EDI Quarterly

Contents

1 Editor’s note

2 Production from Giant Gas Fields in Norway and Russia and Subsequent Implications for Euro- pean Energy Security

6 Brussels is not running out of steam

10 Smart power grids in combination with the efficient and flexible use of natural gas

13 Non-ETS Offset Schemes in Climate Policy

15 Books, reports and upcoming conferences

Q1Volume 2, No. 1, March 2010

Editor’s Noteby Prof. Catrinus J. Jepma, President of Energy Delta Institute

Gas infrastructure investment confusion?There is a thin dividing line between private and public targets. Reaching private targets – e.g ROI, maintaining market shares, M&A – can be left to private investors that will decide based on their own criteria whether or not to move ahead. Reaching public targets, however, may or may not be realized by spontaneous private activity.

Take Security of Supply (SoS) on the gas market as example. Broadly speaking SoS can be threatened by a number of rather different factors related to:a) exploration b) gas contracting c) gas trading d) gas infrastructure investment.

In theory spontaneous private investment activity can be such that SoS is secured by the private market itself so that public authorities can relax. In practice, however, there is not at all any guarantee that it works out like that: a) exploration may be insufficient to secure SoS, e.g. because of investors’ risk aversionb) gas may not be available for political or other institutional reasonsc) gas traders’ behaviour may frustrate SoSd) infrastructure investment may be insufficient to be able to get sufficient gas on the right moment on the right place.

Although all 4 factors mentioned may cause a threat to SoS, the last one may very well be the most serious one in the foreseeable future. That is because: a) it looks like for the time being there is and is going to be plenty of gas during the next decades (especially if we include LNG and unconventionals) so that b) the scope for strategic games is small, and

1

c) liberalisation will probably increasingly discipline the trading process. This leaves us with d) the risk of underinvestment in gas infrastructure, probably the weakest spot when it comes to the public target: SoS.

A first reason why getting to the right level of gas infrastructure investment, and interconnecting capacity in particular, is so com-plex, is because part of it is based on public investment (broadly domestic grids) and part on private investments (broadly intercon-necting grids). In the absence of any clear and generally applicable guidance as to what needs to be done publicly and what privately, and under what conditions, one should be prepared for problems emerging. That is because you cannot have an international grid and everything that comes to it (interconnection, quality conversion, compression, balancing, etc) without a huge variety of Return On Investment (ROI) on its various segments. If left to private investors, they will only put their money in the parts promising sufficient levels of ROI, leaving the leftovers to be picked up by public investment.

Second, insofar as infrastructure investment is in the hands of public investors, such as TSOs, they generally are facing a government / regulator that on the one hand wants sufficient investment to secure SoS, but on the other hand wants to save money by not accepting ROIs anyway nearing what private players would consider fair (In the EU regulator-accepted rates

typically are 6-7% only; US 9-10%!). In the absence of any clear and generally applicable guidance as to what of the two public targets mentioned will get priority, this obviously offers a breeding place for confusion, TSO-regulator conflict and potentially underinvestment in infrastructure.

Third, a new potential problem in the EU: if public authorities are engaged in gas infra investment, is this going to be national or European authorities? So far, national authorities were the prime ones deciding on infra investment. Recently, however, the Euro-pean Commission decided to throw in some 2.3 billion euro to enhance energy infra investment, identifying 43 projects (31 gas-related) it would be willing to support. Although the intentions will undoubtedly be good (primarily SoS concerns), one may wonder if such an initiative does not – once again – raise a new problem; i.e. lack of clarity of what is taken care of by resources from Brussels, and what by national authorities. In the absence of any clear and generally applicable guidance as to what will be ‘covered’ by Brussels, and what otherwise, one runs the risk of strategic ‘wait-and-see’ behavior and gaming as to who is going to pick up the bill.

So, if we do not want to run the risk of insecurity of supply because of a lack of infrastructure, maybe we simply need more clarity, transparency and predictability as to how the various public targets and responsibilities will be framed, interpreted and implemented.

2

Production from Giant Gas Fields in Norway and Russia and Subsequent Implications for European Energy Security

Bengt SöderberghPh.D

The Editorial Board of the Quarterly held an electronic interview with Bengt Söderberg upon the completion of his Ph.D thesis and asked him to elaborate on his results in the Quarterly.

What are your main findings and what does this imply for the European energy security?

The results indicate that resource-constrained models are presently the only feasible tools for long-term gas production forecasting. A gas production model based on depletion rate was found to be consistent with empirical experience on the field level, and to be at least as good as other resource-constrained models on a regional level. The model has consequently been used for modelling the presented gas production scenarios. Since a large share of the global gas reserves is contained in a relatively small number of giant fields, a field-by-field approach has been considered to be the most effective method for forecasting future gas supplies. The results show that the energy security of the EU is heavily dependent on gas supplies from a relatively small number of

giant gas fields. The main import sources for gas supplies to the EU are Russia and Norway, accounting for 62% of EU’s gas imports in 2006. In Norway almost all production originates from 18 fields of which 9 can be considered as giant fields. In Russia 36 giant fields account for essentially all gas production.

The scenarios examined show that there is a limited potential for increased gas exports from Norway to the EU and that Norwegian gas production in all scenarios is showing a decline by 2030. Norwegian pipeline gas exports to the EU may, by 2030, even be 20 bcm/year lower than today’s level. The maximum export increase of Russian gas supplies to the EU, amounts to only about 45% by 2030. In real numbers this means a mere increase of about 70 bcm. At the same time, domestic production within the EU is expected to fall by 126 bcm during the period 2006-2030. As a result, by 2030, the additional gas supplies from Russia will not even be able to compensate for the domestic decline of production within the EU. In addition, there are a number of potential downside factors for future Russian gas supplies to the European markets.

3

Consequently, given the results and assumptions presented, a 90% increase of import volumes to the EU by 2030 will be impossible to achieve. From a European energy security perspective the dependence of pipeline gas imports is not the only energy security problem to be in focus, the question of physical availability of overall gas supplies deserves serious attention as well. There is a lively discussion regarding the geopolitical implications of European dependence on imported gas from Russia. However, the results of this thesis suggest that when asses-sing the future gas demand of the EU it would be of equal importance to be concerned about diminishing availability of global gas supplies.

In order to assess the production capacity of giant gas fields, you have build a model. Can you explain the difference in forecasting future production levels of giant gas fields between your estimations as compared to for instance EIA and IEA estimations?

In the World Energy Outlook 2009, the IEA has used a similar method of field-by-field modelling of the giant fields based on depletion rate. This is an important step towards more detailed modelling and incre-ased transparency concerning what forecasting methods that are being used. The reference forecast for Russian gas production presented by the IEA seems realistic and is not exaggerated. My forecast for Russian gas production is higher, partly because my forecast is a maximum production scenario with more optimistic assumptions regarding start of production for Eastern Siberian fields. The IEA expects Russian pipeline exports to the East Asian markets only after 2020.

Unfortunately, the IEA does not in any figure describe the effects for Russian gas exports capacity to Europe, when new gas supplies from East Siberia, post 2020, are diverted for the Asian markets. The figure for projected Russian gas exports to Europe only extends to 2020, if it had been extended to 2030 it would show that there is a very limited further growth potential after 2020. It is important to bear in mind that the vast majority of the yet-to-be-developed giant gas fields of Russia are situated on the Yamal Peninsula and in East Siberia. The gas from Yamal will most likely be directed for the European markets although the proposed construction of the Altai pipeline might to some extent alter this situation. However, the gas fields of East Siberia are situated at too great distances from the European markets although relatively close to the Asian markets, and the gas will therefore be exported to primarily China.

Given the conclusion that the production capacity in Norway and Russia may fall short in meeting Europe expected import requirements, do you expect that by attracting volumes from the Caspian region in com-bination with LNG supplies are sufficient to meet the gas demand in Europe in the future?

The significant gas producer of the Caspian region is Turkmenistan, and the country has also the potential to maintain and increase its do-minant position. Although many of its traditional producing fields such as Dauletabad-Donmez, Naip and Shatlik are depleted by more than

Fig 1: The fast development forecast with figures from the NPD for undiscovered resources (High Case) and the slow de-velopment forecast, with a lower estimation (Low Case) for undiscovered resources. The Barents Sea is included with High Case (NPD) figures for undiscovered resources and contingent resources. The two forecasts enclose a range in which future Norwegian gas production can be expected to materialize with peak production occurring in 2015–2020 at 124–135 bcm/year. These two forecasts are compared with the high 140 bcm and the low 125 bcm target forecast from the NPD.

4

50%, Turkmenistan may increase its production due to the recently discovered giant gas field South Yolotan/Osman. However this field is a deep high pressure high temperature reservoir with high concentrations of hydrogen sulphide and carbon dioxide, making the field expensive and technically difficult to develop. Therefore it is hard to make any pre-cise production forecasts for Turkmen gas production the coming 20 years, although perhaps a production of 100-120 bcm/year by 2030 is reasonable to expect. However, a pipeline from Turkmenistan to China has already been built, with a planned capacity of 40 bcm/year. Already with three present customers Russia, China and Iran, it is unclear if Turkmenistan will be capable or willing to export any larger gas volumes directly to Europe through the proposed Nabucco pipeline. World LNG production has increased by around 53% during the last five years, and this rapid expansion phase is expected to continue. An additional 146 bcm/year of capacity is under construction, which will take the total capacity to around 400 bcm/year by 2012. Another 417 bcm/year of capacity is in the planning stage, though many of the planned projects have been announced, but not initiated, for several years. According to the IEA, beyond 2012, there are uncertainties regarding the availability of incremental LNG supply for both OECD and non-OECD importing countries. Although a significant amount of capacity is planned and proposed, many projects have yet to be formally sanctioned, primarily because of shortage of skilled labor and higher material and engineering costs. These factors afflict many projects that have already been undertaken. They discourage companies from proceeding to final investment decisions (FID) on other projects and lead to some project cancellations. Only one FID was made in LNG production in 2006, three such decisions were made in 2007, and only one in 2008. For the period beyond 2013 the expansion rate of LNG supplies is uncertain.

With the assumption that half of the planned capacity is utilized, global LNG capacity would reach about 600 bcm by 2030. Of total LNG exports in 2007, the EU imported 21%, Assuming that this relative share remains static until 2030, the available LNG supply for Europe would amount to 126 bcm by 2030. These amounts are not enough to fill the gap between projected increase in demand and pipeline imports from Russia.

In the US the rise of unconventional gas production has reversed the decline in domestic production. Do you expect that unconventional resources can play an important role in the future production of gas within Europe?

Europe must overcome several challenges before the same level of success in shale gas production as in the US could be materialized. One major uncertainty is the European geology. Exploration activity is still at an early stage with little data on potential reserve sizes or formations. Secondly, shale plays cover much larger areas than conventional gas fields and require at least ten times the number of wells, drilled much more closely together, than those required to exploit conventional resources. This means that a much larger surface area is affected by drilling and production operations. Due to the high decline rates of shale gas wells a very high pace of drilling must be maintained in order to sustain or increase the production. Thirdly, shale gas production not only requires extensive land areas but also large amounts of water. The drilling and hydraulic fracturing of a horizontal shale gas well may typically require about 12 million liters. Besides potential problems of regional and seasonal water scarcity, there are additional environmental concerns associated with large scale hydraulic fracturing.

Fig. 2: Forecast for all producing giant fields in Russia and all planned production from giant fields.

5

Lack of nearby facilities to treat and dispose of waste water has already slowed development and increased costs significantly in some North American shale gas deposits plays. Hydraulic fracturing processes in the US have also been accused of contaminating nearby drinking water reserves. Finally, Europe does not yet seem to have the necessary industrial capabilities for a fast pace development of shale gas production. The proximity to existing pipeline infrastructure, a major driver behind the development of the industry in the United States, is a critical factor that could slow the development of European shale gas production. Insufficient amounts of rigs and a lack of skilled labour force may cause further cost problems and project delays. Most likely Europe is at least a decade away from seeing any substantial shale gas production, and shale gas may yield significant production contributions perhaps not until 2025-2030 or later.

Given your conclusion, what would be your advice to European policy makers with regard to their future energy strategies?

When performing long-term energy planning it is important to realize that the global conventional oil and gas reserves are indeed finite resources which are being rapidly depleted. Offshore gas production

in arctic water has yet not been performed in any larger-scale, and the shale gas industry of the U.S has a relatively short production history, although associated with significant production successes in recent years. Figures of large resources in many unconventional gas plays that have been announced by various reports may create a dangerous illusion of long-term gas abundance since the sustainable long-term production potential from these resources is still largely unknown.To expect large production contributions from these new gas sources when planning future energy strategies increases the overall risk level. Prudent risk management requires being prepared for the less desirable scenarios while hoping for the best scenarios to materialize. It is of vital importance to get all the relevant facts and data on the table when performing long-term energy planning. Therefore it is necessary to perform research aimed at estimating the potential future production volumes from conventional gas production as well as from the new emerging gas production methods in order to improve the quality and reliability of the data material that forms the basis of decision for European policy makers.

If you are interested in obtaining the full text, please sent an e-mail to the following adres: quarterly@energydelta.nl

Fig. 3: Forecast for Available Net Exports Capacity for the European and CIS Markets with gas produced in Russia. Exports to CIS markets were 101 bcm in 2007 and Gazprom Central Asian imports were 60 bcm.

Brussels is not running out of steam René Snijder

Partner relations management, EDI

On the contrary, ever more new initiatives seem to surface from within the departments related to energy1. When the EU energy market reform was kicked off in the mid nineties of the last century, the policy emphasis was on the creation of competitive markets. The other two corners of the EU energy policy triangle (sustainable development and security of supply) were considered to be almost automatically enhanced as a result of the introduction of the competitive markets. Only in recent years the emphasis in the EU energy policy is shifting towards more attention for the environment2 and since the Ukraine gas crisis of January 2009, the security of supply.

In the previous Quarterly Nadine Haase discussed the European gas market liberalization and the missing link between investment needs and a regulatory framework providing the right incentives. There are more missing links, that recent legislation is to address. An enhanced role of the Commission, the network operators and the new regulatory agency ACER is envisaged to integrate markets and to ensure security of supply. Some of the new issues on the table are harmonisation of the network codes, coordinated security of supply measures and enhanced sustainability policy in the frame of liberalized energy markets.

This results in a more balanced approach towards all three policy pillars: competitiveness and market integration are now more related to security of supply (incl. affordability and investments) and the mitigation of CO2 emissions and its environmental impact is high on the energy policy agenda.

EDI attended two events in Brussels - the EU Energy Law and Policy conference organised by Claeys & Casteels at the end of January and the Information Day on Trans-European Energy Networks organized by the European Commission on 22 March. Adding some of our own relevant research, we hereby provide you with an overview of the recent EU legal and policy developments impacting the energy sector in the years to come.

Adopted Legislation

Climate-Energy Package

A Climate-Energy Package was adopted on 6 April 2009. Its purpose is to achieve the EU’s overall greenhouse gas reduction target of a 20%3 and a 20% share of renewable energy in the EU’s total energy consumption by 2020. It includes, among others, the new Renewable Energy Directive, a revised more stringent EU Emissions Trading System (ETS) and an “effort-sharing” agreement between the Member States for reducing carbon emissions in sectors not subject to the ETS.

Directive 2009/28/EC on the promotion of the use of energy from renewable sources aims to achieve a 20% share of energy from renewable sources in the EU’s final consumption of energy and a 10% share of energy from renewable sources in each Member State’s transport energy consumption. The Directive sets for the first time for each Member State a mandatory national target and the obligation to adopt a national renewable action plan with concrete sectoral targets. The national targets for the overall share of energy from renewable sources in gross final consumption of energy vary per Member State, taking the specific situation of each Member State into account. The 10% target for the transport sector is set at the same level for all Member States for the sake of consistency in transport fuel

specifications and availability. The action plans outlining the 27 Mem-ber States’ measures for achieving these targets have to be submitted to the Commission by June this year. In practice, however, these targets will be hard to achieve. One of the opinions on the plausible ways to achieve them emphasizes the role of biomass to as much as half of the energy produced from renewable sources.

Directive 2009/29/EC amending Directive 2003/87/EC so as to improve and extend the ETS will apply from 1 January 2013 and there-fore, Member States have until 31 December 2012 to bring their natio-nal legislation in compliance with the EU rules. The Directive provides for harmonised allocation rules to ensure an EU-wide level playing field and introduces auctioning as the general rule for more than 50% of the allowances in 2013. There are elaborate rules for the ways of phasing out free allocation, the target being reaching full auctioning in 2027. The revenues from the auctioning will remain for the Member States, which can individually determine how to use it. However, at least 50% of the revenues shall be used for fighting climate change and alleviating the social consequences of moving towards a low-carbon economy.

Sectors not subjected to the ETS (among others, transport and agriculture and as a total, 60% of the EU’s greenhouse gas emissions) are covered by Decision No 406/2009/EC on the effort of Member States to reduce their greenhouse gas emissions to meet the Community’s greenhouse gas emission reduction commitments up to 2020. The national emissions reduction targets are determined as a function of GDP per capita. Thus Member States with high GDP per capita have to reduce their emissions, but Member States with low GDP per capita still have a room for growth and emissions increase, but not more than 20%.

Regulation (EC) No 443/2009 setting emission performance standards for new passenger cars provides for the first legally-binding standards for CO2 emissions from new passenger cars. It is directly EU wide applicable from 2012 onwards and the car manufacturers will have to gradually meet its targets with their new car fleets.

Directive 2009/30/EC introduces for the first time a reduction target for greenhouse gas emission from fuels: 6% by 2020. Member States have to implement the targets of the Directive in their national legislation by the end of this year. They have the additional possibility to require further reductions of 4%.

Directive 2009/31/EC on the geological storage of carbon dioxide sets up a regulatory framework for the environmentally safe geological storage of CO2. It does not create an obligation for Member States to allow any storage of CO2 in parts or on the whole of their territories and it leaves it to the Member States to determine the areas and the priority they want to give to the building of storage sites. Whenever a storage site is to be built though, the Directive provides for elaborate conditi-ons for assessments, authorization and closure procedures. No storage site may be operated without a permit. Where exploration is necessary for the selection of an appropriate site, it shall only be allowed on the basis of an exploration permit. In the granting of the storage permit, priority is going to be given to the holder of the exploration permit because of the substantial investments he has already made. The draft

6

Ivelina BonevaJunior Energy Analyst, EDI

The full ownership unbundling means that the TSO cannot be controlled by undertakings with supply and/or generation interests and vice versa: the TSO cannot exercise control or any right over any undertaking with supply and/or generation interests.

In the case of an ISO the Transmission system owner is legally and functionally unbundled: the vertically integrated company remains an owner of the transmission system, but its technical and commercial operation is performed by the ISO, which is completely independent, including in terms of ownership, from the vertically integrated company. There is a significant regulatory burden involved in that case, which, coupled with the fact that an ISO exercises control over the company’s network, makes the option of an ISO not a popular one.

The ITO is for now the most popular choice among Member States (and indeed the least desired by the European Commission and the European Parliament). The provisions regarding the ITOs allow the ITO to own the transmission system and still to remain a part of the vertically integrated undertaking. This is the setting from before the Third Energy Package, however with enhanced regulatory burden meant to serve as a “Chinese wall” between the vertically integrated company and the ITO and thus to ensure ITO’s independency.

It is important to note that the Third Energy Package provides for certain restriction of the freedom not to opt for full ownership unbund-ling. Thus, The ISO and ITO models can only be chosen for a specific TSO if on entry into force of the Directives (3 September 2009), the transmission system belonged to a vertically integrated undertaking. Furthermore, a Member State cannot prevent a vertically integrated undertaking from complying with the requirements of ownership unbundling even if the State itself has only chosen to implement the less stringent requirements of ISO or ITO. On the other side, where a Member State has opted for ownership unbundling, the vertically integrated undertaking does not have the right to set up an ISO or ITO.

Another important development brought by the Third Energy Package is the strengthening of the powers of the National Regulatory Autho-rities (NRAs) and where this is not the case yet, merging the different organs with regulatory authority into a single NRA at a national level (e.g.: in Belgium there are 4 regulatory authorities competent in the energy sector, which now have to be merged into one Regulator). The NRAs are now empowered to monitor the energy market, especially in regard to effective unbundling, to initiate and execute investigations and when necessary, to impose penalties (up to 10% of the annual turnover of the TSO (for fully unbundled TSOs and ISOs) and up to 10% of the annual turnover of the vertically integrated undertaking and/or the ITO).

An Agency for Cooperation of Energy Regulators (ACER) is to be set up to close the regulatory gap by performing tasks related to cross-bor-der issues, such as provision of framework guidelines for the European TSO bodies to draft the (potentially binding) EU-wide network codes. ACER is going to be seated in Ljubljana, Slovenia and is planned to be up and running by 3 March 2011. By that time pilot projects to develop framework guidelines and network codes will be handled by ERGEG. Priority will be given for framework guideline on grid connection, con-gestion management and capacity allocation and system operation for the electricity sector. The first framework guidelines for the gas sector shall be on capacity allocation methods, balancing and harmonization of transmission tariffs.

The 3rd energy package also provides for the establishment of European Networks of Transmission System Operators for electricity

7

storage permits, as well as draft decisions on closure of CO2 storage sites, prepared by national authorities shall be reviewed by the European Commission before their final approval. These rules do not apply to sites with a total intended storage below 100 kilo tonnes, undertaken for research, development or testing of new products and processes.

Third Internal Energy Market Package

The Third Energy Package was adopted on 13 July 2009 and will be the applicable law as of 3 March 2011. The package consists of the following five legal acts:

Directive 2009/72/ EC concerning common rules for the internal market in electricity.Directive 2009/73/EC concerning common rules for the internal market in gas.Regulation (EC) 713/2009 establishing the Agency for the Cooperation of Energy Regulators (ACER).Regulation (EC) 714/2009 on conditions for access to the network for cross-border exchanges in electricity.Regulation (EC) 715/2009 on conditions for access to the network for cross-border exchanges in gas.

At the EU Energy Law & Policy Conference the Commission’s Inter-pretative Notes for the implementation of the Electricity Directive

2009/72/EC and the Gas Directive 2009/73/EC, adopted only a couple of days before the event (22 January 2010) were presented. They further qualify, among others, the provisions on maybe the most controversial part of the Third Energy Package - the effective unbundling of Transmission System Operators (TSOs).

There are three options for unbundling envisaged by the Third Energy Package: full ownership unbundling, Independent System Operator (ISO) or an Independent Transmission Operator (ITO).

Fig. 1: Location ACER

8

(ENTSOE) and gas (ENTSOG) through which all transmission system operators cooperate at Community level. ENTSOs shall be responsible for developing the network codes on the basis of the frame-work guidelines of ACER as mentioned above. These network codes may eventually become legally-binding rules through the comitology4 procedure . Another obligation of the ENTSOs is to adopt non-binding Community-wide ten-year network development plans every two years. Both organizations’ first plans are already prepared and available on their respective websites. Draft Legislation

The proposed Draft Regulation concerning measures to safe-guard the security of gas supply places the main emphasis on the role of the internal market (and its proper functioning) to ensure the security of gas supply. Still, one of the underlining principles of the pro-posal is to ensure that the right measures are taken by the authorities if a disruption occurs and the market is not able to solve it.

to planning, implementation, resources and international cooperation in the field of energy technology. It acknowledges further efforts have to be made in regard to the investments in cost-effective low carbon technologies and that public partnering of industry is the only credible way forward.

The Commission’s Action Plan for Energy Efficiency from 2006 consists of 85 measures and 6 priority areas to be implemented between 2007 and 2012. Although not legally binding, the heads of states and government at the Spring Council 2007 committed to a 20% reduction of energy consumption by 2020. Possible measures to reach this target include refurbishing buildings6, smart cities, energy saving in the utility sector and others. Given the proper rights, NRAs and the newly established ACER, will be in a very good position to promote energy savings in accordance with this Plan.

The European Economic Recovery Plan (EERP) and the Trans-European Energy Network (TEN-E) Guidelines provide for possibilities for energy projects to receive co-financing from the European Union. Under the EERP almost 4 billion euros have been devoted to three different energy sub-programmes: gas and electricity interconnections, offshore wind energy projects and carbon capture and storage technology. 43 major energy projects will benefit from this exceptional to the user-pays-principle funding have already been chosen. This is expected to significantly contribute to the econo-mic recovery in the EU, while increasing the security of energy supply

According to the Draft Member States shall be obliged to develop Preventive Action Plans, containing the measures needed to mitigate the risks of supply disruption, and Emergency Plans, containing the measures to be taken in case of a disruption. There are three levels of emergency: Early Warning level, Alert level and Emergency level. Yearly reports on the security of supply situation have to be sent by the Mem-ber States to the Commission.

Common standards for security of supply shall be established encom-passing the “N-1”rule (Even if the largest infrastructure fails, there is still sufficient capacity to supply total gas demand)5, reverse flows and gas supply to protected customers (i.e. all the households and if the Member States decide so, small and medium enterprises, hospitals and schools connected to a gas distribution network).

The Draft Regulation provides for solidarity between Member States, but only as combined with the principle of responsibility: a Member State may only ask for solidarity if it has taken adequate measures and lives up to the commonly acceptable level of preparedness itself. Thus, regional and Community level cooperation is encouraged, but measu-res are taken to avoid “free rides”.

The Draft Regulation is currently being scrutinized by the European Parliament and has inspired 614 amendments in 6 months. These are grouped in 18 proposals , already approved by the responsible Parlia-mentary Committee and likely to be put to a plenary vote in May this

year. If adopted by the Parliament, these amendments still have to be approved by the Council. Therefore, it remains to be seen whether history (the adoption of the Third Energy Package) will not repeat itself, bringing along a lengthy procedure and multiple compromises.

The European Commission has also adopted a Proposal for a Council Regulation concerning the notification to the Commission of investment projects into energy infrastructure within the European Community. The proposed legislation is supposed to increase the transparency on planned and ongoing investment projects, which will help to assess whether there is a risk of infrastructure gaps over the coming years.

Plans

The European Strategic Energy Technology (SET) Plan is a strategic plan to accelerate the development and deployment of cost-effective low carbon technologies. It comprises measures relating

Fig. 2: Günther Oettinger, European Commissioner responsible for EnergySource: http://ec.europa.eu/avservices/download/photo

Source: http://europa.eu/rapid/pressReleases

“ A well functioning internal energy market will provide the right investment signals and will bring clear benefits for electricity and gas consumers across the EU. The full and correct implementation of the energy rules has still not been achieved. This situation needs to change and the Commission will use all means available to make this happen. What is at stake is our ability to reach the goals set in the Europe 2020 Strategy through a secure, competitive and sustainable supply of energy to our economy and our society. “

9

Footnotes

1 Altogether 5 Director-Generals of the European Commission are involved in creating and implementing rules regarding the energy sector: DG Energy, DG Environ-ment, DG Competition, DG Climate Action and DG Research2 Public attention has been drawn to the issues related to climate change only recently. A name worth mentioning in that regard is Al Gore.3 The EU leaders also offered to increase the EU’s emissions reduction to 30%, on condition an international agreements is reached. This did not happen in Copenha-gen, but the EU believes Copenhagen was a first step to such a result.4 Comitology is a procedure for adoption and implementation of Community law. It involves delegating powers by the Council to the Commission to adopt usually technical norms related to the implementation of Regulations or Directives. The procedure ultimately results in no formal involvement of the general public, national parliaments or the European Parliament in the creation of these rules.5 EUROGAS’ opinion is that this rule is too basic and shall be further refined and placed in the context of a broader risk assessment process.6 By now over the period 2006-2008 a total of 812 000 homes have been refurbished. According to the Commission 270 000 per year is a plausible number.7 For comparison: Distrigas committed on 12 June 2007 for 65-70% return to the market, no contracts with large users for more than 5 years, no resale restrictions and others for a duration of four years.8 This regards indeed only the power market. Ambitions for carbon-neutral economy have to take into consideration the fact that 20% of the CO2 is produced by non-energy-related activities, such as agriculture.

by creating cross-border infrastructure. The TEN-E Call for Proposals is now open and until 30 April proposals can be submitted for co-financing of projects up to 50% of the feasibility studies costs and up to 10% of the construction costs. The expected rate of success is between 12 and 21 projects to be co-financed out of about 27-30 ap-plications.

Recent antitrust cases

The last antitrust cases in the follow up of the Sector Inquiry of 2007 have brought about the highest fines by now, relatively new developments on network foreclosure cases, as well as classic customer foreclosure cases.

The record fines (550 Million Euros each) were imposed on E.ON and GDF on 8 July 2009 in the case concerning the Mittel Europaische Gasleitung MEGAL for concerted practices and agreements and res-triction of competition for GDF as of 2000 when competition became possible in France, and for E.ON as of 1998 after the adoption of the new Electricity and Gas Act (competition was according to the Com-mission possible as of 1980) in Germany.

In a customer foreclosure case EDF proposed on 4 November 2009 commitments to be enforced after 1 January 2010, including among others a commitment for at least 60% each year and an average of 65% of its total contracted gas volumes to return to the market, commitments for no restrictions of resale, no new contracts for more than 5 years, etc. The commitments shall apply for 10 years, for as long as EDF has more than 40% market share7.

The network foreclosure cases (RWE, ENI, E.ON and GDF) have escalated to a point where the Commission required release of capacity even when the facility owner uses the capacity itself (the starting point being the essential facility doctrine according to which the facility owner is obliged to grant access to the facility under certain conditions).

RWE accepted on 18 March 2009 far reaching commitments to divest high-pressure transition network in Germany. GDF and E.ON have committed to immediate capacity releases and gradual reduction of

long-term capacity bookings on entry points to below 50% of capacity.

With some of these developments finalized and others still in the pipeline, a new Commission took its place. The Directorate – General responsible for Energy is now separated from the old DG Transport and Energy. The new Commissioner for Energy, towards whom the high expectations of the various stakeholders will directed for the following 5 years, is the German national Günther Oettinger.

EUROGAS expects from the new Commission to work on securing gas supplies to Europe. The organization has already welcomed the draft Regulation on Security of Supply and cooperated with the Commission in the preparatory work. Furthermore, EUROGAS urges the Com-mission to prioritize in regard to the investments in new infrastructure favoring security of supply and to work further for the achieving of a robust internal market. It calls for more support for research and development regarding gas and gas related technology.

EURELECTRIC is also of the opinion that a single electricity market is a part of all policy solutions. The organization believes that EU carbon-neutral power8 by 2050 is achievable with the following priorities for the new Commission: promotion of pan-European electricity market, ensuring a strong emission trading system and setting a longer term (2050) carbon targets and ensuring that the 2020 Renewables target can be met at reasonable costs.

It still remains to be seen how the adopted legislation will be trans-posed and implemented, whether the draft legislation will be adopted and if so, with what consensus, how much can the Commission’s plans achieve and whether DG Competition will keep up with the full speed of acting against the infringements of competition in the energy sector. One of the milestones will be the preparation of an EU Road map for Energy until 2050 that can be expected next year. All these develop-ments have already and will continue to shape the playing field and rules applicable to the energy industry. The industry has proven to be able to adopt to changes that have ultimately lead to a dramatically different picture than the one from 20 years ago. The question is how much more is to be changed and what the picture will look like in 20 and 40 years from now.

10

Smart power grids in combination with the efficient and flexible use of natural gas

René SnijderCurriculum board EBC

Volko de JongProgramme director EBC

Christoph BurgerCurriculum board EBC

A Russian - EU project committee to jointly support the introduction of smart grids and efficient use of natural gas as a flexible primary energy source, was proposed by the 1st group of 17 high potentials from the industry, that attended the 2009 EBC Fellowship program. They advocate that this is the best way to combine the various interests in east and west and form a strong basis to bridge cultural and business gaps in Europe.

The EBC Fellowship on Energy Programme (FEP) initiated by the European Business Congress (www.ebconline.com) brings together the industries of the OSCE countries under the presidency of Alexei Mil-ler CEO of Gazprom. The FEP is open for EBC members only and is executed by Energy Delta Institute in Groningen (EDI) in cooperation with the European School for Management and Technology in Berlin (ESMT).

The programme consists of 3 blocks of one week each, hosted by EBC members. In 2009 the programme was hosted by Gasunie in Groningen, Gazprom in Moscow and Wintershall in Berlin. The challenges of the energy sector in a rapidly changing business environ-ment, the cooperation in Europe and required transitional leadership are the core of the programme. The participants are encouraged to present their vision and debate with executives in the industry, experts from the academic world and representatives of governmental institutes.

The energy challenges

The mission for the future leaders is clear. A growing world population and emerging economies are in need of more energy. In the short run, this ever growing demand can only be met by fossil fuels which adds to global warming. Major investments are needed not only to secure sufficient and reliable energy supplies but also to make the supply sustainable in the long run. To manage this transition, new approaches (paradigm shifts) are needed in the energy industry and transitional leadership must be ready to take up the challenges ahead.

The financial crisis certainly makes financing of energy projects even more complicated. On top of that the goals, interest and culture of the different countries in Europe differ largely. The Anglo Saxon Energy Market model implemented in the European Member States is starting to show its limitations as the solution for security of supply. Russia’s prime interest is to increase energy efficiency and replace it’s old capital stock. Agreement on mutual interest in Europe is, to say the least, still far from obvious, even more than 20 years after the fall of the ‘Berlin Wall’.

CO2 reduction is globally accepted, yet “Copenhagen” has not delivered on global climate change measures and targets yet, thereby adding to the uncertainties on the energy transition process.

Fig. 1: Participants of the EBC Fellowship Programme

11

The Fellowship on Energy Programme

The participants were invited to create a personal and confidential career road map that was discussed with each of the participants. Over 17 hours of case work cumulated in joint proposals to Members of EBC on what EBC could promote as the next step forward to bridge differences in energy markets and energy policies in Europe.

The participants concluded that there is a paradigm shift on-going in the energy sector. The future energy supply will be a mix between new sustainable energy resources and traditional fossil fuels. The percentage of sustainable energy will most likely be moderate in the nearby future. There will be substantial need for flexible fossil fuels. In such a scenario natural gas is the fuel of choice.

There was a large consensus among participants that market players should be preparing themselves for new market conditions where sustainable energy, (wind, hydro, solar and bio fuels) will be growing. They agreed with the IEA forecast, that more than 80% of the energy mix will come from fossil fuels in the coming decade.

Of the fossil fuels, natural gas is best placed to serve as a ‘bridging’ fuel towards sustainability, due to its relatively low CO2 emissions and its high efficient use. But an additional reason to use natural gas is its flexibility which makes it a premium fuel. Gas is flexible in power generation, meeting peak gas demand and through storage, can balance summer / winter demand fluctuations. The liberalized liquid market facilitates the role of gas as efficient and flexible fuel.

However, the decline of natural gas in the North Sea basin will increase the need for the large natural gas resources from Russia. Russia on the other hand sees the demand security diminishing un-der the consequences of demand destruction due to the crisis and the emphasis of policy instruments on reduction on fossil fuels and more renewables. Also new gas sources, such as unconventional gas and LNG, make it harder to invest in new exploration and pipeline projects dedicated for the European market.

One area where all positive aspects of natural gas can be utilized is in the power sector in combination with smart grids. The increase of natural gas use mainly has to come from this sector, illustrating its role as transition fuel.

Advice to the EBC Board

Against this background, the participants came up with an interesting proposition for the EBC Board:

1) Create a joint EU-Russia working committee to integrate the use of smart grids and natural gas as a flexible energy source. Smart grids that incorporate the use of renewable energy and increase the overall energy efficiency should be the way forward as a common objective whereby the flexibility and environmental friendliness of gas is to play a pivotal role. This proposal creates sustainable soluti-ons and tackles the CO2 problem. The EU ambition to reduce CO2 is aligned with a practical implementation of the Russian policy to increase energy efficiency and invest in the relatively old Russian capital goods. EBC members and other market players would benefit from the technological and commercial spin off. The flexibility of gas is an asset that could increase the value in the energy business and could drive the transition. Natural gas will be efficiently used in many forms; as feed stock, base load, pure back up fuel but also more and more as the only fuel that can be used flexibly to meet the increased volatility in demand. To show stake-holders mutually the advantages of gas as transition fuel, smart grid projects in east and west demonstrating the efficient use of gas, could bring markets together and would enhance the acceptance of the stakeholders providing the conditions for the license to operate both in east and west. Funding smart grid/gas projects cross bor-ders would stimulate major investments in Russian natural gas in combination with investments in sustainable energy. The partici-pants promote that this will finally result in a clear vision of Europe as a whole and could be the core of a new European Energy Treaty.

2) Strengthen the EBC FEP initiative. Better and intense cooperation between management in east and west is key for Europe’s energy future. The EBC fellowship program is a way to create a cross border and intercultural community of young managers from EBC members in the industry over the 5 years the program is supposed to run. This community may help to improve the cooperation and decision making in Europe. The EBC is looking forward hosting the next group of ambitious young managers in 2010 to create a community of the next leaders in the energy industry, bridging East and West. The hope is that this will foster the stability and sustainability of energy supply in Europe.

“The very experienced lecturers opened our minds. We started to look outside our boxes and started to learn from and communicate with each other.”

Alexander Rogov, participantOAO Gazprom / Deputy Head of Division, Department of Marketing

“The solution is always in communication. The more we communicate with each other, the more we understand each other.”

Marc Pelletier, participantSchneider Electric / Country Manager

“This programme can contribute significantly to the EU-Russian dialogue”

Dilyara Sydykova, participantExxonMobil Russia Inc./ Public Affairs Manager

The three modules of the EBC Fellowship Program

Module 1: Energy Policy in Europe Groningen, hosted by Gasunie

Energy policy in Europe and how to balance between (1) security of supply and demand, (2) sustainability and (3)

affordability (market regulation) The energy market paradigm is shifting towards sustainability. What ‘license to operate” does the industry require from

its stakeholders? The difference in perspective of energy producing and consuming countries The personal leadership characteristics and communication skills which are needed to steer the energy sector in Europe

through the next decade. Module 2: Investment decisions of energy companies Moscow, hosted by Gazprom How do large energy companies make their investment decisions? What are the investment options in east and west under these changing market circumstances for utilities and energy

suppliers? The intercultural dimensions in executing energy project in the future energy business environment and how to manage

stakeholder expectations and perceptions. Module 3: New developments and future leadership Berlin, hosted by Wintershall New developments in the energy market, new energy sources and smart grids. Leadership requirements in dealing with market uncertainties, different business styles and cultures, determining the

success factors of European decision making. What will be the blue print for the next generation of energy supplies, big or small utilities, businesses or governments,

existing or new techniques?

Non-ETS Offset Schemes in Climate Policy

Wytze van der GaastJoint Implementation Network

Vlasis OikonomouJoint Implemenation Network

Eise SpijkerJoint Implementation Network

13

Under the Kyoto Protocol, European Union (EU) Member States (except Malta and Cyprus) have been assigned with a national amount of greenhouse gases (GHG) that they can emit during the period 2008-2012. Through the EU emissions trading scheme (ETS) part of these so-called assigned amounts have been further allocated to European installations in energy-intensive sectors. The ETS is a so-called cap-and-trade system which has been operational since 2005 and the European Commission (EC) has proposed (in January 2008) its continuation after 2012 with increasingly stricter emission budgets for installations. Installation can add to these allocated allowances emission reduction credits purchased through projects under the Kyoto mechanisms Clean Development Mechanism (CDM) and Joint Implementation ( JI).

However, it has been suggested by the European Council that after 2012, the scope for CDM and JI credit purchase within the ETS will become smaller. Consequently, more abatement efforts need to be made within the EU (EC, 2008a). The ETS covers slightly less than half of EU CO2 emissions. The management of the remaining part of Member States’ assigned amount is generally carried out by governments through carbon/energy taxation, subsidies, voluntary agreements, green/ white certificates, etc. Target sectors/groups are, e.g., built environment, decentralised green energy production, and transport.

Thus far, emission reduction activities within and outside the ETS have taken place separately. One possibility to combine the two is through Non-ETS offset projects, (alias domestic offset (DO) projects), which would reduce emissions of CO2-eq. in the non-ETS sectors and trade these as CO2 credits on the ETS market. This would enable installati-ons covered by the ETS to purchase CO2 credits from a domestic off-sets project and add these to the number of CO2 emission allowances that they must surrender to the European Commission by the end of each year (Flamos et al. 2010).

Figure 1: Biogas digesterhttp://www.gelderlander.nl

Domestic offset advantages

Linking DO projects with the ETS market would have a number of advantages: 1. DO projects stimulate development of low-carbon energy technologies within the EU and could unlock enormous amounts of CO2 savings in non-ETS sectors.2. DO projects create a price signal for fields where emissions are growing and increase the liquidity of the ETS by broadening the market.3. They broaden the scope for ETS installations to comply with their annual targets.4. The economic value of GHG credits reduces the need for government subsidies, e.g. feed-in tariffs, to support low-carbon energy technologies projects outside the ETS. This could also have the advantage that clean technology decisions are taken by the market and not by a government placing a subsidy. In the latter case, the subsidy could either underestimate what is needed for an economically viable project or overestimate this.

DO projects and the accounting modalities for calculating the CO2 emission reductions strongly resemble those for the CDM and JI. A key characteristic of CDM and JI projects is that GHG emission reductions are calculated as reduction below a pre-determined emis-sion reference scenario or ‘baseline’, which gives a reasonable estimate of the GHG emissions in the absence of a project. The DO, CDM and JI project mechanisms are therefore fundamentally different from the ETS where installations receive from their governments CO2 emission allowances and need to stay below this quota. A consequence of this difference is that DO projects will generally lead to higher transaction costs per tonne CO2-eq. emission reduction, as a high quality emission reduction credit requires a solid accounting procedure with validation of the project plan, verification of achieved emission reductions, and certification of these reductions as tradable credits.

Complicating factors

Although the EU ETS has been operational since 2005, Domestic Offsets as a concept has not yet been applied on a large scale by EU Member States; only in France, Spain, Austria, UK and Germany, interest in DO projects has been translated in some studies, pilot projects and programmes. It should be noted though that most of the new Member States of 2004 were already hosting JI projects under the Kyoto Protocol. After their accession to the EU, these countries saw their JI potential significantly reduced to only projects in non-ETS sectors. In other EU Member States JI was not considered an option, mainly because of the relatively high abatement costs (in comparison with options in Central and Eastern European and in developing countries). Also legally, the ETS only allows for purchase of JI and CDM credits, so that domestic offsets could only exist as European JI projects carried out under the Kyoto Protocol. A third reason is that the prices during the two phases of the ETS have been too low to create a strong incentive for projects within the EU in non-ETS sectors.

14

A further complicating factor is that DO projects, although facilitating emissions trading within the EU and supporting installations’ indivi-dual compliance efforts, does not directly help the host and investor Member States to comply with the Kyoto Protocol commitments. After all, as installations’ allowances are directly linked with Member States’

assigned amount under the Kyoto Protocol, each credit transfer based on a DO projects must be accompanied by an equivalent transfer of assigned amount from the project’s host country to the buying installation’s country (Betz et al. 2006).

DO in European energy and climate policy making

In the new EU energy and climate policy context, however, the EU has chosen for a longer time horizon (with 2020 as a mid-term milestone) with ambitious climate and energy policy targets (EC 2008 b,c). Within this post-2012 timeframe, DO projects could contribute to both climate and energy policies and be supportive to the roll out of new low-carbon technologies, which could create a dynamic effect towards the rest of the economy with accompanying additional CO2 emission reductions. Moreover, in the draft directive of the European Commission on the ETS implementation (EC 2008a), during its third phase of 2012-2020, linking emission reduction projects in non-ETS sectors (such as DO) with ETS trading has been explicitly mentioned as a possible instrument from which emission reduction credits could

be traded on the ETS market.In 2009, Arcadis and JI Network ( JIN) in the Netherlands conducted a study project on the scope or GHG reduction projects within the EU, but outside the ETS.1 The study was commissioned by the Nether-lands Ministry of Housing,Spatial Planning and Environment (VROM) and Energy Valley. The study focused on the potential of such DO projects in the Netherlands and explored in which sectors this project mechanism would be most suitable.

The Arcadis & JIN study was conducted in light of the EU and Dutch energy and climate targets for 2020, not only as a climate policy measure but also as a measure to support clean technology deployment and diffusion within the country. The study concluded that based on the energy conservation potential in the Netherlands, DO projects could successfully complement existing policies in the following sectors/project categories:1. Reduction of natural gas consumption in the built environment (government and commercial buildings and residential dwellings).2. Production of biogas and ‘green gas’ (in combination with related agricultural activities).3. Transport and mobility.

Subsequently, for each of these project categories positive and negative aspects of implementing non-ETS domestic offset projects were identified. These aspects are shown in Table 1.

Footnotes

1 Ebbekink, E., W. van der Gaast and E. Spijker, 2009, Domestic Offsets als aanvulling op het Nederlandse energie- en klimaatbeleid, Arcadis/JIN for further information, contact: Wytze van der Gaast, jin@jiqweb.org

Table 1: Positive and negative aspects of DO project application in promising DO sectors in the Netherlands

Books, reports and conferences

H.V., Rogers, March 2010, LNG Trade-flows in the Atlantic Basin: Trends and Discontinuities. Oxford Institute for Energy Studies

In this study Howard Rogers models the interactions between LNG and pipeline gas flows and prices in Europe North America and Asia. Since 2008 markets have moved from a ‘very tight world’ of competiti-on for LNG cargoes and prices around oil parity to a ‘very loose world’ of surplus and prices well below oil parity. The study concludes that the dynamics of future trade flows could imply a succession of these cycles rather than the achievement of a stable converged global gas system. This would suggest that price volatility could increase - and with it the opportunities for trading - which will have a significant impact on markets which continue to link gas prices to those of oil.

More information about this report is available on:http://www.oxfordenergy.org/pdfs/NG41.pdf

N., Ahner, J. M., Glachant, A., de Hauteclocque, March 2010 (RSC), Legal Feasibility of Schengen-like Agree-ments in European Energy Policy: The Cases of Nuclear Cooperation and Gas Security of Supply.

This paper assesses the Legal feasibility of short-run differentiation by means of partial international agreements inspired by the Schengen regime, namely entirely outside the EU framework. The key challenge from a legal point of view is to assess the substantive compatibility of such agreements in energy with the existing rules of the Union. Short run differentiation in energy cannot be assessed at a high level of gene-ralities. We therefore take two areas where legally-binding coordination at the sub-Union level is often called for: nuclear policy and gas security of supply. The possible substantive content of such cooperation is de-rived from the economic and political literature before legal feasibility is assessed. The findings suggest that the scope for such agreements is limited for security of gas supply whereas it could be an improved cooperation device in certain areas of nuclear policy.

If you are interested in the full report, please send an e-mail to: hoenders@energydelta.nl

C., Jones, J. M., Glachant, April 2010 (RSC), Towards a zero carbon energy policy in Europe: defining a feasible and viable solution.

Reducing the European Union GHG emissions by at least 80% by 2050 will require a near zero carbon electricity, road and rail transport indus-try, and heating and cooling in buildings. As compared to “business as usual” the amount of energy required will basically vary according to the level of energy efficiency: it is the “system scale”. Then it is the “sys-tem design” which will provide the needed carbon-free technologies consisting of renewable, nuclear and fossil fuels with carbon capture and storage. A zero carbon energy system by 2050 is then demonstrated to be feasible. However it is far from easy and requires immediate and substantial policy action. The main policy implications are addressed in this paper. The 5 years 2010-2015 will be decisive in establishing a regulatory environment whereby the EU will be in a position, by 2020, to take the next steps to achieve the 2050 goal.

More information about this paper is available at:http://cadmus.eui.eu/dspace/handle/1814/13539

Kinnander, E. January 2010. The Turkish - Iranian Gas Relationship. Oxford Institute for Energy Studies.

With proven natural gas reserves standing at 991.6 trillion cubic feet (Tcf), Iran holds the world’s second largest gas reserves after Russia1. Since the Islamic revolution in 1979, the production of gas in Iran has mainly been intended to meet the domestic demand2. However, at the end of 2001 Iran began to export gas to Turkey. Besides the Turkish desire to explore the Iranian gas market, the huge natural gas resources have also attracted international energy companies worldwide. Howe-ver, from the Iranian side the focus has mainly been on oil exports, and the Iranian gas market has been very difficult for international compa-nies. Policy makers in Iran have also been hard to cooperate with, and tough conditions have been imposed on any company seeking to invest in Iran´s natural gas fields. The most successful Iranian gas export trade in the post-revolutionary era has been between Iran and Turkey even though this relationship, which is the focus of this paper, has been far from successful.This paper intends to examine the bilateral natural gas trade between Turkey and Iran, through analyzing the commercial natural gas cooperation, but also their political relationship. The intention is also to present an analysis that could contribute to the broader picture of Iran as a potential gas supplier to the fourth corridor, i.e. the European market. Bilateral trade between Turkey and Iran reveals much about the commercial reliability of both parties. This is important because the political and commercial relationships between these two countries are of crucial importance for a possible future natural gas route from Iran to Europe. The paper is available at:http://www.oxfordenergy.org/pdfs/NG38.pdf.

Elkins, J., February 2010. Natural gas in the UK: An Industry in search of a Policy? Oxford Institute for Energy Studies.

Natural gas plays a central role in the UK (and the world) energy mar-ket in the first decade of the 21st century, but is facing the prospect of a decline in its importance as environmental factors combine to reduce the importance of natural gas and the other carbon-based fuels. Three questions need to be asked at this point: What is the UK’s energy policy? Where does natural gas sit within that policy? and, Is there a need for more central direction? There is no easy answer to any of these questions.

This report investigated these questions and comes to the following answers:

What is the UK?s energy policy? There is a carbon reduction policy, but it is not specific about the policy for individual fuels.

Where does natural gas sit within that policy? There is no clear answer. The assumption is that the role of gas will be to plug gaps and compensate for the lack of preferred generation fuels, but it is only an assumption.

Is there a need for more central direction? Almost certainly yes, both for overall energy planning and for gas, even if only in certain defined areas, such as supply security.

The paper is available at:http://www.oxfordenergy.org/pdfs/NG40.pdf.

15

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 ChiefProf. Catrinus J. JepmaPresident of Energy Delta Institute

EditorsLeo HoendersMarius PopescuSanne BückingSteven 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

Upcoming conferences

April 13-15: 10th annual global gas village SummitParis, FranceWebsite: http://www.energywise.nl/UGS/summit.html

April 18-21:16th International Conference and Exhibition on LNGOran, AlgeriaWebsite: http://www.lng16.org/

April 20-23:European Energy ConferenceBarcelona, SpainWebsite: http://www.e2c-2010.org/

May 19-21:The 10th anniversary Annual CIS Oil & Gas Summit, Russia, Ukraine, the Caspian and Central Asia.Paris, FranceWebsite:http://www.theenergyexchange.co.uk/3/13/articles/116.php

May 19-202nd Carbon Capture and StorageBerlin, GermanyWebsite: http://www.acius.net/wiki.aspx/Conferences/

June 3-4:Oil and Shale Developer, 5th AnnualTexas, USA Website: http://www.platts.com/ConferenceDetail.aspx?xmlpath=2010/pc023/index.xml

June 11th:Energy Security and its impacts on the international legal systemLondon, United KingdomWebsite: http://www.biicl.org/events/view/-/id/465/

June 21-24: Understanding LNG, terminals a critical link in LNG chainHouston, USAWebsite: http://www.gastechnology.org