EDI Quarterly Vol. 4 No. 4 Polish Gas Hub and Energy Transition

EDI Quarterly Volume 4, No. 4, January 2013

Editor’s Note

by Jacob Huber Welcome to the January edition of the EDI Quarterly!

This issue focuses on gas markets developments in Poland, with contributions from the Polish regulator, an anonymous interview

Q Contents EDI 2

Polish gas exchange - look into the future

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Anonymous Interview - The Polish Gas Hub

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Regional gas market modelling applied to analyse the effect of Polish gas infrastructure investment projects on regional trade

(with a distant market party close to several major stakeholders in the Polish gas market) and the Regional Centre for Energy Policy and Research. The EDIaal section includes contributions by our analysts, discussing the effect of energy transition topics on the conventional energy paradigm.

The themes of the next Quarterly include public acceptance of energy projects (EDIaal) and continue with the perspectives of additional stakeholders on gas market developments in Poland (EDI). Should any of our readers be interested in writing on either of these topics please contact us at the address below. We hope that you enjoy all of the informative contributions in this issue.

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EDIAAL 8

The effect of intermittent renewables on the energy markets

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Good for Business: The EED comes to Town

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Energy efficiency and energy markets

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Public acceptance: why does it frequently become a ‘show stopper’?

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Europe going all electric; what about gas?

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The effect of biogas production on the energy market

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Policy comparison of the EPBD recast impact on several EU Member States

General 31 EDI’s Programme Overview 2013 34

Conferences 2013

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Recent Publications

quarterly@energydelta.nl

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Polish gas exchange look into the future

Andrzej J. Nehrebecki Acting Head of Natural Gas Market Unit, Department for Promotion of Competition, The Energy Regulatory Office of Poland

The President of the Energy Regulatory Office (ERO) is taking steps towards liberalization of the Polish gas market, which at the moment is a single entity segment. The dominant position in recent years in the wholesale and retail gas markets was held by the PGNiG Capital Group1, and gas sales were completed only under bilateral contracts. Due to the lack of competition on the gas market all gas prices in Poland must be approved by the regulator. The market is highly concentrated and continues to be subject to full regulation which is an effect of historical conditioning2.

PolPX signed an agreement with the TSO defining the principles of cooperation between these entities with respect to the launch of the gas exchange.

For these reasons, in the context of the implementation of the Third Energy Package and with the aim of liberalization of the Polish gas market, the President of ERO in cooperation with other stakeholders, in particular with the Polish transmission system operator (TSO) GAZ-SYSTEM SA and Polish Power Exchange SA (PolPX), has taken several efforts to launch the natural gas market on the commodity exchange.

In addition, the new gaseous fuel tariffs approved by the President of the ERO on the 17th of December 2012 for PGNiG SA, the TSO, System Storage Operator and six main distribution system operators (DSO) from PGNiG Capital Group have been in force since January 1st, 2013.

The above-mentioned changes paved the way for launching a gas exchange. In addition, they should contribute to increasing transparency and competition on the Polish gas market.

Measures towards the effective liberalization of the Polish gas market.

The gas exchange

Acting on the basis of the Energy Policy of Poland until 2030, the President of the ERO has prepared a Roadmap for Gas Prices Release. For the time being the document is waiting for approval in the Ministry of Economy. In spite of this, the President of ERO has been working on implementation of the measures provided in the Roadmap in 2012.

These measures include: - launch of a liquid wholesale gas market (creating the proper conditions for prices release for commercial customers), - improvement of the gas supplier switching process, - insuring independence of the gas regulator, - increasing transparency of the wholesale gas market - development of gas infrastructure, - creating the conditions for prices release for small customers and household customers.

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The President of the ERO approved the new Transmission Network Code (TNC) prepared by the TSO on 24th July 20124 and this document came into force on January 1st, 2013. The new TNC introduces several significant changes and implements solutions set out in the Third Energy Package. The most important of these changes include: - changes to the methods of contracting transmission services; - introduction of a virtual gas trading point to the high methane natural gas system; - introduction of auction mechanisms enabling more efficient use of the available capacity; - guidelines for the functioning of the balancing services market; - creation of distribution zones in order to simplify the principles of the functioning of the transmission system and gas market5.

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In November 2012 the amended Regulation on Detailed Conditions of Gas System Operations6 came into force, defining natural gas trading at a virtual point (defined as a point of gaseous fuel delivery located inside the transmission system of unspecified physical location where the trade in gaseous fuel takes place).

On December 20th, 2012 the first entities have submitted orders to the gas exchange launched on the PolPX7. On this day only the Commodity Forward Instruments Market (CFIMg) was started. “As we expected, the market participants are very interested in gas trading on the exchange.

The price in the first transaction executed on the Commodity Forward Instruments Market was PLN 116.57 per MWh,” said the President of the Management Board of PolPX Mr. Ireneusz Łazor8. The gas spot market – Gas Day Ahead Market (DAMg) was launched on the last day of 2012.

Forward Instruments Gas Market (CFIMg) participants have the opportunity of trading monthly, quarterly and yearly BASE-type contracts. Trading takes place in deliveries of gas in the same amount in all hours of the delivery date. Continuous trading is scheduled from 8 a.m. to 2 p.m. on working days and the exchange price of each contract is expressed in PLN per MWh9.

Transactions on the exchange (with respect to the gas market) take place via intermediaries –brokerage houses and commodity brokerage houses10. These entities must be a members of PolPX and of the Exchange Clearing House operated by the Warsaw Commodity Clearing House (WCCH). Work is currently underway on legislative changes to facilitate direct access to the gas exchange for undertakings from gas sector. As long as the law (Energy Law, Act on Commodity Exchanges) is not changed, transactions on the gas market are only allowed through registered brokerage houses.

PGNiG Capital Group – Polskie Górnictwo Naftowe i Gazownictwo Capital Group comprises commercial law companies of production, trading and services profile. As of September 30th, 2012, the Group comprised PGNiG SA, as the parent undertaking, and 46 production and service companies (Source: http://www.pgnig.pl/pgnig/grupa_kapitalowa).

National Report 2012. The President of Energy Regulatory Office in Poland (July 2012).

Energy Policy of Poland until 2030 was prepared by the Ministry of Economy and adopted by the Council of Ministers on 10 November 2009.

Decision of the President of ERO of 24 July 2012 (DPK-4322-10(16)/2012/AK).

GAZ-SYSTEM SA: http://en.gaz-system.pl/centrum-prasowe/aktualnosci/informacja/artykul/201529/

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Figure 2. Average wholesale gas prices in EU gas markets - 2011 Figure 1. Information exchange model – gas market

Source: Progress In the EU Internal Gas Market. Transposition and the IEM Communication,

Source: PolPX SA

Madrid Forum, 2 October 2012.

Perspectives of the Polish gas market after gas exchange startup.

Regional perspectives of the Polish gas exchange

PGNiG SA has declared that 100 mcm of gas will be provided on the exchange on a quarterly basis. Therefore, trading volumes will not be very large for the moment. For this reason, there is a need for introduction of a legal obligation to sell part of natural gas volumes through the exchange market (so-called exchange obligation). Recent legislative proposals suggest exchange obligation at level of 30% (approximately 4,3 bcm on an annual basis with regard to PGNiG SA).

According to the President of the ERO an exchange obligation should be set at 70%, which will allow for effective release of the market. The gas volume sold on the gas exchange must correspond to the gas consumption of the industrial customers, the customer segment that would be released in the first place (hence the 70%)11. The Minister of State Treasury, Mr. Mikołaj Budzanowski also considers that 70% of the gas trading should take place on the gas exchange12. A larger volume of gas on the exchange will contribute towards improved liquidity of the market by increasing the number of possible transactions.

Market mechanisms used on a commodity gas exchange together with supervision of the Polish Financial Supervision Authority (PFSA) ensure that gas prices on the gas exchange reflect the level of balance between supply and demand without opportunities to use a monopoly position in the Polish gas market by the major entity. During the gas exchange opening ceremony the President of the ERO indicated that release of gas prices for the largest industrial customers could take place in the first quarter of 2013. One of the conditions to take this decision is gas trade (on PolPX) on the level of at least 1 bcm13. Target exemption from the obligation to submit tariffs for approval by the President of the ERO will allow gas companies to freely shape their price behavior based on market mechanisms.

The newly launched Polish gas exchange has both the opportunity and potential to become a regional gas hub determining gas prices in the entire Central East European (CEE) region.

In relation to the magnitude of the Polish gas market and the potential of its development this vision of the future of PolPX may be very attractive and useful to many entities in various sectors.

In addition, a large regional gas hub may contribute to a reduction in gas prices on regional markets and to an increase in security of gas supply in the region, in particular in relation with possible interruptions of gas supply from the East. The growing importance of the PolPX in the CEE region depends especially on the liquidity and volume of the market.

About the author

Andrzej Jarema Nehrebecki is the Acting Head of the Natural Gas Market Unit in the Department for Promotion of Competition in the Polish Regulatory Authority (The Energy Regulatory Office). He holds a Masters degree in International Relations focusing on European Integration from the Warsaw University. His coverage area is natural gas, energy and gas exchanges and European energy market integration. He also has professional experience in the fields of renewable energy and combined heat and power. In 2008 he completed an internship in the European Parliament as an MEP assistant.

6 The Regulation of the Minister of Economy of July 2, 2010, on detailed conditions of gas system operations (Dz. U. 2010, no 133, item 891).

7 PolPX is a part of the Warsaw Stock Exchange Group.

8 Polish Power Exchange SA: http://www.polpx.pl/pl/27/aktualnosci/306/od-dzis-polska-ma-gielde-gazu 9 Polish Power Exchange SA: http://www.polpx.pl/pl/27/aktualnosci/306/od-dzis-polska-ma-gielde-gazu 10 Currently on the exchange there are 3 brokerage houses: Dom Maklerski BOŚ SA, Noble Securities SA and TRIGON Dom Maklerski SA. 11 „Ruszyła giełda gazu”, euroinfrastruktura.pl , 20 December 2012 (http://www.euroinfrastructure.eu/finanse-i-prawo/ruszyla-gielda-gazu/).

12 „Giełda ruszyła, pierwszy gaz sprzedany po 116,57 zł za 1 MWh”, Wirtualny Nowy Przemysł, 20 December 2012 (http://gazownictwo.wnp.pl/gielda-ruszyla-pierwszy-gaz-sprzedany-po-116-57-zl-za-1-mwh,186403_1_0_0.html).

13 T. Furman Gaz już na giełdzie. Spadną ceny? Rzeczpospolita, 21 December 2012 (http://www.ekonomia24.pl/artykul/705493,963589-Gaz-juz-na-gieldzie--Spadna-ceny-.html?p=2).

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Anonymous Interview The Polish Gas Hub

Interview by: Jacob Huber, Santiago Katz Energy Analysts Energy Delta Institute

A distant market party close to several major stakeholders in the Polish gas market shares his opinions on the development of a national gas hub.

Q: Is the Polish Gas hub an initiative of the Polish National Regulatory Authority (NRA) or the European Commission?

A. The idea was basically Poland-based. The major sponsor of the idea was the NRA. As you are probably aware, the Polish government remains under pressure from European Commission, which claims that Poland has not fully implemented both the second and third directives into national legislation, and the most important point of commission’s claim is that Poland has not liberalized the sales part of the gas business. In the European Commission’s opinion full regulation of gas sales regardless of market segment, i.e. whether sales is done to big industrials, B2B (business to business) or B2C (business to consumer), stays in contradiction with third package.

Since late 2011 the Polish government has been working on a new legislative package for the energy industry. This new set of regulations was also meant to address issues regarding gas sales, but currently is already delayed by more than 12 months, because there was an attempt to allow the NRA to deregulate sales to the industrial and B2B segment once it sees that the market has achieved an appropriate level of competition. Therefore the regulator promoted the gas exchange, the gas market, and the virtual point because it strongly believes that this is the first step to create competition. Once it sees any signs of competition it will have the proof or evidence necessary to deregulate the sales part, beginning with industrial customers and moving to B2B.

Q: How do you see the role of the incumbent (PGNiG) in a Polish gas hub?

A In my opinion the market sees PGNiG not only as a market maker but as entity that provides basic liquidity to the market. You are probably aware that we have a problem of obligatory stock keeping in Poland and that is actually the legal solution that is effectively blocking the market from any big entities that would be willing to enter the market as resellers. Actually, there is an exemption for individual customers importing gas for their own usage and for the supply companies importing up to 100 million m3 per year, so we are talking more or less 1 TWh of sales, comparing to PGNIG sales volume, which is about 150 TWh/year.

Q. What about the amount of gas to be released in a release program? We have seen differing opinions on 30%, or 70%, what is going on with gas release and what amount do you consider to be equitable and fair?

A. Ok, the discussion about the gas release program has actually ended.

I would say the gas release program as in it’s pure version is off the table right now. What is being discussed right now is something similar to what has been introduced in the power market in 2010. In the power market there is an legal obligation imposed on every power producer to sell a minimum of 15% of its production via the exchange. What is being discussed right now is the establishment of some similar regulation towards gas importers and domestic gas producers.

Right now the 30% level is being discussed - so we are taking about 45/50 TWh of gas sales via an exchange. And I am talking about sales – i.e. any company that will fall under this regulation has to effectively sell on the exchange, not just offer.

This regulation could have a positive effect in terms of market development and competition growth. But as long as gas sales business is regulated we won’t see much development in the polish gas market and PGNiG will do some intra-group trading via an exchange just to fulfill new legal obligations.

Q. Is the regulator effectively able to monitor spot trading for market abuse in accordance with REMIT, for example? Is the feeling in Poland that the regulator is ready infra-structurally?

A. My personal opinion is that the NRA is completely unable to do it and has no experience in this area, as it has never done it before. The NRA is trying to monitor the electricity market and has a number of lawsuits against some power companies but is effectively losing them in the courts, so I would say from the perspective of REMIT regulation and directives (editor’s note: Market Abuse Directive) and its knowledge about the gas market there are simply not enough effective mechanisms and people in place to monitor the market right now.

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Regional gas market modelling applied to analyse the effect of Polish gas infrastructure investment projects on regional trade The aim of this study is to estimate the impacts of planned Polish gas infrastructure investments on regional gas trade and wholesale gas market prices. We also examine whether the price convergence could lead to the growth of market integration, and whether regional commerce could grant Poland the central role of gas trading. During the analysis we apply the Danube Region Gas Market Model of REKK1 to compare the market outcomes for the countries of the region before and after new infrastructure is added.

Methodology

The Danube Region Gas Market Model2 has been developed by REKK to simulate the operation of an international wholesale natural gas market in the Central and South-East European (CSEE)3 region. Given the input data (consumption, production, capacities of infrastructure, TOP contracts and assumptions on the prices of external countries), the model calculates a dynamic competitive market equilibrium, subject to constraints represented by the physical gas infrastructure and contractual arrangements specific to the region. Of the model outputs in this study we use marginal wholesale prices and social welfare indicators. It is important to mention that we are not able to assess the gas hub role with the help of typically used commercial indices (such as churn rate) as our model outputs do not reveal how many times gas changed hands before equilibrium develops.

To analyse the market integration effect of the examined new infrastructure, we created and ran a reference scenario for 2011. Next we add, first one by one, then together, the examined projects to the reference case infrastructure ceteris paribus and compare model outcomes to the reference case. The table below contains the investigated pipeline and LNG projects.

The new interconnectors and the LNG station that we analyse are the following: Interconnectors

Maximum flow (mcm/day)

CZ-PL 8.22

Adrienn Selei, Borbála Tóth Regional Centre for Energy Policy Research

In the case of LNG we analyse the effect of different LNG prices. We assumed three different prices: equal to TTF spot price (low LNG), Italian spot price (medium LNG), and 5% lower than the Russian import price (high LNG). We also examined what happens if we allow virtual reverse flow (backhaul) transactions on the Yamal transit pipeline.

Market integration analysis

We evaluate individual projects and project packages according to the Regional Cost Convergence Index (RCCI) which measures the excess gas purchase cost (in per cent) the Danube Region pays for its gas consumption compared to the case when it purchased the same amount at a continental spot price (TTF price according to our assumption). The value of this excess cost for the 2011 reference scenario, as measured by the RCCI, is 21.22%. Table 2 contains the results of our simulations.

Base case

Backhaul allowed

Table 2: Results of the market integration analysis

These results clearly indicate that, without any further infrastructural investment, the excess price for the region can be lowered from 21.22% to 17.58% by allowing backhaul trade on the Yamal pipeline. To put it another way, the total consumer expenditure of the region is 670 million Euros/year less, if backhaul transactions are allowed.

PL-CZ 8.22 PL-SK 13.70 LNG

Capacity (mcm/day)

LNG-PL 13.7 Table 1: Analysed new infrastructure

1 REKK, the Regional Centre for Energy Policy Research (REKK) was founded in January 2004 at the Corvinus University of Budapest (www.rekk.eu). Its founders and staff includes former regulators, university teachers, full-time and part-time research fellows and postgraduate scholarship students.

2 For a first description and application of REKK’s Regional Gas Market Model see Kaderjak, P., (et al.) (2012) The Danube Region Gas Market Model And Its Application To Identifying Natural Gas Infrastructure Priorities For The Region REKK Working Paper www.rekk.eu 3 The modelled countries are: Albania Austria, Bosnia and Herzegovina, Bulgaria, Czech Republic, Croatia, FYR of Macedonia, Greece, Hungary, Moldova, Montenegro, Poland, Romania, Serbia, Slovakia and Slovenia.

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When projects are added to the model not individually, but in packages, the results depend on the price of LNG: the cheaper LNG is, the better the results are. Assuming that no backhaul is allowed and LNG can enter Poland on a medium high price, then thanks to the new interconnections to the Czech Republic and Slovakia, the regional effect would even reach Slovenia4, as described by the map below:

Chart 1: Model results of allowing backhaul trade on the Yamal pipeline The boxes on the map represent the marginal (yearly average) wholesale gas price of the countries(â‚Ź/MWh), calculated by our model. Grey boxes are exogenous market prices. Arrows show the gas flows, their size indicating the amount transmitted. Grey arrows are congested; bold arrows imply that they ought to be five times larger. The green countries experience a drop of marginal gas price compared to the reference case; the red coloured countries experience marginal price increase.

Chart 2: Model results (â‚Ź/MWh) of infrastructure investment (CZ-PL, SK-PL and medium high priced LNG) New infrastructure is depicted by arrows in a circle.

This means that policy makers/investors must consider the possibility of backhaul before they make any investment decision as the ranking of pipelines changes significantly depending on this regulatory decision. If backhaul transactions are allowed, not even LNG with the lowest price would be used: in our model no gas would enter Poland from LNG sources economically. The best project in this case would be the Polish Slovakian interconnector, that would even be congested to the benefit of Slovakian consumers, reducing their wholesale natural (marginal) gas price from 28.5 Euro/MWh to 25.5 Euro/MWh. If backhaul transactions on Yamal are not allowed, than the same pipeline would not be used and no gas would flow.

Regional social welfare analysis

By completing this project package (CZ-PL, SK-PL, and medium high price LNG) the excess price for the region can be lowered from 21.22% to 19.37% due to a significant drop in wholesale prices in Poland, Austria, Slovakia and Slovenia.

Net consumer surplus change

The result for the Czech Polish interconnector seems to be similar according to our RCCI index - independent from backhaul transaction possibilities, but the direction of gas flow is different. If backhaul is allowed, than the pipeline is congested and gas flows to the (more expensive) Czech Republic and when backhaul is not allowed, gas flows from the cheaper Czech Republic to the more expensive Poland.

Producer surplus change (incl.

LNG)

Storage operation profit change

Net profit change from long-term contracts

TSO auction revenues change

Total social welfare change

Table 3: Changes in welfare measures due to a package consisting of CZ-PL and PL-SK interconnectors, and medium LNG project (million â‚Ź)

4 Note: the DDRGMM model assumes that the domestic pipeline development - that enables new interconnectors to be used - is built.

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As can be seen in Table 3, by adding the project package with a medium LNG price to the 2011 reference case, we can identify ten countries where the new infrastructure projects generate a measurable change in social welfare. Aggregate welfare improvement is up to €1093 million annually, from which Poland and the Czech Republic are significant beneficiaries, while none of the countries suffer sizeable welfare losses.

With regard to market players, producers and consumers are the beneficiaries of the projects while, on aggregate, TOP contract holders take the losses. The growth of producers’ surplus in Poland is due to the realized profit from LNG (€959 million), while producers suffer welfare losses of up to €112 million because of the decrease of prices in the region.

References Kaderjak, P. (ed) (2011a), Security of energy supply in Central and South-East Europe, pp 121-147. Corvinus University of Budapest, REKK. Kaderjak, P., Kiss A., Paizs, L., Selei, A., Szolnoki, P., Tóth, B. (2012) The Danube Region Gas Market Model And Its Application To Identifying Natural Gas Infrastructure Priorities For The Region REKK Working Paper www.rekk.eu

We also analysed welfare effects by project. Our results show that there is no significant effect in the case of the Polish-Slovakian interconnector which is in line with our previous finding according to which this project has no effect on price convergence. The construction of the Czech-Polish interconnector has an overall negative welfare effect (about €479 million).

This is because even though it increases regional net consumer surplus (in line with the reduction of RCCI) this benefit cannot compensate the larger loss of producers and TOP contract holders. Therefore, the overall welfare growth due to the establishment of the analysed project package shown in Table 3 can be assigned to the construction of the LNG terminal (with medium price assumption) whose welfare effects are very similar to the effects shown in Table 3.

The limits of modelling

We have to note that the model lacks a sensible representation of the pricing behaviour of the EU’s external suppliers. In its present form, the pricing of external markets to supply the Danube Region is static: a static mix of oil product price and spot price indexation by Russia, related pricing by Turkey, spot pricing by Germany, Italy and LNG. Therefore the added value of new sources entering Poland (LNG) and the effect of reducing dependence on a single gas source is not considered. We also have to note that the modelled backhaul trade transaction benefits are only possible as long as the TOP contract with Gazprom remain intact.

With reduced ACQ (annual contract quantity) backhaul trade would diminish.

Conclusion

The most important lesson learned from the modelling exercise is that regulatory barriers to trade cost a lot to consumers. By allowing backhaul trade, the gas bill for the Danube Region could be reduced by 670 million Euros yearly. In this case the construction of an LNG terminal does not seem to be economically viable even if its price is equal to the TTF spot price. However, when regulatory intervention regarding backhaul transactions is not possible or is hindered, the building of interconnections and especially the entry of new sources (LNG) can have substantial regional effects as well. The analysis of social welfare (with no backhaul transaction allowed) shows that infrastructural investments – most significantly the LNG terminal – and connecting markets increases the total social welfare of the region by 1 billion Euros/year. Poland and the Czech Republic are the main beneficiaries; however, the benefits enjoyed by consumers are only a third of this amount (380 million Euros) and half as much as in the case of backhaul trade.

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EDIAAL The effect of intermittent renewables on the energy markets

Niels Rop Energy Analyst Energy Delta Institute

Several European countries have seen a strong surge in renewable energy supply – specifically from wind and sun. This development has occurred in countries with clear governmental support for renewable energy like Denmark, Germany, Spain and the UK, and other countries are expected to follow. This trend is expected to continue and may have a significant effect on European energy markets, both natural gas and electricity.

First, this paper will discuss the price effect renewables have on spot prices for electricity. This is a well documented effect that can partially compensate the costs of renewable energy support policies for consumers. Second, the effect of this price suppression on future investment decisions will be discussed. A lower average price for electricity will likely result in investors being less willing to invest in new capacity when necessary, or may cause them to choose flexible gas-fired capacity because of its less capital-intensive nature. In turn, this may result in upward pressure on future electricity prices. Closely related to this is the debate about capacity markets, the basic principles of which will be discussed along with their effect on price development The second part of this article focuses on the effect of these developments on the natural gas market. Gas-fired power plants are the first to suffer with increasing shares of renewable energy generation because of their higher place in the merit order. This will hurt the demand for natural gas from the power sector, although this demand reduction will be relatively small compared to the total market demand for natural gas. If more gas-fired capacity is added to replace retired coalfired capacity or compensate for increased demand, demand for natural gas for power generation may increase. However, this demand is increasingly dependent on changes in weather and weather-related electricity production and will require additional flexibility in the natural gas system.

Spot price suppression by renewable energy production

Renewable energy production may have a large effect on spot prices for electricity, especially at moments of high renewable energy production.

When renewable energy is produced, it takes precedence in the market both because of regulation and its near-zero marginal costs and has the effect of a reduction in residual demand. As electricity demand is almost inelastic in the short-term perspective of a day-ahead market, this shifts the merit order in such a way that a cheaper power plant becomes the price setter and the wholesale power price is reduced. Since this effect shifts market prices along the merit order of power plants this effect is called the merit order effect.

Figure 1: The merit order effect on wholesale market prices1

This price suppression effect of renewables has been proven from both theoretical evidence and simulation studies2 while different studies have attempted to quantify the effect for specific markets. For instance, results for the German market indicate a reduction of the average market price by 7.83 â‚Ź/MWh in 2006, resulting in a merit order effect of about 4.98 billion euro, offsetting most of the costs from financing FiT-schemes that year.3 A similar study performed in Spain comparing the simulated merit order effect due to wind with its financial support calculated savings for consumers of more than two billion Euros between 2005 and 2007.4 Another study examining Spanish prices between 2005 and 2009 reported a marginal increase of 1 GWh of renewable electricity production yielding a 4% decline in electricity prices.5 The merit order effect also has a downside, in this case for the power producer. Due to lower average power prices, power producers receive a lower price for their product and run their plants at lower capacity factors. As a result, the profits of the majority of the utilities diminish6 and these trends will obviously impact future investment decisions.

Future investment decisions

Because of an expected growing demand for electricity and retirement of old power plants driven by economics, technical issues or regulation, there will be a need to invest in new capacity. From a system’s point of view this new capacity should be flexible so that the varying supply of renewable electricity can be balanced and grid stability and security of supply ensured.7 It is also of importance that enough new capacity is built to prevent blackouts when peak demand coincides with low renewable energy production.

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This mix of conventional capacity with higher levels of renewable generation is likely to be different from the mix which would be required without investment in renewable energy. In particular, a higher proportion of conventional plants can be expected to operate at relatively low load factors, since these will be only needed to meet demand at times when renewable energy production is below average. Plants with relatively low capital costs will therefore be favoured over those with low operating costs, compared to a mix associated with low levels of renewables output.8 Decisions to invest (or not) in new capacity are not made based on the technical needs of the system (adequate backup) but on the long-term economic viability of the new power plant and it is not evident that investments necessary to reach an optimal generation stack will materialize without support measures. Investment decisions are plagued with uncertainty due to high but uncertain potential price spikes, depressed average prices and uncertain future regulation. Especially in the case of ‘super peaking’ plants, where the financial feasibility is based on a few short price spikes to cover all costs, it will be difficult to provide a good business case for future investments. These plants will also suffer from load factor risks, as it is possible that their services might not be required at all during a ‘high wind’ year.9 If the current ‘energy only’ market is maintained (with no mechanism to account for capacity) this might result in extreme price peaks, which are necessary to make peaking plants profitable. To prevent such price peaks, capacity markets or similar measures to guarantee available capacity can be introduced to provide incentives for power producers to invest in new capacity or keep old capacity online. However, they may harm proper functioning of the market and there is ongoing debate whether such measures are necessary and desirable.

Future price development

Future price development is highly dependent on whether capacity markets will be introduced in (part of) the Northwest European market.

If no capacity measures are implemented, the mix off generation capacity will be purely based on the economics of the sale of electricity. Changes in conventional capacity needed to balance the system and provide sufficient security of supply will have an upward effect on electricity prices as more expensive generation capacity will be needed earlier in the merit order. The intermittent nature of renewable electricity production means an increase in the level and volatility of peak prices, combined with an increase in the number of hours in which residual demand is so low (relative to the output from “must-run” plants) that some of these must be constrained off the system and prices become negative.10 Especially at moments of peak demand, the limited availability of capacity can cause high price peaks. These price spikes are necessary to provide for the economic viability of peaking plants and serve an important role in the system in the absence of capacity markets.

If capacity markets are implemented it is likely that more peak capacity will be available, meaning that price peaks will be less frequent and less extreme. Price peaks would no longer be necessary as peaking power plants would receive steady income from capacity payments and price peaks as a mechanism to ensure adequate supply would then be redundant. This does not necessarily imply lower consumer prices, as a surcharge would be required to fund capacity payments. Whether the capacity market has a positive or negative effect on consumer prices is mostly dependent on the adequacy of the scheme and a correct capacity valuation by the regulator.

The effect on the natural gas market

Although renewable electricity production has its greatest impact on electricity markets, its increasing presence is also felt in the gas market.

The effects of increasing shares of renewable energy supply on the natural gas market are twofold: On a technical level, increasing shares of renewable energy supply and additional natural gas-fired power generation will require additional flexibility in the natural gas system. The demand for natural gas from the power sector will become more erratic and unpredictable as the power sector responds to changes in power production from intermittent renewable energy supply. Different flexibility requirements of the gas supply can be identified: • Short-term flexibility to deal with short-term variations in renewable energy supply. As gas-fired power production varies with renewable energy production, so will natural gas demand on an hourly and daily basis, putting additional strain on line pack and short-term storage in the natural gas system.

• Seasonal flexibility to compensate seasonal patterns in renewable energy supply. During a cold winter there may be less wind than normal, requiring a larger contribution from gas-fired power generation. This, combined with a higher demand for heating, will require additional flexibility from seasonal storage.

• Year-to-year flexibility to deal with variation in renewable energy supply. The total annual wind supply can vary by as much as 10-20% from year to year. If gas-fired power is used to fill up this gap, uncertainty in Northwest European gas demand on the order of 5-10 BCM may be introduced by 2020.11 So far the gas market has been able to deliver required flexibility – although there may be a need for more storage facilities in specific parts of Northwest Europe. Great Britain, for instance, may need so-called ‘fast storage’ that could respond on much shorter timescales, because of an expected high share of wind energy and limited indigenous storage capacity and import flexibility. Such additional capacity seems, however, relatively small and will not be required until the end of the decade.12 This underscores the notion that storage capacity is currently of an adequate level, but that there will be a larger need for short-term flexibility in the future.

On an economic level, the effect on gas prices will be hard to detect as the share of gas used for power generation will be small compared to the share of gas used for heating and other purposes. The demand of gas for heating strongly depends on outside temperatures, meaning that the effects of a cold winter will dwarf any effect renewables might have on natural gas demand and price.

Even though price effects can be hard to detect, renewable energy supply will have an impact on natural gas markets. Assuming renewable energy supply primarily displaces natural gas-fired generation and the generation stack remains the same, natural gas demand will be lower. The magnitude of price reduction will vary based on a number of factors, including: the relative share of gas used for power generation in the gas market; the degree of natural gas displacement with increased renewable energy deployment; and the possibilities of withholding supply. This reduction is likely to be more significant in the near term than in the longer term.13 In the longer term this effect on prices may be counteracted by generation stacks adapting to the need for flexible backup capacity with investments in additional gas-fired capacity. As this will mostly replace coal-fired capacity, the total demand for natural gas in the electricity sector will rise again.

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Additionally, an increase in volatility of gas demand will affect the volatility of spot prices. As gas demand becomes more dependent on the lack of renewable power, so too will spot prices for gas. This means that gas prices will be relatively high as wind and solar power production is low and vice versa. Such price differences may provide the required economics for the development of more flexible gas storage capacity.

Conclusion

Increasing shares of renewable energy supply will have profound effects on the electricity and, to a lesser extent, natural gas markets. In the short term, renewable energy supply can depress wholesale prices by reducing the average demand for conventional generation. However, it will also introduce more price volatility and higher requirements for flexibility in supply.

Changing price patterns can have a big influence on future investment decisions. Without regulatory interference, this will likely mean less investment in new capacity and more frequent and higher price peaks.

There are measures available to ensure adequate investment in new capacity and prevent extreme price peaks, but the desirability of such measures is currently being debated.

In the longer term, electricity wholesale prices will return to the level needed to compensate the appropriate mix of capacity for the expected pattern of demand. The long-run average price will hardly react to the amount of renewable generation and the price suppression effect of renewable energy will thus be lower over the longer term. Unfortunately, the costs of the support schemes for renewables will, in most cases, remain for twenty years or longer, meaning that the consumer electricity price will likely rise over time due to the support for renewable energy.

For the natural gas business, the increase in renewable energy supply will mean a lower demand for natural gas from the power generation sector in the short term. However, the increase in renewable energy capacity can amplify its flexibility in responding to fluctuating (residual) demand and being profitable with less running hours. This may become a key strength in future investment decisions, especially when some form of capacity valuation is present in the electricity system. This increase in natural gas-fired generation will increase demand, but also flexibility in demand, for natural gas over time.

1 Moreno, Blanca; López, Ana J.; García-Álvarez, María Teresa (2012). “The Electricity prices in the European Union. The role of renewable energies and regulatory electric market reforms”. Energy, In Press.

2 C. Fischer, 2006, How can renewable portfolio standards lower electricity prices? RFF, Discussion Paper 06-20. – Sensfuss, Frank; Ragwitz, Mario (2008). “The merit-order effect: A detailed analysis of the price effect of renewable electricity generation on spot market prices in Germany”. Energy Policy 36 (8): 3076–3084. – P. Linares, F.J. Santos, M. Ventosa, 2008, Coordination of carbon reduction and renewable energy support policies, Climate Policy, 8, 377-394.

3 Sensfuss, Frank; Ragwitz, Mario (2008). “The merit-order effect: A detailed analysis of the price effect of renewable electricity generation on spot market prices in Germany”. Energy Policy 36 (8): 3076– 3084.

4 Sáenz de Miera, Gonzalo; del Río González, Pablo; Vizcaíno, Ignacio (2008). “Analysing the impact of renewable electricity support schemes on power prices: The case of wind electricity in Spain”. Energy Policy (36): 3345–3359.

5 L. Gelabert, X. Labandeira and P. Linares, 2011, Renewable Energy and Electricity Prices in Spain, Economics for Energy, Working Paper WP01/2011 6 Traber, T.; Kemfert, C. (2009). “Impacts of the German support for renewable energy on electricity prices, emissions, and firms”. The Energy Journal 30 (3): 155–178.

7 Rogers, Howard (2011). “The impact of import dependency and wind generation on UK gas demand and security of supply to 2025”. Oxford Institute for Energy Studies.

8 Green, Richard; Vasilakos, Nicholas (2011). “The long-term impact of wind power on electricity prices and generating capacity”. University of Birmingham, Department of Economics.

9 Steggals, Will; Gross, Robert; Heptonstall, Philip (2011). “Winds of change: How high wind penetrations will affect investment incentives in the GB electricity sector”. Energy Policy 39: 1389-1396.

10 Green, Richard; Vasilakos, Nicholas (2011). “The long-term impact of wind power on electricity prices and generating capacity”. University of Birmingham, Department of Economics.

11 Wind and Gas. Back-up or Back-out “That’s the question”. Nora Méray. Clingendael International Energy Program (CIEP). The Hague: CIEP, 2011 12 Pöyry (2010). “Gas: At the Centre of a Low Carbon Future”. Pöyry Management Consulting.

13 Wiser, Ryan; Bolinger, Mark (2007). “Can deployment of renewable energy put downward pressure on natural gas prices?”. Energy Policy 35 (1): 295-306.

10

EDIAAL Good for Business: The EED comes to Town

With the recent passing of the Energy Efficiency Directive (EED) comes real hope for the first time since 2009 – when the 2020 carbon reduction targets were first introduced - that something approaching a 20% improved energy efficiency figure as compared with 1990 levels can be reached. Though it remains to be seen just how vigorously this directive will be enacted into European state law – a process which begins in 2014 – it’s fair to assume that once fully operational the directive will reap large-scale benefits for both the environment and business.

Amongst a number of important energy-saving stipulations, the EED demands that 3% of energy-serviced floor space owned and occupied by central governments must be renovated each year to improve energy efficiency performance.

One of the most obvious advantages to this directive will be the lowered energy bills that will free up much needed capital for homeowners and business to spend elsewhere. With central governments now mandated to upgrade their building premises, another clear winner will be energy services companies (ESCOs) whose job it is to undertake such improvements.

Making the transition to better efficiency for homes and businesses will be made easier by the particular financing structure many ESCOs adopt.

Through this ESCOs take their fees from the savings made from reduced energy bills. Thus, gross energy expenditure remains at the same level typically for around 3 years after work has been concluded, during which time the ESCO is paid off, and after which spending can drop by as much as 40% Another boost from the EED will come through job growth. The directive should spur the creation of a lot of new jobs, many of which will be highly technical and well-paid. The French Ministry for Ecology, Energy, Sustainable Development and Spatial Planning estimates that for every €1 million of investment in property-related thermal renovation, 14.2 jobs are created or maintained in the field of energy performancerelated work. Applying these numbers to the estimated investment need of €60 billion per year would result in the creation or retention of around 850.000 jobs per year in the EU. And, job creation will not just be restricted to the ESCOs. As a complicated process, the retrofitting of building involves teams of architects, designers, component providers, financiers and lawyers.

Ed Butler Conference Manager ESCO 2013 (23-24 January 2013, Copenhagen)

Forecast growth in the market will also attract greater competition which should also benefit the end customer through improved service and competitive rates. The growth of the energy performance contracting (EPC) sector will not go unnoticed by many power utilities which have until now remained outside of this niche. For many years utility business models have been shifting towards the periphery, i.e. to value added services and away from core revenue streams of generation and distribution. Since a further stipulation of the EED has been that energy sales to customers must decrease cumulatively by 1.5% per annum, this move towards value added services will become more acute.

A greater utility presence in EPC is something that should be strongly welcomed and might ultimately prove just as great a boon to the industry as the EED itself. “A competitive market is much better than a regulated market, it is faster and cheaper,” Claus Fest of RWE Effizienz GmbH in Germany told a workshop organised by industry group Eurelectric. With greater competition will come innovation and ultimately improved services. However, some ESCO pundits caution the need for a complete separation between the energy supply and the demand side energy efficiency programs to allow companies to compete freely in Europe and not unfairly limit the competition to utilities.

There are some concerns over implementation of the EED, mainly arising out of the demands that will be made on cash-strapped governments to manage the costs of energy efficiency renovations.

Already hamstrung by existing financial commitments, governments will find themselves having to disappoint others if investment is to be made in EPC. Although many ESCOs adopt the system of putting up the initial capital expenditure to fund projects to then recover fees through energy savings, this model is not universal and the cost burden will still fall on the customer in some countries.

Criticism has also been leveled against the EED for not going far enough. Central-government owned property comprises a tiny fraction of the total European building stock. Although the EED puts into place the most credible plan seen in years for effectively improving energy efficiency, it is still only reckoned to attain an overall 17% net improvement on 1990 energy efficiency levels by 2020 – some 3% short of targets set. Nonetheless, passing the EED has been a big achievement for the EU, particularly in light of the political wrangling

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which has dogged the bill, and shows a determination to make good on previous EU climate commitments. Martin Lidegaard, Energy Minister for Denmark, whose government held presidency of the EU at the time of ratification, can claim much credit for shepherding this bill through.

“There have been tough negotiations,” commented Lidegaard. “It’s only 17% because that was possible to get. We fought like lions. We started at 13%, and now we have 17%, and that is actually something we are proud of ”. All in all, the EED marks a very positive step forward and will help to cement Europe’s place at the vanguard of global climate change.

Martin Lidegaard will be joining other senior stakeholders from policy, energy service companies, city municipalities and finance as a speaker at ESCO 2013, Europe’s most important building energy efficiency conference, taking place on 23-24 January 2013 in Copenhagen.

For more details, see the website: www.esco-europe.com

Public acceptance: From theory to practice Meeting one of the biggest challenges in the energy industry The purpose of this course is to familiarize participants with processes and driving mechanisms behind public acceptance and to provide them with tools for incorporating this knowledge when planning, initiating and implementing energy projects. The course integrates state of the art scientific knowledge and practical experience from industry and is supported by interactive discussions and exercises in order to ensure comprehensive and accurate insight into the topic.

During the 3-day course the participants will: - become familiar with the concept of public acceptance and its implications on the energy sector; - acquire knowledge of the factors influencing public acceptance; - develop skills in analysing and understanding public acceptance at all stages of project development and implementation, and integrate relevant knowledge in planning and decision making processes; - gain a broad overview of previous experiences and best practices with regard to public acceptance and engagement, enriched with insights from academic and practical perspectives; - gain a better understanding of the positions of various stakeholders involved in energy-related projects and services (regulators, consumers, energy producers) and be able to link that to public acceptance and engagement.

The next edition will take place 25 - 27 March 2013 in Groningen, the Netherlands.

For information please contact Thiska Portena, portena@energydelta.nl, http://www.energydelta.org/mainmenu/executive-education/specific-programmes/public-acceptance-course

12

EDIAAL Energy efficiency and energy markets

Jacob Huber Energy Analyst Energy Delta Institute

Energy efficiency (EE) is increasingly being driven to the front of the agenda and examined as a cost-effective way not only to decrease emissions, but also to achieve cost savings in many organizations and households and achieve policy objectives in government.

Indeed, world energy intensity, or total energy consumption per unit of GDP, decreased by 20.6% between 1980 and 2009. This does not tell the whole story as absolute energy consumption and CO2 emissions (from energy related activities) over the same period increased by 70.6% and 72.4% respectively, or 12.1% and 12% in per capita terms.1 In spite of steadily increasing efficiency efforts, worldwide energy demand is growing. However, drastic differences exist between countries and regions having important implications for energy markets.

Running counter to the overall trend of increasing energy consumption, many regions are experiencing decreases in per capita energy consumption and some are even experiencing decreases in absolute terms. In the United States (most significantly in California), for instance, strong and sustained EE efforts have resulted in decreased energy consumption per capita.2 In some regions total primary energy consumption (TPEC) is even decreasing: in Denmark, TPEC decreased 20% between 1996 and 2009 while the population grew by nearly 5% over the same period!3 As energy services reach levels of relative saturation and energy is used with increasing efficiency, not only does per capita energy consumption decrease, absolute energy consumption does as well. Three different stages of development toward absolute decreases in consumption can be identified4: 1. Increasing absolute and per capita energy consumption (China, Europe, World total) 2. Decreasing per capita energy consumption and increasing absolute consumption (US since 2001, Netherlands since 2005) 3. Decreasing per capita and absolute energy consumption (Germany, Denmark)5 There are various causes for changes in per capita energy consumption beyond EE; indeed, the financial crisis and resulting recession have played a role in recent decreases in energy consumption. Nevertheless, intentional improvements in EE have played a large and long term role

Figure 1: Trends in per capita energy consumption

reducing energy consumption in regions as diverse as California and Denmark. The contribution of EE will be discussed in this paper as well as the broad implications of decreased energy consumption for energy markets. In this context it is instructive to examine the effect of EE at the limit: What happens in markets where absolute energy consumption is decreasing? What is the effect on energy markets when less energy commodities are being consumed and which energy commodities are the most attractive in this context?

Before these questions can be answered, efficiency must be defined. In general an increase in efficiency implies a lower amount of energy input for a desired outcome (light, freight transport, etc). For the purposes of this paper, three of the most significant themes will be considering under the aegis of efficiency: efficiency measures in industry (i.e. CHP), buildings (i.e. insulation) and transportation (i.e. electrification)

1 EIA 2 Notably, significant differences exist among US states: California’s consumption was 209.6 million BTU per capita in 2010, while Wyoming consumed 948.1 million BTU per capita.

3 EIA, http://www.eia.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid=44&pid=44&aid=2 4 Of course, radical differences in magnitude of consumption are seen across regions 5 Part of the decline in absolute primary energy consumption can be attributed to negative population growth in the case of Germany, but the trend to lower levels of energy consumption predates the recent period of decreasing population

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Greater levels of efficiency in the industrial sector result in less energy input per unit of product output, for instance more steel or cement produced for the same amount of energy input. In the buildings sector, efficiency implies the reduction of energy input to provide a given energy service such as insulation to lower the amount of natural gas, heating oil or electricity input required to maintain a warm and comfortable building. The electrification of transport, along with the shift to less intensive modes of transport (i.e. public transport) and increasing efficiency standards implies less energy input per passenger/ kilometer or ton/kilometer transported. Demand response also has a context in terms of EE and can reduce primary energy consumption.

Peaking electricity generators tend to be those with the highest marginal costs, and are often those with the lowest efficiencies (among fossil fuel plants). If the runtime of these plants is decreased due to demand response (and more broadly from EE) less primary energy is required for electricity generation.

Trends

EE is one large trend affecting the evolution of energy demand and consumption. In general, it has a suppressing effect on the worldwide trend of absolute and per capita increases in primary energy consumption. At the limit, as energy services reach levels of relative saturation (as in some developed countries like Denmark, Switzerland, or Germany) efficiency can have the effect of lowering primary energy consumption both in absolute and per capita terms. Germany provides an instructive example as they have experienced an average annual decrease of 0.3% (0.4% when corrected for weather and stock effects) in TPEC between 1990 and 2010 in the face of average population growth of ~0.2% over the same period (RWE Effizienz, World Bank Statistics).

On a per capita basis primary energy demand has decreased at an average rate of 0.6% per year. Figure 2 indicates trends in final energy end use in Germany where GHD = services/commercial builds, haushalte = residential buildings, verkehr = transport and industrie = industry.

Although final energy consumption in services (-1.1% CAGR) and industry (-0.8%) has decreased, consumption grew in both transport and residential sectors at a higher rate than population growth (0.4% each). Significantly, growth in electricity consumption across the economy has averaged 0.7% annually (0.8% per capita in the residential sector), increasing in all sectors but agriculture. The trend is toward new uses for electricity and is more than compensated for by increases in efficiency. Indeed, increased efficiency (on the level of primary energy consumption) results in increased electricity consumption.

In German households increasing electrification is increasingly driven by a shift to heat pumps for heating; their share in new builds rose from ~1% in 2000 to 23.5% in 2010. Although not currently the most costeffective solution for single family houses in Germany, prices of heat pump systems are decreasing and heat pumps are already considered the most cost-effective solution for multifamily dwellings in the German market (RWE). Despite the fact that an increasing number of electric devices and appliances are being used in households the trend toward efficiency in these devices is more than compensating for this particular trend. Additionally, the great majority of houses built before 1978 are not renovated with only ~30% renovated significantly (RWE).

Renovations decreasing energy consumption at levels exceeding 70% are considered cost-effective in the German market and significant financial support is given for through renovations, thus significant additional potential exists to decrease consumption. Considering these facts as well as the future contribution of higher penetration of electric vehicles in the future, electricity demand is expected to continue increasing in Germany as well as across Europe, often in the face of decreasing primary energy demand (ECF Roadmap 2050).

Demand response can be considered EE in some cases and has a number of benefits beyond primary energy savings. These include: - Lower wholesale electricity prices - Lower aggregate system capacity requirements - Saved money for consumers from incentive payments - Better matching of supply and demand

Figure 3: Price effect of demand reduction (merit-order effect)

Lower wholesale price result from averting the use of power plants with higher marginal costs during peak periods via the merit-order effect displayed in Figure 3 above. Sustained DR efforts have also been cited with lowering aggregate system capacity requirements and allowing load-serving entities to purchase and/or build less generation capacity while increasing the utilization of existing assets. DR helps to better match supply and demand and helps to alleviate the fact that average cost rates do not reflect actual cost to supply power, which may result in inefficient investment in new generation, transmission and distribution infrastructure. As an increasing number of smart meters are installed and the ability and willingness of consumers to respond to time-of-use pricing increases, DR is likely to have an increasing effect on the electricity market.6

Figure 2: Final energy consumption in Germany, 1990-2010

6 USDOE 2006, Benefits of Demand Response in Electricity Markets and Recommendations for Achieving Them

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Besides DR, a number of benefits of general EE efforts have been noted:7 Reduction in capital costs resulting from deferred entry of new generation plants - Reduction in fuel costs from reduced use of coal and gas in electricity - Reduction in non-fuel variable operating costs - Reduction in costs from deferment of construction on interregional interconnections - Reduction in gas processing and transmission infrastructure costs These benefits are similar to those achieved by demand response activities and tend to result in lower levels of absolute energy consumption. In general, both EE and DR result in lower spot prices on electricity markets due to the utilization of generation resources with lower marginal costs. It is important to mention, however, that DR tends to be most useful for frequency and voltage regulation and responds on a short time scale to reduce or time shift consumption, while EE results in structurally lower energy consumption. On a broader level, efficiency has the effect of lowering wholesale energy prices due the fact that it decreases demand. This effect is more pronounced for fossil fuels, which are increasingly being replaced with electricity for heating and mobility and this situation is likely to have a price-increasing effect on electricity markets. Even in the case that the majority of electricity generated for transport or a heat pump is supplied by fossil fuel generation the superior tank-to-wheel efficiency of EVs and COPs in the range of 3-5 or more still imply lower total primary energy consumption, thus the shift to electricity.

Countering the effects of lower commodity prices is the rebound effect, or Jevon’s paradox. Also known as take-back, this effect assumes that consumers will “take-back� some of the predicted energy savings to realize higher levels of comfort. Those buying a more efficient car may drive more kilometers, or those who have insulated their house may turn the thermostat up. Although this is indeed a noteworthy phenomenon, most studies indicate that this effect does not exceed 30% overall.

Conclusion

The effect of increasing levels of EE on energy markets is difficult to state concretely but a few trends are evident: - Efficiency is encouraging energy carrier shift from fossil fuels to electricity - A shift from fossils fuels to electricity puts downward pressure on fossil fuel prices and investments and upward pressure on electricity prices and investments - In less developed countries EE dampens load growth, while markets at or near energy-service saturation experience declines in primary energy consumption As efficiency technologies become cheaper and EE policy more pervasive, the influence of EE is likely to only increase. In markets near energy-service saturation even population growth cannot be expected to drive increasing consumption of energy. In these markets utilities will not be unable to continuously pursue increasing sales to increase revenue and profit; they will have to look elsewhere for growth and evaluate new business models to find new sources of revenue. Offering a better level of service to their customers in order to extract more revenue per customer and encourage customers to switch to their service via differentiation from competitors may represent a step in the right direction. This strategy may provide particularly attractive as the residential sector (in Germany) is still expressing mildly increasing levels of consumption, while it appears that commercial buildings and industry pursue efficiency with more vigor. For more on the issues of energy services and business models, please see my upcoming article on business models for utilities.

7 Walter Gerardi, Albert Suyanto, July 2010 Electricity and Gas Market Benefits and Costs of an EE Obligation Scheme, http://www.climatechange.gov.au/publications/energy-efficiency/~/media/ submissions/pm-taskforce/electricity-gas-market-benefits-costs-energy-efficiency-obligation-scheme.ashx)

15

EDIAAL Public acceptance: why does it frequently become a ‘show stopper’?

One may call it ‘people power’, or ‘people against power,’ but in essence, the context stays the same - ordinary Europeans are on the verge of becoming experts in delaying or even stopping the introduction of new energy technologies and installations. In recent years, there have been numerous protests all over Europe against the construction of new underground gas storage facilities, power transmission lines, developments with regard to shale gas, but also regarding sustainable energy technologies such as wind turbines and carbon capture and storage (CCS). On a large scale people are forming activist groups, striking and even attempting to elect politicians who promise not to build anything. If that does not work, often with the help of local municipalities or environmental groups, citizens are using the courts to hinder planners and developers of new energy projects from their activities - doing everything possible to prevent intrusion into their living environment and comfort.

Yet, modern society has become dependent on technology and therefore the use of energy. Everybody wants to have light and a warm house, fresh food and access to social media and very few could now imagine their lives without computers or mobile phones.

However, it is essential to realize that energy, which is produced to power our lives, still mainly comes from fossil fuels (coal, oil and gas) and according to the International Energy Agency this dependence will remain in the coming decades, implying the continuing use of massive energy installations. Considering the impact of greenhouse gases produced from combustion of fossil fuels (for energy generation) on the climate, the EU has set various targets* for their reduction, implying (among other impacts) introduction and use of new energy technologies. Altogether this indicates that major investments in the energy sector need to be made in the coming years to satisfy demand for energy, while simultaneously reducing impacts on the environment and climate.

Strangely enough, the innovations and potential solutions for reaching the abovementioned targets are frequently faced with serious barriers to adoption, mainly public opposition. The question arises “why is this the case?”

This article represents an attempt to find an answer to this question, while analysing such issues as the general knowledge of people with regard to current energy and climate issues and the general attitude of people towards change.

Nadja Kogdenko Energy Analyst Energy Delta Institute

Inconvenient reality

When searching for the reasons why new energy projects are frequently opposed by the public, the first and probably the most fundamental one is the overall negative attitude of people towards building any type of installation in their living environment and general change in their lifestyle.

Several terms have been introduced to describe this phenomenon: NIMBY (Not In My Backyard), BANANA (Build Absolutely Nothing Anywhere Near Anyone) and CAVE-man (Citizens Against Virtually Everything).

While NIMBYs oppose a development as being inappropriate for resident’s local area, the latter two terms, particularly CAVE-man, oppose nearly everything, in other words any change (e.g. changes in public policy questions, public transportation routes, parking regulations, etc). Therefore, when people discover plans for installation of a new wind turbine in their neighbourhood (even though people may generally have a positive attitude towards renewable energy), there will certainly be someone demanding that this installation is moved somewhere else, far away from his territory.

The problem is there is no such place far away from everyone, especially in densely populated Europe. ‘Somewhere else’ will inevitably be near ‘someone else’ who will demand that the project go ‘somewhere else’.

This overall negative attitude towards change and particularly construction of new energy installations can partly be explained by the fact that currently there is (on average) little understanding among the lay public of where energy used in households comes from, together with a low awareness of climate change and environmental issues in general. In 2011, the European Commission performed a survey to understand the attitudes and behaviour of the EU citizens towards climate change and their expectations for the future.1 26,840 people were interviewed in 27 European countries, and the results of this survey showed that just over half (51%) of all respondents consider climate change a serious problem facing the world. What is even more interesting is that from these 51%, most respondents (about 80%) answered that tackling climate change is the responsibility of national governments, the EU and businesses, indicating a low level of public awareness of the link between energy consumption and climate change.1 Besides this, another interesting survey was conducted by the European Commission earlier in March 2011 on public awareness and acceptance of CO2 capture and storage.2 One of the questions in this survey was on public awareness of climate change and CO2, showing that half of the respondents (in total, around 13,000 individuals participated in this survey) were not aware what CO2 is. 50% of respondents were able to indicate correctly that it is carbon dioxide, however 11% indicated that it is a highly toxic gas and 7% stated that it is ‘explosive’.3

* 20-20-20 target (20% reduction of the EU’s greenhouse gas emissions by 2020, compared with 1990 levels; 20% increase in the share of renewable in the energy mix, and 20% improvement in energy efficiency) and even more ambitious goals stated in the EU Roadmap to reach the emission reduction of 80-95% by 2050.

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With regard to people’s understanding of the types and quantities of energy sources used for country-specific power generation, the research of McGowan in 2005 suggested that even though people might be aware of different kinds of energy sources (i.e. renewable energy, coal, gas, etc.), the in-depth understanding of them varies markedly among individuals.

The results of the aforementioned EC survey on public acceptance showed that in terms of electricity production, respondents in general had difficulty in assessing how much energy produced in their country was from coal and how much came from renewable energy sources,3 and this is without going in-depth on European energy import dependency.

Even though there is a generally positive attitude and growing support for renewable energy in Europe due to lack of awareness, understanding and perhaps interest, the majority of the lay public does not see the need for new energy technologies and projects, particularly in their neighbourhood. Bearing this in mind, how can the EU governments communicate to the local people the actual need for new energy technologies, such as wind turbines and CCS? Besides a lack of awareness, there is also an issue of trust. People generally don’t trust energy companies, local authorities and even governments, and in most cases there are reasons for this. Concerning the issue of climate change, it seems that at some level EU governments do not truly believe in it themselves. Even though European climate targets are being raised, there still is a lack of legal and financial incentives for reaching those in a given timeframe, leading to very slow progress and results. Several technologies, such as CCS, that are essential for reaching climate goals continue under regulatory uncertainty and the European Emission Trading Scheme, the EU’s key tool for reducing industrial greenhouse gas emissions cost-effectively, is widely criticized as being ineffective. The new Energy Outlook 2012 of the International Energy Agency (IEA) indicates that with the current path of development, the limitation of global warming to 2°C† is nearly unreachable. With all these uncertainties, what kind of impression is made on the local population with limited knowledge? Regarding energy companies that propagandize the environmental benefits of a massive new energy installation over other benefits/impacts, will the local population truly believe the motives of such companies? The research of Terwel et al. (2011)4 indicates that the answer to this question is “no”, and underlying motives of these companies will almost certainly be perceived as exclusively profit making. Terwel et al. argues that similar actions can cause suspicion of “greenwashing” in the public’s eyes, leading to public distrust in the entire organization rather than creating trust and reinforcing NIMBY, CAVE-man and BANANA phenomenon among the local population. Such factors as the type of information provided to the public, the source of this information, as well as individual values and attitudes contribute to the level of public trust in a certain technology and the entire organization, or even governmental actions. The research of Brunsting et al. (2011) on trustworthy information sources showed that research institutes, NGO’s, academics and family and friends were rated most trustworthy, while social network sites and industry were the least trusted information sources.

Considering the fact that most information reaches the lay public by the means of social media these days,3 the quality of already limited knowledge among the lay public on energy and climate issues can be deeply questioned.

The last, but not the least, reason that can be distinguished while searching for an answer to the question “why are new energy projects and technologies frequently faced with serious barriers to adoption?”, is the issue of compensation, or a frequently asked question “what is in it for me?” among the local population. In essence, the compensation issue is strongly interconnected with NIMBY phenomenon. The overall negative attitude of people towards building any type of installation in their living environment, together with the lack of trust, awareness and understanding of the current climate/energy issues frequently leads to a situation in which a new energy project is perceived by local communities as an intrusion into their property with a profit motive. In the view of the lay public, this leaves the local population only with unwilled consequences (e.g. visual pollution) while the energy company gets all the benefits and revenue. People might wonder ‘why should I sacrifice my comfort (note: still powered by energy!) to live and see this ugly installation every day or be in fear of potential health effects and concerned about property values?’ If people don’t see their benefit from a new technology/installation, their already ‘negative spirit’ might grow into irritation and anger, binding them together and provide motivation to organize opposition. This sort of situation can lead to the formation of a strong and growing public opposition, potentially becoming a ‘show stopper’ of the entire project.

Discussion and conclusions

As practice shows, several energy projects, such as the Barendrecht CCS project, construction of the largest underground gas storage facility in Europe (Bergermeer), general developments in energy sector (such as shale gas production in France and Bulgaria), and even renewable energy projects have been postponed or even cancelled due to strong public opposition. As analysis presented in this article shows, there are various interconnected reasons why public opposition can become a ‘show stopper’ for an entire project. To address this pressing issue, EU governments should take major steps to raise the generally low knowledge of energy and climate issues among the lay public and therefore increase their understanding of the need for new energy/ climate installations. Next to this, significant attention must be given to issues of trust and compensation. At the end of the day each and everyone of us wants to have a comfortable life with a warm and well-lit house in a clean environment. Therefore, mutual cooperation while reaching compromises is the key for the future success of energy and climate projects; after all, we all need energy!

1 2 3 4

EC (2011). Special Eurobarometer 372: Climate change. Available at: http://ec.europa.eu/public_opinion/archives/ebs/ebs_372_en.pdf EC (2011). Special Eurobarometer 364: Public awareness and acceptance of CO2 capture and storage. Available at http://ec.europa.eu/public_opinion/archives/ebs/ebs_364_en.pdf McGowan, F. and Sauter, R. (2005) Public Opinion on Energy Research: A Desk Study for the Research Councils. Sussex Energy Group, SPRU, University of Sussex.

Terwel, B.W., Harinck, F., Ellemers, N., et al. (2011). Going beyond the properties of CO2 capture and storage (CCS) technology: How trust in stakeholders affects public acceptance of CCS. International Journal of Greenhouse Gas Control, 5, 181-188. † The commonly accepted goal in science and policy making to prevent catastrophic climate change.

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EDIAAL Europe going all electric; what about gas?

One of the key questions with regard to Europe’s future energy system is the extent to which electrification will occur. According to some experts we both need to almost completely decarbonise the electricity sector and increase the share of electricity in total final energy consumption in order to meet far-reaching overall decarbonisation targets. What does this mean for the natural gas industry? And is an all-electric society bad for the gas industry by definition? In this paper, some projections of leading energy scenarios will be used to shed some light on these developments.

These scenarios contain a wealth of relevant data, as they describe energy system trends and the implications of climate change policy, but also implications of security of supply and affordability issues, among others.

Klaas Kwakkel Energy Analyst Energy Delta Institute

takes a closer look at projected energy demand, after which step two of the ‘trias energetica’ will be outlined, followed by a discussion of the role of natural gas in the energy mix, which fits with step 3 of the ‘trias energetica’.

Scenario selection

Appendix 1 lists the scenarios included in this paper. The scenarios selected meet the following criteria: they are well-known and discussed internationally, have a time horizon until at least 2035 and contain information on a European level.

Total primary energy demand

A common approach is represented by the ‘trias energetica’ when it comes to the decarbonisation of an energy system, shown in figure 1.

As the figure shows, the first step is to limit energy demand. This section

Figure 1: Trias Energetica

Figure 2 shows how total primary energy demand (TPED) in Europe is projected to evolve according to the selected scenarios. Real energy savings already take into account the effects of economic growth. Data is given for 2010, 2035 and 2050 (if available). The figure shows a mixed picture: about half of the scenarios project energy use to remain relatively stable throughout time; the remaining scenarios show significant reductions in energy use, up to 25 % by 2035.

Figure 2: Total primary primary energy demand

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Economic growth

There are two important factors that explain this picture. First, projected TPED is affected by projected economic growth. Projected average annual economic growth among selected scenarios is similar (around 1.8% annually), with the exception of the Greenpeace scenarios indicating 1.4% annual growth. This contributes to the (projected) achievement of strong energy savings under the Greenpeace scenarios, but generally does not explain the differences in energy savings among other scenarios.

Different levels of ambition in energy saving measures

The deployment of energy saving measures is the second and most important factor that helps explain the observed pattern. These measures differ significantly across scenarios, with on the one hand scenarios that can be called bottom-up and on the other the remaining scenarios which are top-down in nature. Basically, top-down scenarios take the desired outcome at a certain moment in the future (for example: 80 % reduction in GHG emissions in 2050 compared to 1990) and then derive a pathway backward through time to achieve that outcome. The desired outcome is established at the top and subsequently works through all layers of the energy system. To reach the end-goal, measures need to be taken that affect some, many or even all layers in the energy system. The more ambitious the end-goal, the more and/or the more ambitious the measures that need to be taken to reach the end-goal and the more is demanded from the energy system and its stakeholders. A bottom-up approach, in contrast, focuses on how the energy system will develop from the current situation towards any future moment. These scenarios leave room for the implementation of additional measures and the level of ambitiousness of these measures. Often, business-as-usual and reference scenarios are bottom-up in nature. In figure 2, top-down scenarios are represented to the right of the black line.

It turns out that all bottom-up scenarios analysed achieve rather negligible real energy savings1 or no real energy savings at all in the period 2010-2035 for the reasons outlined above.2 Top-down scenarios3 on the other hand generally show significant real energy savings. Real

energy savings are considerable under the ‘Energy Efficiency scenario’ of the European Commission (EC) and under both Greenpeace scenarios (equivalent to annual real energy savings of approximately 1.25%). The ‘Energy Efficiency’ scenario assumes a political commitment that supports very large energy savings in 2050 and a very stringent implementation of the Energy Efficiency plan, among others.4 A portion of the large energy savings achieved under the ‘Energy (r)evolution’ and the ‘Advanced energy (r)evolution’ scenario are explained by relatively modest economic growth (see section ‘economic growth’ above) and large efficiency gains in heat supply, the electricity sector, buildings, industry and other sectors, among others.5

Degree of electrification

This section focuses on the second step of the ‘trias energetica’: “use renewable energy to fulfil remaining demand.” To fully utilise the potential of this step, the energy carriers that can be decarbonised most easily must be used to the greatest possible extent. The energy carrier often cited with the greatest potential in this regard is electricity and this section investigates whether this principle is validated by the selected scenarios.

Figure 3 shows the share of electricity in final energy consumption (FEC) according to the selected scenarios. Here FEC is defined as the sum of consumption by different end-use sectors (thus excluding power generation).

All scenarios clearly show an increase in the share of electricity in FEC in the period 2010-2035 which pushes through after 2035 for the scenarios that have data available for 2050. The projected growth in the share of electricity is larger under top-down organised scenarios, increasing to a maximum of 45% (‘Powerchoices’ scenario).

There are two reasons for the increase in the share of electricity in total FEC. First, many of the scenarios selected assume an increased use of electricity in the residential and services sector. Second, all scenarios

Figure 3: Share of electricity in final energy consumption in Europe.

Notes: Black line separates scenarios that are organised bottom-up (left) and top-down (right). NA = not available

1 Real energy savings are nominal energy savings corrected for economic growth or decline.

2 In nominal terms, when economic growth is not taken into account, the scenarios do achieve significant energy savings.

3 The desired end-goal of all top-down scenarios included is the achievement of an 80 % reduction in GHG emissions in 2050 compared to 1990 levels, except for the Powerchoices scenario (75 % reduction in GHG emissions in 2050 compared to 1990). For the Greenpeace scenarios this is complemented with the requirement to completely phase-out of nuclear.

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assume an increasing share of power-driven vehicles, where stronger electrification of transport is assumed under more ambitious decarbonisation scenarios. For example, the EC decarbonisation scenarios all assume around 65% of passenger cars and light duty vehicles will run on electricity in 2050.6

Level of decarbonisation in power generation

The previous section clearly demonstrates that the share of electricity in the energy mix is projected to increase according to the selected scenarios. This section analyses to what extent future electricity will be produced from renewable sources, as required by the second step of the ‘trias energetica’.

according to most of the selected scenarios. Only the scenarios of the International Energy Agency (IEA) and the Eurogas roadmap project an increasing share of natural gas in FEC. For the IEA scenarios, increased electrification in the residential and services sector is projected to be relatively modest, while gas use in transport is projected to increase until 2035, resulting in more natural gas use in absolute terms. The Eurogas roadmap emphasizes the energy saving potential of the direct application of natural gas in the residential and services (micro-cogeneration, gas heat pumps, carrier switching) sectors, and favors fuel substitution towards compressed natural gas and liquefied natural gas in the transportation sector. This leads to an projected increase in the share of natural gas in FEC until 2050 (but not in absolute numbers).

Figure 4: Share of renewables in power generation in Europe according to selected scenarios.

Notes: Black line separates scenarios that are organised bottom-up (left) and top-down (right). NA = not available

Figure 4 shows how the share of renewables in power generation is projected to change from 2010 towards 2035 and 2050, according to the selected scenarios. It shows that the share of renewables in power generation is projected to increase significantly across all scenarios investigated. This increase can be explained by rather specific assumptions about the penetration of renewables in the power mix.

Implications for the natural gas industry

The developments described above have important implications for the natural gas industry. This is the perspective of this section, in line with the third step of the ‘trias energetica’. Note: for absolute figures about projected gas and electricity demand, see EDI’s recently launched Scenario Comparison Tool, which can be found on Syntropolis.

Gas demand in final energy consumption

The projected increase in electricity use in final energy consumption (see section ‘degree of electrification’) has important implications for the gas industry. Especially in the residential and services sector, the use of more electricity will replace direct natural gas use (for example for cooking and heating purposes). Figure 5 confirms this trend, illustrating that over time, direct use of natural gas in final energy consumption (FEC) falls,

Gas demand in power generation

To what extent does the increase in renewable electricity generation occur at the expense of natural gas in power generation? The answer to this question varies across scenarios. Figure 6 represents the share of natural gas in power generation in the period 2010-2035-2050 according to the selected scenarios. The ‘current policies’ and ‘new policies’ scenarios of the IEA project significant increases in natural gas use, primarily caused by the implications of the Emission Trading Scheme (ETS) that make gas-fired power plants relatively competitive compared to coal-fired power7. Under the ‘450’ scenario, natural gas in power generation is projected to loose ground at the expense of nuclear, due to more stringent environmental legislation. All scenarios of the EC also project lower shares of natural gas in power generation. The decline is most remarkable under the ‘high RES’ scenario, where renewable-driven power will replace gas-driven power8. Only in the ‘low nuclear’ scenario the share of natural gas in power generation will remain constant, because it is projected to (partly) replace nuclear power. The same is true for both the Greenpeace scenarios (until 2030) and to a lesser extent for the Eurogas roadmap.

4 WEO2011, p.180, 182 5 Gas-fired power capacity will continue to be in place, but only for back-up purposes for intermittent renewable electricity generation.

6 EC, Impact Assessment 2 accompanying Energy Roadmap 2050, p.4

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Figure 5: Share of gas in final energy consumption in Europe according to selected scenarios.

Notes: Black line separates scenarios that are organised bottom-up (left) and top-down (right). NA = not available

All in all, the outlook for natural gas as fuel for power generation seems rather mixed. None of the scenarios project a new ‘dash for gas’, although gas demand is projected to rise over the period 2010-2035 under the ‘current policies’ and the ‘new policies’ scenario of the IEA. Strong environmental policies in the near future seem to threaten the current market share (approximately 20%) of natural gas in power generation.

This share is projected to decrease under all top-down organised scenarios (to the right of the black line), with the exception of the ‘low nuclear’ scenario of the EC and the Eurogas roadmap.

implications for the role of natural gas. The scenarios uniformly show that both electricity generated from renewable sources and the share of electricity in final energy consumption (FEC) is projected to increase.

The latter increases to approximately 40% at most, against a share of 20% today. Increasing the use of electricity from renewable sources is currently the least demanding option to decarbonise the economy and with current insights appears unavoidable. The increase in electricity use goes only partly at the expense of the direct use of natural gas in final energy consumption in both absolute and relative numbers.

Concluding remarks

In power supply, the analysed scenarios indicate that the share of gas-fired power continues to be stable until 2030. After 2030, gas use for power generation varies widely across scenarios with most scenarios projecting a decline in gas-driven power in both absolute and relative terms.

This paper uses a selection of leading energy scenarios to explore the role of electricity as important driver of decarbonisation in Europe and its

Figure 6: Share of gas in power generation in Europe according to selected scenarios.

Notes: Black line separates scenarios that are organised bottom-up (left) and top-down (right). NA = not available

7 Greenpeace & European Renewable Energy Council (EREC), Energy (r) evolution, 2010, p.86 8 EC, Impact Assessment 2 accompanying Energy Roadmap 2050, p.34

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Appendix 1: list of selected scenarios

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EDIAAL The effect of biogas production on the energy market

Biogas is a gaseous energy carrier consisting mainly of methane and CO2. It can be produced through anaerobic digestion of biological material and is either captured from landfills where it is generated naturally, produced from sewage sludge or in dedicated installations where energy crops are often used to raise energy production. Biogas has a lower energy content per Nm3 than its fossil counterpart, natural gas. Once biogas has been produced or collected it can be used in a variety of applications: to produce heat, electricity or substitute natural gas. In order to substitute natural gas the energy content must be increased; this is normally done by removing CO2. Besides raising the energy content of biogas, it may contain some contaminants that will require removal before it may be used safely. When it is upgraded to the extent that it can substitute natural gas, it is called green gas (or biomethane). Other methods of renewable gas production include gasification and power to gas.

Natural gas versus green gas

Of all the fossil fuels, natural gas emits the least carbon dioxide per unit of delivered energy when it is combusted. Upgraded biogas has the same emission characteristics as natural gas with a much shorter carbon cycle, as the CO2 emitted has been taken out of the atmosphere by the plants the gas was produced from. Thus, biogas has a very short carbon cycle in comparison to natural gas and results in no net carbon addition to the atmosphere.

Figure 1: UK modeled daily wind power generation in generation stack

Steven von Eije Energy Analyst Energy Delta Institute

Benefits of green gas in balancing the energy system

Natural and green gas can easily be stored in an underground gas storage facility at relatively low cost. This storage enables gas to be stored at times of low demand in order to be extracted when demand is high. In contrast to natural and green gas, it is still difficult and expensive to store large amounts of electricity.

Balancing with gas-fired power plants

With an increasing amount of intermittent renewable electricity production, balancing supply and demand of electricity becomes more challenging due to its poor storability and the need for flexible sources of electricity generation increases. Considering the position of gas fired power production in the merit order this means that gas will provide the balancing capacity for the electricity system, as illustrated in the figures below (Rogers 2011)1.

As can be seen in figure 1, an increase in the supply of renewable electricity can be accommodated into the electricity system by ramping down natural gas fired power plants. If the wind power sector in the UK develops according to the (conservative) estimation by Rogers (from 3,8 GW in 2009 to 42,3 GW in 2025) a large share of flexible gas fired electricity production capacity is needed to be able to accommodate this amount of renewable energy into the electricity system.

In 2011 Germany produced 20% of its electricity from renewable sources, where the most intermittent sources such as wind and solar made up 11% of total electricity production4.The total installed capacity of all electric

Figure 2: 2025 UK modeled daily wind power in generation stack (with 42,3GW of installed wind power generating capacity)

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renewable sources combined was 61 GW5 in 2011, while total installed electricity generation capacity in Germany totaled 153 GW6 in 20107.

This level of intermittent generation capacity results in a very serious challenge to balancing electricity supply and demand.

unlimited extent. In addition this hydrogen may be used for upgrading biogas to natural gas quality. With increasing shares of intermittent renewable electricity in the energy mix, power to gas is expected to provide part of the solution to the electricity supply balancing challenge.

Biogas can relatively easily be upgraded to natural gas quality and provides the same benefits to the energy system as natural gas after upgrade. Green gas can provide fuel for flexible gas-fired power plants which can be ramped up or down based on supply and demand in the electricity market. Thus, where intermittent renewable electricity poses an enormous challenge to the electricity system, green gas will be part of the solution to this challenge.

Balancing with power to gas technology

The method outlined above follows supply patterns of intermittent sources of renewable energy by adjusting electricity supply from gasfired power plants. There is also another method to help balance the electricity supply by converting excess electricity into hydrogen through electrolysis: power to gas. Gas produced in this manner is also produced with renewable sources, and is therefore sometimes referred to as green gas. As described in the contribution of Niels Rop, increased renewable energy production creates more volatility for electricity prices and this has helped to enable the business case for power to gas. According to an extensive study8 hydrogen can be injected into the existing natural gas distribution system up to a maximum percentage of 20% without significantly increasing overall risk. In case more than 20% hydrogen is available, it may be converted into methane through the methanation process and can then be injected into the gas transport network to an

Figure 5: Installed capacity Germany14

Current biogas production

In 2011 the EU produced a total of 10.1 Mtoe9 of biogas; converted to Groningen gas-equivalent this represents over 12 billion m3 of natural gas. More than 50% of EU biogas production originates in Germany and the three largest producers combined (Germany, United Kingdom and Italy) generate more than 78% of total EU biogas production.

Renewable gas potential

Even though biogas has a limited contribution to total energy consumption, its share is rapidly increasing; between 2006 and 2011 total biogas production within the EU has doubled12 and the number of biogas production installations in Germany is illustrative of this growth13. In the past 10 years the number of production installations has increased over 460% and if this trend continues in the coming decades, biogas will start to replace substantial amounts of natural gas (and other fuels).

This upward trend with regard to biogas production cannot continue indefinitely as there are various factors limiting the maximum production potential for biogas produced through anaerobic digestion.

Some of the main issues, as described in a previous edition of the EDI Quarterly15 include: the availability and price of co-substrates, differences in production costs between biogas and natural gas and digestate disposal issues. In addition, two new issues have surfaced that may limit total biogas production potential: financing anaerobic digestion plants and the public acceptance of biogas production with co-substrates.

Figure 4: EU biogas production in 2011 12 Bcm is a substantial amount of energy, however, if we compare total biogas production to total

Gasification is a promising technology combining very high temperature and pressure to convert biomass with high lignin content into synthetic natural gas16. Currently, the total volume of green gas produced through gasification of biomass is very limited and some of the larger installations are located at power plants where biomass can be gasified for co-firing purposes. One example is the Willem Alexander plant (in Buggenum, the Netherlands) where 15% of torrefied wood pellets are co-gasified in a 253 MW coal gasification power plant17. If the gasification process becomes more cost effective large volumes of renewable gas production could be realized as this kind of biomass is available in large quantities.

EU gas consumption11, biogas still has a limited contribution of 2.5% and the contribution of biogas in comparison to total primary energy consumption in the EU is only 0.6%.

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Power to gas technology is still in its infancy (the first demo projects are currently under construction) and due to inherent inefficiencies in converting energy carriers, this is still an expensive endeavor. As renewable electricity supply continues to increase and electrolysis technology further develops, the business case for power to gas will become more attractive and volumes of this form of green gas are likely to increase.

In the foreseeable future these three technologies combined are unlikely to push natural gas out of the energy mix, but as production increases, increasing amounts of natural gas will be displaced: estimations of EU biogas production in 2020 vary between 47 and 197.5 bcm Groningen gas equivalent .

Renewable gas; an opportunity or threat?

Despite the fact that renewable gas is likely to substitute a substantial amount of natural gas in the future, it should not be considered a threat to the gas sector. By far the largest amount of biogas that is produced through anaerobic digestion is not upgraded to natural gas quality but used for electricity and heat production and even though this indirectly substitutes natural gas, it also competes with other fossil fuels such as coal.

Renewable gas is likely to be of great value for natural gas suppliers for two reasons: acceptability of natural gas and the creation of new markets.

Both of these may help increase the share of natural gas in the energy mix, therefore the natural gas sector should embrace renewable gas producers.

PR value and acceptability of natural gas

By embracing renewable gas, the natural gas sector can improve its image as supplier of the cleanest fossil fuel and enabler of the energy transition.

In contrast with the coal lobby, the natural gas industry seems to have been asleep, possibly assuming that the beneficial properties of natural gas were too obvious to be disregarded by policy makers and the general public. In contrast, the coal sector has embraced carbon capture and storage (CCS) in order to legitimize new coal fired power plants while hardly any CCS projects are actually implemented. When communicating the benefits of natural gas, the gas sector should also demonstrate the benefits of renewable gas in order to showcase commitment to the transition to a low carbon economy. This would both improve the corporate image of natural gas suppliers and increase the acceptability of the cleanest fossil fuel in the future energy mix. Finally, the gas sector can further reduce its footprint by substituting part of its gas sales by green gas, further increasing the acceptability of natural gas.

transportation (together with electric vehicles using renewable electricity). This may, in turn, induce governments to create favorable fiscal legislation for CNG vehicles giving an important impulse to this market. In fact, favorable fiscal incentives for both efficient conventional and electric vehicles has resulted in significantly increased adoption of these types of vehicles. The increasing price difference between natural gas and petrol will further accelerate this development, and at some point a more mature market will evolve and green gas production will no longer be able to satisfy all demand, at which point the market would require natural gas (which is still environmentally superior to diesel or petrol).

This is only one example of the manner in which green gas could be used to create new markets for natural gas. The same logic applies to LNG for heavy vehicles and shipping, either virtually or directly replaced by bioLNG to achieve the same effect.

How to embrace renewable gas producers?

There are various manners in which the natural gas sector could embrace renewable gas producers and many companies that are active in the gas sector seem to realize this and are already embracing renewable gas producers. One example is GasTerra, committing to accommodate all green gas transported in the Dutch national gas transport network offered at the market price in their annual report19. Parties like GasTerra are much better equipped to take on the risks of a variable supply of green gas than individual renewable gas producers.

An even more striking example of a company that has embraced renewable gas, both with regard to production and consumption, is the Dutch transmission service operator. Gasunie is committed to make its own operations more sustainable and since 2012 they have substituted 80% of their gas consumption (for office heating) with green gas20. In addition, they have replaced part of their fleet with vehicles that operate on green gas and plan to replace their entire fleet with CNG vehicles21.

Gasunie is also promoting green gas developments abroad. In 2011 Gasunie signed a memorandum of understanding with Gazprom and two other companies to cooperate in the development of a green gas project in Russia and if the project comes on stream, the green gas is destined for the EU market22. In cooperation with Greenpeace, Gasunie has also started a power to gas project in Germany where Greenpeace Energy will produce the hydrogen and Gasunie will make sure that it is accommodated in its German transportation network.23

Creating new markets

Renewable gas can also help create new markets for natural gas. An interesting example is natural gas for transportation purposes, in the form of compressed natural gas (CNG) for passenger vehicles or in the form of liquefied natural (LNG) gas for heavy transport and shipping.

There are many hurdles to be overcome when creating a new market, and one of the main issues is the so called ‘chicken and egg’ problem.

Nobody will invest in a vehicle that runs on natural gas if the refueling infrastructure is not available and it is risky to invest in new infrastructure in the absence of customers. The supply side of CNG and LNG fuelling stations is being stimulated by the Dutch government through subsidies and other measures including the innovation contract for small scale LNG. With regard to the demand side, green gas could play an important role. Currently in the Netherlands there is more than enough green gas available to substitute all natural gas used by existing CNG passenger vehicles. If all of this gas were (virtually) substituted with green gas, this would create the most sustainable method of private

Figure 6: The convoy of 21 green gas vehicles leaves for its first trip to the Gasunie Headquarters

Conclusion

Sustainable gas will play an important role in the future energy system helping balance the electricity system through its use in gas fired power plants and by converting excess electricity into sustainable gas. Even though sustainable gas will likely displace a substantial amount of natural gas in medium term, it should be considered an opportunity rather than a threat to the natural gas sector because sustainable gas increases the acceptability of natural gas and can help to create new markets for natural gas.

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1 http://www.oxfordenergy.org/wpcms/wp-content/uploads/2011/08/NG-54.pdf 2 http://www.oxfordenergy.org/wpcms/wp-content/uploads/2011/08/NG-54.pdf 3 http://www.oxfordenergy.org/wpcms/wp-content/uploads/2011/08/NG-54.pdf 4 http://www.oxfordenergy.org/wpcms/wp-content/uploads/2012/06/SP-261.pdf 5 http://www.ren21.net/Portals/97/documents/GSR/GSR2012_low%20res_FINAL.pdf 6 http://www.eia.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid=2&pid=2&aid=7 7 No data for 2011 available yet. The difference in the ratio between production contribution and installed capacity is due to the lower utilization rate of both solar and wind power in comparison to other electricity generation options. However, it is clear that it makes a huge difference on the amount of power that is supplied to the market whether or not the sun is shining and the wind is blowing 8 http://www.naturalhy.net/docs/presentations/mep/The%20NATURALHY%20Project%20Questions%20and%20Answers.pdf 9 http://www.eurobserv-er.org/pdf/baro212biogas.pdf 10 http://www.eurobserv-er.org/pdf/baro212biogas.pdf 11 http://www.bp.com/assets/bp_internet/globalbp/globalbp_uk_english/reports_and_publications/statistical_energy_review_2011/STAGING/local_assets/pdf/statistical_review_of_world_ energy_full_report_2012.pdf 13 http://www.eurobserv-er.org/pdf/baro186_a.pdf 14 http://www.biogas.org/edcom/webfvb.nsf/id/DE_PM-29-12/$file/12-11-16_Biogas%20Branchenzahlen%202011-2012-2013.pdf 15 http://www.energydelta.org/mainmenu/energy-knowledge/green-gas-2/ediaal-publications/hurdles-to-large-scale-green-gas-production 16 The anaerobic digestion method is less suitable for this type of biomass.

17 http://www.technischweekblad.nl/centrale-in-buggenum-mogelijk-dicht.297596.lynkx 18 Van Foreest, F., Perspectives for biogas in Europe. Oies natural gas research programme, December 2012. http://www.oxfordenergy.org/wpcms/wp-content/uploads/2012/12/NG-70.pdf 19 http://www.gasterra.nl/gasterra/Documents/GasTerra_Jaarverslag_2011_NL.pdf 20 http://www.gasunie.nl/nieuws/gasunie-schakelt-over-op-groen-gas?q=groen+gas 21 http://www.gasunie.nl/nieuws/gasunie-gaat-rijden-op-groen-gas 22 http://www.gasunie.nl/nieuws/gasunie-en-gazprom-werken-samen-aan-ontwikkeling-russisch-groen-g 23 http://www.gasunie.nl/nieuws/greenpeace-en-gasunie-maken-opslag-windenergie-mogelijk?year=2012&month=4

Announcing EDI’s new Scenario Comparison Tool!

The Energy Delta Institute has recently launched another interactive tool: the Scenario Comparison Tool. With this tool, users will be able to easily compare different scenarios and their projections regarding future gas and electricity demand and will be extended in the future to include data about additional energy sources and geographical areas. The best part? Its for free! http://www.syntropolis.net/knowledgehub/scenarios/

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EDIAAL Policy comparison of the EPBD recast impact on several EU Member States In Europe, over a quarter of all final energy is consumed by the residential sector. To combat growing energy consumption in buildings and to eliminate wastage of energy the European Union introduced policy in the 1980’s to require energy efficient building, evolving into the Energy Performance of Buildings Directive (EPBD). Two important elements of efficient building policy are labeling, by means of the energy performance certificate, and the requirement to build “Nearly Zero Energy Buildings” (nZEB). In late 2010 EPBD legislation was updated and became binding, with the so-called “EPBD recast”. Article 9 of this directive requires all new buildings to be nearly zero-energy buildings; and after 31 December 2018, new buildings occupied and owned by public authorities must be nearly zero-energy buildings in all Member States (MS). As this appears to be a strict policy, large flexibility is given in the recast EPBD: nZEB is not a technical standard but a policy requirement leading to tightening future buildings’ standards with specific definitions and implementation to be decided by the MS. There is the need for more guidance and common understanding for implementing sustainable yet feasible nZEB definitions. This paper compares three MS on their implementation of the EPBD to demonstrate the different manners in which they implement the broad requirements of this directive.

EPBD recast

On May 19th, 2010, the recast of the EPBD was adopted by the European Parliament in order to strengthen energy performance requirements and streamline some of the provisions from the 2002 directive it replaces. As the November 2008 Commission Communication for the original proposal states, buildings have significant untapped potential for cost effective energy savings “which, if realized, would mean that in 2020 the EU will consume 11 % less final energy.”

Measures of the Recast Directive include: • Article 9 “Member States shall ensure that by 31 December 2020 all new buildings are nearly zero-energy buildings; and after 31 December 2018, new buildings occupied and owned by public authorities are nearly zero-energy buildings”.

• Member States shall furthermore “draw up national plans for increasing the number of nearly zero-energy buildings

Milan Vogelaar Energy Analyst Energy Delta Institute

• “stimulate the transformation of buildings that are refurbished into nearly zero-energy buildings” • a more detailed and rigorous procedure for issuing Energy Performance Certificates (EPC) • Article 2 defines a nearly zero-energy building as “a building that has a very high energy performance. The nearly zero or very low amount of energy required should be covered to a very significant extent by energy from renewable sources, including energy from renewable sources produced on-site or nearby”.

National requirement & roadmaps

The implementation of the EPBD and EPBD recast hasn’t been easy for many Member states. In the following section three MS (Germany, The Netherlands and the United Kingdom) are presented with their implementation of the EPBD. To give a concise overview of the implementation only certification of buildings and roadmaps to nZEB are detailed.

Germany

Responsibility for implementation of the EPBD in Germany lies with the Federal Ministry of Transport, Building and Urban Development, together with the Federal Ministry of Economics and Technology. Since the first Thermal Insulation Ordinance (Wärmeschutzverordnung) in 1977, there have been requirements concerning the energy performance of buildings in Germany, and these requirements have been continuously increasing.3 Because of a long tradition of energy saving in Germany, notable successes have been achieved in actual energy savings in the building sector. The EPC, for instance, can provide initial information about the expected energy efficiency standard of a building for consumers, and can thus help to save energy in the long term by overcoming informational barriers to energy efficiency. The requirements for new buildings are increased in two stages (2014 and 2016), respectively 12,5% (primary energy) and 10% (thermal insulation in the building envelope). No retrofit requirements are included but in real estate ads future energy values must be provided per unit of living space. It will be compulsory to provide the EPC of the building to the buyer or tenant when the contract is offered.

3 The additional requirements of the EPBD were supplemented by the Energy Saving Ordinance 2007 (Energieeinsparverordnung (EnEV)). The last amendment of the Energy Saving Ordinance came into force in October 2009 and strengthened the level of requirements by 30% on average. Since the beginning of 2009, in addition to the requirements of the Energy Saving Ordinance, it has been compulsory nationwide to use renewable energies for heating in new buildings, according to the Renewable Energies Heat Act (Erneuerbaren-Energien-Wärmegesetz (EnEG)).

4 http://www.enev-online.org/enev_2009_volltext/index.htm 5 Towards nZEB – some examples of national requirements and roadmaps – REHVA 2011

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The current requirements (EnEV2009) for new residential buildings are in respect to a so-called reference building. The primary energy demand of a new building must be below or equal to the energy demand of the reference building, and limits for specific transmission heat loss must be reached.4 Official definitions concerning public subsidies for (residential) Low Energy Buildings are subject to programs run by the (state-owned) Kreditanstalt für Wiederaufbau Frankfurt (Kf W). The current requirements are Kf W 70, Kf W 55 and Kf W 40 indicating that the primary energy demand of these buildings must be 70%, 55% and 40% of the reference building. In addition, there is also a subsidy program for “Passiv-Häuser”, which is defined in accordance with the Passiv-Haus-Institute as “Kf W- 40-buildings with an annual heat demand lower than 15 kWh/m²”.This figure can‘t be directly compared with the low energy classes from the other countries as passive houses only have requirements for heating combined with a requirement for the overall use of primary energy to be less than120 kWh/m² including energy for appliances. In 2020 new buildings shall be “climate friendly” with less primary energy demand.5

most stringent in the world, demanding that all emissions from the house and the activities that take place within it be net zero over the course of a year. The initial 2008 building regulation set out that all homes built from 2016 will experience requirements regarding: emissions from space heating, ventilation, hot water and fixed lighting, expected energy use from appliances and exports and imports of energy from the development (and directly connected energy installations) to and from centralized energy networks.

Certification

Certification

An EPC has been compulsory for new buildings and major refurbishments since 2002 in Germany. In subsequent years, an EPC was also gradually introduced for existing buildings. In Germany, EPCs can be grouped into two categories, according to the calculation method: certificates on the basis of calculated demand and those on the basis of metered consumption. Until 2008, there was freedom of choice between the “demand” and “consumption” methods for all existing buildings, while now this applies only for large residential buildings (at least 5 units). EPCs are now calculated on “demand” methods for residential buildings. For a certificate to be issued owners of older small residential buildings which have not been refurbished receive an EPC based on calculated energy demand .

Figure 1 – Germany nZEB policy

Figure 2 – Germany Energy

Current regulation came into force on the 9th of January 2013 (Part L of the Building Regulations) and retains the approach of examining net emissions (including from appliances) over the course of a year.

It proposes that, to meet the zero carbon homes standard, homes should: be built with high levels of energy efficiency, achieve at least a minimum level of carbon reductions through a combination of energy efficiency, onsite energy supply and/or (where relevant) direct connection to low carbon or renewable heat; and choose from a range of (mainly offsite) solutions for tackling remaining emissions.6 7 Requirements regarding certification of buildings were implemented progressively between August 2007 and October 2008. EPCs are produced for buildings on construction, sale and rent. Domestic and non domestic EPCs are valid for ten years.

For new buildings, changes to building regulations mean that developers must submit a design stage assessment demonstrating compliance. The as-built data, which includes test results (actual or sample) for mechanical ventilation and air-tightness is used for the final building regulation submission and the EPC. A central electronic register has been established for the storage of all EPCs and DECs produced. By December 31st 2010, 5.7 million domestic EPCs, 210,000 nondomestic and 72,000 DECs had been lodged.

The EPC provides a rating of the overall energy efficiency of the building on a scale from A to G, where A is very efficient and G is the least efficient.

This is an asset based rating, based on the characteristics of the building itself, its services and a standardized occupancy profile. Domestic EPCs also contain an environmental impact rating, which is a measure of a home’s impact on the environment in terms of carbon dioxide (CO2) emissions - the higher the rating, the less impact it has on the environment. In England and Wales, real estate agents who provide written sale details will need to include graphics showing the energy efficiency and environmental impact rating for the property, or attach the EPC. Agents must verify that an EPC has been commissioned before accepting an appointment.8

Performance Certificate

United Kingdom

The implementation of the EPBD in England and Wales is the responsibility of the Department for Communities and Local Government (CLG), supported by the Department for the Environment, Food and Rural Affairs (Defra) and the Department of Energy and Climate Change (DECC). In Scotland, implementation of the EPBD is the responsibility of the Building Standards Division, which is part of the Directorate for the Built Environment.

The UK government has decided to make all new homes zero carbon from 2016, and the requirements for this program make it one of the

Figure 3 – United Kingdom nZEB policy

Figure 4 – United Kingdom Energy Performance Certificate

6 http://www.zerocarbonhub.org/ 7 Definition of zero carbon homes and non domestic buildings – consultation 2008 8 Implementing the Energy Performance of Buildings Directive (EPBD) – www.epbd.ca.eu

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The Netherlands

In the Netherlands the implementation of the EPBD is the overall responsibility of the Ministry of the Interior and Kingdom Relations and NL Agency, the Dutch energy agency, is the executive body for the implementation process. In December 2006 the ‘Decree on Energy Performance of Buildings’ (BEG) as well as the ‘Regulation on Energy Performance of Buildings’ (REG) were legally implemented enabling the development of an EPC for existing buildings that first came into force on January 1st, 2008. The certification of new buildings was already integrated into Dutch law as early as 1995 when each existing building or building unit, e.g., an apartment, required a calculated Energy-Index according to a fixed methodology. An energy certificate class is then assigned based on the Energy-Index and building type.

Certificates can only be issued by qualified assessors who may attend training voluntarily, but examination by a national board is mandatory.

The so-called Energy Performance Standard (EPN) sets requirements for the energy efficiency of new buildings and major renovations of existing buildings, expressed in an “energy performance coefficient.”

This coefficient is a dimensionless number to indicate the energy efficiency of a new building, and sets an integral requirement for the whole building.

Building requirements (related to energy performance) were first published for new residential buildings in 1995. These requirements were tightened in 1998, 2000 and 2006 (see figure 5). Further adjustments from the current requirement of 0.8 are expected in 2011 (25% efficiency increase to 0.6), 2015 (50% efficiency increase to 0.4) and 2020 (zero–energy or nearly zero-energy new residential buildings)9.

A residential building with an energy performance coefficient of 0 is a home where, annually, no fossil fuel is added to the home for energy use to heat the building, excluding the energy required for appliances used in the home. The energy performance is restricted to the building specific energy supplied per annum, and the public (power) network may be used as a mathematical buffer to compensate for momentary over- or under-generation. Returned energy is deducted from the fossil fuel used in power plants, and in principle this can compensate for gas usage. An energy performance coefficient of zero is often defined as building energy neutral, but the definition of “energy neutral” is currently under development. 10 11

Certificates

The date of implementation of the Directive regarding EPCs was January 1st, 2008. For social housing companies this was one year later on the provision of certification of their complete building stock. Permanent certification for public buildings was mandatory as of January 1st 2009.

In 2009, a revision of the EPC scheme started that led to improvements ranging from training and examination of assessors, to an updated methodology and software, to a new lay-out of the EPC, and a newly adopted quality assurance scheme as of January 1st 2010.

The EPC consists of 3 pages. On the first page, the energy certificate class of the building is indicated, ranging from A (many energy saving measures taken) to G (many energy saving measures possible). The energy certificate class is determined by the calculated Energy-Index that can be found on page three of the EPC. On the front page standardized annual primary energy use in megajoules (MJ) is displayed including a sub-division into electricity (kWh), gas (m3) and heat (GJ). The first page also mentions the building type for which the energy certificate is issued, the assessor of the certificate and the expiration date of the certificate (a maximum of 10 years). The specific energy saving measures advised for the building are described on page 2 of the certificate and page 3 gives a description of the Energy-Index calculation, according to a standardized methodology.

Certification of existing residential and non-residential buildings started January 1st, 2008, making display of the certificate required when a building or building unit is sold or rented. Acquiring a certificate involves a qualified assessor’s inspection of the property and building in terms of the type and quality of construction and installations. The qualified assessor then calculates the Energy-Index with accredited software and issues the EPC. This is done by sending an automated report to the central database hosted by NL Agency which returns a unique number for each certificate which can then be printed.

Figure 5 – Netherlands nZEB policy

Figure 6 – Netherlands Energy Performance Certificate

Impact on residential energy consumption

Comparing the three MS on the impact of their policy implementations is only possible in a qualitative manner. This policy comparison gave insight in the differences between the policy and the fact that there is room for improvement to create a common framework of nZEB principles. Cooperation between countries and the inclusion of a definition for both nearly-zero energy and carbon buildings would be useful as well as integration of sustainable cities and green electricity and help MS move towards a sustainable nZEB future.

9 Implementing the Energy Performance of Buildings Directive (EPBD) – www.epbd.ca.eu 10 NL Agency - Op weg naar minimum energie woningen met EPC≤ 0 11 To fulfill the requirements of energy neutral in practice means the usage of sustainable energy. The amount of sustainable energy used, measured over a year, should exceed the amount of energy acquired from the public power network, gas network or heat network and is measured in megajoules (MJ).

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To assess the overall impact of the EPBD and on energy use in Europe, there is the need to look at the building stock. Buildings account for 40% of the total energy consumption of the EU and they are one of the most significant sources of greenhouse gas emissions (36% of the EU total). The roadmaps presented by the European Commission in 2011 show that, in order to achieve EU strategic objectives, greenhouse gas emissions in the building sector must be reduced by 80 – 95% by 2050 in comparison to levels in 1990. According to BPIE nZEB will account for 25% of the total building stock in 2050. To quantify the impact of this assumption on the energy consumption of the EU is challenging considering the parameters that influence such a time-frame but it will clearly dampen, if not reverse, growth in energy demand for buildings. In light of objectives regarding the emission of greenhouse gases, fossil fuels are likely to play a decreasing role in the buildings sector, with the exclusion of natural gas in the case of high-efficiency technologies such as micro-CHP. In spite of this, according to the Energy Roadmap 2050, gas demand in the residential sector will likely drop by a quarter by 2030 due to energy efficiency measures in the housing sector.

Figure 7 – EU Building Stock 2050, BPIE

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EDI’s Programme Overview 2013 Executive Master and Leadership Programmes PROGRAMME

DATES

CONTENT

PRICE

Executive Master of Gas Business Management (MGBM) 3 x 2 weeks course Summer academy 1 week Master thesis max. 6 months

Executive Master module: Energy Business Management Part 1: 8 – 12 April 2013 Part 2: 13 – 17 May 2013

Focus on strategic management, business development, structures and positions in the natural gas business in context of the international energy markets, the interplay between governments and industry and the changing policy environment.

9.850 per module

This programme fee is including thesis coaching and examination *the courses can be attended separately

Executive Master module: Large Energy Projects Part 1: 11 – 15 November 2013 Part 2: 9 – 13 December 2013 Executive Master module: Natural Gas Strategy Part 1: spring 2014 Part 2: spring 2014

34.500 Complete Master Programme

Summer Academy (1 week) Fellowship on Energy Programme Energy Transition and Leadership In cooperation with: European School for Management and Technology (ESMT)

Module 1: 24 – 27 June Module 2: 23 – 26 September Module 3 (incl. Alumni Day): 27 – 29 November or 4 – 6 December

European energy policy, Energy sources and company portfolios, Energy paradigm shift and transformational leadership

9.500

*dates are preliminary and subject to change

Joint JointExcellence ExcellenceProgrammes Programmes PROGRAMME

DATES

CONTENT

Finance, Risk and the Energy Value chain (FREVC)

5 days 2/year 4 – 8 February 28 October – 1 November

Economics, Valuation, Finance and Treasury, Transactions, Due Diligence and Post Merger

4.950

6 days 1/year 18 – 21 March (part 1) 24 – 25 May (part 2)

Gas in transition, Scenario planning, New business models in energy sector, Energy venturing, Energy innovation policies

5.995

In cooperation with: PriceWaterhouseCoopers

Mini MBA Energy Transition and Innovation In cooperation with: Nyenrode Business University

PRICE

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Specific Programmes

Innovation In cooperation with: Nyenrode Business University

1/year 18 – 21 March (part 1) 24 – 25 May (part 2)

EDI’s Programme Overview 2013

Scenario planning, New business models in energy sector, Energy venturing, Energy innovation policies

Specific SpecificProgrammes Programmes PROGRAMME

DATES

CONTENT

PRICE

Fundamentals of Gas Strategy Course Underground Gas Storage Course (FGS) (UGSC)

5 days 5 days 2/year 1/year 10 – 14 June 11 – 15 November 25 – 29 November

Gas market Storage in gas fields, developments, aquifers and salt customers caverns, trends, legal perspective, aspects, tariffs, geopolitics, risk valuation, visit UGS management, facility competitive strategies

4.750 4.700

Master Class Gas Pricing Strategies Public Acceptance Course (PA) (GPS)

2 days 3 days 1/year 1/year 22 – 23 April 25 – 27 March

Risk management, Public trust in price volatility, stakeholders, functioning of the Compensation free gas market, Mechanisms, Privacy trading exercise, concerns, Public short term vs. long communication term market strategies

2.850 2.850

Master Class LNG Chain

4 days 1/year 30 September – 2 October

4.000

PROGRAMME

DATES

Economical, legal, technical overview, LNG pricing, supply contracts, major markets/players CONTENT

Gas Transport & Shipping Course International Gas Value Chain (IGVC) (GTSC)

2 days 11/year week 2/year 29 – 30 October 8 – 12 April 21 – 25 October

Focus on transport Gas and industry shipping in the overview, portfolio Netherlands, net management, configuration, gas regulation transport services

2.650 4.450

Gas Value Chain (GWK) (currently given in Dutch)

1 week 1/year 3 – 7 June

History gas industry, buying and selling, LNG, field development, liberalisation

4.250

Energy Markets (EMK) (currently given in Dutch)

4 days 1/year 8 – 10 October (part 1) 4 November (part 2)

Overview energy markets, liberalisation, energy transport, market players, renewables, wholesale & trade, focus on Dutch market

3.200

Introduction Programmes

PRICE

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Public Acceptance Course (PA)

3 days 1/year 25 – 27 March

Public trust in stakeholders, Compensation Mechanisms, Privacy concerns, Public communication strategies

PROGRAMME

DATES

CONTENT

International Gas Value Chain (IGVC)

1 week 2/year 8 – 12 April 21 – 25 October

Gas industry overview, portfolio management, regulation

4.450

Gas Value Chain (GWK) (currently given in Dutch)

1 week 1/year 3 – 7 June

History gas industry, buying and selling, LNG, field development, liberalisation

4.250

Energy Markets (EMK) (currently given in Dutch)

4 days 1/year 8 – 10 October (part 1) 4 November (part 2)

Overview energy markets, liberalisation, energy transport, market players, renewables, wholesale & trade, focus on Dutch market

3.200

EDI’s Programme Overview 2013

2.850

Introduction Programmes Introduction Programmes

All programme details are subject to change.

Prices are excl. VAT, accommodation, travel expenses and examination, unless otherwise mentioned.

Cancellation policy

Please find information about the cancellation policy for each programme on www.energydelta.org

Customized Programmes

PRICE

Information

For more information please contact our account manager Richard Sanders via e-mail at sanders@energydelta.nl or telephone +31 (0)50 524 8319, or visit our website www.energydelta.org For the latest developments and actual information please continue to visit our website www.energydelta.org

Besides open enrolment programmes, Energy Delta Institutes recognizes the need for tailor-made knowledge within the energy industry. Subjects from our open enrolment programmes as well as subjects specifically related to your organization needs can be developed by our energy business school. For more information visit our website www. energydelta.org

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Conferences 2013 January January 8-10: Phoenix Arizona, United States 3rd Annual Electric Energy Storage Conference http://www.allconferences.com/conferences/2012/20120824135105 January 28-29: Berlin, Germany Gas Transport & Storage 2013 http://gtsevent.com/ January 19-20: Dubai, United Arab Emirates 2nd International Conference on Clean and Green Energy http://www.iccge.org/ January 23 - 24, 2013: Copenhagen, Denmark ESCO Europe 2013 www.esco-europe.com/ January 23 - 24, 2013: Milan, Italy 3rd Annual Biofuels Summit http://www.allconferences. com/c/3rd-annual-biofuels-summit-2013-january-23 January 28, 2013: Berlin, Germany 4th Annual Smart Grids Summit 2013 http://www.thesmartgridssummit.com/?mc=EL January 28 - 29, 2013: Berlin, Germany Gas Transport & Storage 2013 http://gtsevent.com/ January 28 - 30, 2013: Amsterdam, the Netherlands LNG Bunkering Summit www.allconferences.com/c/lng-bunkering-summit-amsterdam-2013january-28

February February 5 - 6, 2013: Brussels, Belgium 8th Annual EU Energy Law & Policy Conference http://www.euenergyconference.com/ February 11 - 12, 2013: London, United Kingdom 2nd Annual European Renewable Energy Project Finance http://www.allconferences.com/conferences/2012/20120815074334 February 12 - 13, 2013: Houston Texax, United States of America 12th Annual Liquefied Natural Gas https://www.platts.com/ConferenceDetail/2013/pc315/index February 12 - 15, 2013: Moscow, Russia Russia Offshore 2013 http://www.russianshelf.com/ February 18 - 20, 2013: Lisbon, Portugal 3rd Annual Global LNG Forum http://www.europeangashub.com/event/3rd-annual-global-lng-forum. html February 20 - 21, 2013: Singapore, Singapore Small-Mid Scale LNG Asia Pacific Summit http://www.smalltomidlngsummit.com/Event.aspx?id=829424&utm_ campaign=premail&utm_medium=directorylisting&utm_ source=rigzone&utm_content=&utm_term=&MAC=ISG_DLRZ February 21, 2013: New Delhi, India Smart Grid India Energy Efficiency Optimization http://www.allconferences.com/c/smart-grid-india-energy-efficiencyoptimization-summit-new-delhi-2013-february-21

January 29 - February 1: Hoevelaken, the Netherlands Econergie 2013 http://www.econergie.nu/Econergie-2013/page/7764/

February 24 - 27, 2013: Abu Dhabi, United Arab Emirates MEPIPES (Oil & Gas Pipelines in the Middle East 2013) http://www.theenergyexchange.co.uk/event/oil-and-gas-pipelinesmiddle-east-2013

January 29 - 31, 2013: Vienna, Austria European Unconventional Gas 3rd Annual Meeting http://www.theenergyexchange.co.uk/european-unconventional-gassummit-3rd-annual-meeting/s13/a274/

February 25 - 26, 2013: Brussels, Belgium Gas to Power Europe Conference http://gastopowerjournal.com/gas-to-power-journal-events/item/1028gas-to-power-europe-conference

January 29 - February 1: Vienna, Austria European Gas Conference 2013 http://www.theenergyexchange.co.uk/european-gas-conference-2013/ s13/a214/

February 25 - 27, 2013: San Antonio Texas, United States of America Smart Energy Summit http://www.parksassociates.com/events/smart-energy-summit

January 31 - February 1, 2013: London, UK 7th Annual European Carbon Capture & Storage 2013 http://www.platts.com/ConferenceDetail/2013/pc365/index

February 26 - 27, 2013: Atlanta Georgia, United States of America 3rd European American Solar Deployment Conference http://www.pvrollout.com/ February 26 - 28, 2013: Rome, Italy 2nd Annual East Mediterranean and North African Gas Forum http://www.emnagasforum.com/

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Conferences 2013 February 27 -28, 2013: Istanbul, Turkey 2013 Tight & Shale Gas Summit http://www.wplgroup.com/aci/conferences/eu-eug2.asp February 27 - 28, 2013: Buenos Aires, Argentina Emerging Shale Gas & Tight Oil Basins, South America 2013 http://www.emerging-shale-basins-south-america.com/ February 27 - 28, 2013: Amsterdam, the Netherlands Offshore Pipeline Technology Conference http://www.ibcenergy.com/event/opt?xtssot=0 February 27 - 28, 2013: Vienna, Austria 4th Annual Renewable Energy Finance & Infrastructure Summit http://energy.flemingeurope.com/renewable-energy-summit

March March 4 - 6, 2013: Breukelen, the Netherlands Slimme Energie Infrastructuur http://www.iir.nl/energy/event/slimme-energie-infrastructuur/ March 5 - 7, 2013: Sofia, Bulgaria Black Sea Oil and Gas Forum 2013 http://www.blackseaoilgas.com/ March 5 - 8, 2013: Singapore, Singapore LNG Global Congress Asia Pacific http://www.lnggc-asia.com/ March 6 - 7, 2013: London, United Kingdom Unconventional Gas http://www.smi-online.co.uk/energy/uk/unconventional-gas

March 12 - 14, 2013: Rotterdam, the Netherlands World Biofuels Markets http://www.greenpowerconferences.com/EF/?sSubSystem=Prospectus &sEventCode=BF1303NL&sSessionID=168d25768824309d5511e761 0485ca96-17507371 March 13 - 14, 2013: London, United Kingdom LNG for Transport Forum http://www.ibcenergy.com/event/lng-fuel-transport-forum March 14 - 15, 2013: Berlin, Germany ener.CON Europe 2013 http://enercon2013.we-conect.com/en/ March 18 - 19, 2013: Dusseldorf, Germany Energy Storage http://www.energy-storage-online.com/ March 18 - 19, 2013: London, UK 2nd Annual Advanced Hydropower Generation Forum http://www.bis-grp.com/business-events/energy/2nd-annual-advancedhydropower March 20 - 21, 2013: Arnhem, the Netherlands Power-to-Gas http://www.iir.nl/energy/event/power-to-gas/

June June 19-21: Bucharest, Romania Energy and Sustainability 2013 http://www.wessex.ac.uk/13-conferences/energy-andsustainability-2013.html

March 6 - 7, 2013: Amsterdam, the Netherlands Argus European Emissions Markets 2013 http://www.argusmedia.com/events/argus-events/europe/argus-euroemissions/home March 11, 2013: Aberdeen, UK Oil & Gas Outlook North Sea http://www.terrapinn.com/conference/oil-and-gas-north-sea/ March 11 - 15, 2013: Amsterdam, the Netherlands Flame 2013 http://www.icbi-flame.com/ March 12 - 13, 2013: Calgary, Alberta, Canada 13th Annual Arctic Oil & Gas Symposium http://www.arcticgassymposium.com/

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Recent Publications Hakim Darbouche, Laura El-Katiri and Bassam Fattouh, December 2012. East Mediterranean Gas – what kind of a game-changer? The Oxford Institute for Energy Studies.

The discovery of sizable gas resources in the Levant Basin, a geological structure that straddles the territorial waters of Cyprus, Israel, the Palestinian Territories, Lebanon, and Syria, has the potential to be gamechanging for the East Mediterranean region. Hitherto net energy importers, these countries are now faced with the prospect of long-term energy self-sufficiency and the development of a new revenue stream for the economy. With the resource potential of the Levant Basin believed to be much higher than the 35 Tcf of gas discovered recently, the East Mediterranean is now the focus of much interest on the part of major upstream investors. However, in the short to medium term, the development and monetization of these resources present stakeholders with a set of challenges originating in the region’s complex political make-up, as well as in the fact that their energy and gas utilization policies are still work in progress, over and above the technical difficulties relating to the development of these resources. This paper examines the challenges and opportunities that have been given rise to by these discoveries, arguing that to 2020 East Mediterranean gas is more likely to be a game-changer for local energy systems than for regional and international gas markets.

This paper is available at: http://www.oxfordenergy.org/wpcms/wp-content/uploads/2012/12/ NG-71.pdf

Floris van Foreest, December 2012. Perspectives of Biogas in Europe. The Oxford Institute for Energy Studies.

This paper by Floris van Foreest assesses the prospects and challenges facing biomass in the future European energy mix.

In studies and discussions of future energy sources the term gas tends to be synonymous with ‘natural gas’ with its attendant issues of upstream exploration and production dynamics, geo-politics and the ubiquitous speculation around shale gas. Biogas is frequently neglected in such a context, despite its potential to contribute to de-carbonization, in some applications using existing transmission networks.

Floris van Foreest describes the present and future conversion processes in which biomass is converted to biogas, the scale and growth of biogas production in individual European countries and the outlook to 2020 and beyond. The technical and economic challenges facing biogas production, its end-use applications and the regulatory and supporting subsidy schemes in force are discussed.

While the paper questions whether biogas targets for 2020 will be met, given the current pace of development, it provides the reader with a comprehensive understanding of the subject area and objectively addresses the challenges facing this renewable energy source.

This paper is available at: http://www.oxfordenergy.org/wpcms/wp-content/uploads/2012/12/ NG-70.pdf

Simon Pirani, December 2012. Central Asian and Caspian Gas Production and the Constraints of Export. The Oxford Institute for Energy Studies.

There has been a great deal of discussion about the Central Asian and Caspian region’s potential to produce and export gas, and about projects designed to establish new pipeline routes, e.g. to Europe and South Asia.

The discovery of the South Yolotan (Galkynysh) field in Turkmenistan, now confirmed as one of the world’s largest, has renewed interest in the region. But the reality has confounded many expectations. Apart from traditional export routes to Russia and Iran, the only new corridor opened up has been to China. This detailed survey of the region, focused mainly on the four main gas producers (Turkmenistan, Uzbekistan, Kazakhstan and Azerbaijan), examines why the presence of considerable resources does not necessarily guarantee rapid development. The political and economic background, the upstream conditions and domestic markets are considered, as well as the export trade.

This paper is available at: http://www.oxfordenergy.org/wpcms/wp-content/uploads/2012/12/ NG_69.pdf

ed. Jonathan P. Stern, December 2012. The Pricing of Internationally Traded Gas. The Oxford Institute for Energy Studies.

This is the first book in any language to focus exclusively on the pricing of internationally traded gas. Gas accounts for around 25 per cent of global energy demand, and international gas trade is growing rapidly.

The first chapter of this book examines some of the analytical issues and the contribution that economic theory can make to the study of international gas pricing. This is followed by an historical chapter tracing the origins and development of international gas pricing in the four regions which dominated natural gas trade – North America, Europe, LNG importing Asia, and the former Soviet Union – up to the early 2000s. The main part of the book focuses on developments in the 2000s, with a view to how gas pricing is likely to develop during the 2010s and beyond. Aside from the established gas trading regions, the book includes chapters on international gas pricing in: the Middle East, North Africa and sub-Saharan Africa; Latin America and the Caribbean; southeast Asia; India; China; and Pacific Basin LNG markets. These national and regional studies are followed by thematic chapters on the globalization of gas markets and prices, and the potential development of a ‘gas-OPEC’.

The concluding chapter considers the extent to which international gas pricing is likely to remain regional, or whether gas could become a ‘global market’ – with a global price – akin to the crude oil market. A third possibility is whether international pricing is likely to come under the control of a small group of countries, similar to the influence of OPEC in the crude oil market. Overall it is argued that domestic gas price reform will increasingly be driven by international gas prices and that, as gas becomes a more important fuel in the energy balances of many countries around the world, it is becoming increasingly urgent for its pricing to reconnect with economic and market fundamentals, rather than continue to be determined by crude oil and oil product prices, or politically driven subsidies.

This book is available at: http://www.oxfordenergy.org/shop/the-pricing-of-internationallytraded-gas-ed-jonathan-p-stern/

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Recent Publications International Energy Agency, November 2012. The World Energy Outlook 2012.

Drawing on the latest data and policy developments this report presents analytical insights into trends in energy markets and what they mean for energy security, environmental protection and economic development.

It sets out updated projections of energy demand, production, trade, investment and carbon-dioxide emissions, broken down by country, fuel and sector, to 2035.

The World Energy Outlook 2012 is available at: http://www.iea.org/W/bookshop/add.aspx?id=433

David Buchan, November 2012. Europe’s misshapen market – Why progress towards a single energy market is proving uneven. The Oxford Institute for Energy Studies.

Progress to a single European energy market is proving very uneven.

David Buchan explains the European Commission’s worry that rapid development of national renewable and back-up capacity markets could shut off countries’ energy sectors from each other, before efforts to improve cross-border electricity connection and trading can produce results. Brussels may soon have to concede the fight against climate change will do some damage to the architecture of a free energy market, but in the meantime persistent regulation of energy prices is a more immediate menace to the single market than capacity mechanism plans are.

Agnia Gridas, October 2012. The Gas Relationship between Baltic States and Russia – political and commercial realities.

The Oxford Institute for Energy Studies.

Gas markets in the Baltic countries are small, disconnected from the rest of Europe and, despite many plans for diversification over the past 20 years, remain entirely supplied by Russian gas. Not only is Gazprom the only supplier to the region but it also has substantial equity in all of the Baltic gas companies. This has created periodic political problems between the Baltic countries and Gazprom which resurfaced in 2012 following decisions by these countries to unbundle transmission networks, and anti-trust proceedings against Gazprom by European competition authorities following Baltic complaints about excessive gas prices. Agnia Grigas’ study provides a detailed survey of Baltic gas relations with Russia in the post-Soviet era, showing the interrelationships between political and commercial considerations and how these have differed between countries and changed over time.

This paper is available at: http://www.oxfordenergy.org/wpcms/wp-content/uploads/2012/10/ NG_67.pdf

This paper is available at: http://www.oxfordenergy.org/wpcms/wp-content/uploads/2012/11/ Europes-misshapen-market.pdf

James Henderson, October 2012. The Potential Impact of North American LNG Exports. The Oxford Institute for Energy Studies.

This paper by James Henderson assesses the status and possible future impact of the growing list of potential LNG export projects in the US and Canada. It focuses on future North American LNG exports which, while subject to political and production performance uncertainty, have the potential to create considerable impact in the likely destination markets of Asia, and also (through displacement of Middle East or African sourced LNG) Europe. While it is unlikely that all the identified US and Canadian LNG export projects will proceed, there is the potential that sufficient investment will be forthcoming to allow arbitrage to proceed to its ‘equilibrium’, given favorable policy decisions.

This paper is available at: http://www.oxfordenergy.org/wpcms/wp-content/uploads/2012/10/ NG-68.pdf

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The 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 on gas and energy market developments.

Read the latest developments in the energy industry, published daily on the website of EDI. Editor in Chief Catrinus J. Jepma Scientific director EDIAAL* Editors Jacob Huber Nadja Kogdenko Steven von Eije Klaas Kwakkel Milan Vogelaar Niels Rop Santiago Katz EDI Quarterly contact information Energy Delta Institute Laan Corpus den Hoorn 300 P.O. Box 11073 9700 CB Groningen The Netherlands T +31 (0)50 5248337 F +31 (0)50 5248301 E quarterly@energydelta.nl

*EDIAAL is an Energy Delta Institute program that aims to gather, edit and make available independent knowledge on the role of gas in the transition to a low carbon economy. The EDIAAL project is partly made possible by a subsidy granted by The Northern Netherlands Provinces (SNN), Koers Noord. EDIAAL is co-financed by the European Union, European Fund for Regional Development and The Ministry of Economic Affairs, Agriculture and Innovation, Peaks in the Delta.

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