EDI Quarterly

Contents

1 The challenge of a double transition

3 South Stream: Ensuring the Reliability of Supplies through Transit Route Diversification

6 Eurpean Union energy security is at risk because too many decisions are taken at the wrong level of policy making

8 Explaining different regulatory approaches towards gas infrastructure expansion 10 Development of the MILENA gasification technology for the production of Bio SNG

12 Economics of a natural gas in Smart Grids

14 Books, reports and upcoming conferences

Q1Volume 3, No. 1, March 2011

Editor’s Noteby Catrinus Jepma

The challenge of a double transitionThe notion that the world energy system gradually evolves from the current fossil-based system towards a less and less fossil-intensive system is generally accepted. The main driver is the threat of climate change, especially change beyond control; sometimes local pollution and its health impact is another driver. The main discussion is about the required adjustment speed and about priorities with regard to alternatives.

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In other words most countries of this planet are in one way or another engaged in a long-term process that can be labelled the energy transition, and struggle with its impact on society for the next decades to come.

Some countries, however, face another energy transition at the same time. That is when the limits of traditional domestic energy source abundance are coming in sight due to depletion of their traditional energy resources. This typically applies to some oil-rich countries gradually running out of easily accessible oil; it also applies to some developing countries where traditional biomass forming the backbone of traditional heating and cooking is depleted by overuse; and it e.g. applies in some countries that exploited their gas reserves so quickly that the end of the reserves enters the horizon of national energy policy.

A clear example of a country facing a double energy transition is the Netherlands where after fifty years of successful exploration about two thirds of the natural gas of the super giant Groningen field and surrounding small fields has been taken out. So no wonder that

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gradually a national discussion is starting about the issue how to deal with both the energy transition in the spirit of climate policy, and the energy transition towards a world with less and less Groningen gas.

The perhaps surprising policy response in the Netherlands is: now that Groningen gas starts to decline (from about 70 bcm - or about one third of EU production - now to about half that level by 2030), one should focus more rather than less on sustaining the role of gas for our society. In fact the strategy is to further strengthen the Netherlands’ gas roundabout and gas hub function in NW Europe. This also explains why there is significant investment in domestic gas servicing and transmission facilities (the NS grid, the LNG terminal, various UGS facilities, etc.), why national grid ownership has been extended internationally towards UK (BBL) and into Germany (incl. a modest steak in North Stream), and why the country is happy that its gas hub TTF so far has developed into the most voluminous and liquid of the continental gas hubs. In addition, serious effort has been made recently to strengthen gas R&D activity and to introduce sustainability elements e.g. by promoting production and application of biogas, or, once upgraded, green gas to be traded via certificate based systems.

This raises the fundamental, more general question if it is wise for a country to try to stick to and further develop a comparative advantage ultimately based on a domestic resource, but a resource in decline.

The answer is: probably it is.

Sure, various critics to that strategy can be and have been made. One could, for instance point out, that various other countries claim to become THE European gas hub, such as Germany (especially as soon as the number of EEzones has been reduced to just a few), Belgium (transit potential of Russian gas), or Austria (well positioned for transit of gas ‘from the East”). One could also point out that so far by far the largest gas sector rents in the country have been captured in the production and in particular exploration stage. In other words, the largest share of the about 15 bn euro annual gross value added by, and about 60 000 direct, indirect and induced jobs created in the Netherlands’gas sector (according to Brattle 2010) can be attributed to the fact that the gas was there and could be explored and exploited. So, the critics argue, shifting the focus from gas production to gas trade servicing means entering a commercially much less attractive world of smaller margins, regulated business and stronger international competition. Finally, the critics argue that there is an opportunity cost to everything: resources spent on gas sector transition could possibly be spent otherwise with more return for society.

But, why are the critics probably wrong?

First, they disregard how hard it is for a country to establish a comparative advantage (and how easily it can be lost). Virtually any textbook on international economics will tell you that strong export-oriented sectors with long-term competitive success are almost always based on a combination of a sufficient critical mass of economic activity, strong collaboration between the industry, the knowledge sector and public authorities, and a well-developed international trading network. Once such conditions are in place the comparative advantage can be sustained because the sector has become strong, flexible and smart enough to continuously adjust to the new

circumstances. In other words, once you have such a sector, never let it slip. This typically applies to the strong gas sector in the Netherlands, but many other examples can be mentioned worldwide.

Second, where the value is generated shifts all the time. Most industrialised economies generate two third if not more of their national value and income in the services sector: engineering, R&D, consultancy, marketing services are the true money makers. Given the rapid changes also in the energy world, the demand for smart energy mixes, new sustainable applications, smarter engineering, better training will keep increasing, and with it the type of activities where the money will be made. No wonder that the Brattle report mentioned estimated that after on upstream activity the impact of an about 8 bn euro extra investment into the gas sector in the Netherlands on total output would be largest on income generated via R&D. This was found via an Input-Output analysis, so probably strongly underestimating the dynamics of the services market.

But finally, the critics are wrong because they miss the potential of the double transition. Because of the gradual shift towards a more carbon-neutral energy-system, gas may well play another, but also more prominent future role as the cleanest of the fossils, as the most flexible and efficient fuel for power production, and therefore as one of the most obvious candidates for being combined with various renewables. Moreover gas can get greener itself by introducing biogas and futute clean syngases. This is the true long-term challenge, well worth by using the current strong natural gas starting position to go for.

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policy papers, and South Stream is an obvious solution in this sense.

Does Europe really need a new pipeline with a capacity of 63 bcm per year at a time of low European demand?

Notwithstanding the global economic crisis and a resulting temporary decrease in European gas demand, few would disagree that Europe will need additional natural gas imports from about 2015 onwards. The indigenous gas resources are gradually depleting, it is a well-known fact. Moreover, gas demand in the EU has already shown unambiguous signals of recovery, and it is expected that gas will play an ever growing role in the EU’s energy mix thanks to its attractiveness in terms of the environment and 20-20-20 targets. I would like to highlight the fact that South Stream is a long-term investment – the lifetime of pipelines, in general, amounts to several decades. What is important to understand, is that there will be a gradual build-up of supply through South Stream starting in late 2015, based on the demand profile of European customers. Some reports have crafted a misleading image: massive volumes of new Russian gas. One should not use a figure of 63 bcm supply in 2015 – full capacity will be achieved closer to 2020. Moreover, South Stream will in part be used to reroute already contracted volumes. This means that South Stream will not lead to a real increase in the share of Russian gas in EU imports. It will be, first of all, an investment in route diversification. In any case, the volumes will be a function of requirements, with the market driving actual supply. So, economic viability is what drives our project.

How much will the South Stream pipeline cost?

We don’t have an exact number yet, it is too early to say. Only with the completion of the consolidated feasibility study later this year, will the picture become clear, and then we can be more specific… there

South Stream: Ensuring the Reliability of Supplies through Transit Route Diversification

Pipeline politics have become a fascinating topic. Among the projected natural gas pipeline projects in Europe, South Stream, the largest of them all, is well on track to start deliveries in late 2015. According to its CEO, Marcel Kramer, a new route such as South Stream will greatly contribute to Europe’s energy security by linking millions of European consumers directly to the producer holding the world’s largest gas reserves. The project is partly aimed at the reduction of transit risks, which proved to be a sad reality back in 2006 and 2009. Where does South Stream stand now and what are the current developments in the field? Marcel Kramer, a Dutchman who has worked around the globe in the energy field for 35 years, has answered our questions.

First of all, what is the rationale for building South Stream?

South Stream will be a commercially driven investment and at the same time, it is of great strategic significance. It is often said that the gas pricing disputes of 2006 and 2009 served as a “wake up call” for the EU to start seriously considering Europe’s energy security and, in particular, security of gas supply. Those events served as an impetus to act for Gazprom and for some European companies as well. Gas trade is extremely valuable to both Russia and the EU, that’s why it is so important to mitigate transit risks - both technical and political. South Stream will provide a direct connection between the EU and Russia, the country which owns the vastest gas reserves in the world, sufficient to cover the European demand for another century at present production levels. In January 2009, many South-Eastern Europeans were left in the cold because of transit interruptions, and Gazprom has estimated its immediate loss at $2 billion. In fact, the need for transit routes diversification has been acknowledged in a number of the EU

Marcel Kramer CEO South Stream

Figure 1. South StreamSource: Entsog Ten Year Network Development Plan 2011-2020 Annex A: Infrastructure Projects

is no point in doing so now. The feasibility study will establish the exact route, which will determine, for instance, how much compressor stations we need and where - this affects costs. Moreover, steel price will play a considerable role in the final price tag, and we have seen impressive fluctuations recently. We are not hiding the fact that South Stream will be a large investment and we will be perfectly transparent about the costs. It would be realistic to say that South Stream, the onshore and the offshore parts together, will cost between 10 and 20 billion Euros. No governmental subsidies will be required for this investment, the project will be covered entirely by private funding.

What have you achieved with the project so far?

Important steps have been taken in the feasibility studies and we will have a consolidated version of the study in just a few months. Detailed work on our regulatory approach, as well as on environmental impact assessments, has started. We are also in the process of setting up our headquarters in Switzerland and are building up a truly international team. In each of the transit countries, local pipeline companies are being set up. And the people involved are skilled, committed and enthusiastic. We have advanced significantly on all of these and other fronts - perfectly on schedule. In addition, we are now in the process of preparation for the official presentation of the project, a high-level event that will take place in Brussels this Spring.

When is EdF joining the South Stream consortium and what will be its stake? Could you also comment on rumors about other potential shareholders joining the project?1

Negotiations on the entry of EdF into the South Stream project are underway. A lot of progress has been made already, and we expect the French company to join the shareholding structure this year with at least a10% interest. EdF has expressed its commitment to the project on many occasions, and I am convinced, that they will prove a strong and valuable partner in the implementation of the project. As to getting other shareholders, I would say that it is not uncommon for such a big and lucrative investment projects to have additional parties joining the original shareholders at later stages. Just look at the Nord Stream experience, were Gasunie and GDF Suez joined later! We should therefore not exclude the future participation of other companies.

Will South Stream be granted the TEN-E priority status?

Our project is an undeniable priority for all the participating European countries, and the South Stream states have repeatedly and explicitly reaffirmed their support. South Stream will be the decisive trigger for a number of Balkan countries to move towards a more sustainable energy balance, due to the introduction of stable gas supplies and of new modern infrastructure. It also considerably diminish transit risks by giving European customers direct access to Russian gas supplies - gas disruptions, such as in 2009, will be prevented from happening again. Obviously, the South Stream project has all the right cards to get a priority status and I cannot see a valid reason for the contrary.

One reason could be the willingness of the Commission to lessen dependence on Russian gas.

Are we too dependent on Russian gas? The facts are not supporting this claim. Russia’s track record as a supplier is good, also when it is compared with that of other supplies to the EU. South Stream does not significantly alter the share of the Russian gas in overall EU supply.

This share, by the way, has dropped a lot within the last two decades, which is confirmed by all official statistics. The dependence argument is outdated when you consider the EU27. If we look at the EU market as a whole, we can see that it is totally different from what it was 20 years ago. Today there are more storage facilities, more LNG terminals, more interconnections, more suppliers. A great level of diversification has already been achieved. And this trend will continue. The picture is, of course, completely different in South Eastern Europe. Some countries in that region almost entirely rely on imports from Russia. The question arises: if we don’t want a 100% dependence on Russian gas, what do we want? How do we gain it? How much are we prepared to pay for alternative supplies? What implications will it have for our international relations?

How will the South Stream project affect South Eastern Europe?

If we look at the countries in South Eastern Europe, the reliance on coal there is still significant. The average share of gas in the energy mix of that region is quite low, compared to countries in Western Europe. The implications for the environment are serious. For instance, it is being said that the air in Bulgaria is the most polluted in the entire European Union. If we manage to put in some new infrastructure, switching from coal to gas in the region will produce substantial improvements in terms of environment. We have seen it in the former East Germany. Natural gas is the only climate-friendly fossil fuel and it requires relatively low investments. It is the most cost-efficient way to achieve the EU’s ambitious 20-20-20 targets. In addition, South Stream will create long-term commercial profits, thousands of jobs and tax incomes across the entire region. The project, moreover, will provide an impetus for regional cooperation.

South Stream at a glance:

Capacity: 63 bcm per year by 2020First gas: end of 2015Offshore section: four 900 km-long parallel lines under the Black Sea at the maximum depth of over 2 kmShareholders: Gazprom and ENI; EdF’s entry is being negotiatedOnshore section: final route to be determined this year with the completion of the overall feasibility study; intergovernmental agreements have been signed with Bulgaria, Hungary, Greece, Serbia, Slovenia, Croatia and AustriaGas from: the United Gas Transmission System of Russia

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1 Wintershall has joined the South Stream project on the 21st of March

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South Stream is sometimes depicted in the EU as a purely Russian project that promotes the interests of Kremlin and Gazprom alone. How would you comment on this?

This picture was generated by certain media, who tend to exaggerate. Calling South Stream a Russian project is inappropriate. It is a Russo-European project. How can it be otherwise, when there will be participation of such prominent European companies as ENI and EdF, as well as of a number of EU national companies along the route? The project will serve interests of all the parties involved, not only Gazprom’s. Modern and well-managed export infrastructure is a precondition for that. It is of course very important for Gazprom to preserve its status as a reliable long term supplier. For the consumers in Europe, natural gas is vital for economic growth and prosperity and for a better environment. As Barroso has recently stated, Russian energy is key to keeping Europe going. Reducing transit risks is thus of key importance. South Stream, moreover, is a commercially driven project that will benefit all the companies involved.

What has been your experience in dealing with Gazprom as the head of Gasunie and now as the CEO of South Stream?

It has been a positive experience. First deliveries of natural gas from Gazprom to the Netherlands commenced a decade ago and are currently amounting to some 4 bcm of gas annually. As a consequence of gas market liberalization, GasTerra took up the ownership and operation of the Russian gas supply agreements to Holland. Then Gasunie purchased a 9% stake in the Nord Stream AG in summer 2008, which contributed to further enhancing the Dutch-Russian energy partnership. Gazprom is a reliable partner for Europe, and 4 decades of stable supplies have demonstrated it. What happened in 2009 was due to serious transit difficulties. Ukraine’s system is one of the most extensive and complex in the world. A well-defined technical separation between deliveries to the domestic Ukrainian market and transits to the EU is lacking. Besides, huge investments would be needed to modernize that system. This is why it is extremely important to have an alternative supply route.

Any messages you have for Brussels?

Yes, I have some. Such a new European route and large private investment as South Stream deserves to be treated equally with other European pipeline projects. It is not a secret for anyone that Nabucco and other projects within the so-called Southern Corridor enjoy a great level of political support from the Commission. There will be, it is said, preferential European financing and facilitations in permitting and regulatory processes for those pipeline projects. We in South Stream are not asking for such favors or preferential treatment, but there should not be discrimination either. We are asking for a level playing field. Diversification is a worthwhile cause, but the events we can observe today in the Middle East and North Africa clearly indicate that the traditional suppliers must be treated properly as well. EU regulation activities in the energy field should not discourage investments in infrastructure. In general, I am somewhat surprised by all the hassle about Russian gas that is sometimes created in certain EU circles. Let’s be realistic – natural gas is fundamental for the EU’s future prosperity and climate policies. Let’s allow it to find a proper place in the EU’s energy mix. Let’s not treat it as an enemy, just because a considerable part of European supplies comes from the Russian Federation.

Marcel Kramer: CEO of South StreamMarcel Kramer, a Dutch national resident in Switzerland, has been directing the South Stream pipeline project since September 2010. From 1976 Mr. Kramer held a number of international energy-related positions. He worked in this field at NATO Headquarters in Brussels; subsequently he headed the Oil Industry Division at the International Energy Agency in Paris. His next move (1988) was to Canada, where he spent almost four years in Calgary as Director of Crude Oil Supply and Trading in Petro-Canada. In 1992 he returned to Europe to work for Statoil, which saw him take up several key management positions in Norway, Bangkok, Singapore and Caracas over a period of twelve years. In 2003, Marcel Kramer joined Gasunie in The Netherlands and he was appointed Chairman and CEO in 2005. Marcel Kramer is the current President of the Royal Dutch Gas Association, and is also professionally involved in several international energy-related organisations, such as the International Gas Union and the International Association of Energy Economists.

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Expected outcome

I expect to argue that the emphasis of European policy makers when safeguarding energy security should be on completing the up scaling of all facets of the European energy market in order to guarantee long term energy security for European citizens. Most of the current efforts, both politically and scientifically, are, partly, based on rhetoric towards Russia and others that mainly serves as window dressing and does not address the real challenges ahead.

History

At the basis of the European Union lie the efforts of French economist Jean Monnet and French Minister of Foreign Affairs Robert Schuman to pool the coal and steel supplies of European nations in the after-math of the Second World War and the failure to establish a European federation in 1948. This plan submerged partly from the French fear of a resurrection of Germany. Although not for economic, but primarily for military-political purposes, energy resources thus form the basis of European integration.

Despite the prominent role of energy resources in the origin of the European Union, this is an issue-area in which Member States have not adopted a common policy. Energy resources were first placed on the agenda in the Declaration of Messina in 1955: ‘...Putting more abundant energy at a cheaper price at the disposal of the European economies constitutes a fundamental element of economic progress. That is why all arrangements should be made to develop sufficient exchanges of gas and electric power capable of increasing the profitability of investments

This research for a change aims to dive into the EU’s own bosom in order to explain the status of EU energy security. The basic assumption is that European Union energy security is threatened because too many decisions are taken at the wrong level of policy making. To narrow down the scope of this research project, I have focused on infrastructural companies and regulators in the European gas market.

If I examine the current composition of energy markets in the European Union they roughly consist of four facets, namely • The market (consisting of producers, suppliers, consumers and

traders)• Infrastructural companies, always publicly oriented enterprises• Governmental institutions, setting ground rules for the playing

field of market players • Regulators, monitoring market players, fair competition, etc.

If then I examine the level of government / governance at which these facets are operating I can identify remarkable differences: • There is a clear trend of up scaling to the European level in this

sector under influence of Electricity and Gas Directives starting the late nineteen eigthies.

• Major judicial documents come from the European level these days, but implementation of guidelines is still a national matter. Different interpretations and speed of implementation has caused friction. To give an example, I can hint at the issue of unbundling of integrated energy companies throughout the Union and the friction this has caused in the market.

• Both infrastructural companies and regulators have been mostly national domains since the liberalisation of EU energy markets started. Recently I identify some transgressing behaviour, but in fact I can indicate there is a time lap of over two decades here.

Inspecting the scientific debate on European Union energy security as it has intensified since the gas supply disruption in 2005, it is remarkable that this is focusing solely on energy markets and in particular the availability of sufficient supplies. As one can derive from figure 1. sufficient resources are in fact not the problem, the true challenge is getting the resources at the desired place.

Considering the essence of all the elements of European energy markets to guarantee long term energy security, it deserves recommendation to make a scientific contribution that focuses on facets that have so far remained under exposed. This is what this study aims to do.

European Union energy security is at risk because too many decisions are taken at the wrong level of policy making

Tim Boersma1

PhD Student at Groningen University

and PhD intern at GasTerra

Figure 1. Global availability of natural gas versus expected demand, NERA 2009.

1 Tim Boersma has not finished his Ph.D thesis yet. This article represents his results thusfar.

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and reducing the supply costs. Studies will be undertaken of methods to coordinate development prospects for the production and consump-tion of energy, and to draw up general guidelines for an overall policy...’ Later in the document the European leaders ventilate their ambition by proposing a European fund that should for instance be employed to finance power plants throughout the Community.

Since the publication of the ‘First guidelines for a Community energy policy’ in 1968 energy resources have regularly been discussed amongst European states and some policies to safeguard energy security have been implemented, but the European Union still does not have a common energy policy. An obvious question is what this implies for European Union energy security.

An unambiguous definition of the concept of energy security is however not available, hence it is elaborated on in the second chapter of this thesis. Most of the academic research on energy security evolves around discussions about unreliable suppliers (in particular Russia), diversification of supply routs and connected issues.

During the course of this study, issues like the status of EU energy policy in terms of the components markets, infrastructure and regulation that comprise the EU energy market and the current decision making and implementation structures within the EU will be dealt with as well. The results will assess the risks in terms of energy security and what is should mean for future policy making.

Case studies

I intend to analyse four case studies that demonstrate current inefficiencies regarding investments in gas infrastructure (the interconnector between Germany and Denmark, different transport tariffs in Belgium, changing regulatory regime in Germany after Dutch purchase of a pipeline network and the role of the European Investment Bank in Nord Stream), two case studies regarding the European LNG market (remarkable position of Spain towards regulation and the perhaps arbitrary EC support for instance for Polish LNG projects), three case studies regarding gas storage (regulated or non regulated access to storage facilities in the EU and case studies in Germany and the Netherlands regarding market distortions) and finally two case studies regarding energy regulators throughout the European Union (problems following the legal position of regulators in the EU and the future role of ACER).

Several criteria will be used in the case studies in order to test whether too many decisions are taken at the wrong level of policy making . These are, in arbitrary sequence: political feasibility, transparency, regulation or not, price development, third party access, market development and intertwinement with other policy areas. Implications for the gas industry

Up scaling of the mentioned components of the energy markets is expected to have positive effects in terms of completion of the internal EU energy market. European integration from this angle is not a panacea, but given the partial up scaling of the energy market in terms of liberalisation a next step is needed. The case studies are expected to

clearly demonstrate the inefficiencies the status quo has lead to. Hence it is reasonable to expect better future market functioning, resulting in more price conversion on at least a regional basis, better alignment of transport tariffs throughout and an increase of transparency in both infrastructural and regulatory affairs throughout the European Union.

Any comments and/or suggestions about this research are welcome. You can contact the author Tim Boersma on the following e-mail address: t.boersma@rug.nl

The EU gas market requires additional investments in new gas infrastructure in the next decades. This concerns gas pipelines, gas storage facilities and LNG import terminals. In this contribution I explain why different regulation with respect to investments is implemented across these types of gas infrastructure, and why this regulation differs across different EU member states.

Increasing need for infrastructure investment

Although the economic and financial crises lead to a temporary dip in European natural gas demand, demand is expected to increase in the next decade or so. Combined with the continuing depletion of indigenous gas reserves (notably those of the UK and the Netherlands), this causes a substantial need for new investments in gas infrastructure: ranging from investments in gas pipelines (to the European border and within Europe) to investments in gas storage and LNG import terminals. The regulatory framework under which these infrastructure invest-ments need to be realized consists of a number of regulatory choices made at different levels. Relevant regulatory choices are made at both the EU (i.e. EU Directives and Regulation) and EU member state level (i.e. national Gas Acts and Regulatory codes). Choices are made with respect to the role for competition in the expansion of gas infrastructure (i.e. is particular infrastructure expansion considered a free or regulated market) and the type of infrastructure capacity access regime applied (i.e. third party access (TPA) yes or no, if so negotiated or regulated TPA). Current practice shows considerable differences in the regulatory treatment of specific infrastructure expansion projects, both across the EU and between different types of gas infrastructure (i.e. pipelines, storage facilities, and LNG terminals). When the realization of required infrastructure investments is con-cerned a number of public goals are at stake. A lack of (timely) invest-ment in gas infrastructure affects the level of security of supply, whereas inefficient regulation may negatively impact the affordability of the overall gas system for final consumers. An example of the latter would be a regulatory regime that does not sufficiently deal with the incentive problem. Incentives to operate and expand existing infrastructure in a cost-efficient way may be weak, which is something that is typically associated with infrastructures that exhibit so-called natural monopoly characteristics. Too restrictive regulation, with for example relatively low allowed returns on investment, may on the other hand discourage investment and endanger security of gas supply.

How to regulate infrastructure expansion?

In a PhD research that is currently being finalized I aim to explain the observed differences in regulatory approaches towards gas infrastructure investment.2Why are different kinds of gas infrastructure investments treated diffe-rently from a regulatory perspective? After all, all have common proper-ties that point to a natural monopoly (i.e. large initial investment cost, large of investment cost in total cost and long economic lifetime). And

why is the same type of infrastructure investments treated differently across the EU? The methodology adopted in this research combines a review of relevant economic literature on infrastructure investment and regulation with a case study analysis of different concrete gas infrastructure investment projects. The case studies involved (1) a gas pipeline interconnection between two EU member states, (2) a new gas transmission pipeline connecting newly developed LNG terminals with the main transmission system, (3) a seasonal gas storage facility, and (4) a LNG import terminal. The remainder of this article describes the main insights from the case study analyses.

Regulated expansion as default option for pipelines invest-ment but role for competition remains3

EU legislation allows for a hybrid approach when it concerns the choice for the degree and type of competition in infrastructure investment. Based on the natural monopoly characteristics of specifically national transmission (and distribution) networks, the EU Gas Directive 4 dictates that regulation-based expansion should be considered the default option for expansion of these networks. This means that investment costs are recovered via regulated transmission tariffs and that third party access (TPA) requirements apply. However, in exceptional circumstances, the EU Gas Directive allows for a market-based expansion of infrastructure, also referred to as merchant invest-ment. An investment project awarded the merchant status is exempted from TPA requirements is allowed to allocate capacity to the market via long-term contracts.

Although the inclusion of the so-called exemption article in the (second) EU Gas Directive was spurred by concerns over the strength of investment incentives present in the first Gas Directive, the resulting hybrid approach is a correct reflection of what economic theory predicts. In principle, market-based investment is viable approach, also for gas pipeline investments but its practical use in the case of EU transmission infrastructure is limited due to the relatively large density of pipelines in the EU: the EU pipeline infrastructure has meshed character, as opposed to a more radial character of for example North and South-American gas systems. The investment in the gas pipeline connecting the Netherlands and the UK (also known as the BBL5) is a good example in case; this pipeline connects two gas systems that previously had only limited connectivity. Although exempted

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Explaining different regulatory approaches towards gas infrastructure expansion

Jeroen de JoodePhD candidate, TU Delft

Topic coordinator natural gas, ECN

2 De Joode, J. (2011). Regulation of gas infrastructure expansion. PhD dissertation to be published in the Next Generation Infrastructures Foundation series, Delft University of Technology, Delft.

3 De Joode, J. and A. Spanjer (2010). Improving European Gas Infrastructure Regulation: Lessons from Theory and Practice. Energy Studies Review, Vol. 17, Issue 1.

4 EC (2009). Directive 2009/73/EC of the European Parliament and the Council of 13 July 2009 concerning common Rules for the Internal Market in Natural Gas and repealing Directive 2003/55/EC.

5 Balgzand-Bacton Line.

6 As put forward by Codognet and Glachant (2008): Codognet, M. K. and J. M. Glachant (2008). Weak investment incentives in new gas storage in the United Kingdom? Working paper REFGOV-IFM-16.

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infrastructure investments may raise concerns over the negative impact of the exclusive use of realised capacity via long-term contracts, the correct implementation of an open season ex ante and the facilitation of a secondary market ex post in the BBL case ensure a proper level of competition.

In a different case study, a regulated gas pipeline investment in the UK was assessed: a pipeline connecting two planned LNG import terminals to the existing national gas transmission system. The designated gas transport company, National Grid Gas, was required to realise this investment after sufficient market interest in this particular link was expressed in long-term capacity auctions for entry capacity to the UK transmission system. The explicit link between capacity allocation (via short and long –term auctions) and the investment planning is not seen elsewhere in the EU and theoretically assures an optimal dimensioning of new investments. A properly organised open season may be comparable with this approach when outcomes are concerned, but the approaches differ in terms of transaction and regulatory costs involved. Although investment projects aimed at upgrading existing transmission capacity are generally not suitable for a merchant approach, a ‘dedicated’ pipeline as in this case may be suitable for a particular expansion approach, namely the tendering of a clearly defined pipeline expansion project. UK regulation does not consider other pipeline companies to have a role in expanding the national transmission system. Although the particular project could be highly exceptional from the UK perspective, considerations on tendering the identified expansion would have been justified based on the economic efficiency properties of such approach. Such an approach could easily be facilitated by existing UK gas transmission regulation since it already adopts separate incentive regulation for the system operator and the owner of the national gas transmission system: the company winning the tender would be another transmission owner, whereas the integrated system would still be under operation of one system operator.

Market-based investment in gas storage

The EU Gas Directive contains three optional regulatory approaches towards investment in gas storage facilities. Investment in storage facilities can be undertaken under a strictly regulated TPA regime, a looser negotiated TPA regime and an, again exceptional, merchant regime without any TPA requirements. Within the EU legislative framework, individual EU member states may opt for a specific type of approach. In the case of gas storage in the Netherlands, Dutch regulation adopts a negotiated TPA regime and further distinguishes a ´heavy´ and ´light´ variant with the decision on which to apply in a particular investment project being dependent on the economic position of the initiator behind the project. In the view of the Dutch regulatory authority, the market for storage is, in principle, competitive since there are ample opportunities to invest in new facilities (i.e. depleted gas field) and since storage competes with other instruments that may provide the flexibility needed to accommodate fluctuations in gas demand (i.e. the relevant market is the flexibility market).

A caveat here is that there are different types of gas storage facilities, ranging from small facilities with relatively high extraction rates providing short-term flexibility services, and large-scale facilities with relatively low extraction rates providing long-term (i.e. seasonal) flexibility services. Irrespective of the question on the suitable regulatory regime given the economic position of the company investing in any type of storage facility, it may be argued that especially

for the large-scale seasonal storage facilities these regimes may not provide sufficient incentives for investment. Economic theory would ‘predict’ the application of exempted, merchant investment in these cases: risk of not recovering the high initial investment cost, largely related to the cost of cushion gas, would point to the use of committed long-term capacity contracts as allowed only under the TPA exemption Article in the EU Gas Directive. In practice however, the Bergermeer (seasonal) gas storage initiative is being developed under a negotiated TPA regime. There are two possible explanations for this discrepancy. A first explanation is that the contractual arrangement between the storage investors and gas supply company Gazprom Export that specifies that the Gazprom Export delivers the large amount of cushion gas in return for a share in long-term storage capacity rights may, from the investors’ perspective, be sufficient to cover the largest financial risks and is considered ‘just as good’ as the long-term allocation of capacity contracts allowed when awarded the status of TPA exempted project. A second explanation is that obtaining an exemption from TPA and entering long-term capacity contracts with customers may not be considered a feasible option because of a lack of demand commitment6: no gas storage customers may be prepared to contract a significant share of long-term capacity rights. The anticipated unwillingness of possible customers to sign long-term contracts of about the same length of the economic lifetime of the project may have prompted the initiators of the project to search for a different approach.

Diversity in regulatory approaches towards LNG investments

Similar to the case of gas storage the EU legislative framework allows discretion for EU member states to apply a regulated or a negotiated TPA regime to LNG import terminals. Possible determinants in the considerations on which specific regime to adopt in particular cases may include the level of gas market competition in the country, the (relative) dependence of the country on LNG imports, and the number of suitable locations available for the development of LNG facilities. From the perspective of economic theory on infrastructure expansion it makes sense to let the regulatory decision regarding the choice of approach to adopt be dependent on indicators for the economic position of the LNG facility in the (relevant) market and the opportunities for market entrance. The inclusion of an indicator such as the LNG dependence, supposedly related to security of supply, is not something accounted for in theory. This indicates that considerations other than economic efficiency and affordability play a role in regulatory decision-making as well.

As a result, the specific regulatory regime applied to LNG import terminals across the EU varies widely. Spain, a country largely dependent on LNG for its gas supplies, adopts the default option of regulated LNG import terminal expansion, whereas the UK, a country that seeks to diversify its gas supplies has awarded exemptions to all LNG import terminal initiatives implying that only merchant terminals are currently realised. France shows an interesting mix of regulated and merchant expansion of LNG import terminals that remains to be explained.

The different treatment of LNG investment projects across EU member states may to some degree be explained by differences between the

10

market conditions and demand and supply balance in the respective member states but with an increasing level of European market integration, at least at the regional level, the relevant market to be considered in regulatory decision-making should no longer be the national market but rather the larger EU region, if not the whole of the EU. This development should have consequences in the way national regulatory authorities makes decisions regarding the suitable regulatory approach towards LNG import terminal investments. This requires a common vision on the regulation of LNG investments in the medium to long-term, with a sufficient level of harmonization between neighbouring countries.

Conclusions

From the analysis on the different regulatory regimes implemented across different types of gas infrastructure and across the EU the following conclusions may be drawn with respect to the posed research questions.Firstly, differences in regulation across different types of gas infrastructure can be explained by their different generic economic characteristics. Here I refer to the infrastructure investment costs and the relative share of these investment costs in total costs of providing the infrastructure service (i.e. the degree of natural monopoly), and the need for coordination with other (existing) infrastructure. The first aspect is most clearly demonstrated in the case of gas storage where the level of market contestability is different for small gas storage facilities with relatively high deliverability and large (seasonal) gas storage facilities with relatively low deliverability. The second aspect is illustrated by the difference in the case of pipeline investment within a meshed pipeline network and the case of a single pipeline investment within a radial pipeline network.

Secondly, differences in regulation across EU countries can be explained by location-specific factors and by other public goals than the public goal of an affordable (i.e. cost-efficient) gas system. Relevant location-specific factors include the level of competition on the gas wholesale market, and the (real or potential) level of competition on the relevant (geographical) market for the parti-cular service provided by the gas infrastructure. The latter aspect refers to for example the physical opportunities for market entry in the case of gas storage and LNG terminal investment, which vary across EU member states. Also security of supply considerations play a part in explaining differences in regulatory decision regarding on infrastructure investments, which is for example shown in the case of LNG import terminals where the LNG import dependence of a region is included as a criteria in regulatory decision-making.The lessons learned from this research also have particular practical use. Companies with plans to develop for example gas storage or LNG import terminal projects may use the above lessons to argue for particular regulatory treatment of their investment. In the argumentation for a particular regulatory regime it is impor-tant that companies address the whole range of relevant factors as identified in this article; both the economic characteristics that are generic for the type of infrastructure, as well as the location-specfic factors relevant for the considered investment project. In addition, the acquired insights may assist companies in their decision where to locate their investment project. Based on the insights from this research companies can improve their assessment on the likely regulatory regime that their project would be subjected to and its consequential impact on its business case across possible countries.

Any questions or comments are welcome.Contact: dejoode@ecn.nl

Development of the MILENA gasification technology for the production of Bio-SNG.

Christiaan van der MeijdenProject leader at ECN

Methane produced from biomass is referred to as Bio-Methane, Green Gas or Bio-Substitute Natural Gas (Bio-SNG). Bio-SNG has the same properties as fossil natural gas, so it can directly replace fossil fuel consumption. The production of Bio-Methane via digestion (biogas) has been developed and is implemented (mainly) in small-scale installations. The limited amount of suitable digestible feed stock (e.g. manure and food residues) demands for development of new technologies which can convert a wider range of biomass, like wood residue, into Bio-Methane. Gasification is such a route that can convert a wide range of (ligno-cellulosic) biomass into methane.

The Energy research Centre of the Netherlands (ECN) has developed a new biomass gasification process (MILENA) that can convert biomass

into methane. The overall process from biomass (e.g. wood) to Bio-SNG is shown in the figure below:

gasifier

tar removal

CH4 synthesis

gas upgrading

3 H2 + CO CH4 + H2O

further gas cleaning

fuel

Bio-Methane

Figure 1: Simplified process scheme for the production of Bio-Methane

Biomass (fuel) is converted at a typical gasification temperature of 850°C into a combustible gas. The gas contains CO, CO2, H2, H2O, CH4, C2H4, C6H6, tars and several pollutants. After removal of tars and pollutants the gas is converted into Bio-SNG / Bio-Methane. The Milena biomass gasification technology is characterized by a

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medium calorific value producer gas (12 – 18 MJ/Nm3 dry gas), not diluted with nitrogen. The theoretical efficiency from wood to SNG of a complete plant is up to 70%. This overall efficiency is high because of a relatively low gasification temperature (typical 850°C), low input of fluidization gas and a complete fuel conversion in the MILENA reactor. A drawback is the high amount of tar that is produced in the gasifier. The producer gas is treated with the ECN-Olga technology to remove tar. The tar is recycled to the combustion section of the gasifier, where it acts as a fuel.

Biomass is considered a CO2 neutral fuel, as the amount of CO2 released on burning biomass equals the uptake of CO2 from the atmosphere during growth of the biomass. Fuels like hydrogen, methane, FT diesel and methanol produced from biomass have the potential to become a CO2 negative fuel, because part of the biomass carbon is separated as CO2 in a concentrated stream during the production process. If this pure CO2 stream is sequestrated, these fuels can become even CO2 negative. This might be an attractive option for reducing the level of greenhouse gasses in the atmosphere. Figure 2

Natural GasReserve

CO2 in atmosphere

Biomass

Natural Gas Grid

Users

CO2 from combustion of

Methane

800

+800 kton/y

CO2 Sequestration

Natural GasReserve

CO2 in atmosphere

Bio-MethaneProduction plant500 MW Bio-SNG

0.4 bcm/year

Bio-Methane

Biomass

CO2

CO2 to grow biomass

Biomass

CO2 emissions from transport, etc.

Natural Gas Grid

Users

CO2 from combustion of Bio-Methane

8002000 250

400 kton/y

800

-550 kton/y

0.4 bcm/year

0.4 bcm/year

Figure 2: CO2 balance for Natural gas and Bio-Methane produced from woody biomass

Figure 3: pilot-scale MILENA gasifier (left) and installation of the OLGA pilot-scale gas cleaning (right) at ECN.

shows the CO2 balance for Natural gas and Bio-methane produced by gasification of woody biomass. As can be seen from the figure the CO2 emissions from 0.4 billion cubic meters (bcm) of natural gas (assuming 100% CH4) per year are 800 kton/year if conventional Natural Gas of fossil origin is used. These figures exclude emissions from transport / compression of natural gas. If conventional natural gas is replaced by Bio-Methane produced by gasification of woody biomass, the CO2 emissions would drop to 250 kton/year. If the pure CO2 stream that becomes available during the production process is not vented into the atmosphere but sequestrated in an empty gas field, the net CO2 emissions become negative (-550 kton/year).

ECN produced the first Bio-Methane in 2004. The lab-scale results were promising and led to the realization of an 800 kWth pilot plant in 2008. An extensive test program was done in the lab-scale and pilot-scale MILENA installations. Different fuels, such as clean wood, demolition wood, sewage sludge and lignite were tested. A duration test using demolition test was done in 2010 in the 800 kWth MILENA pilot plant in cooperation with HVC. Figure 3 shows the MILENA pilot plant gasifier and the installation of the OLGA gas cleaning pilot plant. HVC, energy and waste company, is a modern public service waste company. HVC converts waste streams which cannot be recycled into usable forms of energy. HVC has a large waste wood boiler in operation. HVC has decided to join ECN with the development, demonstration and implementation of the MILENA Bio-SNG technology.

ECN and HVC are preparing a 12 MWth demonstration plant based on the ECN Milena technology. This demonstration plant will be located in Alkmaar. Demolition wood will be used as fuel. In the first stage the

gas will be fired in a gas engine or boiler. After a successful operational test program the methanation unit will be added to the process for the final conversion of the gas into Bio-SNG. The produced gas will be injected in the gas grid. The foreseen Bio-SNG production is around 5 million m3 per year. This demonstration plant is seen as a development step towards large scale production of Bio-SNG. Further scale-up is required to make a significant contribution in replacing natural gas by Bio-SNG. Supporting research regarding catalytic upgrading of the gas and improving the process is being done as part of the EDGaR program.

Commercial scale Bio-SNG units are expected to produce between 0.025 and 0.5 bcm/year of Bio-SNG. The estimated amount of biomass available for energy production vary strongly, but the data shows that the potential is there to replace a major part of fossil natural gas by Bio-SNG.

More information about the development of the MILENA gasifier for the production of Bio-SNG can be found in the Ph.D. thesis of Christiaan van der Meijden:www.ecn.nl/docs/library/report/2010/b10016.pdf

Any questions or comments are welcome.Contact: vandermeijden@ecn.nl

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Economics of natural gas in Smart Grids

Karel van der Lingen1

Business Analyst, GasTerra

2 This research has been carried out as part of the Master Industrial engineering and management and it is connected to his Master’s thesis on the same subject. The results have not yet been approved by the University and are thus preliminary. The content of this article are the authors’ sole responsibility and do not represent the view of GasTerra.

When discussing the role of smart-grids in the future supply of natural gas, there are two major questions to be answered. The first one is whether you can apply smartness to a gas grid, and the second is whether there is a future for gas in newly developed urban districts at all. These questions are actually mutually related, given that for the foreseeable future adding smartness to existing grids is not an issue. On the one hand, when gas is not regarded as a realistic option in new districts, you cannot apply smartness as the grids are then non-existing. On the other hand, when smart grid can be applied to gas infrastructure, this could keep or regain the competitive edge of natural gas in residential energy distribution.

Smart Grid

Before being able to answer these two questions, we first have to take a look into what a smart grid actually is. The concept of a smart grid has become somewhat of a buzz word for almost every innovation that is demonstrated in the world of energy grids. For this analysis, a smart grid is defined to refer to the household level, where the grid is such that it enables a household to change its energy consuming behaviour based on an external price incentive, and this change of the behaviour is supported or executed by an automated process. In proposed smart grid architectures, this automated process is often embedded in or controlled by a smart meter.

Advantages

Often the main advantage that is claimed to result from the introduction of a smart grid is high or higher flexibility on the energy demand side, which can be used to balance demand and supply. This can be on the very short term (minutes to hours) on the supply side to support volatile renewable sources, such as wind energy, and on the demand side when demand changes unexpectedly in such a way that traders are unable to balance their portfolio. But it can also be on the longer term (hours to days), to balance consumption throughout the day or week, so the need for high backup capacity for peak load decreases. There are two other reasons that are often quoted. Firstly, a smart grid is said to reduce the wear and tear of expensive parts of the grid or production due to peaks in grid load. Secondly, it enables users to become more conscious about their energy consumption due to the active feedback they get from the system.

Gas, electricity or both?

When referring to the concept of a smart grid, mostly such references are about the electricity grid. There is however no reason why such a reference should exclude the gas grid, or maybe should even be at the forefront of the discussion. For example, there is quite some flexibility in domestic heating; a boiler, especially one with a hot water storage tank, can advance or postpone heating when there are margins in the temperature of the home it is intended to heat. Such advances or

delays lead to very little or no loss of convenience for the household, while it gives a lot of flexibility to the gas grid. Another very interesting application is the concept that currently receives a lot of attention: the micro-CHP (mCHP), which is a domestic power plant. In contrast to a normal CHP, a mCHP delivers mostly heat and only a little power, i.e. it generates electricity mostly based on heat demand. With the use of a mCHP the option arises to arbitrage between using electricity from the grid and producing your own electricity, based on the different incentives, and provided that there are integrated smart grids both for electricity as well as for gas.

Within-day balancing

Not only is it possible for gas to be part of a smart grid infrastructure, it actually gets more economically interesting as per April 1st. On that date, the balancing regime of the national Dutch grid will be turned into a within-day market-based balancing system, and with this an interesting opportunity emerges to extract value from flexibility on the demand-side in the same way it did for electricity. Because of the physical difference between gas and electricity, balancing in the electricity market is done on a 15 minute basis, while gas will be on a 60 minute basis. As is well known, electricity is almost impossible to store economically on a larger scale, while gas has the advantage of being possible to store and to use the physical range of pressure allowed in the grid (line-pack).

Gas in new urban districts?

Having answered the question about the possibility of applying smartness to a natural gas grid with a resounding ‘yes’, the question still remains whether gas should be part of a future infrastructure at all. The answer to this question seems to be pretty simple: yes, it should. Every energy debate is around three issues: sustainability, affordability and reliability (or security of supply). Let’s analyse building a new urban district, and evaluate the option of building only an electrical infrastructure on the one hand, or both a gas and an electrical infrastructure on the other, along these three issues.

Sustainability

The sustainability issue is clear, as long as the electricity that house-holds consume is produced using ‘grey’ sources such as coal. In such a case it is impossible to suggest that using only electricity is ‘greener’. And when in the future we decide to switch fully to renewable sources,

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the gas grid would not become obsolete; it can be used to transport green gas or even hydrogen, enabling a CO2-neutral society. It must be said that from all fossil fuels, natural gas is by far the cleanest, both from a CO2-perspective as from the perspective of other pollutants resulting from burning fuel.

Affordability

Looking at the issue of affordability, this actually provides the easiest case for the gas grid. From an interview with a large Dutch grid opera-tor, it has become clear that an ‘all-electric’ infrastructure is between 1,5 to 2 times as expensive as a combined infrastructure. This is because the amount of electric power needed for electrical household heating is so large that the capacities of the power cables have to be considerable increased, which is very expensive. Besides this, the largest cost of building new infrastructure is digging into the ground to lay the actual lines, and when this is done at the same time, there are few ad-ditional costs for the gas infrastructure.

Reliability

Contrary to commonly held believe, the reliability or security of supply issue is also not very difficult. The newest expected global natural gas reserves are so large that it could be possible to use natural gas for maybe another 250 years. What is more, together with these additional reserves also the number of independent suppliers will increase, making consumers or consuming countries less dependent on a small number of suppliers. These additional reserves are by the way again partly situated in The Netherlands.

Even if in the long run one would foresee a depletion of the natural gas reserves, the grid can be used just as well for new renewable gasses, like green gas or hydrogen.

To the question whether new districts should keep getting connected to the gas grid, the answer is simple and clear from every perspective: yes, they should. Now to see how a combined natural gas / electricity smart grid in practice works using smart appliances, such as a mCHP and a smart washing machine, a simulation model was designed. The model shows that a natural gas connection has economic value for consumers by solving flexibility issues for consumers.

Designing a simulation model

To see how a combined natural gas/electricity smart grid for house-holds works in practice, a simulation model was designed. The advantage of a simulation model is that it can be run with different parameters to get results for different scenario’s. Its main fallback is of course that it has to model human behaviour, which is difficult. The model uses aggregated data on response mechanisms. This means that the number of different responses a household can give, have been averaged per household. Every household has been assigned a different response degree, according to a distribution which is derived from literature describing the elasticity of energy consumption. In other words, some households react strongly to higher prices, most of the households give a moderate response and some hardly any.

Data in the model

Although some of the value of balancing is achieved by balancing in a local area, there is currently no public administration and thus economic valuation of local imbalance. As a result the value of dealing

with imbalance in the electricity market is calculated on a national scale where imbalance settlements are carried out every 15 minutes by the Transmission System Operator Tennet. For gas such an imbalance market does not exist yet, so a typical yearly consumption pattern is taken with hourly data. The year is split up in periods with a similar profile (a winter-profile is very different from a summer-profile). Subsequently every hour of the day is compared with the average of that hour in the same period to determine the deviation of the consumption . The typical degree of response that was assumed for households is -0,5 per deviation of the norm in percents. In other words, if the price rises 10%, the consumption decreases 5%. It is important to note that the total consumption in this case does not change. Only the consumption profile gets slightly rearranged, with almost no loss of comfort for consumers.

Results

Using household price data from the Dutch statistical agency CBS for 2009, a household can save 3,4% on their electricity bill and 8,6% on their gas bill. The following data was used: a consumption of 3000 kWh electricity with an average price of €0,267/kWh and 2000 m3

gas with an average price of €0,591/m3. This would have meant an annual saving of €128,8. The model can and should be further developed according to new insights, for instance resulting from the introduction of the new Dutch balancing regime per April 1st. Furthermore, results from other studies or test-cases can be used to fine-tune the parameters.

Conclusions

There are obvious reasons why gas should be part of a smart grid infra-structure. Even though the grid may be less vulnerable to short changes in supply and demand than the electricity grid, on a longer time scale the reasons to support smart grids do apply. Building a new district without gas infrastructure does not seem to make sense and claims of this being green are unsupported. When a smart gas grid is applied, the decrease of the household energy bill for a household can be substantial, even with the total consumption staying equal. Whether it justifies investing in an expensive mCHP-installation remains a question.

Any questions or comments are welcome.Contact: karel.van.der.lingen@gasterra.nl

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Books, reports and conferences

James Henderson, November 2010. Non-Gazprom gas producers in Russia. Oxford Institute for Energy Studies. Review by Nicholas Newman

This book by James Henderson, who is currently Head of Russia for Lambert Energy Advisory in London as well as a Senior Visiting Research Fellow at OIES, provides a useful insight into the intricacies of the Russian domestic gas market. It not only describes in a concise and knowledgeable manner the complex organisational interrelationships between gas producers, brokers, investors and government agencies, but also comments on how these various stakeholder relationships have evolved over time since the beginning of the post-soviet era to the present day.

This book details how Gazprom and the independent gas producers, such as Novatek and Lukoil, emerged out of the chaos of the 1990’s to the present day. It examines how the geo-political developments both inside Russia and in Europe, have influenced the market, including how the collapse in European gas prices has slowed or put on hold indefinitely Gazprom’s ambitious plans to develop the high cost and technically difficult fields in the high Arctic of Siberia. It details the role that non-Gazprom production from both domestic and imports from Central Asia has played in meeting the needs of the domestic market. In addition, it examines the ability of non-Gazprom producers to replace the proposed new capacity that Gazprom had planned to develop in the high Arctic. In fact, James Henderson describes how non-Gazprom producers can develop cheaply sufficient output to meet expected growth in the domestic market for years to come, from their existing assets.

In addition, this book identifies and details the major non-Gazprom producers, their strategies, prospects, as well as their relationships with government agencies. As a regular commentator on this topic, I appreciated James confirming my own view about the importance that companies place on maintaining a good relationship with the Kremlin, to ensure a prosperous outcome.

This book is available at: http://www.oxfordenergy.org/bookdetails.php?ng45

Jonathan Benjamin Alvaro et al., December 2010. Cuba’s Energy Future. Brookings Institute. Review by Nicholas Newman.

This book poses the challenging question what steps can Cuba take to achieve both short term and long-term energy sustainability and self-sufficiency. The often-complex solutions are based on three alternative scenarios of little change, some reforms and a full liberalisation of the Cuban economy will surprise many readers not familiar with the Cuba’s energy sector or the developing world.

This book provides a well-argued and evidence backed logical case of why trade sanctions are against America’s own interest.

In the oil and gas chapter by JB Pinon and JB Alvarado, it is argued that developing Cuba’s capacity to increase crude oil and petroleum

products output is vital in offsetting the declining output from America’s traditional oil suppliers of Mexico and politically unstable Venezuela. The US Geological Survey conservatively puts Cuba’s probable oil reserves at a least half that of Alaska, with the advantage of not having the environmental and technological difficulties of developing the North Slope fields of Alaska. What is clear from this chapter is that Cuba has a great potential to dramatically increase its crude oil and petroleum products output, which is being held back by the American trade embargo. Though, what many readers might find impressive despite American trade sanctions, Cuba, with the help of major non-American energy companies such as Norway’s Norsk-Hydro, Brazil’s Petrobras and Canada’s Sherritt International, has managed to develop a successful domestic oil and gas industry.

This book is available at: http://www.brookings.edu/press/Books/2010/cubasenergyfuture.aspx

Anouk Honoré, December 2010. European Natural Gas Demand, Supply & Pricing: cycles, seasons and the impact of LNG price arbitrage.

The rationale of this book stems from the fact that, while there is much material dealing with gas supply availability, there is very little research on European gas demand from publicly available source. Some of the conclusions are:- The timing and the shape of the gas demand growth recovery in Europe remain uncertain. But despite the general pessimism, there is some potential for additional demand, driven mostly by the construction of new gas-fired power plants. - We expect natural gas demand to increase by 50 bcm (up to 635 bcm) or 0.6 percent per year on average by 2020, but with major differences between national markets, sectors of consumption and period of recovery. - European gas demand will be close to Take-or-Pay (TOP) levels of contracted pipeline gas in 2010, but the tightness should relax in 2011. - Contracted gas, including LNG, is sufficient to cover gas demand until 2014. - Europe will need to secure additional gas post 2015, a period of large uncertainty for world gas supply in general.

The book provides not simply an analysis but also a methodology for looking at the evolution of European gas demand and supply.

This book is available at: http://www.oxfordenergy.org/bookdetails.php?oies36

International Energy Agency, November 2010. The contribution of Natural Gas Vehicles to Sustainable Transport.

The International Energy Agency (IEA) has released a working paper titled “The Contribution of Natural Gas Vehicles to Sustainable Transport,” which considers costs and benefits associated with using natural gas vehicles (NGVs) for road transport, as well as policies related to its use and market development.

15

The paper begins by highlighting the current status of NGV markets and technology, before discussing their environmental performance, economics and policy, and sustainable pathways for their future use. The paper also includes six case studies of policy and markets for NGVs in Brazil, India, Iran, Pakistan, the US, and Europe.

Among its main findings are that, depending on the national context, NGVs can have very positive benefits on air quality and noise, energy security, and budgets by reducing the need for road fuel subsidies. Such vehicles also provide large CO2 savings in comparison to many alternatives. Finally, the paper also finds that in most cases, infrastructure costs have been balanced by market growth and have had resulted in positive returns, although sometimes government support may be necessary.

More information about this paper is available at:http://www.iea.org/papers/2010/natural_gas_vehicles.pdf

Hakim Darbouche, March 2011. Algeria’s shifting gas export strategy: Between policy and market constraints.

The new publication of Hakim Darbouche gives an in-depth insight in Algeria’s gas marketing strategy, analysing the main drivers of this strategy since the beginning of the 21st century.The poor performance of Algeria’s gas export in 2010 raised several questions about its short-to medium-term gas marketing strategy. In this paper, the author attempts to address the issues related to oil-indexation in Continental European gas supply contracts, market share, spot prices and producer cooperation, LNG sales, and capacity utilisation.The author argues that the changing market conditions (gas supply crunch), owing to the policy inconsistencies of the administration of former energy minister Chakib Khelil, currently Algeria’s gas export strategy is constraint. The formulated goals of 85 bcm/y by 2010/2013 and 100 bcm/y sometime thereafter seem unlikely to be realized. The situation inherited by the new leadership at Sonatrach and the Algerian energy ministry leaves limited options for the optimisation of Algeria’s gas exports in the short to medium term.The author concludes that until 2014-15, the main driver of Algeria’s gas marketing strategy is likely to be the maximisation of the value of exports, regardless the impact it might have on its market share. In the context of a buyers market and the emergence of more LNG suppliers, it will become more difficult to regain the possible lost market share. Until then, large parts of the country’s gas export infrastructure will still be under-utilised. In order to address this situation, the new energy administration in Algeria will need to take action to improve the supply-demand balance. This implies the articulation of the energy policy and plans for intensified upstream development of unconventional and offshore gas resources as well as cutting the $7bn subsidizing gas and electricity end-users every year.

This article is available at:http://www.oxfordenergy.org/pdfs/NG48.pdf

Florence Gény, December 2010. Can Unconventional Gas be a Game-Changer for European Gas Markets?

The rise of unconventional gas production, and in particular shale gas, has been the greatest revolution in the US energy landscape since the Second World War and has the potential to transform that country’s requirement for LNG imports (and hence global LNG trade). This

paper analyses the potential for European unconventional gas to be developed and transform European gas markets. The main conclusions focus on the challenges to replicate US best practices in Europe, and analyses the European response needed to make unconventional gasa success story in the continent, as well as the potential implications of unconventional gas development for European gas markets. Understanding the conditions that have made shale gas exploitation successful in North America is fundamental to an analysis of the potential of shale gas in Europe. This study identifies five catalysts, both policy and market-based, that triggered modern unconventional gas production in the US.The development of unconventional gas in Europe is likely to be a long-term story, and is unlikely to become a sudden gas revolution as in the US. There will be no significant production before at least 2020 due to:* the immaturity of the European industry in terms of geological knowledge of unconventional reservoirs;* very few announced drilling investments over the next three years, which will translate into a long testing and play de-risking phase, and;* lead times of about 5 years based on US shale gas projects.In addition there are many operational, regulatory and commercial challenges to the development of unconventional gas resources which are specific to Europe.

In order for operators to be able to produce unconventional gas at high levels, the two biggest challenges to overcome are land access (spatial and regulatory constraints as well as local acceptance of this new activity) and cost levels (yielding poor commercial viability comparedto alternative gas supply projects).* Land access for drilling, logistics and building infrastructure is a huge issue linked to severe spatial restrictions resulting from high levels of urbanisation in North Western Europe; extensive regulatory protection of sites and landscapes; and difficulties in accessing private land due to local hostility (although this situation varies from region to region).* Shale gas costs in Europe are driven by geology (reservoir depths and complexity), a higher general cost of doing business compared to the US, and an oligopolistic service industry.

This article is available at: http://www.oxfordenergy.org/pdfs/NG46.pdf

16

EDI Quarterly is published in order to inform our readers not only about what is going on in EDI, but also and in particular to provide information, perspectives and points of view about gas and energy market developments.

Read the latest developments in the energy industry, daily published on the website of EDI.

Editor in ChiefCatrinus J. JepmaScientific director EDIaal*

EditorsLeo HoendersMarius PopescuNadezda KogdenkoSteven von EijeIvelina Boneva

EDI Quarterly contact informationEnergy Delta Institute Laan Corpus den Hoorn 300 P.O. Box 11073 9700 CB GRONINGENThe Netherlands T +31 (0)50 5248331 F +31 (0)50 5248301 E quarterly@energydelta.nl

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6-10 June 2011, Berlin, GermanyThe 19th European Biomass Conference and Exhibition (EU BC&E),http://www.conference-biomass.com/

13th to 14th June 2011, London, UKBioGas 2011http://www.smi-online.co.uk/events/overview.asp?is=5&ref=3481

15 – 16 June 2011, Rotterdam, The NetherlandsLNG Value Chain http://www.acius.net/wiki.aspx/Conferences/Upcoming?view=overview&id=185

* The EDIaal project is partly made possible by a subsidy granted by The Northern Netherlands Provinces (SNN). EDIaal is co-financed by the European Union, European Fund for Regional Development and The Ministry of Economic Affairs, Peaks in the Delta.