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GAS SECURITY IN EUROPE

Summary of the analysis

and recommendations provided

to the Group of Seven (G7)

2015-2016

IEA STUDY ON GAS SECURITY IN EUROPE

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CONTENTS

1. EXECUTIVE SUMMARY .................................................................................................................. 3

2. RECOMMENDATIONS FOR ENHANCING GAS SUPPLY SECURITY AT A GLANCE ........... 4 2.1. Transform the building sector .......................................................................................................... 4 2.2. Continue to push wind and solar into the power system .................................................................. 4 2.3. Improve connectivity and flexibility of European gas infrastructure and complete integration

at EU level ................................................................................................................................................ 5 2.4. Strengthening gas storage ................................................................................................................ 6 2.5. Maintain the viability of nuclear power in countries that decide to rely on it ................................. 6 2.6. Expand the Southern Corridor, enhance partnerships with key exporters ....................................... 7 2.7. Support shale development with an adequate regulatory framework .............................................. 7

3. INTRODUCTION ................................................................................................................................... 8

3.1. Natural gas in a modern energy system ........................................................................................... 8 3.2. Gas supply security – the state of play and the impact of current market and policy trends ......... 12 3.3. Even with efficient markets, European import dependency on Russian gas will not

meaningfully decrease ............................................................................................................................ 14 3.4. LNG markets will become more competitive and secure, but remain limited in their

contribution to global security of gas supply .......................................................................................... 20 3.5. China emerges as a key driver of global gas markets .................................................................... 26 3.6. Swing production capability is declining, especially in Europe ..................................................... 27 3.7. Fuel-switching capability is declining ............................................................................................ 27

4. RECOMMENDED MEASURES TO ENHANCE EUROPE’S GAS SUPPLY SECURITY .............. 30

Box 1: Enhancing Europe’s gas supply security..................................................................................... 30

5. REFERENCES ...................................................................................................................................... 54

Preface

Given the increasing globalisation of gas due to the expansion of LNG trade and the deep interactions

of gas with the rest of the energy system, especially through power generation, a narrow approach

focusing only on gas as a standalone fuel in an individual region is no longer appropriate. A new

approach covering both the security and transparency issues of the LNG value chain as well as the

demand side aspects of supply security is required.

Considering the new challenges and opportunities emerging with the globalisation of natural gas

markets, Ministers have asked the IEA Secretariat at their 2015 IEA Ministerial meeting to develop

potential options for IEA activities that would enhance global gas supply security. To operationalise

the mandate, the IEA secretariat is developing an action plan with the aim of enhancing transparency

and helping policy makers in resilience assessments. The action plan evolves around three areas:

creating an LNG knowledge centre, conducting comprehensive resiliency assessments of gas systems

in various countries and regions, and a regular gas market and supply security report, with focus on

the interaction of gas with the rest of the energy complex and the infrastructure aspects of supply-

security. Over the past years, IEA activities on gas security have supported the renewed efforts of G7

countries to strengthen the collaboration on gas security under the German Presidency in 2015 and the

Japanese Presidency in 2016. The analysis presented in this study builds on the work that the IEA has

conducted on gas supply security in the framework of its G7 mandate, in close cooperation with the

European Commission. This work has been made possible by a voluntary contribution from the UK

Government.


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1. EXECUTIVE SUMMARY

Market development and security implications: key findings of IEA analysis

Natural gas has a growing role in the global energy system and it remains critical in maintaining

both electricity security and residential winter heating in temperate climate conditions. Because

of the sensitivity and exposure of both electricity and heating sectors, gas security remains high

on the policy agenda.

Geological resources of natural gas are sufficient to cover projected global gas demand for

decades. On the other hand, due to the physics of gas transportation, gas pipeline infrastructure is

more capital intensive than oil transportation, which led to regional markets and a higher region-

specific exposure to the risk of a single supply source and its disruption.

In a carbon constrained world (IEA 450 scenario), gas share remains important, as is used to

balance renewables up to 2020, however total gas use declines after 2030 towards 2050. This

leads to a more rigid gas demand with less demand side response capability. As the coal – gas

interaction of the conventional system is replaced by the wind (solar) – gas interaction in a low

carbon system where gas is running only when the renewable resource is not available, the ability

to switch to another fuel in short notice in the case of a market disruption declines. As a result,

the contribution of gas to a low carbon system requires a more resilient gas infrastructure.

Conventional gas fields provide swing production capability. These fields are increasingly

replaced by long-distance imports (in Europe) or shale gas (in North America) which both has

considerably less short-term swing potential. Structural changes on the supply side reinforce the

transformation of the demand side to create more rigid gas markets and call for an enhanced

infrastructure and storage flexibility.

Under IEA baseline projections Europe’s gas imports from Russia will not meaningfully

decrease. The growth of renewables is significant but fails to compensate for the simultaneous

decline of coal, nuclear and domestic gas upstream. Given policy and infrastructure constraints

in the Middle East and the Caspian, pipeline diversification (the Southern Corridor) will not

reach a transformative scale. Global LNG supplies expand, but under baseline projections

Gazprom retains the ability to price out North American LNG from the European gas market if it

chose to do so. The report provides for seven policy options to reduce Europe’s dependency on

Russian gas. Such a reduction is possible, but it requires stronger policy measures especially

relating to energy efficiency in buildings, investment in renewable energy, notably for the heat

supply diversification as well as the promotion of investment in a diversified import portfolio.

LNG plays a crucial role as it increasingly links the major regions and it enables global responses

to a regional shock such as the way European coal power plants enabled reducing EU LNG

imports and their redirection to Japan. The emergence of Australia and North America as major

LNG suppliers will lead to a more efficient and competitive gas market. On the other hand, no

LNG exporter is likely to maintain swing production capability (like Saudi Arabia in the oil

markets); LNG markets could redirect existing supplies only in the short term.

Europe’s gas infrastructure and internal connectivity has improved, but limitations in the ability

to respond to large-scale supply disruptions persist, particularly in Eastern Europe and South

Eastern Europe. Reverse flows have become available; however, not everywhere in the region.

The structural changes in the energy system mandate a new approach to gas supply security.

Moreover, the Ukraine conflict has a potential to change the energy security perceptions of

Russian gas which is, and remains in the baseline, the single biggest gas supply source of Europe.


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2. RECOMMENDATIONS FOR ENHANCING GAS SUPPLY SECURITY AT A GLANCE

2.1. Transform the building sector

Governments should accelerate energy efficiency improvements and deployment of low-

carbon heating systems in new and existing building stocks.

In the European Union, building heating is the single biggest component of gas demand,

significantly exceeding power generation. It is very rigid due to the lack of short-term substitution

possibilities and is with social and political sensitivity. These natures make this demand segment

more significant in energy security terms than its share in energy balances. Although the building

sector offers a large and cost-efficient energy efficiency potential, practically no country is on

track to achieve this. Governments should redouble efforts to accelerate energy efficiency

improvements, especially through the refurbishment of the existing building stock. This will

require strong policies, information dissemination, and careful management of the energy

efficiency supply chain as well as the provision of creative financing solutions to tackle credit

rationing problems. In addition to the improvement of energy efficiency, further efforts are needed

to accelerate the deployment of low-carbon heating systems such as renewable heat and electric

heat pumps. Very often the policies on renewable heat and heat pumps lack ambition and are

hindered by transaction costs, investment barriers and inadequate financing. Governments will

need to make sure that the policy attention and financial resources committed to renewable heat are

proportional to its potential contribution to emission reduction and gas supply security.

2.2. Continue to push wind and solar into the power system

Given the major benefits of wind and solar deployment on CO2 emissions and import

dependency on fossil fuels, governments need to support the system transformation required

to facilitate the integration of variable production.

Wind and solar deployment has already had a major impact on both CO2 emissions and gas supply

security. While the improving cost efficiency of wind and solar technologies is a major

achievement, large-scale deployment necessitates a system transformation to facilitate the

integration of variable production. The beneficial impact of reducing import dependency must not

be achieved at the price of deteriorating electricity security. In a number of IEA member states,

including Japan and Germany, electricity grid constraints and system operation difficulties are a

more serious obstacle to wind and solar deployment than the cost of support policies. In order to

fully achieve the potential energy security and sustainability contribution of wind and solar power,

a system transformation is needed. Instead of rigid, infant industry policies, renewable support

schemes should increasingly create incentives for system-friendly deployment by exposing wind

and solar to price signals from a technology neutral balancing market as well as to location signals

that incorporate network bottlenecks and costs. Electricity system operation should embrace the

capabilities of modern IT systems with close to real-time system operation and gird monitoring.

Enhancing interconnection capabilities and integrating control zones enable a more cost-efficient

and secure renewable deployment. Retail market regulation and metering policies should

encourage a more elastic demand side response. Last but not least, flexible conventional balancing

capacity − especially gas turbines − will remain essential to maintain grid stability for decades to

come. As a result, an electricity market design is needed that maintains the investment viability of

these capacities, taking into consideration their evolving role in the power system.


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2.3. Improve connectivity and flexibility of European gas infrastructure and complete integration

at EU level

At the EU level, governments should further advance gas market integration and liber-

alisation by establishing physical and legal infrastructure for better interconnection, in-

cluding reverse-flow capabilities.

The creation of a properly integrated single market is an important component to enhance energy

security and facilitate the entry of new gas sources. A single gas market requires a pipeline

infrastructure that can serve as a physical platform and a regulatory environment that enables

genuine open access and market-based pricing. From a regulatory stand point, this process has

long been completed in the United Kingdom. However, in other parts of Europe – particularly in

Eastern and South Eastern Europe – the opening and liberalisation process, as well as the upgrade

of underlying physical and regulatory infrastructure, has proceeded more slowly.

Since 2009, Europe has made important progress in implementing reverse flows, in the aftermath

of the disruption of the gas supplies from Russia via Ukraine and thanks to co-funding from the

European Energy Programme for Recovery (EEPR) during 2010-12. This was supported by the

2009 technical study of possible reverse flows in Europe conducted by GTE+ (predecessor of

ENTSO-G). Nevertheless, to date, there is no – or only limited – reverse-flow capacity on some

key borders that could act as gateways for alternative gas sources such as France to Germany, Italy

to Austria and in general towards South East Europe.

To aid investment decisions policymakers could benefit from a granular assessment based on gas

flow models that can identify specific constraints under different scenarios and that could be used

to identify effective cost measures to address them. This would include identifying the wider

benefits from enhancing reverse-flow capacity on some key borders, including to other countries.

Establishing reverse-flow capability is a cost-efficient method to enhance supply security and

market functioning. Reverse flows are mandatory under EU security of gas supply rules (EU Gas

Security Regulation No. 994/2010, Article 6.5 and Article 7). Unfortunately, it seems many

exemptions from the reverse-flow capability obligation have been granted too lightly under the

Article 7 procedure by the national competent authorities concerned. The European Commission

should review all reverse-flow exemptions granted with a full consideration of the potential

security benefits, based on regional risk assessments. As part of the review of the EU Regulation

No. 994/2010, revising the article 7 exemption procedure towards a regional approach in

determining reverse flow benefits based on the regional risk assessments and plans with a review

role for the European Commission should therefore be considered.

In addition to reverse flows, new physical infrastructure will also be needed to complete the single

market, especially in the North-South direction. Such projects are often held up by disputes on cost

allocation, despite the fact that their investment cost is trivial compared to the EU import bill. The

Commission and ACER together with the national regulatory agencies should take a strategic

approach towards supporting projects that complete the market integration. Last, but not least, an

effective single market needs not only physical infrastructure but also a functioning market design.

The overall principle of transparent market-based allocation of cross-border capacity is absolutely

correct, but needs to be consistently applied and enforced. In several cases, interconnection

capacity has been allocated in a non-market based fashion, often to the incumbent monopoly; long-

term contracts often create contractual congestion. The development and implementation of the

new gas target model needs to be kept on track and adequate competition oversight should be

vigorously applied.


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2.4. Strengthening gas storage

Governments should review and redesign current regulations and tariff structures to give

stronger incentives to gas storage investment and storage fill.

Gas storage can make a very powerful contribution to supply security. Gas storage was the single

most important channel for responding to both the 2009 Russia – Ukraine gas disruption in Europe

and to the 2013/14 polar vortex in North America. In a theoretically perfect market, spot and

forward price signals would create an incentive to store gas, and widening price differentials create

incentives for new storage investment. Unfortunately, it is debatable whether this perfect market

case is an adequate basis for regulatory policy. While winter – summer demand fluctuations are

typically well reflected in the forward price curve, the possibility of low probability – high impact

events − such as a transit disruption or a sudden demand upswing − is not necessarily. In Japan and

Korea, geology constrains gas storage options while in Europe, the overwhelming majority of gas

storage capacity has been designed for a winter – summer cycle and has a rigid operation. Raising

the peak withdrawal rate compared to the mobile capacity (the gas stored annually) and enabling

multiple cycles is a very significant additional investment; many storage operators would be

reluctant to commit this financing on the basis of forward price signals only. In the absence of very

high balancing charges that reflect the social and economic cost of a disruption, market

participants could have an incentive to undercontract and rely on spot markets; but this, in turn,

could lead to liquidity disappearing in less-than-perfect markets.

The experience of countries that adopted strategic stockpile policies has been that it is a rather

expensive policy and is difficult to set up without causing market distortions. While governments

in especially exposed regions might consider strategic stockpile policies, recommending it as an

overall IEA best practice does not appear to be justified. On the other hand, there are options to

fine tune the regulatory policies to improve the supply security contribution of storage.

Transmission tariffs could be redesigned to improve the business viability of gas storage. In

several countries, storage tariffs are regulated which creates the opportunity to design tariff bands

that incentivise a higher level storage fill, taking into account the high fixed costs of storage

facilities. Better interconnections and market integration enables the optimal utilisation of storage

capacities on a regional or even continental basis. Governments should maintain trust in the market

functioning. At the same time, market participants need to be confident that their title for gas

stored in another country will be respected even in a crisis situation, with governments refraining

from intervening in storage allocation and interconnection flows in order to gain security benefits

at the expense of their neighbours.

2.5. Maintain the viability of nuclear power in countries that decide to rely on it

Governments with policies to continue reliance on nuclear power should adopt regulatory

systems to ensure investments in the nuclear sector without compromising safety.

In both the European Union and the United States, nuclear generates over three times more low-

carbon power than wind and solar combined. In Japan, even the current ambitious renewable

policy will not reach the scale of the pre-earthquake nuclear production for decades. Uranium

supplies are secure and well diversified, and several months’ fuel supply is routinely stored at the

plant sites. IEA member states have strong domestic technological capabilities for nuclear power

generation and the fuel cycle. Nuclear plants generate baseload power that is straightforward to

integrate into a conventional transmission system. Some IEA member countries have made a

legally binding decision to not use or phase out nuclear power. This set of recommendations

accepts the sovereign decision of these countries, and instead focuses on those countries who, in

their energy policy strategies, count on a contribution from nuclear. Nuclear capacity is aging in


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IEA member states; without new investment a substantial fall is expected in the foreseeable future.

A combination of project management risk, very long lead times and high initial capital

commitment as well as low or non-existent carbon prices means that it is highly debatable whether

private nuclear investment is possible on the basis of wholesale electricity market signals.

Countries that aim to maintain a viable nuclear production fleet should adopt licencing and

regulatory regimes that minimise the risk of project management problems without jeopardising

nuclear safety. In addition, such countries should consider the introduction of risk management

methods that that enable the mobilisation of investment that will be necessary to replace aging

reactors. Such measures can take the form of long-term contracts or contract for difference

structures, capital and credit guarantees as well as the enabling of vertical integration in the

regulatory system.

2.6. Expand the Southern Corridor, enhance partnerships with key exporters

Governments should render policy support and mitigate risks for energy infrastructure

projects that aim to import gas from diverse regions.

Natural gas resources are abundant; there is no geological constraint on gas supply security for

decades. Unfortunately, a substantial proportion of the gas resources that could in principle be

developed to enhance diversification in importing regions is affected by a considerable degree of

political and security risk which makes their full potential unlikely to be developed on a purely

private basis. Moreover, such gas resources, especially landlocked ones typically require

politically complex and capital intensive transit infrastructure development. The capital investment

need of gas infrastructure can easily exceed the investment need of upstream, and is a completely

sunk investment which can become stranded as a result of changes in supply – demand

fundamentals, geopolitical events or energy policy changes in either the exporting or importing

region. In some cases, there are serious doubts about the ability of the private sector to execute the

necessary infrastructure investments that enable the mobilisation of new upstream sources. In such

cases, the energy infrastructure projects should receive strong and coordinated foreign policy

support from the G7 and other IEA member states. In certain cases, it could be legitimate to apply

financial risk mitigation to facilitate infrastructure investment in the form of capital guarantees,

interest rate insurance or through development aid finance and export credit institutions.

2.7. Support shale development with an adequate regulatory framework

Governments should adopt regulations based on “Golden Rules” to obtain a “social license”

to develop shale gas resources.

Shale gas development makes an important contribution to gas supply security and international

gas markets. Experience from large-scale commercial development in North America suggests that

technologies, like hydraulic fracturing, have a potential environmental impact, but legitimate

environmental concerns can be addressed through the appropriate regulatory and management

oversight. Shale gas bans and moratoria that several highly import-dependent countries have

applied can have a detrimental impact on energy security. Environmental impacts can be managed

without jeopardising the economic and security benefits of shale gas. The licencing and regulatory

regime must take into account the technological characteristics of shale development, especially

the need for scalability, standardisation and large-scale production methods. An overly intrusive

licencing policy leading to project delays and high transaction costs can undermine the economic

viability of shale and equal to a de-facto moratorium. Governments should adopt a “Golden Rules”

regulatory environment that enables large-scale shale development to strengthen energy security

while ensuring social acceptance and environmental integrity.


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3. INTRODUCTION

This document gives attention to the short-term and long-term policies needed to strengthen security of

gas supplies and enhance the resilience of the European gas system to supply disruptions.

3.1. Natural gas in a modern energy system

Natural gas plays a crucial role in energy supply. It has been consistently growing more rapidly

than total energy consumption. In all OECD regions it is dominant in building heating, which is

the largest single component of gas demand in Europe. Building heating is characterised by a rigid,

temperature dependent demand, a slow moving capital stock with significant but gradual energy

efficiency opportunities as well as the lack of both consumer on-site storage and short-term fuel

switching opportunities. For understandable reasons, building heating has very high social and

political sensitivity. A very similar dominance of gas (or gas-based cogeneration) is observable in

the former Soviet Union. In Northern China, which has temperate climate and a population

exceeding Europe’s, natural gas is rapidly increasing its importance in building heating.

While growth in building heating gas demand is reasonably stable except for China, gas use in

power generation has grown rapidly (other than in Europe) and globally represents the largest

component of gas demand. Modern combined cycle gas turbines have short investment lead times,

low capital costs and their operations combine high efficiency and flexibility with a relatively low

environmental footprint. As a result, they have dominated private investment in power generation

in competitive electricity markets in both Europe and North America. There has also been a

significant build-up of gas-fired power generation capacity in the Middle East and the Former

Soviet Union, in both cases driven by the availability of cost efficient domestic gas resources. The

important exception is the Asia-Pacific region where the constrained availability and the high price

of gas till recently combined with abundant and cheap coal resources constrain its role, although

gas-based power generation is growing even there. Globally, 22% of electricity is generated from

natural gas, but this greatly understates its importance for two reasons:

The combination of lower environmental footprint and high energy density makes gas uniquely

well suited for densely populated urban areas.

A substantial proportion of global power generation is baseload nuclear and coal units or non-

dispatchable renewables. Gas plants tend to run at lower load factors so compared to its 22%

share in the power generated, it plays a disproportionate role in providing capacity and

flexibility to the power system.

Given this important role of gas plants in electricity system operation, without gas it would

currently be impossible to keep the lights on in most North American and European regions, as

well as in the Middle East, Japan, Korea, Russia, several other non-OECD countries.

Natural gas supplies around 20% of the energy needs of industry. This headline number

understates its importance for industry for two reasons:

Steelmaking, which has very large energy needs, is dominated by coal as an energy source and

reduction agent. In industrial energy use other than the steel industry the share of natural gas is

considerably higher.

The biggest single source of final energy consumption in industry is electricity, which in turn

has a considerable indirect dependence on natural gas.


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Natural gas is broadly used in industry for heat for chemical processes, mechanical engineering,

food processing or textiles. In addition, it also has a major role as a chemical feedstock in

petrochemicals and the fertiliser industry. Modern agriculture is critically dependent on natural gas

based fertilisers which represent around 2% of global gas demand.

A still relatively minor, but rapidly growing segment is the use of gas as a transport fuel, especially

in road vehicles and as a maritime bunker fuel. Natural gas vehicles use internal combustion

engines with minimal modifications but deliver substantial improvements in local air quality and

often in fuel costs as well. IEA projections show that in the next five years the expanding role of

gas in the transport sector (especially in China and the United States) will cut oil demand growth

by around 0.5 mb/day, which is considerably more than biofuels and electric cars combined. In the

shipping industry new environmental regulations drive a shift away from heavy fuel oil, with LNG

emerging as a credible replacement. For heavy trucking and shipping, it is technically possible to

build the vehicle as dual fuel so that it has the capability to run on both gas and oil, sometimes

even changing en route. Such flexibility is obviously beneficial for gas supply security.

IEA projections show gas continuing to increase its share in global energy consumption. The long-

term growth rate of natural gas demand (IEA World Energy Outlook New Policies Scenario - WEO

NPS) is 1.4%, considerably faster than total primary energy demand (IEA, 2015a). Importantly,

both in Europe and the United States, gas is on track to bypass oil as the largest single energy

source before 2035, although this is taking place in the context of declining oil consumption. On a

regional basis three regions play a crucial role in the growth of global gas demand in the medium

term leading to a reshaping of trade flows:

In China, despite slowing total energy consumption, increasing policy priority on air quality

and reducing dependency on coal drives a substantial increase of gas consumption, equivalent

to around one quarter of global consumption growth by 2040.

In North America, abundant and cost efficient domestic gas supplies coupled with a

substantial decommissioning of old coal-fired power generation capacity leads to steady gas

demand growth by 2040.

In the Middle East, extremely strong electricity demand growth coupled with policy objectives

to reduce oil burn increasingly drive the growth of gas-fired power generation and thus gas

demand, primarily absorbing domestic supply, although several countries in the region

increasingly import.

On a sectorial basis, although discussions on the role of gas often focus on the electricity sector,

gas does not significantly increase its share in power generation on a global basis. Power

generation does represent the single biggest growth driver for gas but this is sufficient only to

roughly stabilise its role in global power generation. Rapid, policy driven deployment of

renewables and the continuous robust economics of coal limit the share of gas in several important

regions including Europe and China. Gas does increase its share measurably in industrial energy

use while in the building sector its share remains constant, as the spread of gas heating in China is

offset by energy efficiency measures elsewhere.

On the supply side, IEA analysis finds that global gas resources are sufficient to supply growing

demand for decades to come. Although the spread of shale gas production outside North America

has been slow and faces both geological and regulatory difficulties, even without large scale non-

North American shale production the combination of abundant conventional resources and North

American shale production paints a reassuring picture of resource availability. Importantly, during

the upswing of shale production in North America, large conventional discoveries also continued

to take place.


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Of course those resources need to be developed and brought to markets. Natural gas upstream is

the technological twin brother of oil upstream, relying on the same type of investments into

seismic assessment, drilling and reservoir management. Very often it is undertaken by the same

companies and a substantial proportion of global gas supply is produced together with oil. This

relationship has advantages and disadvantages. Gas often benefits from the technological progress

of oil upstream such as the application of horizontal drilling to shale gas formations. Associated

liquids often provide a powerful financial benefit for gas projects, enabling field development at

lower gas prices. On the other hand, the recent cost inflation in oil upstream for drilling as well as

offshore operations also has had a major impact on gas upstream project costs.

Overall, the IEA World Energy Investment Outlook (IEA, 2014a) foresees an over USD 6 trillion

investment need in gas upstream in the next two decades. This investment is undertaken either by

privately owned, well capitalised oil and gas companies or by the National Oil Companies (NOCs)

of the resource holding states that tend to have strong oil revenues as well. There appears to be no

major concern over the availability of investment capital for gas upstream and the ability of the

industry to finance upstream investment. That said, several governments especially in the Middle

East and Africa set regulated producer prices on gas upstream, often at a level that is inconsistent

with investment costs. This has a potential to act as an investment barrier. Substantial gas

resources are located in countries affected by security risks or geopolitical barriers such as Iran,

Iraq or Nigeria. Such political risks and constraints do play a role in determining which gas

resources will be developed first, with higher cost, geologically difficult but politically secure

resources such as Australia often prioritised. Nevertheless, the sheer scale and geographical

distribution of resources is such that even incorporating real life political and security constraints,

there is little concern about resource availability.

The similarity between oil and gas becomes a marked difference beyond upstream. Due to the

gaseous nature and lower energy density of gas, the infrastructure component of the investment

need is markedly higher. The two technical options for gas transport that are in large-scale use,

pipelines and liquefied natural gas (LNG) tankers, are both capital intensive and require a

considerably higher investment than oil transport for the same energy quantity. According to

WEIO analysis, transportation represents 8% of the global oil investment need, but 30% of the

global gas investment need. Given that global gas investment includes the substantial but not very

transport-intensive domestic North American and Middle East systems, the importance of

infrastructure is even higher for the gas export projects that play a crucial role in the supply

security of importing regions. In fact for LNG projects, liquefaction and shipping capacity

routinely represent more than half of the investment need, and this can easily be the case for long

distance pipelines as well.

Capital intensity of gas infrastructure has hindered development of globalised gas markets.

Historically, most gas was sourced close to consumption centres, inter-regional trade was

relatively small, and supplies were primarily transported by pipelines based on long-term

contracts. Operating costs (primarily energy consumption for pipeline compressors and

liquefaction trains) represent only a minor proportion of gas infrastructure costs. Consequently

such an infrastructure, especially pipelines, represents a sunken investment which is heavily

exposed to the risk of underutilisation due to changes in regional supply – demand balance. In the

case of oil, investment is dominated by upstream and the existence of a global market provides a

hedge. For example, regional consumption of both oil and gas has declined in Europe. This did not

lead to any significant value destruction1 in upstream oil due to the ability of the global market to

absorb the impacts of European decline. For gas, significant value destruction took place as some

1 For European oil refineries (which are region-specific, sunk investment), significant value destruction took place.


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pipeline systems and even some upstream assets such as the Bovanenkovo development in Russia

have been seriously underutilised.

Of course the existence of underutilised upstream and infrastructure assets normally improves

resilience, but it also creates a reluctance among investors to engage in investments in the absence

of contractual guarantees that are generally not needed in oil upstream. Consequently, financing

the over USD 2.6 trillion investment needed for gas infra-structure that the WEIO foresees in the

next two decades represents an energy policy challenge. The infrastructure investment dilemma

can be especially acute for projects that primarily promote diversification and improvements in

energy security rather than serving baseload demand. In this case utilisation rates and revenues

from the project itself can be low, with benefits yielding to market participants other than the

project sponsor (for example customers that can negotiate lower prices from a larger supply base).

Every major region of the world economy except for Europe is expected to increase its gas

production. The geographical discrepancy between production and demand growth means that

long distance trade also increases, although the regions driving demand growth − namely China,

North America and the Middle East − also have a robust growth of production. In the case of

China and the Middle East, this fails to keep up with demand, leading to a growth of import

dependency in China and falling exports for the Middle East, whereas a rapid expansion of shale

production turns North America into a sizeable exporter even with robust demand growth.

On the basis of its massive reserves and already well developed infrastructure, Russia is set to

remain the largest exporter for decades to come. Its production growth is driven by exports,

increasingly towards Asia. Apart from new Russian and Central Asian pipeline supplies to China

and new pipeline flows from the Caspian to Europe, the bulk of new supply to importing regions

will be transported in the form of LNG. Despite the high capital costs, LNG has a strategic value

as it is the only technical option to transport gas across continents, and thus separate the upstream

value from the developments of an individual region. With the emergence of Australia, North

America and East Africa as significant new LNG exporters, LNG supply will become measurably

better diversified with a lower level of geopolitical risk.

Natural gas has less exposure to climate policy than other fossil fuels. In fact it is the only fossil

fuel whose demand still increases by 2040 in the IEA 450 ppm scenario2. This resilience has two

main reasons:

Gas has lower carbon intensity than other fossil fuels. In the power generation sector, switching

from coal to gas can deliver large CO2 emission reductions. Gas fired power generation is a

scalable technology ready for large-scale deployment without a major reconfiguration of the

electricity system. As a result, especially in coal-heavy systems such as China the expansion of

gas fired power generation is an important potential channel of reducing carbon emissions.

Decarbonisation of the electricity system relies heavily on the deployment of variable

renewables, wind and solar. IEA analysis suggests that dispatchable power generation will

remain essential for electricity supply security, but the cost efficient integration of renewables

will require a system transformation with low capital costs, flexible capacity added. Modern

gas turbines fit this role perfectly.

It is clear that gas alone cannot achieve decarbonisation to the level required for a 2 degrees

Celsius climate target. In fact global gas reserves alone have higher carbon content than the carbon

emission budget that is consistent with a 450ppm climate stabilisation. As a result, in the later

stages of decarbonisation, gas demand will also have to decline unless gas plants are equipped with

2 The IEA 450 ppm scenario describes the transition to a low-carbon energy system. In the 450 ppm scenario, supply side and energy

efficiency investments are modelled in a fashion to be consistent with a 450 ppm GHG stabilisation.


12

CCS. In the longer-term analysis, this must take place in the period 2035 - 2050. This is beyond

the investment horizon of most upstream investment projects, but very relevant for investment

decisions concerning long-lived large-scale gas infrastructure projects.

Nevertheless, due to the decline of conventional production in practically every region, there is a

need for new gas supply investment even in the WEO 450ppm scenario. For example, European

gas import needs increase from the current level in the 450ppm case until 2020. However, they

increase much slower than they would otherwise and after 2030, imports needs will actually

decline in the 450 ppm. The Paris Agreement 2015 sets out the ambition to limit the global average

temperature rise to well below 2 °C and pursuing efforts to limit the temperature increase to 1.5

°C. In a carbon constrained world, the demand of natural gas is expected to be compressed, but its

role will change towards a flexibility fuel. The role of natural gas has to be assessed from a climate

change perspective. This may not support the business case for the construction of additional

large-scale physical infrastructure projects in Europe. In some regions, especially in Europe, we

currently observe the write off and mothballing of gas power generation assets, but this is an

electricity market design issue, as the capacity will be needed even in a low-carbon power system.

3.2. Gas supply security – the state of play and the impact of current market and policy trends

Gas supply security policies have been implemented in various countries for decades, and gas

supply security has been formally part of the IEA work programme for several years. As a result,

there is strong policy and regulatory experience to draw upon to identify the key aspects and

enablers of gas supply security. Nevertheless, current market trends as well as the interaction of

market, technology and policy drivers that reshape the role of gas in the energy system could

potentially have significant implications for gas supply security and could necessitate a revaluation

of gas supply security policies. In summary, the current policy view on gas supply security has

been shaped by the following factors:

Due to the capital intensity of gas infrastructure, gas does not have a global market.

Consequently, supply security policies have been developed on a national or regional basis. The

typical disruption risk is regional in nature rather than global as in the case of oil.

Gas storage is several times more expensive than oil storage and faces more serious technical

limitations. The large majority of gas storage capacity has been designed to follow seasonal

demand fluctuations driven by winter heating. Those storage capacities require a substantial

injection period to fill and typically switch between store in and out cycles only twice a year, at

the end of seasons. As a result, their response capability to a sudden supply shock is limited.

As a result of the cost and technical limitations of gas storage, an “oil style” dedicated strategic

stockpile system has typically not been seen as a “first best” solution, except for situations with

a very high degree of dependency on a single import or infrastructure source. A significant

majority of the gas consumption of IEA member states is taking place in countries that don’t

have a strategic gas stockpile; several have had policy reviews that explicitly investigated and

rejected this option, although other IEA countries have implemented strategic stockpile

policies.

Demand side response in the form of interruptible contracts has been seen as a critical

component of gas supply security. Usually, interruptible consumers fall into two broad

categories:

Energy-intensive production of bulk manufacturing, where gas is a very large proportion of

production cost, so these companies have been willing to shut down production temporarily.

For these companies, such as plastics or fertiliser producers, the risk of a short shutdown in

production could be compensated by a continuous discount on gas prices. Alternatively, they


13

might curtail production voluntarily if gas spot prices peak during a disruption as a price

peak can eliminate the profit margin. On the other hand, for industries that have a very high

added value compared to their gas cost and run just-in-time production systems like the car

industry such interruptibility is not an attractive option.

Power plants and other industrial facilities such as petrochemical plants which has a physical

fuel substitution capability. Traditional oil- and gas-fired steam plants had the ability to

substitute between fuel oil and gas at a very short notice. Given the very high degree of

import dependency and lack of good storage sites, Japan and Korea have maintained a

considerably bigger oil switching capability than either Europe or North America.

Most countries have had regulations in place that mandated transmission system operators to

prioritise supplies in a crisis situation to protected consumers such as households or hospitals.

These consumers usually use gas for winter heating, so they tend to have a rigid, weather

dependent demand. In some countries that have a very high reliance on gas-fired power

generation at least some plants with a systemic importance have been also protected.

Although there is no physical substitution between gas and coal in an individual facility, in

countries that have a diversified mix of coal and gas-fired generation, the change in the average

load factor of the gas and coal fleet provided a powerful macro level fuel-switching potential

that has been a major component of gas supply security resilience. IEA analysis suggests that

for a given gas and coal fleet, the most important factors that enhance fuel switching potential

are the existence of efficient wholesale markets providing real price signals and a strong

transmission system that can accommodate shifting power flows from the changing coal and

gas plant utilisation.

Domestic production from conventional fields (North Sea and Groeningen in Europe, Gulf of

Mexico and Texas/Louisiana in North America) has been operated with a seasonal winter swing,

so in addition to gas storage, production fluctuations have also played a role in smoothing

seasonal volatility. Long distance pipeline imports such as the Russian contracts have less

seasonal flexibility embedded. With the gradual globalisation of LNG markets, LNG has been

increasingly seen as the “ultimate” supply security source. Under the EU Gas Supply Security

Regulation, an unused capacity in an underutilised LNG terminal can be counted into the n-1

resilience of the system. Several countries initiated the construction of LNG import terminals that

are not economical under normal circumstances and are likely to be underutilised, but they can

provide access to international LNG markets in case of a regional disruption.

For decades Russia has been the largest gas exporter in the world economy and the largest single

gas source in Europe. IEA WEO analysis does not foresee this to change until 2040 (IEA, 2015).

However, there has been no clear energy policy consensus on the energy security implications of

this dependence on Russian gas. Diversification has always been among the headline priorities of

European governments but none of the diversification projects received financial assistance that

could have been comparable to the resources committed to other priorities such as renewables.

Diversification projects have been expected to be financially viable on a market basis, with a

policy and licencing facilitation and only a minimal level of financial incentives. At the same

time, broad groups of policymakers and the gas industry have regarded a stable partnership with

Russia as a cornerstone of European energy security. Even after the gas supply interruptions of

2006 and 2009, there has been a debate as to whether they should be seen as interruptions of

Russian gas (in which case diversification of sources is the adequate response) or interruptions of

Ukrainian transit (in which case transit routes should be diversified). Northstream was eventually

completed as a “Project of European Interest,” and practically all the top European energy

companies made strategic investments in Russian upstream or infrastructure joint ventures. While

some observers discussed the nature of the relationship between Gazprom and the Russian state,

the European gas industry had a considerable sympathy towards Gazprom’s argument that the


14

main reason for the 2006 and 2009 incidents was Ukrainian non-payment. Gazprom had certainly

not been the only major energy company to have a sceptical view of the unbundling provisions of

the 3rd

energy liberalisation package which required intrusive changes in corporate governance.

The common ground of the broadly diverging views on Russian gas has been the notion (hope)

that an effective single market based on 3rd

party access will dilute Gazprom’s market power and

mitigate the energy security exposures in regions that currently have a high dependency on a

single source or a single transit infrastructure.

The existing framework for gas supply security evolved in parallel with the expanding role of gas

and has operated in a sufficient manner for decades. Nevertheless, with structural changes in the

energy system the role of gas is evolving in a fashion that would justify a comprehensive

evaluation of gas supply security. In addition, the Ukrainian conflict has a potential to have a

lasting impact on the energy relations with Russia and the energy security perceptions of

reliance on Russian gas. The IEA does not attach probability of such an attitude shift happening,

but notes that should that happen, the implications for gas supply security policy would not be

trivial.

Even without the potential foreign policy impacts of the Ukrainian developments the following

market changes are currently reshaping gas supply security:

3.3. Even with efficient markets, European import dependency on Russian gas will not

meaningfully decrease

Establishing a genuine single market has been a signature EU policy priority for decades. A well-

functioning single market indeed would bring multiple benefits. With a single market, gas supplies

will flow responding to intra-regional price signals; such internal redirection increases resilience to

region-specific shocks, as long as adequate supplies are available at a continental level. Market

integration dilutes the market power of incumbent suppliers in every region and thus can lead to

more efficient competition and potentially lower prices. Moreover, a large and efficient market can

provide price signals that are robust and trusted enough for upstream investors to base their

investments on them, eliminating the need for oil price indexation.

However, even a well-functioning integrated single market can be exposed to supply shocks or

market power at a continental scale. A disruption of all Russian supplies to Europe would belong

to this category as this would lead to a gas shortage in the entire single market. Moreover, given

the large-scale and fundamental cost and infrastructure advantages of Russian gas, there is little

doubt that Gazprom would have market power even in a perfectly functioning single market. In the

absence of long-term contracts that constrain not only the buyer but Gazprom as well, Gazprom

would have a substantial ability to influence hub prices in Europe. While diversification has been

on the policy agenda ever since Russian (Soviet) exports started, IEA analysis suggests that

Europe’s dependency on Russian gas and the market power of Gazprom in EU gas markets will

not diminish significantly in the coming decades. In the WEO NPS scenario, 40% of OECD-

Europe gas imports (or 140 bcm) still come from Russia by 2040.

At the same-time the demand-side flexibility of the European system is expected to diminish.

Coal-fired generation capacity is projected to fall by three-quarters by 2040, removing one of the

major demand-side flexibility mechanisms of the system, while short-term substitution

possibilities in the building and industrial sectors are much more limited. Energy efficiency

improvements will also impact gas consumption for heating, mainly affecting winter demand. We

estimate that the resulting flatter demand profile will lower winter storage fill levels by around

10 bcm. LNG and a well-functioning single market will be helpful in mitigating the impact of

potential disruptions, but these alone will not be enough. By 2040, Russian imports to Europe are


15

projected to still be equivalent to almost 30% of global LNG trade. LNG markets are likely to

become more flexible and efficient over time but this is unlikely to be enough to make up for large

losses of Russian gas. As a comparison, the diversion of LNG flows that was needed to make up

for the loss of nuclear power capacity in Japan following the Fukushima’s nuclear accident was

just 6% of global LNG trade.

The main drivers of this assessment are the following:

Shale gas fails to stabilise domestic production. The bulk of domestic production in Europe is

coming from the North Sea and the Groeningen field in the Netherlands. Norway is not a

member of the EU, but is a member of the European Economic Area. Consequently, Norwegian

gas is sometimes accounted as import or domestic depending on the context. Despite the fact

that the upstream prospects under Norwegian waters are considerably better than those in other

parts of the North Sea, the IEA expects Norwegian production to decline moderately by 2040 as

lower demand and cheaper import options deter new investments in more expensive Norwegian

projects. Consequently, North Sea production will significantly decline. Production is declining

in the Netherlands as well and is constrained by regulatory decisions in the wake of upstream-

related earthquakes. There are prospective upstream plays such as the Eastern Mediterranean or

the Romanian section of the Black Sea, as well as considerable potential for CO2-based

enhanced recovery on the North Sea. Nevertheless, these would not be able to compensate for

the conventional decline.

EU + Norway conventional production is expected to decline from 280 bcm to 170 bcm by

2040. Europe does have shale resources, but in its baseline projections the IEA does not expect

them to play a major role. The fundamental geology is less favourable than in North America:

shale plays are deeper, leading to higher drilling costs; they tend to have higher clay content;

and the potential for light tight oil and other associated liquids that play a major role in North

American shale economics is considerably less. Moreover, due to the lack of an onshore

upstream tradition, the field service capabilities in North America exceed the European ones by

a factor of 20. Consequently, the same upstream development in Europe is considerably more

expensive than in the United States. In fact, IEA analysis suggests that under realistic

parameters, North American shale gas liquefied and shipped to Europe could be competitive

with the shale production costs of Europe. Nevertheless, given higher European gas prices,

even the less-favourable shale plays could be attractive if there are no policy and regulatory

barriers to development. The IEA estimates that under optimistic assumptions on both policy

and regulations (defined as the Golden Rule Case) EU shale gas production could reach 40 bcm

by 2040 (IEA, 2012). Such a level, while meaningful, would not be transformative for the

European gas system. It would be roughly 11% of today’s US shale gas output and would not

be enough to stabilise Europe’s imports. Moreover, contrary to the assumptions of the Golden

Rules Case, there are multiply regulatory obstacles to shale development in Europe ranging

from outright bans to excessive licencing requirements. The WEO NPS that incorporates such

policy constraints projects only around 10 bcm of shale production in the EU. This means that

around three quarters of the geologically and economically viable shale gas stays underground

because of the policy restrictions. Theoretically, gas supply security and gas import dependency

concerns have the potential to turn around the anti-fracking sentiment, especially as evidence

accumulates about the major economic benefits in North America, but so far there is little sign

of that happening.

Pipeline diversification will not reach a critical scale. The average transportation distance of

Russian gas to Europe is 5500 km. The regions within this radius include the Middle East, North

Africa and the Caspian which together have gas resources that are equivalent to centuries of EU

import needs. As a reflection of this fact, construction of a direct pipeline link from these regions


16

to Europe (the “Southern Corridor”) has been on the EU policy agenda for more than a decade.

The Southern Corridor is moving ahead: the TANAP/TAP pipeline system through Turkey,

Greece and Albania to Italy as well as the associated Shah Deniz II upstream development in

Azerbaijan both made final investment decisions, and will come online by 2019/20. However, at

this stage, these two projects will transport only 10 bcm or around 2% of EU gas supply. At the

same time, pipeline exports from North Africa have declined recently, leading to a diminished

rather than more diversified pipeline import structure: Libyan exports that in their peak were

roughly at the level expected from Shah Deniz never recovered from the 2011 conflict; and the

political and security outlook in Libya continues to be unpredictable. Algerian gas exports to

Europe peaked in 2005, since then declining production and rapidly growing domestic demand

has constrained exports. Algeria undoubtedly has huge upstream resources, but a combination of

security issues and price regulation has led to upstream underinvestment. If the Southern

Corridor stays at its current scale, it will compensate for the shortfall of Algerian and Libyan

supplies, arriving at roughly the same entry area in southern Italy and thus will not have a

measurable impact on the market share and position of Gazprom. Theoretically, TAP could

forward gas to the domestic Italian SNAM transport system to the north and serve as a gateway

for gas towards Central Europe. However given the limited volumes and high transport cost,

such routing appears to be extremely unlikely. TAP itself could be scaled up to around 25 bcm

by adding compression capacity, and numerous other routes have been under discussion as well,

if sufficient gas quantities can be secured. Despite the abundance of geological resources such an

expansion is hindered by a multiple set of above ground issues.

Iran has the second largest gas reserves after Russia but several political and financial barriers to

gas upstream development persist, in spite of the recent improvement in the geopolitical context.

In particular, there seems to be limited investor interest in a pipeline in Iranian territory and

subject to Iranian legal risk. In the EU direction the combination of pessimistic demand

prospects, the robust competitiveness of Russian gas benefiting from sunk cost infrastructure and

the persistent financial weakness of the key European utilities would make the transit

infrastructure investment challenging as well. As a result, Iranian production is expected to

expand only slowly to a level well below the geological possibilities and Iran fails to become a

significant gas exporter in the baseline projection. Similarly, Iraq also faces formidable

challenges in emerging as major pipeline supplier to Europe. The 2013 IEA WEO Special Report

on Iraq did foresee a dynamic upswing of Iraqi gas production, but this is expected to be mainly

absorbed by domestic power generation, leaving only minor quantities for export. Moreover, that

report already warned about the risk of political and security problems derailing development

which arguably have become more challenging recently. Iraq (especially Kurdistan) certainly

has the geological potential to be a major pipeline supplier to Europe, but the policy and other

conditions would require very optimistic assumptions.

In Turkmenistan there is a very rapid infrastructure build-up towards the East, for sending gas

exports to China. Turkmen exports to China were 28 bcm in 2014. By the end of the decade,

capacity will reach 65 bcm. This project development speed is around four times what the EU

achieved with the Southern Corridor. The supergiant Galkynysh field has the resources to

support large-scale exports in both directions, but field development is lagging. In addition, the

Trans – Caspian pipeline that is a missing link towards Europe has made no visible progress in

the past 20 years. The WEO projects Turkmen gas production to grow to only 200 bcm by

2040, just two-thirds of what could be achieved with an optimal field development in

Galkynysh. The overwhelming majority of the production increase will be absorbed by growing

exports to China where underlying demand is increasing and where gas exports also form part

of a broader economic co-operation between the two countries.


17

Israel has had major offshore discoveries, especially the Leviathan field. However, it is by no

means certain that exports to the EU are the optimal monetisation channel for this gas, as

opposed to using it for desalination and transport, exporting it to the region or building an LNG

plant on the Red Sea. Exports to Europe do not seem to take priority in Israeli energy policy.

The IEA does expect Leviathan to be developed, but any minor quantities exported to Europe

would not have a transformative impact.

While the Southern Corridor has rightly been a policy objective and it will play a role, it is not

on track to transform Europe’s dependency on Russian gas. The resource potential is there, but

the developments that would be needed, all rely on political assumptions that go beyond a

baseline case and would require a dedicated effort on energy diplomacy.

Coal significantly declines in Europe. In a context of declining electricity demand and fast

penetration of renewables, coal consumption has proved much more resilient than other fuels

over the past five years. As of 2014, coal consumption in Europe was still above the 2009 level,

while gas consumption had declined by 13% over the same period. In particular, the increase in

coal consumption between 2009 and 2012 has attracted considerable policy attention, with

measurable new coal-fired capacity having either come online or being in advanced stages of

construction. Up to 2013, robust LNG demand in Asia kept European gas prices high, despite

weak demand, while coal prices declined, leading to a highly favourable relative price for coal.

Much lower gas prices over the past year have not significantly altered the picture.

With the exception of the United Kingdom – where the existence of a meaningful carbon price

floor has triggered some gas to coal substitution – gas remains broadly uncompetitive to coal.

This could theoretically be counterbalanced by a high CO2 quota price in the European

Emission Trading System (ETS). However, mainly due to the energy demand weakness arising

from the Eurozone crisis, the ETS is greatly oversupplied and quota prices have been

consistently low. Large-scale renewable deployment has also contributed to the lack of quota

demand and thus low prices. As a result, the ETS has failed to have a meaningful impact on

the competition between coal and gas. However, the 2009-12 upswing of coal has been

predominantly based on the expanding operations of existing, sunk-cost coal capacities, often at

the very end of their lifetime. The coal projects that are under construction made final

investment decisions in 2005-2007 in a very different market environment: electricity demand

projections were much more optimistic, and utilities before the Eurozone crisis had the balance

sheet strength to undertake capital intensive projects. Under the new market circumstances that

are transformed by weak demand and strong renewables growth, it is very unlikely that the coal

plants under construction will recover their capital costs. Given their low marginal costs, they

will run, but the return on investment will be significantly below what would attract investment

in additional new projects.

At the same time, aging capacity and new environmental regulations3 lead to a significant

decommissioning. Unabated coal use at the current level would make the 2030 EU CO2

emission reduction targets almost impossible to achieve. The IEA projects that until 2040, 147

GW coal capacity will be decommissioned in Europe and only 36 GW capacity will be built.

As a result, coal’s share in EU power generation will decline from 28 to 6%.

Coal makes a major contribution to energy security but given its high carbon emissions, it

represents a major challenge for decarbonisation. Coal is abundant and its supplies are

geopolitically well distributed. As coal transport over intercontinental distances does not

require special infrastructure and is considerably cheaper than LNG. The global seaborne

market for coal is considerably bigger in energy terms than the LNG market; it is liquid,

3 The Large Combustion Plant Directive and later the Industrial Emissions Directive.


18

competitive and well diversified. There has never been a geopolitical event triggering a coal

market disruption and it is very difficult to construct a logically consistent scenario in which

this would occur. Energy security analysis should not make a distinction between coal imports

from secure, competitive markets and domestic resources. The cost of coal storage is trivial

compared to the cost of gas storage facilities. Most importantly, coal still plays a major role in

power generation, even in OECD countries, let alone China or India. Replacing EU coal with

gas would require more gas than the current imports from Russia – so in the absence of other

sources, dependency would double. Replacing coal with gas in the United States would need

more than the entire current shale gas production. In Japan and Korea, both coal and gas (LNG)

are imported, often from the same suppliers like Australia. Even in today low gas price

environment a modern coal plant replacing gas in that region recovers its capital investment in

just seven years. The structural decline of coal in Europe will create a continuous pull on gas

imports. Of course with the deployment of carbon capture and storage (CCS), a low-carbon

energy system can continue to enjoy the abundance and security of coal. Unfortunately CCS

deployment is greatly behind schedule, and NPS does not expect a large acceleration.

Nuclear is declining in Europe. Even after a decade of ambitious renewable policies, nuclear

produces in Europe almost three times as much low-carbon electricity as wind and solar

combined. The average age of nuclear reactors in the European Union is around 30 years.

Several European countries have explicit legislation in place to phase out or never to build

nuclear power. Nuclear projects have experienced cost overruns and project delays that

together with structural changes in electricity markets can undermine their economics even in

countries with a supporting policy stance. If all reactors are closed at the end of their current

licencing lifetimes, Europe would experience a drastic fall of nuclear production in the 2020s.

IEA WEO projections are more optimistic than this: a combination of lifetime extensions and

replacement investment is expected to slow down the decline of nuclear. Nevertheless, EU

nuclear capacity is expected to decline by 20 GW between 2013 and 2040, from 27% to 23%

of EU power generation. This four-percentage-point decline would represent 25 bcm

additional imports needed if completely replaced by gas.

Building sector energy efficiency continues to lag behind the policy ambition. Building

heating is the largest single source of gas demand in the EU. There is a general consensus

that a large and potentially cost efficient energy efficiency opportunity exists in the EU

building sector; unfortunately, it is also clear that serious barriers hinder the realisation of

this potential. Most EU countries do have strong standards for newly built buildings, but

this is of secondary importance only. Due to a combination of economic, social and

cultural factors, the replacement of the building stock in most European countries is

extremely slow, and in the case of historical cities, buildings may be protected so never

replaced. Consequently, the key to energy efficiency improvements is the refurbishment of

existing buildings, which is uneven and generally slow. Moreover, even with an aging and

stagnating population, the number of households in Europe continues to increase due to a

falling average household size. As a result, WEO NPS projects only a mild decline in gas

consumption of the building sector. Slow progress on energy efficiency locks EU gas

demand at a high level, and with declining domestic production almost guarantees an

increasing import dependency.

Renewables continue to grow, but alone they fail to compensate for the limited progress on

clean coal, nuclear and energy efficiency. The EU has had an ambitious and large-scale

policy effort to expand the role of renewables in the energy system. While hydropower

remains a large but mostly saturated renewable source in Europe, and biomass use has been

expanding, the fastest and most transformative growth took place in wind and solar. Since

2005 when European gas production peaked, wind and solar expanded by 270 twh. Modern


19

CCGT plants would require around 50 bcm gas to generate that much electricity, which is

almost equivalent to the decline of European domestic production during the past decade. As

a result, wind and solar succeeded in compensating for the decline of European domestic

production, mitigating the growth of import dependency. IEA4 projections show that this

will be maintained until the end of the decade. Of course wind and solar, the most rapidly

growing renewable sources, are variable and depend on the weather. Consequently, while

they do mitigate import dependency, they generate non-trivial challenges to integrate them

into the electricity system while maintaining electricity security. Most electricity systems

that have high shares of variable renewables are located in Europe and experienced rapid

technological and institutional innovation in facilitating integration. IEA analysis suggests

that while dedicated policy and regulatory attention to electricity security and significant

market design reforms are needed, further growth of wind and solar can be safely integrated

into the power system, even with the current grid and energy storage technologies.

Maintaining the growth of renewables requires the maintenance of supportive investment

frameworks and adequate regulatory attention to market design, rather than a fundamental

technological breakthrough. Nevertheless, for solar, the geographical conditions are not ideal

in Northern Europe, which has a temperate climate and a winter peak demand for electricity.

In a number of cases, such as in Germany, peak demand comes after sunset during the

winter, so the capacity contribution of solar is zero at system peak. In the absence of large-

scale electricity storage deployment, this will limit the optimal share of the technology and

increase integration costs.

Due to macroeconomic factors, EU power demand has declined since 2008. The IEA regards

such weakness as due to both structural and cyclical factors. With the normalisation of the

macroeconomic environment, EU power demand is expected to increase very mildly in the

NPS and to stagnate in a 450 ppm path. Overall demand growth is weak enough that with the

continuing large-scale renewable deployment, the incremental wind and solar coming to the

system year after year is more than the trend demand growth. As result, wind and solar do not

simply increase their share in the power mix, they reduce the use of other power generation

technologies in absolute terms over the medium term. If other domestic sources were stable,

this would be a very powerful reduction of import dependency. However, wind and solar do

not arrive to a static electricity system: they are deployed into a system with a structural

decline of coal and nuclear.

By 2040, coal and nuclear combined are projected to lose a 26 percentage point share in EU

power generation. Compensating for this would absorb 25 years of wind and solar deployment

at the 2014 investment level, which will slow down, according to IEA projections, due to the

saturation of the best sites and the increasing grid integration challenges. The 450 ppm

scenario has a much more robust wind and solar deployment, but even in the 450 ppm case,

the incremental growth of wind and solar is just roughly half the current EU nuclear and coal

production, so it would fail to compensate for the decline of both. In fact, the 450 ppm scenario

relies on a significant expansion of EU nuclear as one of the decarbonisation pathways which

would require major policy changes. Consequently, while wind and solar do play a beneficial

role in mitigating the growth of gas import dependency, they largely compensate for the loss of

coal and nuclear, leaving gas-fired generation − and thus import needs − on a growing path.

One also has to consider the interaction between renewable deployment and the

conventional fleet. Given the time profile of renewable production and the current state of

competition between coal and gas, a very significant proportion of new wind and solar in the

rest of the decade will generate electricity in hours when the power system has coal as a

4 IEA Medium-Term Renewable Market Report 2015.


20

marginal generator, so those renewables drive out coal rather than gas. Of course this is

precisely the objective from a climate change point of view: low-carbon deployment has a

direct and large impact on carbon emissions. However, given the superiority of coal over gas

from an energy security perspective, the extent to which they displace coal rather than gas

limits the energy security contribution of renewables.

As a consequence of the interplay between policy and investment factors, renewables and

energy efficiency will not be able to compensate for the decline of domestic gas upstream,

coal and nuclear, setting Europe on a path toward strongly increasing gas import needs.

None of the new pipeline sources are likely to have a transformative role either. As a

result, the most effective constraint on the market power of Gazprom could be an

expanded and more competitive LNG supply. All countries that are affected in a severe

disruption scenario should ensure they have access to an LNG facility. The limitations on

domestic production, efficiency, renewables and other energy sources are not

technologically predetermined, but the results of investments shaped by energy policies that

operate under institutional and political constraints. A dependency reduction scenario in

which those factors make a bigger contribution as a result of changing policies will be

discussed in a separate chapter.

In Europe, global gas balances point to a change in Gazprom’s operating environment over

the medium-term. Oversupply in global LNG markets will lead to increased competition to

gain - or maintain - access to European customers. Due to the flexibility of its gas system

and well-developed spot markets, Europe has traditionally been the outlet of last resort for

unwanted LNG supplies. However, weak demand growth and very low coal prices will limit

how much incremental gas the region can absorb. This is set to keep spot gas prices under

pressure.

For those US projects that are today under construction – and for which the large capital cost

incurred by developers is predominately covered by binding long-term capacity reservation

contracts and can therefore be considered a sunk cost– US gas supplies can today reach

Europe, economically, at a price in the region of $4-5/MMbtu and below European spot and

futures prices. So can Qatari supplies. For Gazprom to achieve its stated strategy to maintain

market share in Europe, it will need to adopt a more competitive pricing strategy than it did

in the past. The past 12 months have shown signs that the company might be opting for a

more flexible approach; whether this will be sustained remains to be seen, as US LNG

exports are just beginning to ramp up and EU gas demand remains flat. Nonetheless, the

decline of natural gas production in Europe means that LNG supplies however will not be

able to fully replace Russian gas imports to Europe.

Many new LNG terminals in Europe have been constructed in recent years, in some

countries they are also an effective insurance to mitigate possible geopolitical security

concerns.

3.4. LNG markets will become more competitive and secure, but remain limited in their

contribution to global security of gas supply

In the last decade, LNG trade has been growing considerably more rapidly than overall gas

consumption, driving the globalisation of natural gas. This trend is expected to continue, leading to

discussions of a possible emergence of an integrated global gas market that would function

comparably to oil. There is no doubt that such a phenomenon would be greatly beneficial for supply

security: in an integrated global market any individual shock could be absorbed more easily as prices

would drive an efficient supply and demand adjustment in all regions. For example, North America

has both a large demand-side response capability and a substantial price-elastic upstream that could


21

expand production on a medium-term horizon if price signals provided incentives. Currently this

does not play any meaningful role in the supply security of importing regions as North America is an

isolated “gas island”.

Unfortunately, under baseline assumptions, such a smooth global gas market is unlikely to emerge

in the coming two decades. Oil is liquid to begin with, whereas gas needs to be liquefied with

specialised equipment in a capital and energy-intensive process. The cost of liquefaction is driven

by the fundamental thermodynamics of the process; there is no prospect for an innovation that

would lead to cheap liquefaction. In fact, the recent industry experience has been a worrying

degree of cost inflation. After liquefaction, LNG needs to be kept liquid in super-cooled, isolated

tanks that make both shipping and storage several times more expensive than for oil. While there

are promising initiatives for smaller scale modular LNG projects, the overwhelming majority of

global LNG supply will continue to come from large-scale LNG projects where capital needs of an

individual project can easily exceed USD 10 billion and project implementation times can reach a

decade. Most industry participants believe that some form of a long-term contract structure will

remain essential for the bankability of LNG projects.

Theoretically, capital intensity and long project lead times do not preclude the existence of

competitive spot markets. Some oil projects such as oil sands or deep offshore have similar

financial and project development characteristics to LNG, yet investment is undertaken without

long-term contracts. However, those projects benefit from the already existing liquid oil

commodity market – the project might face significant geological or project management risk, but

market access is assured. In the case of LNG, the fundamental cost of transport infrastructure and

the underdevelopment of gas markets in the Asia – Pacific, the most important LNG consuming

region, creates a “chicken and egg” problem: underdevelopment of markets necessitates long-term

contracts which in turn hinder the development of liquid markets. As a result, the IEA does not

expect the development of a single, global price of gas determined by an integrated global market:

regional discrepancies will persist, and various infrastructure and regulatory barriers will hinder

the efficient redirection of gas supplies across regions.

Nevertheless, there is no doubt that LNG markets will move towards a more efficient, competitive

state, and will provide enhanced resilience for supply security. Already, the traditional business

model of rigid long-term contracts creating isolated transactions has started to be transformed by

several factors:

The positive supply shock of North American shale gas production eliminated the previously

expected LNG demand of the United States. As a result, substantial quantities of LNG were

looking for new markets and have been redirected. Some of it went directly to spot markets,

such as Angola LNG that auctions individual cargoes, but the majority was redirected within

the LNG portfolio of large global companies that can resell them in bilateral contracts. This

LNG played a major role in facilitating competition, but should not lead to complacency: US

shale gas is no longer a new phenomenon; practically all the gas that could be redirected from

North America has been redirected and already absorbed by global demand growth, especially

in Asia.

The Eurozone crisis in Europe and the loss of nuclear power in Japan – independently from

each other – created parallel demand shocks in the opposite direction. Japan needed a sudden

upswing of LNG supply at the same time of the emergence of demand weakness in Europe. A

well-functioning liquid market would redirect supplies from Europe to Asia and this was

precisely what could be observed: European LNG imports have declined by half, a significant

re-export and cargo redirection trade emerged, and although at record high prices, Japan could

purchase the required physical quantities. It is worth emphasising that in the critical 2011/2013

period global LNG supply actually declined due to a host of geological, policy and security

issues in Nigeria, Egypt, Indonesia and other countries. The upswing of Asian demand was thus


22

not covered by a supply increase, but rather, demand response in Europe and a rearrangement

of global gas flows. The only gas producer in the global economy that could increase its exports

was Gazprom: around half of the LNG redirected to Asia from Europe has been replaced by

Russian pipeline exports that reached a historical peak by 2013. This should serve as a warning

sign about overoptimistic expectations about the short-term crisis management contribution of

LNG markets should Russian supplies themselves be disrupted. Certainly, today’s much looser

market conditions would make it possible to re-direct LNG supplies at a much lower cost, but

overall the lack of short-term swing LNG production capability remains a structural limit to the

contribution of LNG to security of supply.

Despite the progress, there are clear indications that the LNG market adjustment was constrained by

market inefficiencies which prevented an optimal outcome. The Asia – Europe price differential has

been consistently higher than the level that transportation cost differentials would justify. If LNG

markets had been efficient in a microeconomic sense, Europe’s reliance on Russian gas would have

been even higher as more LNG would have been redirected to Asia leading to lower Asian and

higher European price. A significant quantity of LNG was physically delivered to Europe, reloaded

to a different tanker and then shipped to Asia - in some cases following largely the same route back.

Such phenomena could be observed in the case of unneeded US LNG imports as well: for example,

in 2012 a cargo of Qatari LNG was delivered to the US Gulf Coast and then shipped back to

Kuwait. In other cases, the redirection took place directly from the production point, with the

trading profits shared by agreement, but such LNG trade patterns are far from what could be

considered optimal routes. This is mainly due to contractual restrictions but also to a degree due to a

lack of effective 3rd party access and domestic competition in some key importing countries.

Shipping capacity also proved to be inflexible – unsurprisingly given the special technical

characteristics of LNG tankers. As cargo redirection led to higher average shipping distances,5

tanker rates doubled in less than a year, although as new shipping capacity became available, a

correction could be observed.

The most worrying sign about the potential energy security contribution of LNG is that even

sustained record high Asian LNG prices failed to trigger a short-term supply upswing. LNG export

terminals are almost invariably built for baseload operation; their capacity and production is

routinely presold by long-term contract. Some LNG capacity is controlled directly by the equity

investors in the terminal, be they the national oil companies of the resource holding government or

an IOC that takes the LNG to its global gas portfolio. Such capacities might have a very limited

swing capacity to take advantage of optionality. While a limited degree of maintenance can be

rescheduled, it will not generate a meaningful swing production capability. In fact, not only LNG

trade, but supply itself also displayed visible inefficiencies due to lack of functioning markets in a

number of key producing countries. In 2012 and 2013, global LNG supply was around 20 bcm

lower than total liquefaction capacity, which is the same order of magnitude as Japan’s incremental

LNG needs. A substantial unused LNG capacity thus existed, but did not come online even with

record high prices. In some countries such as Yemen and Libya, this was due to hard security

issues. However, the most important reason for underutilisation has been a lack of feedstock gas in

countries like Egypt, Algeria or Indonesia where rapidly expanding domestic demand absorbs

often stagnating or declining domestic production. In Egypt, the government explicitly prohibited

LNG exports, leading to a vis major. In Algeria, Sonatrach has been buying back gas from the

production sharing agreement partners at Japanese prices, and then selling it at regulated domestic

prices that are 90% lower. In all of these countries, domestic prices are regulated at a below cost

level and subsidies fuel low efficiency consumption. In Egypt, for example, the average efficiency

5 For example Nigeria – Japan instead of Nigeria – Europe.


23

of gas-fired power generation is 27%, around half of the modern standard, and domestic power

generators get gas at prices as cheap as USD 2/mbtu, around one third of the export value of gas

(albeit recently some contract renegotiations have occurred). Improving energy efficiency and

expanding renewables in gas exporting countries in order to facilitate the full utilisation of sunk-

cost gas infrastructure could be an important field of co-operation between G7 countries and gas

exporters. This would reduce the risk of unexpected shortfalls in exports which have been common

in a numbers of exporters (for example, North Africa) in recent years While the development of

efficient gas markets in major gas exporting countries is likely to be a slow process which is only

indirectly influenced by IEA member states, still there are good reasons to expect the development

of a much better functioning LNG market in the foreseeable future. This is primarily driven by

investments into new supply as well as new regulatory and business models that are emerging in

the LNG trade.

After several years of stagnation, the IEA projects a massive 40% increase in global LNG supply by

the end of the decade. The most important ongoing already committed investment is in Australia.

The Australian projects under construction follow the traditional business model: around 85% of

their capacity is covered by long-term contracts with take-or-pay commitments, usually with oil price

indexation. Given Australia’s stability, they will lower the average geopolitical risk of global LNG

supply and there is no risk of a government intervention to prioritise domestic consumption either.

Moreover, even with a long-term contractual structure, they will play a beneficial role in enhancing

market efficiency. Several buyers in Asia currently rely on spot purchases even for baseload demand.

New baseload supplies from Australia will release some of that to the spot market. Major utilities

from the Asia – Pacific region play a key role in Australian LNG projects both as equity investors

as well as anchor consumers. If there is a change in the supply – demand balance such as the

prospective restoration of nuclear in Japan, they will have a strong incentive to use the spot market

to readjust their portfolio. Often they benefit from “equity lift” – the extent to which investors in

upstream are entitled to a share of the physical production without any destination restriction.

IOCs, another major group of investors in Australia also tend to use this structure.

While Australia will have an important indirect impact on LNG market development, the United

States does not simply emerge as a major LNG exporter, but also introduces a new business model

which will have a disproportionate impact on improving the efficiency of LNG markets. North

America has such liquid and competitive commodity markets for gas that vertical integration into

upstream is redundant. While LNG projects outside North America are typically vertically

integrated and buy gas from other upstream producers only as an exception, in the United States

LNG plants are regarded as the midstream infrastructure part of the gas value chain. The gas

midstream companies – often the owners of terminals originally intended for imports –are the

project developers, not the major upstream producers. Broadly speaking, such midstream

companies do not aim to engage in global LNG trading operations. The typical business model is

very similar to the midstream business structure in the North American gas industry: a long-term

capacity reservation contract guarantees the recovery of the infrastructure investment and enables

access to low-cost financing, but the marketing of the LNG itself is up to the buyers, with LNG

typically changing ownership at the US export terminal FOB. A substantial proportion of US

LNG is contracted by the major Asian utilities who under normal circumstances intend to ship it to

their home markets, but they have no legal obligation to do so. Major US LNG contracts have also

been signed by companies that already have a diversified LNG portfolio and sell to a multitude of

markets, so those quantities will directly expand spot LNG supply. Given the current new US LNG

projects under construction with 85 bcm in total, completion of these projects would nearly double

the availability of flexible spot LNG supplies. Several major projects are under development in

Canada as well. Canadian LNG is similar to the US in benefiting from a large shale resource base


24

and from low investment risks. However, it involves major pipeline developments and most

Canadian projects follow a more traditional, integrated business model.

The emergence of North America as a major LNG supplier is undoubtedly a beneficial

phenomenon for gas supply security as it combines well-functioning markets, a flexible

business model and very little geopolitical risk. Unsurprisingly, this development has been

the focus of considerable media and policy attention. IEA analysis shows that North

American LNG will play a beneficial role but will not be a single transformational “silver

bullet” that makes the other components of a comprehensive gas supply security policy

redundant, for the following reasons:

There is still a considerable degree of uncertainty over the future level of US exports. The main

source of the uncertainty appears to be upstream and liquefaction economics rather than export

licensing decisions of the US government. The North American shale resource base is huge;

however, a considerable proportion of it cannot be economically produced at current gas prices.

Exceptionally favourable conditions in some plays, mainly Marcellus as well as large-scale

associated gas production from wet gas projects benefiting from the value of liquids, keep US

gas production growing. However, continued growth of US gas demand is also expected. This

is mainly driven by the expanding role of gas in the US power generation sector. With the aging

coal fleet and the new US climate regulations (the “Obama plan”), the coal to gas switch of

recent years is expected to continue. In addition, gas is emerging as a major transportation fuel

in North America. In addition, given the strong competitiveness of the region as a location for

energy intensive industries, industrial demand is also growing. IEA analysis shows that the

North American resource base is sufficient to supply growing domestic demand and significant

exports, but this will necessitate intensive drilling activity in dry gas formations that will be

economical only at a higher gas price level. Moreover if today’s low oil prices persist, US gas

production could be negatively impacted. A substantial portion of shale gas is produced in

association with oil and is therefore predominantly driven by oil well economics. Even for non-

associated gas, the wet hydrocarbon stream is usually responsible for a relatively high share of

revenues, even when it accounts for little in volume terms. Consequently, in a low oil price

scenario, comparatively higher gas prices would be required to generate the same growth of US

gas supplies. In the IEA NPS North American LNG exports remain competitive, but the very

attractive margins that could have been achieved in 2012/13 will narrow measurably. WEO

NPS projects 100 bcm LNG exports from North America, as 60% of the production increase

will be absorbed by domestic demand.

While five US projects are currently under construction, many more have been proposed and

there is unavoidably a degree of uncertainty over US LNG exports. From an energy security

perspective it is important to emphasise that the emergence of North American LNG supplies is

not necessarily additional to what would have been available in the absence of them. There are

three major clusters of potential new LNG supplies6 outside North America: East Africa, a

second generation of Australian projects and Russia. The combined potential production of

proposed projects in those regions exceeds expected LNG demand by a considerable margin. It

is very likely that not all of them will be built. Consequently, if North American LNG projects

successfully progress and lock in demand, they will drive out other new supplies. In some

cases, those new supplies would not be inferior to US LNG from the point of view of supply

security. For example, several potential second generation Australian projects have been

cancelled or put on hold. This is unlikely to be independent of the acceleration of North

American LNG export prospects and the way the same Asian utilities that played a key role in

6 If Qatar were to lift the moratorium, it could emerge as an additional cluster of its own.


25

facilitating the current Australian investment wave have made major commitments to North

American LNG.

Important in the current European context, the upcoming upswing of US LNG production does

not automatically mean that Russian pipeline exports to Europe would be the marginal supply

that is squeezed out. On the contrary, due to the large potential for cost efficient production

upswing in Yamal and the sunk-cost transit infrastructure, the marginal cost of Russian exports

to Europe is low. While the IEA projects US LNG to be competitive with the contractual price

of Russian gas exports in Europe, it is not competitive with the Russian marginal cost.

Consequently, the start-up of new LNG production – and the potential for further investments

on top of what is already under construction – leave open the option for Gazprom to price it out

from European markets. It is worth noting that neither the new EU gas target model that is

based on interlinked hubs and entry – exit transport tariffs nor the repricing of long-term

contracts from oil to hub indexation eliminates this option. The IEA did develop an alternative

scenario, the WEO 2013 Accelerated Convergence Case, in which a higher North American

LNG capacity succeeds in creating a genuine global gas market with a breakdown of oil

indexation. The Accelerated Convergence Case delivers major benefits for the importers of the

Asia Pacific, but has only a marginal impact on Europe: The Henry Hub + formula that

becomes the “global” gas price in this scenario is very close to the cost of other gas sources to

Europe, so has a limited market impact. Even in Asia the impact is mainly on prices rather than

physical quantities: gas demand is price inelastic, so a measurable price decline from the oil

indexed level does not trigger a large demand upswing. This also means that the additional

North American LNG of the Accelerated Convergence Case drives out some other gas supplies

from the market and is not entirely incremental.

While US LNG will have destination flexibility, under most circumstances it will not have

volume flexibility. US LNG projects are covered by long-term capacity reservation contracts

with ship-or-pay provisions. With such a contract structure, liquefaction, which is the most

capital intensive segment of the LNG value chain, becomes a sunk cost for the off taker: even if

the price differential between US and export prices narrows, the terminals will operate and

export, unless the price differential narrows to the level of operating and shipping costs. Price

differentials will not narrow to that extent under IEA baseline projections; if they do then

indeed there will be a price-driven swing in production capability. If a disruption drives prices

outside North America up, then the off taker − instead of paying the tolling fee and leaving the

gas in the United States − will export it. As a result, if an overinvestment in US liquefaction

narrows the price differentials to below the fixed cost of liquefaction, then the United States

will indeed be a price-sensitive swing supplier, with highly beneficial energy security

consequences.

However, this is not the intended business model of the US terminals; there are currently no

market participants who would reserve capacity for the optionality. If, in contrast to IEA

expectations, pride differentials narrow below liquefaction costs, investment into US

liquefaction will stop. A price-driven flexibility is feasible only in a scenario of a sudden and

unexpected narrowing of price differentials, in which case it would also lead to substantial

stranded costs. As a result, the US LNG would not have a swing production capability under

normal circumstances. Its destination flexibility would enhance the efficiency of markets to

redirect available supplies in responding to a disturbance, but the total volume of those supplies

would not have short-term flexibility. Resilience would have to come from the supply –

demand response of individual regions, although a global, efficient LNG market would make

the aggregation of regional flexibilities much more feasible.


26

3.5. China emerges as a key driver of global gas markets

China represents almost one-fourth of global gas demand growth by 2040, with the role of gas

growing in practically every segment of the energy system. While it will not challenge coal as the

largest primary energy source in the Chinese economy in the foreseeable future, still – given the

scale of the Chinese energy system – the growth of gas in China has a potential to transform

international gas markets. The traditional Asian LNG importers of Japan and Korea share some

important characteristics: they have isolated energy systems with no domestic upstream potential

and no electricity or pipeline interconnections. All of this is translated into price-inelastic LNG

demand and switching to oil as the only measurable demand response possibility. China has a

continental scale energy system with a large domestic fuel switching potential between coal and

gas. Increasingly, strict environmental regulations limit this potential to an extent, but the latest

generation of Chinese coal-fired power plants is equipped with modern environmental controls and

coal will remain the backbone of power generation there. Although China’s import dependency is

rising, it will see a meaningful increase of domestic production. Tight gas already plays a major

role in China and shale is expected to do so, which similar to the United States can lead to a

domestic upstream that is price elastic in the medium term. Moreover, China has also been

successful in building a diversified pipeline import structure, from Central Asia, Myanmar and

Russia as well as a domestic pipeline infrastructure that is increasingly able to link different

regional supplies to demand centres.

All of these changes point towards the potential emergence of a diversified, competitive gas market

in China. Importantly, there is increasing diversification on the supply side, with CNPC dominant

in conventional upstream and pipeline imports, CNOOC active in LNG and a broad group of

investors engaged in non-conventional gas and coal gasification projects. The key legal and

regulatory building blocks are still missing: China does not have effective third party access to an

unbundled pipeline system and gas pricing is heavily regulated across the value chain. However,

there is an active discussion on gas market reform, and considerable progress has been made.

The emergence of a large competitive market for gas in China has important and positive

implications for the supply security of other importing regions. The attention is often on the

growing import need of China, which is indeed large, but Chinese energy policy and the

activities of the major Chinese NOCs have been very successful in facilitating the development

of new supplies, often in regions where it is difficult to see how those reserves could have been

developed without Chinese investment or contracting. The recent Russia-China gas deal is a

good example of this: given the remote location of the Kovytka and Chayandinskoe fields in East

Siberia, there is little doubt that without Chinese import demand they would be stranded

resources. Given the abundance of the geological resources of gas, China is not “taking away”

gas from other regions, the increasing role of gas in China is large enough to have a significant

impact on global gas demand but it has also triggered up until now a parallel increase in global

supply. On the other hand, given the lack of swing LNG production capacity, any region can

purchase short-term LNG supplies in a disruption only if there is a demand response in another.

China potentially will have a large demand response capability for LNG due to its large fuel

switching potential and diversified supply structure. In fact, Turkmen imports to China seem to

have a swing production capability already, so China is one of the countries that can potentially

reduce LNG purchases should LNG markets tighten unexpectedly. Currently, the lack of efficient

short-term price signals together with the incomplete domestic infrastructure would limit China’s

demand side response but this might change in the future. Gas market reform in China thus could

make a significant global contribution to supply security.


27

3.6. Swing production capability is declining, especially in Europe

Conventional gas fields usually have swing production capability and traditionally they have

played a role in providing flexibility both for seasonal fluctuations and disruption response.

Due to technical reasons the swing production capability is often expensive, but with efficient

market signals it is available. As a result of swing production capability, the gas system needs

less storage than would otherwise be needed. The contribution has been significant: for

example, in October 2010, European production surged by 7.4 bcm, more than the monthly

imports transiting through Ukraine. However, due to falling reservoir pressure, swing

production capability quickly declines in a depleting field. Thus the decline in European

production does not simply increase import needs, it also decreases domestic flexibility and

response capability. Even if a significant upswing of shale production should occur, it would

not compensate for the swing capability: shale gas has significant medium-term price elasticity

since drilling activity can be scaled up if price signals make it economical. In North America,

the time horizon of this is around half a year for shale plays that are already connected to the

gas network, so the response time is determined by licensing, reorientation of drilling

equipment and drilling and fracking itself. However, in a shorter time horizon, the flow from a

fracked shale well is almost mathematically determined by the geology of the play and the

operator does not have any short-term swing capability. For example, during the “polar vortex”

of the first months of 2014, US shale gas production failed to show any short-term surge since

it was based on wells drilled and fracked in 2012/2013. The decline of swing capability means

that additional flexibility is needed to maintain the same resilience to possible disruptions.

3.7. Fuel-switching capability is declining

Fuel switching, especially in power generation, is a powerful supply security enabler. Oil storage

is considerably cheaper than gas storage, while the cost of storing coal is trivial. However,

structural changes in the electricity system have resulted in a decline of fuel-switching capability

leading to a more rigid demand side with potential supply security consequences.

Oil’s role in power generation has been declining since 1974. Oil and gas-fired power generation

plants of that vintage are steam turbine plants with boilers that can burn heavy fuel oil and gas

often in combination and have substitution capability at very short notice. However, such power

plants have not been built outside the Middle East for decades; in IEA member countries, the last

ones are likely to be decommissioned this decade. Modern gas plants are combined cycle gas

turbines. CCGTs can be designed and built to have a dual fuel capability. However, under normal

market conditions they run exclusively on natural gas: on oil-fired mode there is a drop in

efficiency; additional water injection is needed to avoid an unacceptable increase of NOx

emissions; and, in general depreciation costs increase. The liquid fuel is usually a low sulphur

middle distillate that is considerably more expensive than crude oil. As a result, gas has to be

even more expensive than oil parity in order to make it economical to switch. Given that this is a

highly unlikely event even in gas importing regions, the recovery of the additional investment for

the dual fuel capability is questionable. Some countries have a regulatory obligation to build dual

fuel capability and oil supply infrastructure in CCGTs, but the experience of countries without

such an obligation shows that the overwhelming majority of market-based investment chooses

natural gas-only turbines.

Between coal and gas, the substitution is not in an individual facility but on a macro level: a

change in the relative price of coal and gas (influenced by possible carbon pricing) will shift the

merit order --and thus power plant dispatching – which changes the demand for the two primary

fuels. This optimisation is subject to constraints in both the electricity infrastructure and power

plant operations, but nevertheless is potentially significant. Modern supercritical coal plants have

considerable operating flexibility and even subcritical coal plants can be retrofitted to increase


28

flexibility provided that there are market or regulatory incentives to do so. The largest single

demand side response capability in a typical gas system is substitution between coal and gas-

fired power generation. In the aftermath of the Japan’s nuclear accident without the upswing of

coal-fired generation in Europe, it would have been very difficult to maintain gas supply security

in LNG dependent regions: the upswing of coal replaced around half of the LNG that was

redirected from Europe.

There are strong reasons to suspect that further fuel switching capability is very limited in both

Europe as well as in OECD Asia Pacific. The elasticity of fuel switching critically depends on the

change in the merit order triggered by a change in relative prices. This requires a starting situation

when the marginal cost of coal and gas-fired generation are reasonably close to each other and coal

and gas plants overlap each other. This has been the situation in the United States where – with low

gas prices - gas is in neck-to-neck competition with coal. As a result, when gas prices recovered in

2013, a USD 1.6/mbtu gas price increase (much less than what could be expected in Europe in the

case of a disruption of Russian supplies) triggered a 10% (112 twh) decline in gas-fired generation.

This flexibility should not be expected in Europe, Japan and Korea. In the importing regions, gas

prices are considerably higher, so in the absence of a carbon price, there is a large gap between the

marginal costs of coal and gas-fired power generation, favouring coal. In a situation like this under

normal circumstances, coal generation will run with a reasonably high load factor, gas for mid

merit and peak, and if gas prices go up further the fuel switching will be limited. In Japan,

domestic coal-fired generation did not play a major role in replacing nuclear since it had already

been running with a high load factor even before the earthquake. Several major coal plants

suffered extensive earthquake damage, so changes in coal-based production largely reflected

changes in available coal capacity rather than load factor changes.7

In Europe, coal could ramp up and contribute to LNG redirection because in 2009/2010, due to the

combination of weak demand and LNG redirections from North America, gas was competitive in

Europe, helped by a higher carbon price that led to an underutilised coal fleet. By the end of 2013,

most of the fuel switching potential had been exploited. Europe still has underutilised coal

capacities: if all the coal capacity in Europe run on baseload, that could in theory reduce gas

demand by 40 bcm. However, the most underutilised coal capacities are located in regions such as

Spain and the Balkans that are weakly connected to the rest of the European electricity system:

due to transmission limitations, Bulgarian coal cannot substitute for Dutch gas-fired generation. In

addition, especially in Germany renewable deployment has reached such a critical mass that in

windy and sunny hours, zero-marginal-cost renewable production now constrains the load factor

of hard coal plants as well.

Around half of the gas-fired generation that survived the past three years in Europe is

cogeneration, where operations are determined by the heat need, and the rest is increasingly used

for balancing renewables: Gas is running if there is no wind and solar so the capacity is needed for

system adequacy or if there is too much wind and solar, and the minimum stable load of coal

plants is too high, so gas needs to be kept online for flexibility.8 In either case, there is no

economic substitution between renewables and gas; renewable deployment leads to a lower but

more rigid gas demand. It is worth mentioning that policy ambitions will push the power system

further in this direction. In a 450 ppm pathway, by 2040 Europe on average will have a

considerably higher share of wind and solar than Spain or Germany today, the two systems that

7 Japanese coal-fired power generation did increase by new capacities coming online, but still the bulk of nuclear replacement was oil, LNG

and demand side response.

8 Electricity system operation is constrained by the minimum load of plants: the lowest production at which the plant has a stable operation.

This is typically more problematic for coal than for gas plants. As a result, in a windy dawn the system operator might keep a gas rather than a coal plant in operation at a minimum level, which then can ramp up in the morning.


29

are regarded as a taste of things to come. In both countries, the load factor of gas generation is

extremely low, with arguably very little price elasticity. With old, high marginal cost coal

capacities progressively decommissioned in both the European Union and the United States, the

plants that remain and newly come to the system will tend to have low marginal costs:

supercritical hard coal and vertically integrated lignite units, which even with a measurable carbon

price are likely to have baseload operations.

The decline of substitution capability between coal and gas is a major potential energy security

concern which can create problems even in North America. A good empirical example is the “polar

vortex”, the extreme cold weather of December 2013 – March 2014. Extreme weather conditions

pushed US electricity demand 5% higher than the same period the previous year, in a period when

due to the same reason residential heating demand was also record high. In the US power system,

80% of the incremental generation that supplied the demand upswing came from previously

underutilised coal plants, several of which will be decommissioned during the rest of this decade.

In the absence of a coal upswing, US gas demand in power generation would have been around

12 bcm higher during the critical four months, putting storage and pipeline systems under a very

serious strain. At the very least, it would have pushed North American prices to a level which

makes exports uneconomical. The same polar vortex in 2020 with considerably less coal capacity

but substantial US LNG exports would temporarily suspend US exports as off takers would find it

more profitable to sell the gas domestically. As a result, with a decline of coal fuel switching

capability, an extreme weather event in North America would have the potential to cause a gas

supply disruption in the importing regions.

Therefore, for the entire projection period until 2040, the share and importance of Russian gas

remains much higher than the short-term flexibility that the gas system can be expected to have

on a market basis in the form of commercial gas storages, LNG flexibility and demand response.

Consequently, if the disruption of Russian supplies is seen as a credible risk, a strong policy

intervention would be needed based on seven no-regret policy measures which are explained in

the following section.


30

4. RECOMMENDED MEASURES TO ENHANCE EUROPE’S GAS SUPPLY SECURITY

Given the market developments as described in the previous chapters, there is no single policy

instrument that generates meaningful improvement of gas supply security in Europe. The components

of required policies for security enhancement are the following:

Box 1: Enhancing Europe’s gas supply security

Recommendation 1: Transform the building sector: Governments should accelerate energy

efficiency improvements and deployment of low-carbon heating systems in new and existing

building stocks.

Recommendation 2: Continue to push wind and solar into the power system: Given the major

benefits of wind and solar deployment on CO2 emissions and import dependency on fossil fuels,

Governments need to support the system transformation required to facilitate the integration of

variable production.

Recommendation 3: Complete market opening and integration at EU level: Governments should

further advance gas market integration and liberalization by establishing physical and legal

infrastructure for better interconnection and access to LNG and gas storages, including reverse-

flow capacities

Recommendation 4: Strengthening gas storage: Governments should review and redesign current

regulations and tariff structures to give stronger incentives to gas storage investment and storage

fill.

Recommendation 5: Maintain viability of nuclear power in countries that decide to rely on it:

Without compromising, nuclear safety, licensing and regulatory regimes should be adopted that

minimise the risk of project management issues and ensure investments in the nuclear sector,

including replacing aging reactors

Recommendation 6: Expand the Southern Corridor and enhance partnerships with key exporters:

Governments should render policy support and mitigate risks for energy infrastructure projects that

aim to import gas from diverse regions.

Recommendation 7: Adopt a Golden Rules approach to shale gas development with an adequate

regulatory framework, learning from international best practise: Governments should adopt

regulations based on “Golden Rules” to obtain a “social license” to develop shale gas resources.

4.1. Transform the building sector

Despite the attention on gas-fired power generation, the building sector is the biggest gas demand

source in Europe. 140 million gas boilers heat residential and commercial buildings, a system

which has low turnaround. Putting the building sector on the pathway of the 450 ppm scenario

would reduce gas demand by 30 bcm by 2040 relative to the NPS. This could be achieved by a

portfolio of measures:

Deep energy renovation. The average space and water heating energy consumption of the

housing stock in Europe is approximately 138 kwh/m2/year, with wide dispersal among

countries with similar climatic conditions. The average European level is actually around

double that of North America. The reason for this is that due to different social habits (older

cities and preference for keeping the traditional building stock), the turnover of the building

stock is much slower in Europe and consequently the average age of the stock is much older.

Recent significant EU progress on building codes for new buildings will not trigger a

significant change in aggregate energy consumption for decades-- there is simply not enough


31

new construction. The recent EU wide requirements that mandated condensing gas boilers

(e.g. typically 90% efficient compared to 80%) will help reduce gas demand, although this

measure alone does not outstrip impacts from population growth. Furthermore, the fact that

many old buildings have very poor heating distribution systems along with a long moderate

heating season means that efficient heat generated in modern boilers does not get efficiently

distributed to the occupied spaces. As a result, the key challenge is not to develop standards for

new buildings, which are important, but refurbishment of existing buildings that is slow and

hindered by multiple market failures. For a typical European family house, a reasonable

refurbishment can cut gas consumption by an order of magnitude of 500 - 1000 m3/year.

9

Consequently, a deep energy renovation activity will be needed for energy efficiency to make a

meaningful contribution to a 30 billion m3 gas demand reduction for the 450 ppm pathway.

The refurbishment activity would have to be more rapid than what is the normal level

determined by real estate markets: currently only around 1% of the European building stock is

refurbished annually, and the refurbishments that do take place are often optimised for

convenience and taste and thus deliver only minor energy savings. In fact, given that after a

refurbishment the owner is likely to be reluctant to refurbish again, only moderate efficiency

improvements are locked in. Some elements of building energy efficiency improvements are

very cost efficient and require standards, regulation and better information rather than financial

support. Other measures face credit rationing and might require loan guarantees or other

financial incentives. In general, the costs of energy efficiency refurbishments vary widely

depending on labour market regulations and wage costs in construction services. As a result, the

transformation of the building sector requires a portfolio of policies rather than a single

instrument.

The preferred option should be a deep energy renovation that results in at least 50% energy

savings associated with space heating, water heating, and lighting; often if very old buildings

are renovated, space heating alone can be reduced by 75% to 80% (GBPN, 2013). Deep energy

renovation involves the addition of insulation, high performance windows, air sealing, and very

small space heating equipment that offers reduced capital expenses to offset thermal envelope

measures. With generally high EU energy prices, these system-level measures are usually very

cost effective if the building is undergoing typical inefficient building renovation, and the task

is to ensure that the renovation will optimise energy performance as well as fulfilling its other

objectives such as the convenience and preferences of the owner. On the other hand a major

renovation just for energy efficiency is considerably more expensive (IEA, 2013).

It seems that the EU can pursue deep energy renovations at a rate of about 3% per year and be

cost effective. Such an effort will make a major contribution to the long-term carbon abatement

policy of the EU, but will impact gas demand only gradually. However, additional component

level policies can be effective at saving gas demand while helping to establish a viable market

place to enable deep energy renovation to become an everyday common practice. For example,

when building envelope components are replaced − such as a leaking roof, or very old windows

− there need to be requirements that specify use of very efficient materials. Arguably, the

installation of electric resistance heaters for space conditioning needs to be banned across the

entire EU, extended even to water heaters after an appropriate transition period. The immediate

policy could have a negative impact on gas equipment demand, but the medium-term impact

would be a much more viable heat pump market in the EU. Today, heat pump water heater per

capita sales are only about 1/40th that of Japan and the prices are over three times more

expensive than in the United States. Lastly, for buildings that may only have a limited

remaining service life of 10 to 15 years, or other buildings where whole building renovation is

9 IEA estimate.


32

not possible for quite some time, there are many immediate solutions to reduce space and water

heating demand. For example, thin film low-e window films can reduce heat loss in single panel

windows by 40%; low-e storm windows can reduce heat loss by 60%; and properly fitted and

sealed, insulated, cellular shades can reduce heat loss by up to 75% or more. Air leakage should

be measured and validated by energy performance certificates. Such improvements can reduce

heating loads by 10% to 30%. Energy management, consumer education, and behavioural

changes can also save 10% to 30%. Most of these short-term measures are cost effective over a

shorter timeframe, such as 5 to 10 years. Another major focus has to be more R&D on advanced

gas equipment. The development of gas thermal heat pumps with improved performance could

have a large direct impact for buildings that will continue to use gas heating, especially if such

equipment that is less expensive were to be installed and combined with improved distribution

systems. The net impact could be reduced gas consumption of up to at least 50%.

Cogeneration is usually classified as an energy efficiency measure, but its investment and

policy aspects are somewhat different from building refurbishment. Certainly, cogeneration

significantly improves efficiency by utilising the thermodynamic losses of power generation.

However, its potential is conditional on a stable heat market. Given the high fixed cost of heat

distribution, improving energy efficiency lowers the combined heat and power (CHP) potential

since an individual building will consume less heat; thus, a wider and more costly heat network

will be needed to provide heat load for the same cogeneration. Industry also has a substantial heat

need, making it potentially suitable for cogeneration. Establishing new district heating systems

requires major modifications to existing buildings and considerable urban planning, whereas in

industry a large proportion of the cogeneration potential is already served by CHP plants. The

remaining economically feasible unused CHP potential does not appear to reach the magnitude

needed to transform gas import dependency. It should be noted that gas CHP lowers gas demand

only if it replaces the combination of gas heating and gas power generation; if the replaced

electricity would have been coal, then gas demand would actually increase although emissions

would be much lower. In addition to major supply considerations, significant improvements can be

made to improve the efficiency of district heating networks including improved insulation, lower

operating temperatures, and ensuring that customers have individual heat control along with sub-

metering to encourage conservation.

Renewable heat has a considerable potential to cut gas consumption of buildings. While

electricity today accounts for around 20% of global final energy demand, heat accounts for

more than 50%.The potential to develop cost competitive renewable heating and cooling

systems certainly exists across a number of sectors, and a number of renewable heat options are

cost competitive with gas or heating oil. Apart from biogas fed into conventional gas distribution

systems, introduction of renewable heat often requires a refurbishment and modification of the

building, so ideally it is coupled with an energy efficiency retrofit as well. The biggest renewable

heat source is biomass, usually in the form of firewood and wood pellets. In the 450 ppm scenario,

biomass energy use in the EU building sector grows by 70%, roughly by the equivalent of 70

million tons of wood annually. Given that Europe already imports large quantities of wood to be

burned in biomass power plants, and the land use and lifecycle carbon impacts of this are already

controversial, the Dependency Reduction Scenario does not assume incremental biomass use in

power generation over what is already embedded into NPS, but assumes that decentralised local

heating needs enjoy priority for biomass use. This is not the case currently. In most European

countries, biomass-based power generation enjoys a far stronger financial and regulatory support

than biomass for local heating use, although it is debatable whether centralised large-scale power

generation is the optimal use for biomass resources except perhaps for biomass-based cogeneration

where waste heat is also utilised.


33

A major barrier is that markets for renewable heat are fragmented and costs vary widely between

countries. Renewable heat technologies also face non-economic barriers in much the same way as

energy efficiency faces in the buildings and industry sectors.

Most importantly, renewable heat remains a relatively neglected area in policy terms. While most EU

member states do have policies on renewable heat, they remain more segmented and less ambitious

than renewable electricity policies. There is clearly significant scope to expand the use of renewables

for heating and cooling to reduce energy consumption and enhance energy security. But unlocking

this potential requires the more widespread adoption of support policies for renewable heat. The key is

to provide policy support which is predictable and which encourages development of larger and more

competitive markets, since experience shows that these conditions can lead to significant and rapid

cost reduction.

Many EU countries have encouraged the use of renewable heat by providing capital grants for

installations based either on a percentage of costs or a fixed grant. (Austria, Bulgaria, Czech

Republic, Estonia, Finland, France, Germany, Hungary, Ireland, Italy, Luxembourg, Malta,

Poland, Portugal, the Slovak Republic, Slovenia and the United Kingdom). The United Kingdom

introduced a version of a feed-in tariff for heat for non-domestic users in 2011, which has recently

been extended to domestic customers. The Netherlands has also introduced a similar scheme.

Obligations to use renewables (or specifically solar) for heating have been introduced in the Czech

Republic, Belgium, Denmark, Germany, Greece, Ireland, Italy, Portugal, Slovenia and Spain.

These financial mechanisms are often backed up with other measures designed to tackle non-

economic barriers to the deployment of renewable heating systems. For example, several countries

have introduced quality assurance certification schemes as a prerequisite for receiving financial

support in a drive to ensure the reliability of systems and their proper installation.

There are some good examples of situations where a competitive supply chain for renewable heat

installations has been created. For example in Denmark, support polices including a carbon tax on

fossil fuels have been an important driver for the development of solar heating to provide part of the

energy needed for Denmark’s already extensive district heating network. In a competitive market

situation between local suppliers, the system costs of Danish large‐scale solar thermal installations

are now in the range of USD 350/kWth to USD 400/kWth, whereas in other European countries

costs are up to USD 1 040/kWth (IEA, 2014b). While there are specific circumstances in Denmark

which have aided this cost reduction, the example shows how competition within a sizeable market

can lead to rapid cost reduction.

Despite some encouraging increase in market growth and good examples of falling costs, currently

the costs of heat from renewable systems differ markedly between markets. These differences can

only be partly explained by differences in the available renewable resource. The capital costs of

similar systems vary widely between countries, and do not always represent the state of market

development. Prices in some countries with well‐established markets can be higher than in those

with less-mature markets. Charges for installation and the “soft costs” associated with marketing

and customer acquisition play an important role in these differences.

There is also some evidence that vendors do not recognise the need to reduce costs to open up

more, larger‐scale markets, since small‐scale local markets are seen as relatively price-insensitive.

In such circumstances financial incentives can discourage further cost reductions in technology. A

UK study, for instance, found that financial incentives in combination with relatively high fossil

fuel prices made biomass heating systems economically attractive for some consumers and thus

led to stable demand for installers. There was thus little pressure on the installer side to achieve

further cost reductions (Carbon Trust, 2012).


34

An additional push is also needed to identify and encourage the use of renewable heat in industrial

applications, which, in the long term, may be the most significant role for these technologies in a

low-carbon energy system. Future efficient and low-carbon urban environments will be based on a

more integrated approach to the production and use of energy for electricity, heat and transport.

(IEA, 2013).

Biogas from municipal waste and agricultural residues does not generate land use concerns. After

the appropriate treatment, biogas can be fed into the gas distribution network or used close to

production in decentralised cogeneration. Biogas currently accounts for 3% of EU gas demand.

The potential is certainly bigger than that although whether it can be scaled up to the level where it

has a major impact remains to be seen. Today, the overwhelming majority of biogas incentives are

paid through the electricity component of biogas CHP plants. From a system perspective, this

subsidy’s structure is questionable, however. In a context where the share of low marginal cost

base-load sources in the system – like wind and solar – is increasing there is no real need for

incentivising more costly forms of base-load generation such as biogas CHP plants. By contrast,

with the right policies, biogas could play a key role in responding to the increasing balancing

needs of the system. Incentives should aim at encouraging biogas upgrading into methane. This

would allow taking advantage of the storability of gas in responding to the growing variability of

the power system.

Except for Italy, the scarcity of active volcanic zones in the EU implies that most geothermal

resources are low temperature. While technically even low temperature geothermal resources can

generate electricity, this requires capital intensive equipment and has low efficiency. In most of

Europe, geothermal resources are much more suited for heating purposes, ideally in feeding

district heating or low-temperature industrial heat loads.

Solar collectors are a very cost efficient way to generate heat even in temperate climates provided

that system costs follow best practice. On a typical home, they can replace a substantial proportion

of residential hot water needs, although for climatic reasons their contribution to winter heating is

limited. Residential hot water accounts for around 20 bcm gas consumption in Europe.

Electric heating is already used on a large scale, especially in France and Scandinavia. Given

that gas does not play a significant role in the electricity system in either region, this effectively

reduces gas demand. Heaters based on electric resistance transform electricity to heat with a

roughly one-to-one ratio. This is detrimental for energy efficiency as the losses of the power

system (most of which is waste heat from power plants) become final losses. Electric heat

pumps, on the other hand, can transform electricity to heat at a one-to-three ratio. This means

that even if a heat pump is running on gas-fired electricity, there is a substantial reduction of

gas demand since a roughly 50% efficiency is then magnified by a factor of three. Installing

electric heat pumps is a significant investment which requires modifications in the heating

system. As a result, it is best coupled with a broad energy efficiency retrofit which lowers heat

needs and switches them to a heat pump. A typical retrofit project would replace around

2000 m3 gas demand with 4 Mwh electricity demand.

10 Due to the large underutilised gas fleet

in Europe, the most likely source of the incremental power demand is gas, but even in that case

there is a net gas demand reduction of 1200 m3. Moreover, there are a significant number of

hours when the marginal generator is coal, in night hours even nuclear or renewables, in which

case the demand reduction is 100%. Note that a heat pump running on coal-fired electricity has

lower CO2 emissions than individual gas heating.

10

IEA estimate.


35

Large-scale penetration of heat pumps would increase winter electricity demand. Europe already

has a winter peak, around 50 GW higher than in summer which is unfortunate from a gas supply

security point of view: in the United States, peak gas demand for power generation is in the

summer when heating demand is minimal, whereas in Europe peak gas use in power generation

coincides with the heating peak. In addition, a winter peaking system severely limits the usefulness

of solar PV for supply security as solar has practically zero capacity credit (the system peak is

during winter evenings after sunset). In addition, heat pumps can make a potentially very valuable

contribution to electricity supply security as they offer a large and cost efficient demand side

response potential. Heating systems have considerable thermal inertia, and heat pump systems can

be remotely controlled offering demand response. As a result, while they increase winter peak

demand, they facilitate an even larger-scale deployment of wind, which in Europe is stronger in the

winter. In addition to reducing gas import dependency, heat pumps are likely to play a major role

in decarbonising the building sector. Unfortunately they are not on track: there has been significant

progress in France and Germany, but overall the EU significantly lags the rate of sales compared

to Japan and the United States.

If the growth rate is not dramatically increased, it will not meaningfully influence aggregate gas

demand in the next two decades. The most likely barrier for heat pump deployment is the large

initial investment cost and the significant modifications that are required on the heating system of

the house. In addition, in most European countries the relative price of household gas and

electricity tariffs is heavily influenced by the regulatory charges, most often renewable incentives

that are charged on the electricity bill, whereas typically gas is less burdened by additional charges.

As a result, in the absence of special tariffs for heat pumps in most European countries, switching

to heat pumps from gas has a negative net present value.

4.2. Continue to push wind and solar into the power system

Wind and solar PV are genuine success stories of energy technology policy. Deployment of wind

and solar in Europe since 2005 compensated for the decline of European domestic upstream by

replacing gas-fired power generation. In 2014, Europe brought online around 12 and 7 GW of

wind and solar capacity respectively, which would have required an additional 1.2% of EU gas

demand burned in gas-fired power plants. Even in the United States, their growth contribution to

power generation is comparable to gas, which is a major achievement in the context of the shale

revolution. There is no doubt that this trend will continue. On the basis of current policies and

investment activities, the IEA Medium-Term Renewable Market Report 2015 foresees a 171 Twh

expansion of wind and a 35 Twh solar in Europe by 202011

(IEA, 2015). Importantly, this is

considerably more rapid than demand growth, so it reduces the reliance on other power generation

technologies in absolute terms. Given the interactions in the power system, it is not straightforward

to estimate the gas demand reduction that this will achieve as this is region and time specific: For

example, the increase of wind power at night in Germany will reduce coal rather than gas

demand as in these periods coal plants are the marginal generators in the German system.12

On

the other hand, solar PV in Italy will reduce gas-fired power generation during the day.

Under realistic assumptions on coal, gas and CO2 quota prices, coal plants will continue to have

lower marginal costs in Europe than gas plants. Consequently, coal capacities will tend to run at a

higher load factor than gas plants, and expansion of low marginal cost generation will constrain

coal operations only after gas plants are at the minimum level.13

Given demand weakness and the

11

OECD Europe, wind includes onshore and offshore wind.

12 It could also increase German power exports up until the interconnectors are not congested in which case the impact will depend on the

structure of the importing system.

13 Due to operating constraints, the minimum level might be higher than zero.


36

already high share of renewables, this is a credible scenario especially in Germany and Spain;

nevertheless there is no doubt that renewable deployment has a measurable impact on gas demand

in the power sector. On the other hand, while available coal capacities will continue to run at a

reasonably high load factor, a substantial coal capacity will be decommissioned and thus the ability

to burn coal will be physically constrained. Europe is also likely to lose nuclear capacity, especially

in the decade of 2015-2025. As a result, in base case projections (MTGM and WEO NPS)

renewables and gas-fired generation grow in parallel, due to the decline of coal and nuclear.

Renewables slow the growth of gas demand but do not reverse it.

This is not a technological inevitability. In the WEO 450 ppm scenario, gas-fired power generation

by 2040 falls to around 60%the current level, lowering gas demand in the power sector by around

75 bcm instead of increasing it by 40 bcm in NPS. Robust expansion of wind and solar are a major

factor behind this decline: compared to the NPS pathway, cumulative investment in the 450 ppm

pathway into wind is 43 GW and solar is 25 GW higher. Stronger assumptions for nuclear

generations and lower overall electricity demand are equally important factors in reducing gas

consumption in the European electricity system in a 450 ppm scenario.

Unfortunately, as the NPS projections show, even with the recent policy success Europe is not on

track for a renewable deployment that is consistent with the 450 ppm scenario. In fact, there are

worrying signs that renewable investment might slow down. Several European countries

implemented cuts in their incentive schemes, in some cases retroactively which has had a

detrimental effect on investor confidence. Rising electricity prices have generated considerable

social and political concern which has an impact on the scale and ambition of renewable policies

despite the fact that renewable incentives are by no means the exclusive reason for rising electricity

prices in Europe. Some European regions with attractive natural potential seem to be saturated with

onshore wind, although repowering still offers a potential. Typically transmission and distribution

upgrades are lagging behind renewable deployment and in regions deployment of wind and solar

occurred rapidly and concentrated in hot spots this has led to a strain especially on distribution

grids. So far, the ability of Transmission System Operators (TSOs) to integrate variability from

renewables to the grid exceeded expectations, and there have been no cases of a supply security

problem arising from renewable related variability. Nevertheless, most TSO’s have a conservative

approach and some of them were outspoken in their concerns which might influence renewable

policy ambitions. Moreover, while the integration of wholesale electricity markets has progressed

well, renewable incentives remained stubbornly national. This creates uncertainty over the period

beyond 2020 when only an EU-level renewable target will be binding. In the absence of an EU-

level policy instrument for renewables, an EU-level binding target would have to emerge as a

mathematical combination of indicative national policies. Maintaining the consistency and

credibility of renewable policies under such circumstances will not be straightforward.

Reflecting all these financial and policy barriers, the WEO NPS pathway does show a

measurable slowdown of renewable deployment. In the 2020 – 2030 decade, average incremental

capacity is around 8.5 GW wind and 3 GW solar, compared to around 12 GW wind and 7 GW

solar in 2014.

Putting the EU electricity system on track for a 450 ppm wind and solar path requires strong,

robust and credible renewable policies that channel high levels of investment into wind and solar

capacities as well as a significant change in system operation and regulation.

The incremental investment needed in wind and solar to move from an NPS to a 450 ppm

trajectory is around 13% of the total investment in the NPS. It would equal to 21 000 windmills

and 5 million solar rooftops. There is no doubt that capital is available if the investment risks and

returns are adequately balanced. While the European Emission Trading System needs to be

reinforced, it would be optimistic to assume that it could reach a stage where a carbon price alone

can trigger rapid and large scale low carbon investment. Low-carbon deployment on the 450 ppm


37

path is considerably more-rapid than the natural turnover of the capital stock, so there is a policy

generated artificial excess capacity depressing wholesale prices. Due to sustained low wholesale

prices, a carbon price which would bring new capital-intensive capacities into the system would

have to be extremely high. As a result, an investment policy for low-carbon capacities is

justified. On the other hand, there is an increasing recognition that with very large-scale

deployment, the investment and operational incentives have to be efficient to control policy

costs; first generation feed-in tariff policies might no longer be optimal. A careful balance will

have to be struck between investment security and adequate incentives.

It should be emphasised that with adequate policy design, the average incremental cost of new

deployment will be much lower than the current policy cost: the large majority of the already

committed incentive payments is associated with the first generation, very expensive

deployment, which, due to inadequate policy design, often resulted in bubbles. However, at least

partly due to the large-scale deployment in Europe, a substantial investment cost reduction took

place. The policy costs of the “learning by doing” phase are already sunk, and the further

deployment with an adequate policy design will be cheaper. Due to excess capacity, it will not be

competitive with the marginal cost of expanding the utilisation of existing gas-fired capacities,

but the cost gap has narrowed measurably and the additional climate and energy security benefits

are measurable.

The possibility of a centralised tendering process at EU level, following a template similar to that

already utilised by other countries such as South Africa or Brazil, could be a low cost and

effective system to achieve the EU 27% renewable target by 2030.

Electricity supply security needs to be maintained, as a series of blackouts would surely undermine

the social support for the policy. During the large-scale deployment of the past decade, a substantial

accumulation of know-how and innovation took place for operating electricity systems with high

shares of renewables, to a significant extent by European utilities and system operators. IEA analysis

shows that the renewable capacities consistent with the 450 ppm scenario can be securely integrated

into the electricity system even without technological breakthroughs on electricity storage, but

several changes are needed in operations and regulatory design:

Initial deployment was usually based on the assumption of the system adjusting to incorporate

variable renewables whose volatility was taken as given. This was the underlying assumption

behind “priority dispatch” policies that exempted renewables from bidding and balancing

obligations. There is now an increasing realisation that “system friendly” renewable

deployment can greatly facilitate integration. This can take the form of different wind turbine

designs optimised for smoother operation, proactive management of renewable production to

avoid steep ramp-ups and even providing spinning reserves from windmills. The key policy

measure to provide such incentives is a technology neutral balancing market which, reflecting

the characteristics of wind and solar, settles close to real time.

Integration of electricity markets is a major enabling factor for energy security and renewable

deployment. Neither renewable production nor demand patterns are perfectly correlated so

integration across a broad area reduces overall volatility and provides a partly self-balancing

renewable portfolio. Market integration requires both an infrastructure platform and a regulatory

support; neither is complete in Europe. Expansion of transmission interconnections is clearly

lagging in Europe. Most of the interconnections that succeeded are undersea direct current cables.

Such projects usually have a merchant business model, being exempted from normal price

regulation. Perhaps even more importantly, they run on the seabed so they don’t face social

resistance from local landowners. There has been remarkably little progress in enhancing

transmission in the core interconnected European system, in fact on some very important borders

such as France – Germany available interconnection capacity declined. Accelerating transmission

development with streamlined licencing and targeted financial incentives should be a priority.


38

The regulatory environment has made impressive progress in integrating wholesale power

markets with the rollout of decentralised market coupling. On the other hand, there has been

little progress in integrating real time balancing and system operation. This is unfortunate since

with a large share of renewables the importance of short time horizon markets and operations is

increasing. There is cross-border ownership of transmission assets,14

but even those are

operated and regulated on a strictly national basis.

A more elastic demand side enhances market efficiency and facilitates renewable integration. It

seems that if the institutional and behavioural barriers can be tackled, it is a cost effective

flexibility option. Most EU electricity systems lag behind the best practice15

in mobilising

demand side response, suggesting room for improvement. It should be emphasised that

deployment of smart meters will alone not enhance demand response; it needs to be coupled

with supportive regulations, incentives and innovative system operation solutions. Measures

that are oriented towards reducing gas consumption in the building sector will have to include

heat pump deployment as well, which could significantly expand the demand side response

potential.

While IEA projections do not rely on assumptions of a technological game changer in storage,

there is no doubt that electricity storage expansion facilitates renewable deployment.

Unfortunately, recent market changes have made the business model for electricity storage

more challenging, leading to the cancellation of high profile storage initiatives. Excess power

capacity and the increase in daytime solar PV production cut the peak/off-peak price

differential that is the traditional value proposition of storage to a level where any new

investment is likely to be uneconomical. On the other hand, a storage specific investment

incentive does not appear to be justified; the system contribution of storage should be

compensated in the context of a broad market design reform.

Even with the mobilisation of demand-side response, under realistic assumptions on feasible

transmission development and electricity storage, dispatchable power plants will remain the

dominant source of system flexibility for decades to come. Modern gas turbines fit the role

perfectly given their rapid start up and flexible operation. In the 450 ppm scenario, the EU power

system sees major new investments in gas-fired power generation: gas capacity expands by more

than the current gas fleet of Germany, the United Kingdom and the Netherlands combined. This

does not lead to increased gas demand, since the role of gas-fired generation is fundamentally

different: as gas plants run only when there is not wind and solar, their average utilisation is

compressed to around 1300 hours/year compared to around 3-4000 in a conventional system.

The disconnection of capacity demand from electricity demand from the point of view of a gas

plant is a major challenge for their business model: The conventional value proposition of

recovering investment from the difference between gas and electricity prices (the spark spread)

has been deeply loss-making in the past three years, and industry widely considers it to be broken.

A perfect market could, in theory, rely on price peaks in windless, dark hours to provide

investment incentives but there are serious doubts because of market failures. These concerns

have led to the discussion and introduction of various capacity mechanisms in the majority of

European countries and in most US regions as well. While detailed assessment of electricity

market design issues is beyond the scope of this analysis, it is an exercise that should be

undertaken with adequate attention not to interfere with either interregional trade flows or

innovation in storage and demand response.

14

For example, part of the German grid is owned by the Dutch TSO Tennet.

15 The most successful examples are in the Eastern United States.


39

4.3. Improve connectivity and flexibility in European gas infrastructure and complete integration

at the EU level16

Gas infrastructure in Europe has expanded significantly since 2009, but while regional

connectivity has improved, Europe’s gas supply structure has remained broadly the same. Better

interconnections, also through reverse flows, have been developed within regions and from North

West Europe (NWE) to Eastern Europe and Southeast Europe (SEE), although some countries

remain dependent on a single supply source. Eastern Europe and SEE show the greatest

vulnerability in the event of a supply disruption due to limited storage and interconnections.

The implementation of reverse-flow projects has been a key pillar in the strategy towards better

integrated European markets. Implementing reverse flow capability on existing pipelines that are

currently unidirectional is typically more cost efficient than building new pipelines. The most

significant physical reverse flow project has been implemented in the Germany – Czech Republic

– Slovakia direction. Today, available physical capacities in the West-East direction exceed East-

West capacities on these systems, enabling traders to ship gas from Germany to the Czech

Republic or Slovakia. This development is largely due to the 2009 disruption of Russian gas

supplies via Ukraine and the number of reverse flow projects implemented in Central Europe,

which were co-funded by the European Energy Programme for Recovery (EEPR).

The completion of the Nord Stream and related Opal and Gazelle pipelines has strengthened gas

supply availabilities in the German Southern gas market area of NetConnect Germany (NCG).

Price arbitrage between the liquid NCG and high-price Baumgarten hub have favoured reverse

gas flows for several years making it the new dominant flow direction (Figure 1). According to

ACER,17

historical contracts for the transit of Russian gas from Slovakia through the Czech

Republic to Germany and next to Western Europe have been transposed from the Brotherhood

pipeline system into the Nord Stream – Opal – Gazelle system.18

These contracts are now

delivering gas from Nord Stream to NCG and from there to Czech Republic and onwards.

A number of alternative shippers are very active in booking physical reverse flow capacities at

the DE-CZ interconnectors, motivated by price differences between German versus Czech and

Slovak and Austrian gas spot prices and also sales opportunities in Ukraine. Traditionally, prices

at Baumgarten have been above TTF due to dominance of one supplier and low competition,

despite the lower transportation costs to Baumgarten for gas which flows in the East to West

direction. Increased reverse flow capability in the West to East direction has increased Eastern

Europe’s ability to mitigate the market power of Gazprom, as well as allowing supplies of

meaningful volumes of gas to Ukraine through suppliers other than Gazprom.

Two other reverse flows have become a crucial diversification tool. The EU became a moderator

for launching the reverse gas flows through one of four main pipelines at the Uzhgorod-Velke

Kapusany gas transit points on the Ukraine-Slovak border from EU countries to Ukraine in the

summer of 2014, and facilitated the signing of the so-called "winter package" of Russian gas

supplies to Ukraine in the autumn of 2014, thanks to trilateral talks. Reverse flows from Greece

to Bulgaria are going to become more important. As of 1 July 2016, gas flows between Bulgaria

and Greece (only 10% today, see Figure 1) are enabled with a new interconnection agreement

between the gas network operators, which will open a gas corridor between Greece, Turkey,

FYROM and Ukraine and provide the Balkan region with access to diversified supplies,

including from LNG and the Caspian region.

16

This chapter benefits from Research provided by the Regional Centre for Energy Policy Research (REKK). See also:

http://www.entsog.eu/public/uploads/files/publications/TYNDP/2013/8workshop/REKK_131120_WS_8_CBA_.pdf 17 ACER (2013), Transit Contracts in EU Member States. Final results of ACER inquiry, 9 April 2013. pp 41-42.

18 The Gazelle pipeline entered into the regime of exemption from third party access as of 1 February 2013.


40

Beyond this major new trunk-line, several other upgrades and debottlenecks have occurred across

the EU gas transmission system. More often than not, however, the reverse flow capability on

cross-border points has not been introduced in full, either due to the lack of the necessary

upgrades to the relevant domestic transmission systems or due to exemptions from the regulation

itself. Physical reverse flow capability on the German-Polish border of the Yamal pipeline was

established only by the early 2014, with limited capacity: reverse flow capacity from Germany to

Poland is only up to 13% of the Yamal capacity from Poland to Germany. This leaves Poland

vulnerable to Russian pipeline disruptions, although the start-up of the Swinoujscie LNG

terminal would help mitigate the impact of any disruption.

TAG (ATIT) and WAG (ATDE) provide physical reverse flow capacities (see Figure 1),

although TAG physical reverse flow could serve as an important transportation route for North

African gas and Italian LNG to Central Eastern Europe, as well as for TAP gas to Central Europe

in the longer run.

Figure 1: Reverse flow directions, in % of dominant direction

AT Austria

BA Bosnia Herzegovina

BG Bulgaria

BY Belarus

CZ Czech Republic

DE Germany

EE Estonia

FI Finland

GR Greece

HR Croatia

HU Hungary

IT Italy

LT Lithuania

LV Latvia

MD Moldova

MK Republic of Macedonia

PL Poland

RO Romania

RS Serbia

RU Russia

Sl Slovenia

TR Turkey

UA Ukraine

Note: The dominant direction is determined by the value of the technical capacity available at each border point as contained in

ENTSOG capacity map, wherever the capacity is higher.

Source: ENTSOG (2014a) and Regional Policy Centre for Energy Research (REKK).

Implementation of reverse flow projects in the South-East European region generally began later

and took more time than those in Central Eastern Europe (CEE). Construction works in the

Northern part of Romania to enable reverse flow within Romania up to the Ukrainian border

faced technical and commercial difficulties. Other projects needed to enable reverse flow further

South on the Bulgarian-Greek border have only very limited capacity or are lagging behind.

In recent years the Hungarian gas transmission system operator initiated and completed with its

partner TSOs important new interconnections, which for the first time opened up possibilities for

North-West South-East and North-South gas co-operation in the CEE region. The HU>RO

(4.8 mcm/day) and HU>HR (19.2 mcm/day) interconnectors were commissioned in 2010. Both of

these interconnectors were designed to provide bi-directional services. However, the

implementation of these physical reverse flow projects has been delayed. The first reverse gas flow

happened to take place in the RO>HU direction in February 2014. Successful off-shore gas


41

exploration on the Romanian section of the Black Sea by OMV and ExxonMobil might necessitate

the implementation of potentially significant gas transportation capacities in the RO>HU>AT

direction in the future. Hungary sought to implement physical reverse flows on the Hungarian-

Austrian gas pipeline (HAG), but the Austrian partner asked for and received an exemption to this

project. In this case, the reverse flow would actually run in the East-West direction. While it would

not shield Eastern European markets from a possible Russian supply disruption, the introduction

of bi-directional capability would nonetheless be useful towards market integration.

While the HU-HR interconnector is operational in the Croatian direction, the lack of a compression

station and other bottlenecks on the Croatian side precludes physical reverse flows in the HR>HU

direction. The implementation of this option could help to balance the Croatian gas system as

well as provide a route to ship LNG (in

case a terminal was to be established) to

CEE and further to Austria or Ukraine.

An important component of the North-

South gas corridor in CEE was recently

added with the start-up of the SK-HU

interconnector this year. Although the

pipeline operates in both directions, the

offered capacities are asymmetric: 11

mcm/day in the SK>HU direction and 4.4

mcm/ day in the HU>SK direction. The

HU>SK capacity could be expanded by

building additional compression capacity

on the Hungarian side. The HU-SK

interconnector illustrates well the

challenges of building infrastructure

primarily for security of supply purposes.

Several failed open season procedures for

the construction of the project had signalled

its limited commercial value under normal

market conditions. Utilisation today

remains very low.

While in North West Europe the current

infrastructure is clearly sufficient to allow a

well-functioning market, it might not be

enough to deal with a prolonged large scale

emergency, in an integrated market manner.

Europe has large underutilised LNG import

capacity. Total regasification infrastructure

repre-sents about 45% of the region’s consumption. In theory, if fully utilised, this capacity could

cover the entire, annual average consumption of Europe’s residential and commercial sector. In

2014, NWE (the United Kingdom, France, the Netherlands and Belgium) accounted for 47% of the

total capacity and Spain for another 29%. At just above 20%, average utilisation remains remarkably

low. Despite low utilisation levels, LNG capacities in Spain and the United Kingdom would remain

underutilised in the case of a large-scale supply disruption due to the internal bottlenecks of the

European system.

In the case of the United Kingdom, the key constraints are the lack of capacity to redirect

Norwegian gas to Germany and the insufficient capacity to forward UK gas through Belgium

Figure 2: Interconnection points and related technical firm capacities in NEW (in GWh/d)

Source: ENTSOG (2014b)


42

towards Germany. In particular, it would not be possible to run the Zeebrugge LNG terminal

(Nominal Annual Capacity: 9 bcm/a) and the UK-Belgium interconnector (Technical Capacity:

25.5 bcm/a, Zeebrugge entry) at full capacity without running into bottlenecks in the Belgium-

Germany direction assuming total technical firm capacities from Belgium to Germany of

9.4 bcm/a. However, it should be noted that technical capacities at an interconnection points

cannot be straightforwardly determined and more granular analysis of possible bottlenecks in the

gas infrastructure should be performed based on gas-flow models (e.g. by ENTSOG).

In the case of France, its large spare regasification capacity would be useful in replacing

disrupted Russian flows directed to France. Yet, full utilisation of the French regasification

infrastructure would remain hindered by the lack of reverse flow capability on the Megal pipeline

(in the France to Germany direction). In the case of Spain, given the limitations of the pipeline

infrastructure through France (limited Spain – France interconnection and lack of reverse flow

capability from France to Germany) the practical flexibility would be redirection of export flows

within Algeria towards Italy. This, however, would necessitate deep co-operation. Moreover, as

described at the beginning of this chapter, any LNG supplies forwarded to Germany and Italy

would face further bottlenecks towards the Central and South Eastern European region that is

highly dependent on Russian gas. Compared with enhancing reverse flow capabilities in the

North-West to Central Eastern Europe direction the build-up of a new green field pipeline

connecting Spain to France does not look as the most efficient option from a pure cost

perspective.

Overall, while major progress has been made since 2009 it seems that exemptions to the general

reverse flow obligation were granted too lightly and cost allocation disputes hold up even for

reverse flow projects with a major energy security benefit. The infrastructure, regulatory and

contractual barriers of the single market should be addressed by infrastructure development and

enforcement of existing energy regulation. Reverse flows are especially important as an

alternative supply source for Ukraine itself where neither pipeline nor LNG alternatives are

feasible in the medium term. Given that the Energy Community expands the single market to

Ukraine, contractual as well as non-market based efforts to limit reverse flows to Ukraine should

be countered by a vigorous enforcement of EU competition law.

4.4. Strengthening gas storage

Alongside well interconnected markets, gas storage can have a very powerful contribution to

supply-security. Gas storage was the single most important channel of responding to either the

2009 Russia-Ukraine gas disruption or to the 2013/14 polar vortex in North America. In a

theoretically perfect market spot and forward price signals would create an incentive to store gas,

and widening price differentials create incentives for new storage investment. Unfortunately is

debatable whether a perfect market case is an adequate basis for regulatory policy.

Price signals might fully reflect variations in demand but not the likelihood of high-scale low

probability disruptions. While winter-summer demand fluctuations are typically well reflected in

the forward price curve, the possibility of low probability-high impact events such as a transit

disruption or a sudden demand upswing are not necessarily. In Europe the overwhelming

majority of gas storage capacity has been designed for a winter-summer cycle with rigid

operation. Almost 90% of existing storage capacity comprises of depleted fields or aquifers –

which are primarily used to respond to seasonal demand fluctuations. Raising the peak

withdrawal rate compared to the mobile capacity (the gas stored annually) and enabling multiple

cycles is a very significant additional investment and many storage operators would be reluctant

to do so, on the basis of forward prices only.


43

In the absence of very high balancing charges that reflect the social value of a disruption, market

participants could have an incentive to under-contract and rely on the spot market but this could

lead to liquidity to disappear in less than perfect markets. On the other hand, the experience of

countries that adopted strategic stockpile policies show that it is rather expensive and it is difficult

to set up without causing market distortions.

There are a number of options to fine tune the regulatory policies and improve the supply

security contribution of storage. In particular when competing to offer flexibility, a storage

facility’s position is strongly determined by the transmission tariff structure of the market they

are part of. High transmission tariffs on the boarder – and especially storage entry/exit tariffs to

the network can prohibit the ability of some facilities to compete with other forms of flexibility.

If regulators want to encourage higher levels of storage fillings, they have to take into

consideration the set of bundled storage and transmission fees. As in several countries storage

tariffs are regulated, one option could be to design tariff bands that incentivise a higher level of

storage fill, taking into account the high fix cost of storage facilities.

On an aggregate level, Europe has vast storage capacity, albeit unevenly distributed. Insufficient

physical interconnectivity of markets and limited access to other countries’ storage facilities in

certain cases (for example transmission capacity bookings on an interruptible basis between two

national markets) create barriers to the emergence of efficient regional storage markets in

Europe. Addressing these constraints could improve the efficient utilisation of storage.

Given the European Union’s large storage capacity accounting for 20% of its domestic demand,

the efficient use of the existing infrastructure for security of supply is critical. In several

countries, the use of gas storage is changing and policy measures are under consideration to

increase the availability and flexibility of gas storage capacity. Regulated third-party access

regimes are becoming more attractive in changing gas storage markets, where summer-winter

spreads are increasingly disappearing.

In summary, the continuing economic viability of gas storages in an evolving market

environment is essential from a security of supply point of view. Three elements are critical to

secure the viability and availability of gas storage: 1) ensuring effective and transparent third-

party access (TPA) to storage capacity, including across the borders, and where appropriate,

applying regulated TPA which places storage in the regulated asset base 2) recognising the value

of storage for the system through lower transmission tariffs at the entry and exit which reflect

actual cost, and 3) taking a regional approach to optimize storage use (and lower its costs).

Storage obligations can be expensive and discriminatory in an evolving market. For example, in

France considerations are given to a new storage regime. Amid low storage levels at the

beginning of winter 2012/13, the French Ministry raised storage obligations to 80% of shippers’

capacity rights, corresponding to all customers connected to the distribution grid (previously the

obligation was limited to domestic customers and customers providing services of general

interest). Higher obligations on shippers pose challenges in a context of negotiated TPA.

Additionally, the current model, where access to storage is prioritised to shippers with final

customers, is less justifiable than it once was, considering today’s higher levels of competition

and liquidity in the wholesale gas market. The French government is therefore re-assessing its

storage access regulation with the aim of proposing new rules in the autumn of 2016 and having

a new regulatory framework in place by 2017.

For a decade, the United Kingdom and the Netherlands have seen their swing storage capacities

declining. Investment in new gas storage has been successful in the Netherlands with the

Bergermeer gas storage facility. The United Kingdom has not seen similar investment in seasonal

gas storage. Bergermeer is now the largest third-party access underground storage in Europe and


44

large capacity has been auctioned to the market, in large parts also replacing the flexibility of the

Groningen gas field. However, gas storage tariffs have reached a record low. In Germany,

negotiated third-party access is in place, but the commercial viability of the gas storage business

is impacted by the disappearing winter/summer spread.

Discounts of the transmission costs for companies that want to store gas already exist in countries

like Germany, Belgium, United Kingdom, France and the Netherlands. Looking ahead, Europe’s

storage needs are likely to shift increasingly towards more flexible capacity. Efficiency gains are

starting to erode residential demand loads, while is gas is taking up a bigger role for intermittent

power generation. This will require substantial level of investments to adapt the existing storage

capacity.

4.5. Adopt adequate policies in countries which choose to maintain nuclear power as a viable

component of energy supply

Nuclear is the largest low-carbon energy source in Europe, around two and half times bigger than

wind and solar together. With the current renewable deployment speed, it would take around

thirty years to replace nuclear with wind and solar. Given that nuclear is a baseload source, this

would not only delay decarbonisation but would necessitate a large-scale transmission and

electricity storage deployment as well. Historically, the nuclear investment wave in the 1970s to

a significant degree was motivated by energy security concerns and played a crucial role in

reducing European oil imports by replacing oil-fired power generation. The majority of European

nuclear comes from that 1975 – 1985 generation which will approach the end of its lifetime in

the next 20 years. If that generation is not replaced, nuclear’s contribution to reducing import

dependency will prove to be temporary. Oil will not return to the EU power generation sector

under any foreseeable scenario, but for gas the structural decline of nuclear is one of the possible

drivers for increased dependency: replacement of EU nuclear with CCGTs would roughly double

gas imports from Russia. While on an individual country level, Germany is on track to replace

nuclear with renewable energy sources, this does not seem to be realistic at the EU level. At the

very least, it would delay decarbonisation by decades. In the 450 ppm scenario, the expansion of

nuclear (a nuclear “renaissance”) is an important component of decarbonisation.

Political and social attitudes toward nuclear diverge broadly in EU countries, ranging from

constitutional bans to state-facilitated investment policies. Although gas supply security and

import cost concerns clearly play a role in the discussions on nuclear, in this analysis we do not

expect that countries that have made a policy decision to phase out or not have nuclear at all will

reverse it. Rather, the assumption is that countries that already have nuclear and do not have an

explicit phase out policy as well as countries that are considering building their first plant will

implement policies to facilitate nuclear investment.

Both European and North American experience suggests that the lifetime of 1970s/80s vintage

nuclear reactors very often can be extended without jeopardising nuclear safety. This requires

investments but those are significantly below the cost of new construction and, given the additional

production, compare favourably with the cost of several other low-carbon options. There have been

cases where due to failures of the original design or the aging of the equipment, lifetime extension

was not possible. In those cases, nuclear safety must receive an absolute priority. Fortunately, this

does not seem to be the case for a substantial proportion of the EU fleet. Governments that intend

to continue to rely on nuclear power should encourage and facilitate lifetime extensions while

maintaining the highest standards for nuclear safety. The WEO NPS assumes a large-scale lifetime

extension in the absence of which the decline of EU nuclear production would be even more

pronounced. However, lifetime extensions alone will not be able to stabilise EU nuclear production,

which is declining even in WEO NPS. In the decarbonised energy system of the 450 ppm scenario,

EU nuclear capacity is 16 GW higher in 2040 than in the NPS path, making a significant


45

contribution to CO2 emission reductions. Together with the investment necessary to replace current

plants that cannot be extended, it represents an investment wave that would be equivalent to around

ten nuclear reactors under construction19

in Europe at any given time over the next two decades.

This would represent a major investment challenge.

In theory, a perfectly functioning market could provide incentives for nuclear investment:

wholesale electricity prices would signal investment needs into new capacity and carbon pricing

would adequately reflect the value of low-carbon production. Unfortunately, this is highly

unlikely in reality. Weak electricity demand and a rapid expansion of renewable production

generated a persistent excess capacity depressing wholesale prices. This is detrimental to the

economics of capital-intensive generation forms, such as nuclear. The same two factors also led

to a decline of carbon prices to a level that fails to have a major impact on investment decisions.

Although reinforcement of the European emission trading system is rightly on the political

agenda, climate policy will not be able to rely on only the carbon price only as a single

instrument. Moreover, due to the very long time horizons inherent in nuclear projects, future

carbon prices are discounted, and they have to be very high to have a major impact.

Nuclear projects also have an unusual level of project management risk. They are very large,

complex, have long time horizons as well as highly sensitive and sometimes unpredictable

regulatory issues. They are not the largest projects in the energy industry: the large LNG projects

and the complex oil megaprojects are even bigger financially. However, the international oil

companies (IOCs) have a stronger balance sheet by an order of magnitude than even the largest

electric utilities and they routinely use project-based diversification, where several companies share

the financing of an individual project.

Nuclear plants have a track record of cost overruns and project delays which have such a powerful

impact on project economics that is difficult to compensate with carbon pricing: A project

management problem causing a yearlong delay and a billion euro/GW higher investment cost

would require a 40 euro/ton higher carbon price to generate the same net present value.20

It seems

extremely unlikely that any private investor would undertake a nuclear investment on the basis of

European wholesale electricity and carbon prices. Consequently a “laissez faire” policy on nuclear

is equivalent to a phase-out policy in its end results: closure of nuclear at the end of its licenced

lifetime and its replacement with other energy sources.

Vertical integration is a widely used corporate response to long-time horizon market uncertainty.

Both of the nuclear projects currently under construction in Europe have substantial vertical

integration:21

Olkiluoto in Finland benefits from the participation of energy-intensive industrial

consumers for whom it will provide stable electricity supply, whereas Flamanville in France is

developed by Electricité de France (EDF), which has a very large and stable market share in the

French retail market. Unfortunately, both projects have had difficult project management

experience, and it is unclear whether their business model can be scaled up to the level that would

be required. It seems very likely that either long-term contracts, risk management instruments such

as the Contract for Difference applied in the United Kingdom and even direct capital guarantees

would be indispensable to mobilise investment into nuclear. Appropriate compromises will need to

be found with EU competition and state aid regulations in order to avoid distortions to the single

market but also maintain the important climate and energy security contribution of nuclear

19

With a 1.5 GW reactor size and seven years’ construction time.

20 The reference case was assumed to be a 4 billion euro/GW investment cost and 6-year construction time. Note that the example is

relatively mild compared to some real life nuclear projects in the EU.

21 The most successful nuclear investment programme in OECD countries is in Korea, which also has a vertically-integrated electricity

sector.


46

investment. In addition, pro-nuclear governments should consider reviewing and streamlining their

licencing procedures in order to minimalise the risk of project management problems, obviously

without compromising nuclear safety.

4.6. Expand the southern corridor, enhance partnership with key exporters

From Algeria to Turkmenistan, Europe is surrounded by very large geological resources of gas, a

considerable proportion of which is actually geographically closer to Europe than the supergiant

fields of West Siberia. As a result, a direct pipeline link with these regions has rightly been a

policy priority for a decade. After a complex process, the Shah Deniz project in Azerbaijan took a

final investment decision, and chose the TAP (Greece – Albania – Italy) route for delivery. A

separate consortium (TANAP) will expand transit capacity to Turkey. There is no doubt that this

is a major and positive development: Shah Deniz is the first major upstream project dedicated to

the EU market that has taken an investment decision since the 3rd

energy package transformed

European gas and power markets. The progress of Shah Deniz is a strong vote of confidence that

creation of efficient competitive energy markets in Europe is compatible with developing complex

and difficult new upstream projects. On the other hand, the quantity will not be transformative:

10 bcm by the end of the decade will barely compensate for volumes lost from Algeria and Libya,

leaving the position of Russian gas largely intact. In order to fulfil the strategic role that was

envisaged in European energy policy, the Southern Corridor will need to be expanded beyond the

Shah Deniz export quantities. This will likely require new initiatives.

The easiest expansion is probably Azerbaijan itself, where Shah Deniz is not the only gas

potential. Due to the Absheron field, the gas layer of the giant Azeri Chiang Gunasli field as well

as further exploration potential, IEA projections for the growth of Azeri gas production to

significantly exceed the potential of the Shah Deniz field. Azeri gas production is foreseen to

reach 58 bcm from the current 20 bcm by 2040. Half of the growth is expected to take place after

2020, indicating further growth potential beyond the Shah Deniz/TAP contracts. This could

probably proceed in the institutional framework that governs the current Shah

Deniz/TANAP/TAP route.

Beyond Azeri gas, further expansion of the Southern Corridor will face serious obstacles. On the

one hand, the economic viability of many of the potential routes is seriously questionable, while

on the other hand, strong efforts from energy diplomacy will be required, which go well beyond

what can be reasonably included in a base-line case Notably, the Shah Deniz/TANAP/TAP

project should be regarded more like one off success story rather than as template for future

investments. The outlook for European gas demand has changed dramatically over the past five

years. As an illustration, the IEA base-line projections for EU gas demand in 2020 have been

revised down by as much as 100 bcm between 2010 and 2015 and the IEA’s latest projections

point to stagnant EU gas demand by 2040. Consequently, projects which could have previously

attracted at least some form of market-based private investor’s interest – as it was the case for

Shah Deniz/TANAP/TAP - would now require a much stronger degree of public sector support.

Iraq has considerable gas potential. Even in the absence of significant targeted gas exploration

efforts, proven reserves, largely associated with Iraq’s massive oil reserves, are three times

higher than in Azerbaijan. Iraq is flaring large volumes of gas, indicating the potential for very

cost efficient supply once the infrastructure is completed. However, Iraq has a serious domestic

electricity shortage and relies on inefficient oil-fired power generation. Consequently, priority

will be given to the expansion of gas-fired power generation and to satisfying domestic demand

before Iraq will consider exporting gas. With most gas production concentrated in southern Iraq,

a pipeline route to Europe would not be optimal given the distance involved and the fact that a

large part of northern and northwestern Iraq, areas the pipeline would have to transit, is

currently under the control of the militant group Islamic State and it is not yet known when


47

Baghdad will be able to regain control. Within the region, the UAE and Oman have had to

import gas to satisfy demand despite being gas exporters while Yemen, an exporter of LNG, has

seen its exports disrupted repeatedly in recent years due to revolution and war. OPEC member

Kuwait has in recent years relied increasingly on LNG imports to meet high domestic demand.

All this suggests that a southern outlet is likely to prove more attractive for Iraqi gas at some

point in the future. In the north, the semi-autonomous Kurdistan region also has significant gas

potential. The Khor Mor and Chemchemal giant gas fields are among the two discovered fields

with large gas reserves and there is potential for further gas discoveries beyond recent smaller

gas finds by foreign oil companies operating in the region. Khor Mor, the only field in the

Kurdistan region producing significant quantities of gas, lies just 300 km from the Turkish

border and its NGL content supports upstream economics so it could become a very competitive

source of supply to Europe. The Kurdish regional government is likely to prefer direct exports

over transit through the rest of Iraq to a southern outlet. However Baghdad and Erbil have been

unable to reach a satisfactory agreement over oil exports and revenue sharing. The latest accord

reached last December collapsed and the Kurdistan region is exporting oil independently of

Baghdad, leading to a further rift between the two sides. Some of this Kurdish oil was exported

to European Union member states despite the threat of legal action by the Iraqi government,

which considers such exports illegal. Gas requires permanent infrastructure so it cannot rely on

individual, one-off transactions. European energy policymakers together with the other

members of the G7 should vigorously promote the creation of a stable and functioning legal

framework to govern pipeline exports from Kurdistan. Due to significant geopolitical risk,

credit might be difficult to secure for a traditional pipeline take-or-pay contract model. A case

could be made for more direct financial involvement in the building of the necessary transit

infrastructure. Although neither the Khor Mor and Chemcemal fields nor the prospective transit

route are in territories affected by Islamic State activity, the large-scale upstream and

infrastructure developments are probably impossible without a measurable improvement in the

political and security situation. The European Union should regard this as a priority and support

international efforts aimed at the stabilisation of Iraq.

Iran has an estimated 34 trillion cubic meters of gas reserves, second only to Russia. Despite its

large resource potential, the country exports only around 8 bcm to Turkey. In recent years the

upstream sector has suffered from limited access to capital and technology due to sanctions. The

normalisation of international relationships and Iran’s gradual return to international markets

would be a positive development for global energy security. Yet, even under those

circumstances, there would be no guarantee that Iran would emerge as large gas exporter. In

contrast to oil, Iranian natural gas production is already at a historical peak, so while the

resource base could certainly support further growth it would require additional upstream and

infrastructure investments.

In the current oversupplied situation, there is very little appetite from private investors for new

LNG projects; in fact, the industry witnessed a wave of project delays and cancellations. While

the production cost of South Pars is likely to be attractive compared to some other potential

frontier projects, a major disadvantage for Iranian LNG is that liquefaction, the most capital

intensive segment of the LNG value chain would be located in a country that still faces a high

risk premium. In the absence of foreign investment interest, Iranian LNG would require NIOC

prioritising LNG over oil upstream for its capital allocation. Given the dominance of US and EU

engineering firms in key components of the LNG technology, investment will require access to

dollar financing. Similar observation can be made for pipeline export projects as well: there

seems to be limited investor interest in a pipeline in Iranian territory and subject to Iranian legal

risk. Bottom-up improvement in Iran’s taxation and regulatory framework would also be

required to attract foreign investment. In the EU direction the combination of pessimistic


48

demand prospects, the robust competitiveness of Russian gas benefiting from sunk cost

infrastructure and the persistent financial weakness of the key European utilities would make

the transit infrastructure investment challenging as well.

Additionally, Iranian gas domestic consumption is set to continue to grow robustly, particularly

as slow upstream investment in recent years has caused supply shortages. Gas accounts for more

than 50% of the country’s total primary energy consumption and the power, industrial and

residential/commercial sectors are all heavily reliant on the fuel. In the power sector,

consumption has fluctuated but has not increased materially since 2008. Despite a government

policy favouring substitution of oil products with gas, the latter has lost market share to oil in

power generation, pointing to gas supply constraints. Gas demand in the sector could therefore

benefit from faster gas production growth. There is scope for substantial efficiency gains if

capital availability improves, as most power plants in Iran have reached the end of their design

lives and need to be replaced or upgraded. An improving investment environment thus would

have ambiguous effects on gas demand in the power sector: faster substitution from oil fired

generation leads to higher total gas fired generation but more modern CCGT plants would lead to

substantially higher efficiency. Nevertheless, without a significant subsidy reform a major

investment in power generation is unlikely even if sanctions are lifted.

The industrial sector accounts for 30% of Iran’s total gas consumption. The petrochemical sector

alone consumes approximately 20 bcm of gas as feedstock and fuel. The value of the country’s

petrochemical exports stood at almost USD 15 billion in 2011 before production and exports fell

in 2012/2013 due to the intensification of international sanctions prohibiting sales of

petrochemical products; the removal of petrochemicals from the international sanctions list in

November 2013 is likely to have led to a recovery since. Iranian officials remain optimistic about

further development of petrochemical capacity and state-owned National Petrochemical

Company (NPC) has ambitious plans to aggressively expand petrochemical production in the

coming years. Better availability of capital, technology and natural gas feedstock could support

faster demand growth in the sector.

The residential and commercial sectors also account for roughly 30% of total gas consumption.

Household per capita gas usage has fallen since 2011, most likely due to the price increase

prompted by the 2010 subsidies reform, a programme that is being restructured by the current

government. Unless Tehran moves forward with further gas price liberalisation, which would

have the effect of curbing wasteful consumption, gas usage in the residential/commercial

segment is set to increase along with population growth. Urban population is growing at rate of

over a million persons/year, leading to significant construction activity that is not subject to

modern energy efficiency standards.

Additionally, Iran is one of the most successful countries in introducing natural gas as a

transportation fuel. The country has over 3 million natural gas vehicles, with both refilling

stations and a vehicle retrofit supply chain widely available. The main driver of NGVs seems to

be the desire to reduce refined product imports as well as a high value added utilisation of natural

gas resources: NGVs enable higher oil exports at an investment need that is comparable to the

investment need of gas export infrastructure, it is not subject to structural changes in gas markets

and can be implemented domestically. These advantages are likely to maintain the attractiveness

of gas as a transport fuel for Iran.

Given the above, gas export infrastructure investments, particularly targeting Europe, will not

realistically materialise in the absence of major efforts both in terms of energy diplomacy and

direct financial support.


49

Turkmenistan: the gas resources of the Eastern side of the Caspian, especially Turkmenistan,

are significantly higher than those in Azerbaijan. The supergiant Galkynysh field in

Turkmenistan has been the largest gas discovery since the development of West Siberia in the

1970s. Field development started in 2009 with first production in 2013. While there is limited

transparency on the field development options, there is little doubt that the field is in the same

league as Bovanenkovo and similar to it could sustain a plateau production of over 150

bcm/year. Nevertheless, WEO NPS projections do not foresee a meaningful role for Turkmen

gas in Europe. The most important reason for this is the lack of a transit route: the two potential

onshore transit routes would run through Russia or Iran respectively, but neither is currently

attractive from an energy security point of view. Since the dissolution of the Soviet Union, there

have been plans for a Tran-Caspian pipeline which would connect Turkmenistan with

Azerbaijan and then feed into the TANAP route already under development. From a financial

and engineering point of view, the Tran-Caspian could be constructed – it would be

considerably easier than NordStream for example. In fact, due to extensive offshore

development in both countries it could to a degree rely on already existing offshore

infrastructure. Unfortunately, due to various political difficulties as well as a lack of a clear

business model, it has made very little progress in the past decade. The policy approach

foreseen in WEO NPS does not foresee a breakthrough, so the ramp up of Turkmen production

feeds increasing pipeline exports to China rather than Europe. Even the geopolitically somewhat

challenging Turkmenistan – Afghanistan – Pakistan – India route is seen by the WEO as more

realistic than European exports, so Turkmenistan in NPS emerges as a meaningful pipeline

supplier to India. However, there are reasons to assume that if the Trans-Caspian pipeline

received adequate support from energy diplomacy and financing, the chances of success could

be better than in the past decade. The Russia – China pipeline deal undercuts the pricing of

Turkmen gas in China by a significant margin. CNPC already suffers losses on Turkmen

imports which are partly compensated by a special tax subsidy by the Chinese government.

Russia has high profile plans to expand export capacities further to China on a new western

(Altai) route. If those exports become available at a pricing comparable to the Power of Siberia

deal, this will create a formidable competition for Turkmen gas.

In addition, China will benefit both from new LNG supplies coming online as well as its

expanding domestic production, so the future Chinese gas supply structure will be increasingly

competitive and diversified. Moreover, slower Chinese demand growth is enhancing

competition among the different supply options. In this context, is highly doubtful whether the

additional Turkmen supplies to China can achieve the netback valuation of the existing contract,

making new export outlets more profitable.. In the meantime, the Indian route will require a

very optimistic political outlook in both Afghanistan and Pakistan. The third outlet for

Turkmenistan is Russia on the Soviet legacy Central Asian trunk line, which given the changing

balance of the Russian gas system, seems to be increasingly unattractive. As a result, a potential

new export channel towards Europe is potentially more valuable than it has previously been.

There are still significant legal and political issues to be overcome, but even from that

perspective, the situation appears to be more favourable for the Trans Caspian link.

The European Union is currently examining the possibility to develop demand aggregation

mechanisms that could increase the bargaining power of European utilities. In the context of the

expansion of the Southern Corridor to Iraq and Turkmenistan, this should be considered. In fact,

the proposal builds upon the example of the Caspian Development Corporation which aimed to

play a similar role for the Trans-Caspian pipeline. An unusual level of geopolitical complexity

makes these routes very difficult to develop for any individual company. Even for Shah

Deniz/TAP where those issues were easier, it is doubtful whether the infrastructure development

would have been feasible without the strategic commitment of the Azeri national oil company


50

(Socar). Today’s low gas prices and poor growth outlook for European gas demand make these

routes difficult to justify from a commercial perspective, with the competitiveness of their

upstream production not enough to offset the large investment needs for transport infrastructure.

Moreover, they might easily face credit rationing due to their complex and difficult-to-hedge risk

profile, especially in the case of the Transcaspian to Turkmenistan. In both cases arguably the

upstream producer would have a preference for an integrated approach from the European side.

Nevertheless, careful attention needs to be given to the design of the institutional setup of any

such demand aggregation so that it is compatible with a competitive single market. Should such

an initiative proceed, it should be accompanied with safeguards such as constraints on companies

with a pre-existing dominant position, gas release programmes and other obligations for a

transparent and non-discriminatory sales structure.

4.7. Adopt a “Golden Rules” approach to shale gas development

European domestic production has been declining since 2005, and this tends to be regarded as an

unavoidable and irreversible declining trend. However, this was precisely the consensus about US

gas production until around 2007 when the decline was transformed by the emergence of shale

production. Ever since the scale and impact of US shale production became apparent, broadly

diverging opinions emerged about the European prospects. Certainly, the geological resource base

in Europe is estimated to be significant. However, the geological resource base is only an

assessment of hydrocarbons underground, where the cost and difficulty of getting them out can

vary widely. The most widely quoted number, the global assessment of the US Geological Survey,

has been revised down by more detailed surveys of the national agencies in several European

countries. Initial attempts to apply the North American shale production techniques in Europe

have largely been disappointing in recent years, due to a host of issues:

While the overall concept of shale production is well understood – and in fact, hydraulic

fracturing has been routinely used in Germany, Austria and Hungary for enhanced recovery of

mature conventional fields – shale production is not a completely modular technology that can be

transplanted without any modification. At the beginning of non-conventional activity, there was

an insufficient appreciation of the fact that European shale activity is better characterised as

exploration rather than field development: substantial exploratory drilling is needed to ascertain

the shale geology which is much less known than in the United States. Given the different

geological conditions, development cannot rely on the North American fracking techniques

without modification; companies need to experiment with modifications that are fine tuned to the

local geology. The unmodified application of North American methodology generally yielded

inferior flow rates, which led to high profile investors such as ExxonMobil pulling out first from

Hungary, then from Poland. None of the top US non-conventional specialists (EOG, Chesapeake,

Anadarko and others) have meaningful European activity. The need for an “exploration and

learning by doing” phase in itself does not preclude development if there are credible expectations

of a large-scale and profitable production. However, it does lead to higher development times,

raises the wholesale price level that enables investment, due to the time horizons, makes project

economics more sensitive to geological and regulatory risks.

Shale gas is an intensive development process that relies on a strong supporting “ecosystem” of

upstream service companies, specialised equipment and skilled labour. Even before the

emergence of shale gas production, North American supply chain capabilities have exceeded

European ones by an order of magnitude. In contrast with North America, Europe has never

had a large-scale onshore upstream industry; the large majority of European upstream is

offshore. As a result of the underdevelopment of onshore upstream, Europe has neither the

service company infrastructure nor the skilled labour that the North American pioneers could

rely on. The large-scale, intensive “mass production” of wells that plays a major role in the


51

North American plays is currently not possible in Europe. Consequently, drilling and well

completion costs are considerably higher even for the same shale depth. Moreover, most

European shale plays apart from the United Kingdom are deeper than in the United States,

which – given that beyond 2500 metres drilling costs nonlinearly increase with depth – is

detrimental to project economics. In addition, European shale is less wet; it contains less NGLs

and light tight oil that currently plays an indispensable role in North American shale

economics.

All of these fundamental factors would undoubtedly lead to considerably slower and more

expensive development than the North American experience. Moreover, today’s abundant LNG

supplies and lower Russian gas prices are likely to prevent any meaningful scaling up of shale

gas exploration activity in Europe over the medium term. Slow demand growth, cheap alternative

supplies and CAPEX cuts in the oil and gas sector will restrain investments flowing into shale

gas development. Over the longer term, however, the level of shale gas activity in Europe will

depend on whether public acceptance and regulatory frameworks become more supportive. No

one expects European shale to be able to replicate the speed and cost efficiency of the North

American plays but it does not have to: EU gas prices are higher and import needs are set to

increase even with weak demand. US shale gas might be competitive with EU domestic shale

even after liquefaction and shipping, but this is a much higher bar, and the high cost of

alternatives could provide support for domestic development. Despite the differences in

geological fundamentals, a supportive regulatory environment could generate meaningful private

investment. While even under relatively optimistic assumptions, shale gas is not expected to play

a transformative role for European gas supply security, it could nonetheless slow down the

region’s increase in import dependency.

A supportive regulatory environment for shale gas development in Europe cannot be taken for

granted. The possible environmental impacts of hydraulic fracturing (fracking) have generated

considerable controversy in all current or potential shale regions, but it is fair to conclude that the

tone of the debate and the balance of public opinion is considerably more hostile to shale

development in Europe than in most North American regions. In North America, some regions

like New York or Quebec implemented bans as shale development spread out from traditional

upstream areas such as Texas. Nevertheless, the industry managed to obtain and maintain broad

social and political acceptance. The Marcellus formation, which bypassed all other shale

formations and represented over one third of the total global increase of gas production, is

located in a region (Pennsylvania and West Virginia) where practically no oil and gas upstream

existed just five years ago.22

More wells were drilled in Marcellus in the past three years than in

Europe during the entire history of the oil and gas industry. It is worth emphasising that

Pennsylvania has roughly the same population density as France23

so population density alone

does not appear to be a prohibitive obstacle.

One factor that influences the political economy of shale development is that in the United

States, mineral rights belong to the landowners, so the mineral royalties benefit the landowners.

In contrast, in Europe, these royalties are collected by governments. As a result, local

communities in the United States typically have strong incentives to facilitate development: a

single shale well which causes a four-to-six week disruption during drilling can generate up to a

million dollars in royalties. However, the North American experience also shows that mineral

ownership alone is not decisive. After all, landowners in New York also own the mineral rights,

but this did not prevent a fracking ban; and in California the development of the Monterrey Shale

22

Pennsylvania was the birthplace of the oil industry in the 19th century, but no intensive drilling for a century, and both states have

extensive coal mining which has a much more intrusive environmental impact.

23 The Utica shale in Ohio which currently ramps up production very rapidly is also located under a densely populated region.


52

has been very slow. On the other hand, landowners in Alberta do not own the mineral rights

under the Canadian constitution, but given that all other factors are supportive, large-scale

upstream developments are progressing. The only state in the United States where landowners

don’t own mineral rights is Louisiana,24

where major scale shale developments (Haynesville

South, Mississippi Lime) have taken place. Thus, maintaining the broad social acceptance and

credibility of the industry’s environmental performance is probably more important than mineral

ownership itself. In any case, mineral rights are deeply integrated into European constitutional

systems, changing this just for shale gas would not be a practical recommendation.

Even in cases when there is sufficient private investor interest, shale development in Europe is

often hindered by restrictions on drilling and fracking that are typically motivated by

environmental concerns. They can take two broad forms: one is an outright ban on shale

development, such as in France and Bulgaria, that takes the form of national legislation. The

other form is in countries where shale development is not legally banned, but the combination of

licencing procedures, regulatory requirements and often bottom-up social resistance makes

development in practice nearly impossible For example, Austrian national oil company OMV

abandoned the Vienna basin after difficult licencing obstacles and protest movements. Spain and

Germany also fall into the category where shale development is not illegal, but the actual

regulatory environment makes it extremely unlikely.

For the assessment of the impact of the regulatory environment, it should be emphasised that

shale development is an intensive activity. An individual shale well produces around 10 – 20

million m3 gas in the year after fracking, but then has a rapid decline, with the first year

representing around half of the total production. This makes it necessary to maintain a continuous

intensive drilling activity to maintain production. The North American industry is using mass

production methods which enable a very high capacity utilisation of the equipment and lead to

low unit costs. Licencing and environmental permitting regimes that require lengthy individual

processes on a well-by-well basis can easily prevent development as they push up production

costs to an unacceptable level. Given the standardised nature of shale well development, this

individual approach might not be necessary.

The most broadly shared environmental concern about shale development is the potential for

groundwater pollution. This issue is relevant, but also often misunderstood, so effective

communication is essential. There are no documented cases of pollution reaching the water table

from the fracking process itself, which takes place in the shale layer usually at least 2 km below

the groundwater. There is a credible risk of water contamination from inadequate well insulation

where the well crosses the water table, and especially on the surface where developers have to

deal with around 10-15 million litres of used fracking water that is pushed back to the surface

after the fracking.

Such environmental risks are not qualitatively different from the water management issues

inherent in the conventional oil and gas industry, as well as many other industrial sectors. An

adequate wastewater treatment and disposal system is necessary, but this is already part of

general environmental regulations in most countries. There is a rapid learning process in the

industry: the disposal in open ponds that indeed could lead to migration of pollutants has been

phased out in North America; geological disposal in deep formations has become widespread;

and the leading companies increasingly recycle and reuse their fracking water. There is no reason

to assume that shale development would represent a unique environmental risk that is

qualitatively different from other industrial activities and would require a special level of

regulatory caution. Shale gas is currently around 2% of global primary energy consumption, it

probably represents a considerably smaller proportion of the total environmental impact, and a

24 Louisiana inherited the Code Napoleon based legal system from France and was subsequently acquired by the United States in 1804.


53

hugely disproportional share of the social and media attention. In the past, there have been

serious cases of industrial pollution from conventional upstream, refineries and various chemical

industries; the adequate response has been to fine tune the industrial and regulatory practice

rather than banning the activity.

It should be emphasised that even with the fundamental cost factors, European shale gas does not

need and should not receive a subsidy. Given the early stage of development, there is a

considerable degree of uncertainty and a possibility of failure. Recent developments have

generally been on the negative side, due to both disappointing drilling tests and no real progress

on either the degree of public acceptance or the regulatory framework. This has dimmed

prospects for a rapid acceleration in shale gas development in the region. The WEO Golden

Rules case (IEA, 2012) - which assumed a regulatory environment (the Golden Rules) that

maintains social and political support for shale – projected 80 bcm shale production in the EU by

2035. While there has been no detailed update to Golden Rules scenario, today the IEA estimates

that in the most optimistic case, EU shale gas output could reach 40 bcm by 2040.

There are two broad sets of reasons behind this more downbeat view. First is a less-positive

assessment of the geology itself. On the one hand, a number of national surveys have

downgraded initial shale gas estimates while, on the other, the results of appraisal drillings –

particularly in Poland, which has been at the forefront of shale gas exploration in Europe – have

been below initial expectations. Consequently, the emerging picture is one where the geology

itself is less supportive than originally thought. Second, over the medium term, the case for

investment is complicated by the large availability of competitive LNG supplies. Companies

might hesitate to spend on a new resource that requires an intensive drilling programme to kick

start the process and bring costs down (with no guarantee of ultimate success).

Notably, even if shale gas development in Europe ultimately takes off, it would help to moderate

the increase in EU’s import dependency, rather than stabilising domestic gas production. WEO

NPS – which incorporates the current policy and regulatory constraints such as shale bans –

projects only 7 bcm of shale production in Europe, which would represent only 2% of demand, and

does not play any major role in energy security.


54

5. REFERENCES

Carbon Trust (2012), Biomass Heat Accelerator. Carbon Trust, London.

ENTSOG (European Network of Transmission System Operators for Gas) (2014a), Transmission

Capacity Map 2014, ENTSOG, Brussels, www.entsog.eu/maps/transmission-capacity-map/2015.

ENTSOG (2014b), Gas Regional Investment Plan 2014-2023, South North Corridor GRIP, ENTSOG,

Brussels.

GBPN (Global Buildings Performance Network) (2013), What is a Deep Renovation Definition?,

Paris.

IEA (International Energy Agency) (2012), Golden Rules for a Golden Age of Gas, World Energy:

World Energy Outlook Special Report on Unconventional Gas, OECD/IEA, Paris.

IEA (2013), Transition to Sustainable Buildings: Strategies and Opportunities to 2050, OECD/IEA,

Paris.

IEA (2014a), World Energy Investment Outlook: World Energy Outlook Special Report, OECD/IEA,

Paris.

IEA (2014b), HEATING WITHOUTGLOBAL WARMING, Market Developments and Policy

Considerations for Renewable Heat, OECD/IEA, Paris.

IEA (2015a), World Energy Outlook 2015, OECD/IEA, Paris.

IEA (2015b), Medium-Term Renewable Market Report 2015, OECD/IEA, Paris.

For further information, please contact:

Mr. Laszlo Varro

Chief Economist

Economics and Investment Office

+33 (0)1 40 57 67 30

[email protected]

Ms. Costanza Jacazio

Senior Gas Analyst

Gas, Coal and Power Markets Division

+33 (0)1 40 57 65 16

[email protected]

http://www.entsog.eu/maps/transmission-capacity-map/2015

mailto:[email protected]

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