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

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 supplysecurity. 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. 2

IEA STUDY ON GAS SECURITY IN EUROPE

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.

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

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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.

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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.

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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.

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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.

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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 lowcarbon 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 liberalisation by establishing physical and legal infrastructure for better interconnection, including 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; longterm 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 lowcarbon 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 longterm 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.

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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.

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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 nonNorth 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.

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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

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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

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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 wellfunctioning 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 OECDEurope 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

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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 upstreamrelated 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

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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.

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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.

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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

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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 largescale 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.

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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

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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 21

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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.

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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 sunkcost 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

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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 nonassociated 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.

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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.

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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.

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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 NO x 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

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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 gasfired 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

8

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. 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.

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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.

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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 reverseflow 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

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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.

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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 submetering 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.

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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 noneconomic 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).

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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.

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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 12

OECD Europe, wind includes onshore and offshore wind. 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.

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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 EUlevel 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

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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. 37

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 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 15

For example, part of the German grid is owned by the Dutch TSO Tennet. The most successful examples are in the Eastern United States.

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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 EastWest 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.

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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 (ATIT) and WAG (ATDE) 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 BA BG BY CZ DE EE FI GR HR HU IT LT LV MD MK PL RO RS RU Sl TR UA

Austria Bosnia Herzegovina Bulgaria Belarus Czech Republic Germany Estonia Finland Greece Croatia Hungary Italy Lithuania Latvia Moldova Republic of Macedonia Poland Romania Serbia Russia Slovenia Turkey 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

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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 HungarianAustrian 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 Figure 2: Interconnection points and related case a terminal was to be established) to technical firm capacities in NEW (in GWh/d) CEE and further to Austria or Ukraine. An important component of the NorthSouth 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. Source: ENTSOG (2014b) 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 41

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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 BelgiumGermany 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.

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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 thirdparty 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

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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

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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 20

With a 1.5 GW reactor size and seven years’ construction time. 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.

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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

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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

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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.

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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

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(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

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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.

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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.

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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.

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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]

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