenging,
especially for dual-engine vehicles.
Carbon emissions and energy ratios
Energy ratios (fossil fuel input to biofuels output) are around 1:3 for biodiesel but vary from
1:8 for sugar cane bioethanol down to 1:1.2 (or lower) for corn bioethanol in the USA. Here
diesel is used for crop production, drying and transporting the grain, and electricity, natural
gas or coal are used to fuel the processing and distillation plant. “Well-to-wheel” analyses
have shown that biofuels can range from being close to carbon neutral to producing only a
13% reduction in emissions of GHG per km travelled compared with when using petroleum
fuels. It depends on the level of fossil fuel inputs to produce the energy crop (including
fertilisers) and used by the processing operations. For sugar cane ethanol most of the
energy inputs for heat and power come from bagasse-fired cogeneration plants. Diesel fuel
is only used for harvesting and transporting the crop to the processing plant, so high carbon
mitigation potential results.
3.3.3 Economic feasibility
The commercial viability of biofuels depends on future oil and feedstock prices, land use
change, and possible technological breakthroughs. The existing fuel distribution
infrastructure can be utilised with minimal modifications. Although the future market potential
is uncertain, hundreds of biofuels processing plants are currently planned or under
construction, partly due to the higher oil prices making blending biofuels more attractive.
WEO 2006 projections of 2030 market potential range from 4% (Reference Scenario) to 7%
59
(Alternative Policy Scenario) of total transport fuels but these all have a high degree of
uncertainty.
Cost analysis of biofuels need to be in terms of “litre of gasoline equivalent” (lge) since
bioethanol has a lower heat value of around 63% that of gasoline, and that of biodiesel is
around 91% of diesel. However, the superior properties of biofuels, when they are
combusted in an engine, partly offset these lower heat values. Commercial bioethanol
production costs currently range from USD0.25/lge (sugarcane, Brazil) to USD0.80/lge
(sugar beet, UK) with corn ethanol around USD0.60/lge (USA) and ligno-cellulosic ethanol
from pilot scale plants claimed to be between USD0.80 – 1.00/lge. Biodiesel costs range
from USD0.42/l (animal fats, New Zealand) to USD0.90/l (oilseed rape, Europe; soybean,
USA) with palm oil, Malaysia in between. Development of improved processes and learning
experience and plant scale-ups could lower production costs of bioethanol by 2015 to
USD0.25-0.65/lge and biodiesel to USD0.40-0.75/lge. It should be noted that in the USA and
Europe energy crop gross margins are linked to agricultural subsidies. Excise tax
exemptions also distort the biofuels retail price.
A comparison was made between current and future biofuels prices versus gasoline and
diesel ex-refinery (fob) prices over a range of crude oil prices over a 16 month period until 31
March 2006 (Figure 10). Ethanol from sugar cane (ES) can compete with oil price around
USD40/bbl and biodiesel from animal fats and waste cooking oils (BA) around USD60/bbl
(although volumes available are limited). Other biofuels, based on other more expensive
feedstocks, will only compete when oil is above USD70/bbl unless the production costs can
be significantly reduced by plant scale-up, RD&D investment and learning experience.
Alternatively, government interventions through agricultural subsidies, excise tax exemptions,
carbon charges and other support measures will be necessary.
However, crop requirements for water and nutrients could be constraints. Deforestation to
produce more cropping land to grow energy crops would be a major environmental setback.
The extensive worldwide production of biofuel crops may also result in substantial increases
in the use of artificial fertilisers and pesticides with consequent high risks of contamination of
water supplies.
“Second generation” biofuel technologies will come mainly from cheaper sources of nonedible biomass such as crop and forest residues. Conversion of these ligno-cellulosic
materials by hydrolysis to hydrocarbon biofuels has been researched for decades but so far
with limited commercial success. Several novel systems endeavouring to produce a range of
synthetic fuels and di-methyl esters are under development. Biomass refineries to produce a
range of chemical products as well as biofuels are also under investigation.
60
Figure 10: A comparison between current and future biofuel production costs (US¢/ l
gasoline equivalent) versus gasoline and diesel ex-refinery (fob) prices over a range
of crude oil prices over 16 months
Source: based on IEA, 2006h
Research, development and deployment initiatives will play a crucial role in commercialising
these technologies.
Globally, there are a number of drivers underpinning a rapid increase in demand for
bioethanol and biodiesel as a transport fuel. These include:
• The lucrative carbon credits market, created to allow nations to fulfil their Kyoto
Protocol commitments;
• Mandated requirements on oil companies to retail a share of product as biofuels in
the European Union, Japan and elsewhere;
• The growing use of ethanol to replace the environmentally harmful additive MTBE in
US gasoline;
• Consumer demand for environmentally acceptable replacements for higher priced,
GHG producing fossil fuels; and
• The desire to increase national economic security through a reduced dependence on
oil.
61
In many regions, generous tax breaks are afforded to the bioethanol and biodiesel industry
to encourage its growth. Furthermore, the wealth of experience gained in using blends of
ethanol and gasoline has given confidence to legislators and ethanol producers to
encourage the growth of this industry. Collectively, these drivers are leading to the
establishment of an international commodity market in biofuels. This market will likely
exceed 100 billion litres per annum by 2010 and 250 billion litres by 2020.
By mid 2006, 34 states and eight nations had implemented mandatory biofuels targets to
transport fuel retailers. Such quotas, as described below for the European Union, need to be
carefully designed as they could be met by high cost biofuel technologies and with limited
carbon dividends. Transport fuel supply security will result if dependence on imported oil can
be reduced. However, society will need to determine at what cost it is willing to achieve this
supply security.
Trade in biofuels is seen as a key component of this strategy. Currently there is no specific
customs classification for biofuels and bioethanol is grouped in with industrial ethanol for EU
import duty levies.
The ambitious EU vision for biofuels out to 2030 is that up to 25% of Europe’s transport fuel
demand could be met by biofuels using a wide range of biomass feedstocks (Biofuels
Research Advisory Council, 2006). In addition European technology may well be used by
countries exporting biofuels to Europe. By that time gaseous and liquid fuel demanding
spark and compression ignition engines will probably remain the main powertrains in
vehicles but engine designs will have evolved to better match the second generation
synthetic biofuels. In addition low fuel consuming engines will become common (for example
plug-in, hybrid biodiesel vehicles) so that less biofuels will be consumed per km.
This vision will be met only if biomass feedstock supplies can be produced in a sustainable
manner and biofuels can be manufactured using innovative processes which are
commercially viable. Certainly using the whole harvested plant through an integrated biorefinery (OECD, 2003) is critical but nutrient cycling and water conservation will be other key
elements needed for success.
The 2030 EU target will require a phased development initially aiming at improving existing
biofuel production and processing technologies together with reduced fuel consumption in
the short term whilst also seeking commercial development and deployment of second
generation biofuels in the longer term.
62
Case study of the European Union: the Biofuels Directive
In May 2003, the Council of the European Union promulgated that Member States should ensure
that a minimum proportion of biofuels should be placed on their markets (EC, 2003a). To that
effect national indicative targets needed to be set. A reference value for these biofuels targets was
2%, calculated on the basis of energy content, of all petrol and diesel for transport purposes
placed on their markets by 31 December 2005 and 5.75% by 31 December 2010.
Currently transport accounts for 21% of GHG emissions in the EU and is continuing to rise. Oil is
virtually the sole energy source which gives concerns as it is known to be limited in reserves
which are restricted to a few world regions. Securing transport fuel supplies for the future requires
a wide range of policy initiatives including diversification of sources and technologies and to also
reduce import dependency.
Options include encouraging the manufacture and use of more efficient vehicles, upgrading the
public transport systems, supporting cycling and walking, avoiding unnecessary trips and gasoline
and diesel substitution with biofuels. “The EU is supporting biofuels with the objectives of reducing
greenhouse gas emissions, boosting the decarbonisation of transport fuels, diversifying fuel
supply sources and developing long-term replacements for fossil fuels” (EC, 2006b). By February
2006 less than 2% of the European liquid transport fuels market was supplied from biofuels and
the policy targets are unlikely to be met.
Meeting the Biofuels Directive target of 5.75% (EC, 2003a) would require using between 4 and
13% of the total agricultural land to grow energy crops in the EU (which roughly equates to the set
aside area). However, integrating food, fibre and energy production would reduce this area. It
would also help meet the GHG reduction targets and develop a new industry.
The Biofuels Directive of 8 May 2003 on the promotion of the use of biofuels and other renewable
fuels for transport is to be reviewed by the end of 2006. Emphasis will be placed on its cost
effectiveness, level of ambition after 2010, and the assessment and monitoring of the full
environmental impacts of biofuels versus security of supply.
A “Biomass Action Plan” was adopted in December 2005 to encourage the uptake of biofuels (EC,
2005). The strategy aims to:
• Further promote biofuels in the EU and developing countries, ensure their production and
use is positive for the environment and that economic competitiveness is taken into
account;
• Prepare for the large scale uptake of biofuels by reducing their costs through the
optimised cultivation of dedicated feedstocks, researching “second generation” biofuels,
and supporting market penetration by scaling up demonstration projects and removing
non-technical barriers; and
• Explore the opportunities for developing countries to produce feedstock and biofuels and
to set out the manner in which the EU could support such an initiative for the development
of sustainable biofuel production.
However, the assessment of the Biofuels Directive in the Biofuels Progress Report (EC, 2007a)
showed that the 2010 target is unlikely to be achieved with present policies given the disparities
between the targets that Member States announced for 2005 and the low shares that many
achieved.
To provide clearer and stronger signals for market development, the European Commission in its
Roadmap for Renewable Energy of 10 January 2007 proposes legally binding targets for EU
member states of at least 10%, calculated on the basis of energy content, by 2020 (EC, 2007b).
At the European Council summit on 8-9 March 2007, the member state governments formally
endorsed the adoption of a 10% binding minimum target for biofuels and a binding target of a 20%
share of renewable energies in overall EU energy consumption by 2020 (European Council,
2007).
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3.3.5 Summary
Biofuels could become a potential part solution to some of the most challenging issues
facing the world, including increasing national and global insecurity, rising oil prices,
worsening local and global pollution levels, rising climate instability, and rural and agricultural
development in a sustainable manner.
Bioethanol from sugarcane is the leading contender based on Brazil’s experience and
production should be encouraged elsewhere with technology transfer already going to
developing countries such as Fiji, Mozambique, Paraguay, Bolivia, South Africa and other
African countries.
The potential for biofuels to meet a significant share of transport fuel demand by 2030 is
dependent on the future success of RD&D investment, which will help reduce the production
costs, the availability of suitable land, and learning how to optimise the production of
integrated multi-products, including bioenergy, from relatively scarce land, water and
nutrients,
Energy efficiency improvements and design changes to vehicle engines will be needed at
the same time as biofuel research is conducted to ensure engines are compatible with the
new fuels. Partnerships between oil companies, engine manufacturers and governments will
ensure this occurs. Already, several oil companies have close partnerships with other
smaller private sector companies seeking to produce commercially viable second generation
biofuels.
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4 Conclusions
Security of energy supply should be a key objective of governments if they are to meet other
objectives relating to economic growth. Following a period of stable and reliable energy
supplies since the Second World War (with the exception of the 1970 oil shocks), IEA
member countries, and more recently non-member countries, have invested in roads,
buildings and infrastructure with the expectation that cheap and readily available energy
supplies would continue. Now that a number of threats to the future continuation of
conventional energy supplies have been identified, there is growing concern that other
energy sources need to be found.
Renewable energy systems are well placed to reduce the risk of energy supply disruptions
and the current reliance by many countries on imported fuels. Renewable energy sources
are widely distributed and, in many locations, can provide alternative choices for generating
electricity, producing heat and manufacturing transport fuels. In addition, significant
greenhouse gas reductions and various other co-benefits can be obtained.
The use of renewable energy in itself is not risk free. Supplies vary due to the natural
variable availability of many forms and the costs can be relatively high compared with
traditional energy supplies. In recent years however the costs for renewables have trended
downwards whilst the costs for fossil fuels (including a carbon charge) have increased. Thus
renewables have become more competitive and world growth in capacity for wind and solar
has been around 20% per year for 10 years or longer.
In order for governments to obtain greater security of energy supply, and to help meet their
climate change policy targets, greater uptake of more energy efficient technologies, demand
reduction, and adding more renewable energy systems to the national portfolio make good
sense.
Good co-ordination and collaboration among IEA member nations and between the public
and private sectors is essential if renewable energy technologies are to be successfully
developed to help meet the goals of sustainable development and climate change mitigation
as well as to reduce the risk of continuing disruptive energy supplies.
There is significant scope for further work on the effects of renewables on energy security.
Of particular interest is a detailed quantitative analysis of the impact of RETs on energy
security.
65
66
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72
INTERNATIONAL ENERGY AGENCY
The International Energy Agency (IEA) is an autonomous body which was established in
November 1974 within the framework of the Organisation for Economic Co-operation and
Development (OECD) to implement an inter-national energy programme.
It carries out a comprehensive programme of energy co-operation among twenty-six of the
OECD thirty member countries. The basic aims of the IEA are:
„ To maintain and improve systems for coping with oil supply disruptions.
„ To promote rational energy policies in a global context through co-operative relations
with non-member countries, industry and inter-national organisations.
„ To operate a permanent information system on the international oil market.
„ To improve the world’s energy supply and demand structure by developing alternative
energy sources and increasing the efficiency of energy use.
„ To assist in the integration of environmental and energy policies.
The IEA member countries are: Australia, Austria, Belgium, Canada, Czech Republic,
Denmark, Finland, France, Germany, Greece, Hungary, Ireland, Italy, Japan, Republic of
Korea, Luxembourg, Netherlands, New Zealand, Norway, Portugal, Spain, Sweden,
Switzerland, Turkey, United Kingdom and United States. The Slovak Republic and Poland
are likely to become member countries in 2007/2008. The European Commission also
participates in the work of the IEA.
ORGANISATION FOR ECONOMIC CO-OPERATION AND DEVELOPMENT
The OECD is a unique forum where the governments of –thirty democracies work together
to address the economic, social and environmental challenges of globalisation. The OECD is
also at the forefront of efforts to understand and to help governments respond to new
developments and concerns, such as corporate governance, the information economy and
the challenges of an ageing population. The Organisation provides a setting where
governments can compare policy experiences, seek answers to common problems, identify
good practice and work to co-ordinate domestic and international policies.
The OECD member countries are: Australia, Austria, Belgium, Canada, Czech Republic,
Denmark, Finland, France, Germany, Greece, Hungary, Iceland, Ireland, Italy, Japan,
Republic of Korea, Luxembourg, Mexico, Netherlands, New Zealand, Norway, Poland,
Portugal, Slovak Republic, Spain, Sweden, Switzerland, Turkey, United Kingdom and United
States. The European Commission takes part in the work of the OECD.
© OECD/IEA, 2007
No reproduction, copy, transmission or translation of this publication may be made
without written permission. Applications should be sent to:
International Energy Agency (IEA), Head of Publications Service,
9 rue de la Fédération, 75739 Paris Cedex 15, France.
PRINTED IN FRANCE BY THE IEA
April 2007

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