EDI Quarterly Vol. 3 No. 2 by Energy Delta Institute

EDI Quarterly Volume 3, No. 2, June 2011

Editorâ&#x20AC;&#x2122;s Note

by Jacob Huber

A Role for Natural Gas in the Pragmatic Transition to a Sustainable Energy System It is clear that a paradigm shift is taking place in which the current energy system dominated by fossil-fuels will yield to one based on renewables and low-carbon solutions. Such shifts do not, however, happen over night and a facilitating role is evident in this transition for the cleanest, most flexible fossil fuel: natural gas. This paper seeks to elucidate the role of natural gas in the pragmatic transition to a sustainable, low-carbon energy system.

Contents 1

A role for natural gas in the pragmatic transition to a sustainable energy system

Negotiary Antitrust: The E.ON case

Simulating Energy Transitions

10 Hurdles to large scale biogas production in the Netherlands 12 Organizing Future Energy Systems for Reliability 17 Books, reports and upcoming conferences

At any point in history, the constraints of most thinking are defined by a ruling paradigm, according to Thomas Kuhn. When its effectiveness begins to diminish, its foundation come into question and thus begins the breakdown process; a paradigm shift yields the establishment of a new paradigm. Such shifts are, however, sufficiently open-ended â&#x20AC;&#x153;to

leave all sorts of problems for the redefined group of practitioners to resolve.” This very sort of shift is taking place, changing the way energy issues are viewed and our very assumptions regarding energy generation and consumption and their associated impacts on the environment and society. A focus on the supply side without attention to the end use of energy is being replaced with a greater concentration on the demand side, emphasizing the end uses of energy and services that this use provides. Thus, energy efficiency is seen as playing a large role in the transition to a sustainable energy system based on renewables. Such transitions do not however happen overnight and conventional energy resources and technologies will continue to play a large role in the short- and medium-term.

shortcomings present a technical barrier to their significant penetration in the short and medium term. Natural gas will play an important role in that its storability allows it to be dispatched upon command to account for a sudden shortfall of wind-based generation, for example. Development of gas-fired combined cycle power plants that are able to enter the grid in as little as 30 minutes (compared with a number of hours for coal and days for nuclear plants) provide a perfect fit with the variable nature of wind and allow integration of a much larger percentage of intermittent renewable sources. In addition, a large existing infrastructure of pipelines, storage, and power plants (as well as associated knowledge) minimize the capital expenditure required for capacity expansion.

The newest project of EDI, EDIaal, aims to contribute to the dialogue surrounding the transition to a sustainable, low carbon energy system. Integral to this objective is the development of competencies in all transition issues including legal and regulatory aspects, renewables, energy efficiency, CCS, smart grids, and the appropriate context of fossil fuel technologies. This knowledge will then be provided through the development of training programs, seminars, and other events as well as tools for sharing knowledge of the role of natural gas in this transition. Natural gas is the contemporary source of energy most suited to playing a facilitating role in an efficient transition. It is well known that the contemporary energy system is dominated by fossil fuels, the negative aspects of which are motivating the push for a more efficient and sustainable system. These drivers include concerns ranging from climate change and pollution to resource depletion and security of supply. It is clear that the current system, which has been such a force for the development and advancement of humanity, cannot be suddenly abandoned and that a gradual transition toward the

Energy efficiency is seen as playing a role in dampening growth in worldwide energy demand in the face of strongly increasing demand in developing economies, and here natural gas has a part to play. Natural gas has a role in the efficiency component of a sustainable energy system, both on the supply-side and in end-use efficiency. Carrier switching, distributed generation, and combined heat and power (CHP) together represent an enormous opportunity to increase system-level efficiency and thus minimize the extent to which capitalintensive renewable generation technologies must be implemented. The flexibility of natural gas allows it to fit into these niches and optimize system-wide performance.

Figure 1. IEA Technology Perspectives 2010, BLUE Map Scenario

ultimate goal of a clean and sustainable energy system must be pursued. A future sustainable energy system is seen as being based on three pillars: energy efficiency, renewables, and clean fossil fuel technology (via carbon capture and storage, or CCS). It is expected that energy efficiency in various forms will account for 58% of carbon reductions in the IEA’s BLUE Map Scenario (Fig. 1). Renewables and CCS will account for 17% and 19% respectively, with the remaining 6% being due to nuclear. Natural gas in its various forms will play an essential role in this transition due to its cleanliness, flexibility, and other favorable characteristics. Current renewable or “sustainable” energy generation technologies, such wind and solar, are inherently intermittent and their product energy carrier (electricity) is essentially impossible to store on a large scale for significant lengths of time with current technology. While the resource represented by renewable technologies is large, these

Carrier switching involves the choice of the most appropriate energy carrier to supply a given end use, with the objective of minimizing primary energy consumption and greenhouse gas emissions. In most contexts, it is more efficient to provide space heating, domestic hot water, and heat for cooking from natural gas than via electrical resistance from a grid-mix of electricity. For every 10 units of primary energy (PE) used to supply domestic hot water (DHW) via electrical resistance 3.8 units of final energy (FE) would ultimately be available to provide hot water after accounting for losses in power plants and transmission and distribution. 1 If provided by a natural gas boiler with an efficiency of 90% ten units of PE would yield nine of FE for water heating. This simple example illustrates the powerful role of carrier switching in energy efficiency. Although the penetration of natural gas in DHW, space heating, and cooking for the Netherlands is already extremely high, considerable potential for this sort of carrier switching exists in Southern Europe, the United States and other parts of the world. In the USA 10 units of PE yield 3.4 of FE delivered through the electricity grid on average, while in the IEA-EU 3.6 units are produced.2 In the IEA BLUE scenario, this sort of “end-use fuel switching” alone is expected to account for 15% of CO2 reductions. Distributed generation represents another domain of natural gas in the scheme of energy efficiency. The flexibility of gas allows it to be used on any scale from large centralized power plants to medium and small plants that can be strategically placed to reinforce the electricity grid. This can have the effect of lowering losses due to shorter transmission distances and less congestion, but also minimizes the requirement of electricity grid expansion and associated capital expenditures. Perhaps more significantly such a system allows for the greater usage of waste heat for industrial processes or district heating/cooling via systems of combined heat and power (CHP). These factors combined further demonstrate the ability of natural gas to contribute to efficiency efforts. The largest opportunity for natural gas in the scheme of energy efficiency is likely represented by CHP. Such systems make use of 1 2

IEA Energy Balances ibid

the waste heat from electrical power generation for industrial process heat or district heating and cooling. Through the advent of adsorption chillers, waste heat can also be used to generate cold water for district or process cooling. According to the IEA around 2/3 of fuel used to produce power on a global scale is wasted and CHP, through better utilization of waste heat and the lowering of transmission losses, has the potential to more than double this efficiency. In general, CHP plants convert 75-80% of the fuel source into useful energy, and those with the most modern technology have achieved efficiencies in excess of 90%. This figure stands in contrast to the ~60% efficiencies achieved by only the most advanced combined-cycle gas turbine (CCGT) power plants, representing the cutting edge in thermal power plant efficiency. CHP plants also deliver on an additional selection of policy objectives including reduced emissions of CO2 and other pollutants, cost savings for energy consumers, and a reduced need for transmission and distribution networks. It must be noted that appropriate system design maximizing utilization of waste heat is necessary both in order to maximize the economic viability of CHP systems and achieve the efficiencies stated. If the system is driven by heat demand with electricity as a “byproduct” to be utilized on-site or injected into the grid system efficiencies can easily reach the previously mentioned levels. If the system is driven by electricity demand complete utilization of waste heat is not assured and thus system efficiencies are lower. An illustrative example can be found in the case of a steam turbine CHP system with a power efficiency of 38%, and “heat” efficiency of up to 42%. 3 Assuming maximal utilization of heat, an overall efficiency of 80% can be achieved. In a system driven by the price of electricity at times of high demand it is conceivable that only a portion (or even none) of the waste heat can be utilized, driving overall efficiencies as low as the 38% electrical efficiency. Thus, such a system could be economically viable but inefficient when compared with contemporary CCGT power plants. This example underscores the importance of proper system design in order to achieve theoretical efficiencies in the real world.

US EPA Technology Catalog

Natural gas has its final role to play in a sustainable energy system as a large-scale source of clean and climate-neutral energy in combination with CCS. CCS is currently being developed and scaled and will likely be ready in the medium term to make a significant contribution. In fact, the IEA expects CCS technology to deliver around a fifth of the 50% reduction of CO2 by 2050 in their Energy Technology Perspectives “BLUE Map Scenario.” Fossil fuels have their role to play in the energy system of the future and it likely that natural gas, being the cleanest among them, will only expand its role in power generation for the foreseeable future. Favorable characteristics are also displayed by natural gas in the context of the traditional energy paradigm include its large existing reserves, especially with their recent expansion due to the contribution of unconventional resources. Its scalability is also an advantage in that it can fit into the energy system on any scale from a small boiler for domestic hot water to a 1000MW power station. It is also traded on a large scale in liquid markets facilitated by its readily available delivery by pipeline or, increasingly, liquefied natural gas (LNG) carrier and the associated network of terminals. Production of renewable or “green” gas from such sources as biomass (via gasification), or agricultural waste (via biogas digesters) is also being pursued. Such gases can be injected into the natural gas network (after being upgraded to an equivalent composition) and take advantage of its existing infrastructure. One significant hurdle to the faster growth of renewable generation capacity is represented by their large, up-front costs. Although technologies such as wind and solar do not have fuel costs their capital requirements present an obstacle, particularly with the current economic climate characterized by limits in the availability of credit and liquidity. Investments in conventional generation technologies with a lower capital intensity thus often appear more attractive. Continuing with such investments in the cleanest forms of contemporary generation technologies thus make sense in allowing alternative technologies to become more commercially viable, counter intuitively allowing investments to leverage larger capacities of alternative generation in the long term. The shorter lead-time for construction of natural gas power plants (in comparison to coal and nuclear) represents another favorable characteristic in this context.

Table 1. External Costs of Electricity Generation Country

Coal/Lignite

Austria

Belgium

4-15

Denmark

4-7

Finland

2-4

2-5

France

7-10

8-11

3-6

5-8

1-2

Germany

Peat -

Oil

Gas -

Nuclear

Biomass 2-3

Hydro

Wind

0.1

1-3

1-2

0.5

2-3

0.1

2-4

0.3

0.2

0.6

0.05 0.25

Greece

5-8

3-5

0-0.8

Ireland

6-8

3-4

2-3

0.3

Italy Netherlands

3-4

1-2

0.7

0.5

Norway

1-2

0.2

0-0.25

Portugal

4-7

1-2

0.03

Spain

5-8

1-2

3-5*

0.2

Sweden

2-4

0.3

0-0.7

U.K.

4-7

1-2

0.25

0.15

* Biomass co-fired with lignites Source: ExternE

It is clear that conventional generation technologies and sources of energy will continue to expand and play a large role in the medium term. The question must therefore be asked: Which of the current energy sources are most feasible from an environmental, economic, and technical perspective? From a technical perspective, all of the current major technologies (natural gas, oil, nuclear, and hydropower) are well developed. Large reserves of coal and natural gas exist but those of oil are rapidly being depleted and the majority of suitable hydropower locations have been exploited. The EIA’s 2010 International Energy Outlook estimates a current reserves-to-production ratio (R/P) of 60 years for natural gas (excluding unconventional sources excepting those in the USA) and 129 years for coal. Uranium ore is widely available (R/P of ~60 years) but the future of nuclear power is uncertain, particularly considering that the recent Fukushima disaster in Japan is likely to have a long-lasting adverse impact on the acceptance of nuclear generation. Coal and natural gas are the most widely available and scalable in addition to being relatively cheap and requiring of low capital investment. Coal, in comparison to natural gas, exhibits significantly higher CO2 emissions and negative externalities including pollution (particulate matter, NOx, SOx,, mercury, etc). The EU project “ExternE” estimates externalities resulting from coal electricity generation in the EU

Negotiatory Antitrust: The E.ON Case The European Commission would do just anything to inject more competition into the deregulated, yet still very rigid, European energy markets. Often times it resorts to antitrust enforcement to intervene on the market structure. This results in pervasive structural remedies that bring about vertical or horizontal dismantling of energy incumbents, in line with the Commission’s liberalization policy. However, what triggers off and legitimates an intervention under competition rules are anticompetitive concerns and the antitrust remedies are there to remove these concerns. Once the Commission’s focus gets blurred by other policy objectives, i.e. energy liberalization, its intervention may well result in remedies that, while being generally pro-competitive, do not really eliminate the anticompetitive concerns, the very reason of its enforcement action. This article takes a closer look at capacity divestments closing the 2008 antitrust investigation against E.ON and questions whether they effectively eliminate the anticompetitive concerns of strategic capacity withholding. Introduction The enhanced intervention under competition rules started with an energy sector inquiry through which the Commission wanted to fully understand the functioning of the European energy markets and its problems. The extensive amount of data collected in this sectorwide in-depth investigation did not go down the drain: soon after the

(including global warming, public and occupational health as well as material damage, Table 1) at 2 - 15 Euro-cent/kWh, while those for natural gas are 1 - 4 cents/kWh. The IEA estimates that deaths per 10 billion kWh of electricity produced by coal range from 2.8 - 32.7, with those from natural gas falling between the range of 0.3 - 1.6. These include deaths resulting from mining accidents, explosions, pollution, and similar causes. Finally, a simple switch from coal to natural gas represents a reduction in CO2 emissions on the order of 50%. Renewables, despite recent rapid growth and development, still require time to scale from their current levels to a leading role in the provision of energy for humanity. They currently lack the flexibility necessary to optimize energy system efficiency in the near-term and scale to account for significant portion of primary energy in the medium-term. Natural gas is already well developed and integrated into the contemporary energy system but will additionally support the transition to a more efficient system in its new role. This role comes in the form of a flexible, clean, and reliable energy carrier in the supporting a sustainable energy transition based on renewables, energy efficiency, and clean fossil generation technology. Thus, although its function will evolve, natural gas has an increasing role to play in the provision of a sustainable energy supply for the continued advancement of humanity.

Malgorzata Sadowska1 P.hD student

inquiry a wave of individual antitrust investigations rolled across the energy business. In most of the cases the Commission claimed that the energy incumbents abused their dominant position in their respective markets. What we are talking about here are not standard infringement cases, where the Commission finds an abuse and arbitrarily imposes remedies. Instead, these are relatively quick settlements, antitrust deals, where undertakings, after some negotiations with the Commission, offer remedies (so called commitments) and if those are sufficient to address the anticompetitive concerns, the Commission agrees to close the investigation with no finding of abuse and in consequence, no further penalties. The idea to use antitrust rules to open up energy markets seems appealing, given the slow and troublesome process of energy liberalization via regulatory tools. These legislative difficulties arise partly due to significant political resistance in some Member States, Germany being a good example, and partly because the Commission simply lacks competence to foster competition in the energy markets through regulatory means. In these circumstances direct negotiations with energy incumbents under competition rules appear to be an attractive alternative, a way to achieve the desired regulatory outcome bypassing at the same time the difficulties in the liberalization process. However, these settlements are not antitrust anymore. They are a new phenomenon in the European competition enforcement. In these antitrust negotiations the Commission clearly uses its bargaining power to intervene on the energy market structure, something which

goes hand in hand with its energy liberalization policy. What results are extensive commitment packages, not really designed to address the anticompetitive concerns at issue but instead shaped by the Commission’s interest to introduce competition into the historically monopolized European energy industry. The 2008 antitrust investigation against E.ON provides a good example. This case concerned German electricity wholesale market. The Commission claimed that E.ON abused its dominant position by capacity withholding, i.e. output reduction, and in this way manipulated the electricity market clearing price on the German power exchange. To settle this investigation, E.ON offered substantial structural commitments, namely it agreed to sell off 20% of its generation capacity. In the following I will shortly explain how capacity withholding works to demonstrate that the divestment package offered by E.ON could not really fix the problem.

Price in Euro/MWh

P2 P1

tra

de -o ff

oil GT CCGT

coal hydro nuclear

lignite Q

Capacity in MW

The economics of capacity witholding Electricity is supplied by a variety of power plants, each having different production costs, according to the technology they employ. For the sake of efficiency we first call on stream plants with low production costs (like hydro or nuclear). These plants are cheap and can run all the time. When electricity demand rises more expensive power plants are dispatched. The market clearing price is determined by the production costs of the last plant needed to meet demand at a given hour. This price in turn determines the revenue of all producing generators at this given hour. Let’s suppose that one of the generators withholds some capacities (Figure 1). By doing so, he creates a shortage in supply which

Price in Euro/MWh

P1 GT CCGT gas coal hydro nuclear

lignite Q

Capacity in MW

Figure 1. Capacity witholding (schematic representation)

PhD Candidate in Law & Economics (EDLE), University of Bologna 1 (malgorzata.sadowska@unibo.it). This short article is based on M. Sadowska, “Energy Liberalization in Antitrust Straitjacket: A Plant Too Far?”, forthcoming in World Competition: Law and Economics Review, Vol. 34, Issue 3, September 2011.

must be filled up by more expensive generation called on stream as a second-best. In this way capacity withholding may result in a higher market clearing price (P2) and an inefficient dispatch. According to the Commission this is what E.ON could have done. However, capacity withholding is not as straightforward as one could think. It implies a trade-off between the expected mark-up earned from

Figure 2. Capacity witholding (schematic representation)

the price increase and the fall in output, as pointed out by the blue double arrow. In other words, a generator finds withholding profitable if its mark-up is higher than the loss incurred due to output reduction. However, the profitability of capacity withholding is far from clear in real market conditions. First off, the very design of the European Energy Exchange (EEX)3 is such that the market players – even if they wanted to manipulate the market price – would not do it by limiting their output, but rather by excessive bids. The generators do not submit plant-specific bids. Plants are chosen only after the market clears. An energy regulator or competition authority cannot really observe whether the bids reflect the production costs of the chosen plant. Hence, a market-savvy generator would simply submit a higher bid to raise the market clearing price rather than trying to manipulate outages.4 Secondly, the profitability of capacity withholding depends on various factors, the structure of generation portfolio being one of the key variables. For a profitable withholding a generator must own a sufficient number of low-cost plants generating and benefiting from the price increase. However, a base-load oriented portfolio is not enough to find withholding profitable. This is because low-cost generation may appear too costly to be withdrawn from the market. Hence, our generator needs also a certain number of higher-cost plants which would better suit for “planned” outages due to their lower shutdown opportunity costs. Let’s have a quick look at the E.ON’s generation assets. They reflect a cross-section of technologies covering all demand levels. Judging solely by its generation mix E.ON may have incentives to withhold capacities (50% share in base-load generation) and also ability to do this (coal and gas-fired power plants). Having said that, we can now ask the key question, namely, what kind of assets should be divested to effectively eliminate the risk of capacity withholding? And here is where the economics kicks in. It is widely accepted in the economic literature that the ownership of marginal generation (i.e. high-cost generation) confers greater market power than the ownership of base-load generation. It is in fact highly profitable to withhold capacities at periods of high demand (Figure 4, blue bracket). The merit order curve gets very steep, so even a small amount of capacities withheld results in a substantial price increase. At the time of low demand, on the contrary, a generator would have to create a serious outage to trigger off any price increase at all.

others

oil

gas

coal

lignite

hydro

nuclear

hydro 0

Figure 3. E.ON’s technologies as a share of its total generation capacity (in %). Source: own illustration based on data from E.ON, ‘Strategy and Key Figures’, 2008: 39-42.

2000

4000

6000

8000

10000

Figure 5. E.ON’s divestitures in each technology (in MW). Source: own illustration based on data from the Commission Decision of 26.11.2008 in case COMP/39.388 – German electricity wholesale market, Annex ‘Commitments to the European Commission’ (Schedule 1 and 3) and E.ON, ‘Strategy and Key Figures’, 2008: 39-42

others oil gas

before

coal

after

lignite hydro nuclear Figure 4: Merit order curve for Germany, 2008. Source: Serafin von Roon, Malte Huck, Merit Order des Kraftwerkparks. Forschungsstelle für Energiewirtschaft e. V.: München, Juni 2010 (Figure 3 at p. 3). Bracket added.

In line with this argument, some recent economic studies suggest that a targeted divestiture of high-cost generation is more effective in mitigating market power than a divestment of base-load plants. 5 Disposal of marginal plants flattens the individual merit order curve of a generator and therefore effectively reduces its incentives to use its assets strategically. Which assets have been divested in the E.ON case? Upper bars on Figure 5 represent E.ON’s generation technologies before the divestment. Short bars below the long ones indicate the divested shares in each of its technologies. It appears from the chart that E.ON sold a share of its marginal generation (gas and coal) but also plants down its merit order curve (lignite, nuclear, hydro). It wasn’t therefore a targeted divestiture, focusing on a particular technology, but rather an acrossthe-board one. Finally let’s have a look at the impact of the divestment on E.ON’s generation portfolio, as demonstrated by Figure 6. Comparing the shares of each technology in E.ON’s total generation capacity before and after divestiture we observe a striking result: they are virtually

Germany’s energy exchange. Thanks are due to Bert Willems for his insightful comments. 4 Crawford, Crespo and Tauchen (2007), Wolak and McRae (2008), 5 Federico and López (2009), Lave and Perekhodtsev (2001). 3

Figure 6. E.ON’s generation portfolio before and after the divestiture (in %). own illustration based on data from the Commission Decision of 26.11.2008 in case COMP/39.388 – German electricity wholesale market, Annex ‘Commitments to the European Commission’ (Schedule 1 and 3) and E.ON, ‘Strategy and Key Figures’, 2008: 39-42.

the same before and after the divestiture. This means that in fact the divestment had no impact on E.ON’s portfolio structure. Conclusion To sum up, the remedy in the E.ON case was an across-the board divestiture, amounting to a capacity reduction in absolute terms (by 20%) but having no impact on the generator’s portfolio structure. This critique does not mean that an across-the-board divestiture is not a procompetitive remedy. It does create competition. By selling off different technologies E.ON will face more competition on each demand level. However, it is questionable whether this remedy sufficiently addresses the problem of capacity withholding, the risk of which the Commission wanted to eliminate in the first place. Instead, the Commission targeted E.ON’s dominant position. It clearly wanted to reduce the firm’s market share in absolute terms and introduce competition in the market at each demand level. The remedy in the E.ON case changed the structure of the German generation market, in line with the Commission’s liberalization agenda. We are left with a question whether this is still competition policy or is it already liberalization policy. And more importantly, is it an effective policy to open up the European energy markets?

Simulating Energy Transitions Have you ever wanted to know whether a CO2 tax outperforms the EU emissions trading scheme? Or how long it really takes markets to change and to let consumers choose differently? We explored simulation models to provide us with answers before policy interventions are implemented and we showed that, by developing agent-based models, we can simulate energy transition. We demonstrate that agent-based models yield a powerful tool for governments and companies: they allow them to assess the long-term effect of their policies and strategies in our complex, interconnected world. In the 21st century, our energy infrastructure systems must change in order to secure the accessibility, affordability, reliability, and quality of energy services. This is due to the depletion of traditional resources, the threat of climate change, and globally increasing demand. Systemic change of energy infrastructures towards a more sustainable energy system is widely known as energy transition. Energy infrastructures are complex socio-technical systems that enable suppliers and consumers of energy products and services to connect in terms of physical connections and contractual agreements. Over a longer time period our energy infrastructures evolve. Every strategic decision or policy intervention is taken under deep uncertainty – we simply cannot predict the exact consequences of specific interventions, because we are dealing with complex evolving systems. At best we may explore trajectories of long-term development infrastructure and attempt to discern patterns of evolution emerging as a function of interventions. Using a complex socio-technical system’s perspective, we have defined transitions as “substantial change in the state of a sociotechnical system” .2 Although many authors claim that energy transition can be ‘managed’, suitable tests and indicators to monitor the progress of energy transition as a result of specific interventions – and therewith verify the viability of energy transition management – are lacking. Central is how to translate the broad notion of energy transition to systematic research questions and approaches that allow us to explore transitions and transition management, bit by bit. We have conjectured that we can increase insight into the possibilities for steering transitions in energy infrastructures by simulating the evolution and behavior of (subsystems of) these infrastructures. Such insight may contribute to an assessment of the viability of transition management, which we define as “the art of shaping the evolution of sociotechnical systems” 2. In the remainder of this paper, we provide some highlights from agent-based simulations and serious games.

Agent-based simulations Assessing the effects of transition management activities requires the investigation of structural change resulting from policy interventions. Agent-based modeling is the only modeling paradigm that allows for an emergent and changing system structure. We have developed a framework – a set of guidelines – to build such models. 3 In an agentbased model (ABM), actors are represented as computer-coded agents, having properties constituting an individual identity or management style. Agents are equipped with coded decision rules, some that deter-

Emile Chaplin1 PhD Student at TU Delft

mine their strategic decisions and some that determine their operational decisions. The term agent is, therefore, reserved for pro-active and autonomous components in the system. Markets are also represented as agents if they are institutionalized with their own rules according to which, for instance, prices are determined. Physical components are considered objects. They are represented as computercoded physical nodes/elements with properties regarding technical capabilities and flexibilities. Both social and physical components interact. Any intervention may affect the agents in the decisions they make. The structure and dynamics of the system emerge from the physical causalities governing the system and from the decision making rules of agents, which make them respond to policy interventions.

Simulation of the transition to a CO2-extensive power generation portfolio Three subsystems of the energy infrastructure were selected as case studies. Each of them is a complex socio-technical system in itself. Each case covers a specific segment of the energy value chain (production, transport, consumption) and specific interventions (policy measure, governance/no intervention, regulation). In this article, we describe one of those. The case discussed in this article is that of decarbonizing of the electricity infrastructure. 3,4 Significant reduction of CO2 emissions requires investment in clean(er) power generation technologies. The main question in this case is: will the transition to a CO2-extensive power generation portfolio be successful? The main objective of the modeling exercise is to compare and evaluate the different policies for CO2 reduction: carbon taxation (CT), emission trading (ETS) and no intervention. The objective is to compare as best as possible the merits of those three strategies. A quantitative agent-based model (ABM) was developed to simulate the evolution of the structure and performance of a hypothetical electricity market in the next 50 years using insights from microeconomics,

This article is based on: Simulating Energy Transition by E.J.L Chappin 1 2011 - ISBN: 9789079787302. PhD thesis Delft University of Technology, Published by Next Generation Infrastructure Foundation. Chappin, E.J.L, Simulating Energy Transition. 2011, TU Delft, Delft, The 2 Netherlands. Chappin, E.J.L and G.P.J Dijkema, Transition Management in Energy: 3 Design and Evaluate Transitions with a Suitable Simulation Framework in Energy and Innovation: Structural Change and Policy Implications, M. van Geenhuizen, et al, Editors. 2010 Purdue University Press. Chappin, E.J.L and G.P.J Dijkema, On the impact of CO2 Emission4 Trading on Power Generating Emissions. Technological Forecasting & Social Change, 2009. 76: p. 358-370. Chappin, E.J.L, G.P.J Dijkema and L.J.d. Vries, Carbon Policies: do they 5 deliver in the long run?, in Carbon Constrained: Future of Electricity, P. Sioshansi, Editor. 2009, Elsevier.

The system is represented in agents, markets, and physical installations (see Figure 1). The agents in the model, the power producers, need to negotiate contracts for feedstock, the sales of electricity and, in the case with emissions trading, emission rights. In the longer term, the agents need to choose when to invest, how much capacity to build and what type of power generation technology to select. Agents interact through the markets to negotiate contracts. In their investment decisions, not only financial aspects but also agent’s conservativeness, aversion to nuclear power and risk attitude are relevant. Despite the large weight of financial considerations, these individual style aspects have an effect, especially when financial differences interventions no intervention, emissions trading, carbon tax

system representation government implements policy scenarios demand, fuel prices technology

agent preferences

investment dismantling operation of power plants buy/sell

physical asset control investment divestment

power plants with all design, economic and physical properties

physical networks

social networks

Figure 1. Agent-based model of CO2 policies and power generation

between options are small. Conservativeness is modeled as ‘preferring more of the same’; risk attitude translates to different responses to historic variance of CO2 and electricity prices. In the model, power plants are characterized by their fuel type, costs, technical life span and fuel usage (conversion efficiency). The model includes an extensive set of ’state-of-the-art’ power generation technologies as well as technologies that are expected to be commercially available within 10 years time, most notably CCS.

Bidding on the electricity market is therefore modeled as bidding on ten smaller electricity markets, each with a different demand. Since the supply curve is the same on those markets, higher demand will result in the same or a higher price. The time step of the model is one year and the simulations span a horizon of 50 years. In each time step agents are allowed to perform their tactical actions, given the carbon policy active. In addition, agents will get the opportunity to invest. The order in which the agents make their investment decisions varies randomly and the decisions are modeled to match expected demand growth. The characteristics of the modeled system are emergent: the generation portfolio and merit order, fuel choice, abatement options, as well as electricity and CO2 prices and emissions emerge as a result of the decisions of the agents. The simulation results indicate that under a taxation scheme with an average tax level equal to the CO2-market price, emission reductions are accomplished faster and further, with less income transfer from consumers to producers (see Figure 2). The main reason is that the emissions trading scheme involves higher policy uncertainty than the carbon tax. Under emissions trading, the price on the CO2 market is volatile. Consequently, the incentive for abatement varies strongly over time: it is large when the cap is approached (or not met), and small otherwise. This is not the case for a carbon tax, which provides a more stable incentive. An additional effect is that on the electricity price. The effect of carbon policies on electricity price relates to CO2 emissions times CO2 price level. Under an emissions trading scheme, the CO2 price is higher when emissions are higher and, therefore, the effect on electricity prices is large. With a comparable carbon taxation this is not the case: a progressive tax can provide a low tax level at high emission levels and a high tax level when emissions have dropped to reasonable levels. The result is a much more affordable carbon policy. At the end of the day, in a taxation scheme with an average tax level equal to the CO2-market price, emission reductions are accomplished faster and further. 120 CO2 Emission (Mton/year)

market design, agent theory, process system engineering and complex system theory. An ABM represents a set of interacting ’agents’ with certain properties who live in an external world whereupon they have no influence, an agent-based paradigm that matches the electric power production sector, where independent power producers, governments and consumers can be considered agents that compete and interact via markets.

100

No intervention

80 60 Cap

Emission trading

40 20 0

Carbon taxation 0

20 25 30 Time (year)

Figure 2a. Simulation results

The electricity demand profile consists of 10 steps per year that reflects a typical load-duration curve, in order to reflect the different emissions levels, costs and operating hours of the different power plants.

players learn to analyze the impacts of policy instruments and policy uncertainty upon investors. Experience indicates that the simulation game creates a high level of involvement by participants, which results in much deeper insight than more traditional didactic methods. Furthermore, the improved understanding that the game provides has been successfully used to augment insights from agent-based simulations. Participants were able to understand results and insights from agent-based models faster and better.

Electricity prices:

Price (euro/GJ)

Emission trading

140 Carbon taxation 120 No intervention

100 80

Conclusion and outlook

CO2 market price

60 40

20 CO taxation level 2 0

20 25 30 Time (year)

Figure 2b. Simulation results

Serious game of CO2 and power markets For the same case we developed a serious game in which the agents are replaced by human players, which was demonstrated to facilitate the knowledge transfer from the modelers to the target audience (see Figure 3). This game was originally developed for educational purposes 6 : to help students, market analysts and policy makers understand the short and long-term dynamics of electricity markets. Small groups of participants play the roles of competing electricity generation companies. They need to bid their electricity into a power exchange and decide about investing in new electricity generation capacity. However, they operate in an uncertain environment: they do not know their competitorsâ&#x20AC;&#x2122; strategies, and fuel prices, wind and the availability of their assets vary. During the game an emissions trading scheme can be implemented, which effectively changes the rules of the game. This way,

We conclude that we can assess the long term consequences of policy interventions in evolving energy infrastructure systems. This can be done by analyzing the outputs of agent-based models which have been systematically developed using the modeling framework we developed. In order to assess the viability of transition management, a necessary ingredient is that they represent the socio-technical system in a way that assessment of the effects of interventions is possible. Agent-based models (ABMs) are suitable to simulate energy transitions, because they can capture change in the system structure and dynamics. Insights gained from ABM simulations show advantages and disadvantages of specific policy interventions in energy infrastructures, by showing the variability in the long-term effects on the affected energy systems. With the models developed, we have shown cases where a specific intervention affects the many distributed decisions taken by relevant actors in a way that is likely to alter the dynamics and the structure of the socio-technical system along a desired trajectory. ABMs can determine likely effects of interventions without claiming to perfectly predict future states of socio-technical systems For more information, please send an e-mail to e.j.l.chappin@tudelft.nl or go to www.chapping.nl.

Figure 3. Serious game of CO2 and power markets

De Vries, L.J., E. Subramahnian, and E.J.L Chappin, Power games: using an electricity market simulation game to convey research results. in Proceedings of the second International Conference on Infrastructure Systems 2009 (INFRA 2009): Developing 21st Century Infrastructure Networks. 2009. Chennai, India.

Hurdles to large scale biogas production in the Netherlands Natural gas is the major primary energy source in the Netherlands. It makes up 45%1 of the Dutch primary energy mix. In total 48.8 billion cubic meters (BCM) of natural gas are consumed in the Netherlands in 2010. In addition to being the cleanest of the fossil fuels and the most flexible back up for renewable electricity it has also greatly contributed to the wealth in the Netherlands. In 2010 gas revenues for the Dutch government totalled around €10 billion.2 The need for renewable gas production Globally, there is a consensus that we should move towards a low carbon economy. In order to do so, also CO2 emissions related to the Dutch energy supply need to be reduced. Natural gas has the lowest CO2 emission in comparison to other fossil fuels. Nevertheless it is necessary, due to its prominent position, to take gas into account in the attempt to decarbonize the energy mix in the Netherlands. By producing biogas from organic material, we shorten the carbon cycle by several million years. While natural gas is formed by organisms and organic material that have sedimented millions of years ago, the carbon cycle of biogas is only as long as it took for the organic material to grow. The CO2 absorbed by this organic material is released again upon combustion of the gas, but no additional CO2 is emitted to the atmosphere. In addition to the common realization that we should decarbonise, we are also obliged to do so by the European Union. The renewable energy directive (2009/28/EC) states that the share of renewable energy sources in the gross final consumption of energy needs to be 14% in 2020 for the Netherlands. In 2009 natural gas consumption totaled 48.8 BCM of natural gas in the Netherlands. If decarbonisation of natural gas is to proportionally contribute to the renewable energy production target we would need to produce more than 6.8 BCM of renewable gas. At this moment only 0.318 BCM of biogas (natural gas equivalent) is produced (0.65% of total gas consumption). The largest part of this gas is directly burned in a combined heat and power installation (CHP). Currently only 0.037 BCM is upgraded to natural gas quality (green gas), or 0.076% of total gas consumption. It is clear that at current production levels renewable gas will not provide a proportional contribution to achieving the target. It is of course possible to compensate for this shortage of renewable gas production with other sources of renewable energy, such as renewable electricity. Taking into account the large percentage of gas in our primary energy mix however, it will be extremely difficult to compensate the shortage of renewable gasses with other sources. In this article I will try to analyze the main hurdles to large scale biogas production in the Netherlands, and discuss whether renewable gasses can provide a serious contribution in our quest to achieve the Dutch renewable energy production target as stated in the renewable energy directive.

Biogas or green gas? Gas produced through anaerobic digestion is called biogas, when the gas is cleaned and upgraded to natural gas quality it is called green

Steven von Eije Energy Analyst at Energy Delta Institute

gas. As mentioned, a large part of the biogas that is produced is not upgraded to green gas. The reason for this is twofold. In the old subsidy scheme, ‘the environmental quality of electricity production (MEP)’ the focus was on renewable electricity production. Biogas producers were incentivized to convert the biogas into electricity by using a CHP installation. In case the heat would be fully economically utilized, this is the best option from an economic as well as from energetic and environmental viewpoints. The biogas would then replace an equal amount of natural gas (based on energy equivalent). Since in most cases, the heat cannot be fully economically utilized, the old subsidy scheme was (in many cases) incentivizing a suboptimal solution. In case the heat cannot be used, it is best to upgrade the biogas to green gas.3 In order to upgrade biogas to green gas the contaminants present in biogas need to be taken out. The most predominant ones are H2S, NH3, excess water and siloxanes. Biogas also has a lower energy content per m3 than natural gas. In order to increase the energy content of biogas, CO2 is removed, until the gas has the same Wobbe index as natural gas. The equipment for cleaning the gas and removing CO2 demands a substantial capital investment and the process consumes energy. This makes green gas more expensive than biogas. In order to move from a small scale subsidized industry into a large scale mature industry, enough demand needs to be secured for the renewable gas. Since the gas is usually produced in more rural areas due to a larger availability of biomass, it is often impossible to find enough economic/efficient heat demand. Therefore a large part of the gas needs to be upgraded to green gas in order to secure sufficient economic/ efficient demand. In case green gas is injected into the national distribution grid, demand for the gas will not pose a problem. Users that are connected to the grid will in general use the gas for an optimal end use since they have to pay the market price for the product.

Subsidy for green gas production Both the issue of incentivizing only electricity production from biogas and the issue of higher costs for the production of green gas are now recognized in the new subsidy regime which is called ‘Stimulation of sustainable energy production’ (SDE+). The new subsidy scheme subsidizes both renewable electricity production and green gas production. The producer can therefore decide on the optimal end use, instead of being incentivized to convert biogas into electricity. The SDE+ compensates for the higher production costs of green gas, providing a subsidy of €0.62 - €1.04 per Nm3, depending on the tranche of the subsidy scheme in which the subsidy is requested. In the SDE+ scheme there are four tranches in which producers can apply for a subsidy. The first tranche will offer the lowest subsidy and the last tranche will offer the highest subsidy. This is done in order to stimulate http://www.energydelta.org/mainmenu/edi-intelligence/ 1 interactive+world+gas+map http://gasterraverslag.nl/2010/nl/jaarverslag/ 2 http://www.r-e-a.net/document-library/policy/policy-briefings/Biome3 thane%20Injection%20full%20REA%20briefing%20F.pdf

the most cost effective production methods. An aspiring producer could wait until a later tranche, to receive a higher price per Nm3 while accepting the risk that the next tranche is never opened due to a limited budget in the SDE+ scheme. With the help of this subsidy it should be possible to increase the amount of green gas production facilities. The budget made available for all sources of renewable energy production in 2011 in the SDE+ scheme is €1.5 bn. This budget should cover the difference between the price received in the market for the renewable sources of energy produced and the cost price of producing this energy. Since this budget is available for all sources of renewable energy production, only part of this budget will be available for green gas production. Taking into account that in the wholesale market around €0.25 is paid for a cubic meter of natural gas, and assuming that all green gas producers would request subsidy in the first tranche, per m3 of green gas, €0.62 - €0.25 = €0.37 subsidy is available. The total amount of subsidy needed for the production of 14% green gas, in comparison to total gas consumption in the Netherlands would then amount to €2,516 bn. In order to decarbonise 14% of the gas consumption in the Netherlands through green gas production, the 2011 SDE+ budget would be €1 bn short. In practice the shortage of subsidy is much larger, since the SDE+ budget is not only available to green gas producers. Besides the subsidy, green gas producers can also benefit from the revenues of selling green gas certificates. In order to receive the green gas certificates the producers need to meet the requirements as they are set by Vertogas, the issuing organization for green gas certificates in the Netherlands. Green gas certificates can be sold in the market to parties that are willing to pay more for renewable gas than for fossil gas. This will generate additional revenue from green gas production. These certificates could stimulate large scale production of green gas.

Biogas production It is cheaper to produce biogas instead of green gas because it does not need to be upgraded to the same extent. It may therefore be interesting to use biogas directly to satisfy local heat demand. As opposed to green gas and renewable electricity production, there is no subsidy available for biogas production. This might induce a biogas producer to upgrade the biogas to green gas, even though there may be a more optimal solution available in the form of burning the biogas directly in order to satisfy local heat demand. In case there is no local heat demand available, it would also be possible to transport the biogas through a dedicated pipeline to a not too distant location where heat demand is available. Unfortunately no green certificates are available yet for biogas that is used to replace heat demand locally. To realize the green value of the biogas it would be desirable to devise a reliable certification scheme for biogas.

Availability of biomass In the 2007 report ‘Full gas ahead’4 the estimate of the green gas potential in the Netherlands in 2020 is estimated to be between 2 and 3 BCM. This assumption is based on full utilization of available domestic biomass. In a more recent report 5 a very thorough calculation has been made about the available domestic biomass, and the forms of energy

conversion they could be used for. Since the calculations are made for the year 2020, four scenario’s are used. In the two most sustainable scenario’s the biogas and green gas production are the highest. In the so called strong Europe scenario, a total of around 38 PJ biogas will be produced, this is equivalent to 1.2 BCM biogas (natural gas equivalent). Out of this total, 25PJ would be used in CHP engines and 13 PJ would be upgraded to green gas. In the regional communities scenario a total of 39 PJ biogas will be produced, this is equivalent to 1.23 BCM biogas (natural gas equivalent). 29 PJ will be used in CHP engines and 10 PJ will be converted to green gas. It is clear that in both scenarios the availability of biomass is an important hurdle to green gas production. This can in part be solved by importing biomass, this will however raise the costs of biomass and reduce availability in other countries that also need to achieve renewable energy production targets. In addition the transport of biomass will have associated CO2 emissions which could partly offset the environmental benefits.

Acceptability of using biomass for energy production In a recent report of the foundation ‘Natuur en Milieu’ (nature and environment)’ 6 an analysis has been made about the sustainability of green gas. One of the conclusions of this report is, that even though the term green gas suggests that gas produced from biological materials is a good thing for the environment, this is not necessarily always the case. The report advises that sewage waste, landfills and organic waste from households are always sustainable sources for biogas production. The report further details that for other sources of organic material it should be considered if they cannot be used for feedstock or for food, or other applications which have a higher added value. If this report is widely accepted, large scale production of biogas will not materialize because of a further reduction of available feedstock. The reasoning behind the advice is that biomass should be used there where it has the highest added value. The use of biomass for energy production does not necessarily have the highest added value. As a matter of fact, energy production is ranked as the lowest added value for biomass in the report. Biomass should firstly be used for the production of pharmaceuticals and fine chemicals, secondly as food and feed, thirdly for the production of various chemicals, and only after it is not suitable for all of these end uses, it should be used for energy production. In a perfect market this allocation of biological materials to the product with the highest added value would automatically take place. This process may, however, be distorted by subsidies. We have already witnessed this in the case of biofuel production, where high subsidies were given in order to increase biofuel production. This incentive resulted in increased food prices, making food unaffordable for the poor. While other renewable technologies, especially concentrated solar power, are rapidly becoming less expensive, for biogas the opposite trend can be noticed. This is due to an expected increase in the cost of biological materials necessary for biogas production due to a higher Platform nieuw gas., Vol gas vooruit! De rol van gas in de Nederlandse 4 energiehuishouding. April 2008 Koppejan J., et al. , Beschikbaarheid van Nederlandse biomassa voor 5 elektriciteit en warmte in 2020. November 2009 Wiskerke, W., Helder groen gas. Een visie op de duurzaamheid van groen 6 gas. Natuur en Milieu. Mei 2011

demand for biological materials from other end uses. The higher price of input materials could well become a bottleneck to large scale production. This may be partly off-set by progressing on the learning curve as far as the production process and equipment is concerned.

Feedstock of dependency of producers

are very strict regulations to adhere to. The permitting process thus forms an appreciable hurdle to rapid expansion of the number of biogas digesters.

Production costs of natural gas

The biomass waste streams may be available for free at the moment the final investment decision for a biogas digester is taken. As soon as it is built, this will create an uneven power base for the supplier of waste streams. This supplier could decide to no longer deliver the biomass waste streams for free. The owner of the bio-digester would have to choose between a higher price for his input materials, or not producing at all. At the start-up phase it is therefore necessary to agree on long term contracts for input material.

As described in the first paragraph, the Groningen field is a blessing to the Netherlands; not only do we have cheap gas available for domestic consumption, it also provides the Dutch government with around €10 billion per year. While this gas field is a blessing to the country as a whole, it just might be the reason that a large scale, mature biogas industry will not materialize in the Netherlands. At a price of around €0.03 - €0.04 per cubic meter to produce natural gas from the Groningen field, it is unlikely that biogas production could ever financially compete with natural gas production.

Digestate

Conclusion

In the case of co-digestion, energy crops, such as corn, are added to the digester to increase gas production. This practice increases the amount of digestate that is produced. In the Netherlands there are very strict regulations with regard to manure management. There is a maximum amount of minerals that is allowed to be applied to the agricultural land. In case of intensive livestock breeding this generates a local surplus of manure. With the addition of energy crops in the digester the total amount of digestate is also increased. Farmers that have excess manure often have to pay parties to get rid of their excess manure. This adds to the total costs of biogas production.

There are several hurdles to large scale renewable gas production. The main hurdle to large scale production is the availability of biomass, this hurdle will become even higher in case the report of the foundation ‘Natuur en Milieu (nature and environment)’ would be widely accepted. The manure legislation, the slow and strict permitting process and absence of biogas certificates are also inhibiting factors to large scale biogas production. Finally the low production price of natural gas may just prevent a large scale mature biogas industry altogether. These hurdles to large scale biogas production in the Netherlands indicate that replacing 14% of natural gas consumption by renewable gasses is very unlikely. By no means this article is meant to say that we should stop producing biogas. Biogas is one of the most efficient means of converting biomass into energy. In spite of the hurdles we should strengthen our efforts to produce a maximum amount of renewable gas, while keeping the environmental balance in mind and using only biomass that cannot be used for higher value added purposes.

Permitting process In order to build a biogas digester, a permit from the local government is required. Unfortunately it often takes a long time for an aspiring biogas producer to obtain a permit to build the digester and often there

Organizing Future Energy Systems for Reliability The reliability of energy infrastructures has organizational requirements. However, the perception of energy infrastructures as socio-technical systems has not yet made its way into the planning for future energy systems; while the technical and economic aspects of new renewable energy infrastructures are well-researched, the organizational structure required for their reliable functioning is not. So what are the organizational requirements of new renewable energy systems; and how to know? The Organizational Requirements of Reliability and the Challenge of an Energy Transition Modern economies greatly depend on the well-functioning of energy infrastructures. Without a reliable supply of energy, industrial machinery, household appliances, agricultural equipment, transportation,

Daniel Scholten1 P.hD candidate, TU Delft

communications, and PCs all come to a halt. Consequently, policy makers and industry incumbents have traditionally kept a close eye on reliability, i.e. “the ability of the system to deliver the product (or service) transported over the network without interruption and without deterioration of its quality” (CPB 2004, 18). Over the last decades our understanding of energy infrastructure reliability has undergone some profound changes. “Until about a decade ago, most infrastructures were run as public monopolies, dominated by an engineering culture, with an almost exclusive focus on the technical assets” (Weijnen and Bouwmans 2006, 127). This meant that “[a] ccident investigations remained largely limited to the discovery of the direct causes of accidents” (De Bruijne 2006, 52), i.e. the technical PhD candidate at the Delft University of Technology, faculty of Technology, 1 Policy and Management, section Economics of Infrastructures.

The realization that the reliability of energy infrastructures has organizational requirements has great implications for how we should think about planning for future energy systems. Not only do we need to consider which technologies to use and how to introduce them, but also how they should be operated to ensure infrastructure functioning once they are in place. These concerns may seem rather premature, but developing energy systems without planning for their functioning seems rather careless in return. Yet this is exactly what is happening. Consider in this regard the plans of governments for a transition towards more sustainable energy systems. While the technical development and market deployment of new renewable energy sources and carriers plus supporting technologies and infrastructures are thoroughly investigated in visions and roadmaps, the organizational requirements for their reliable functioning are often neglected. And if included, then organization is rarely linked to reliability concerns. Plans for solar panels, wind farms, or biogas rarely focus on how they may alter the interaction among producers, transmission and distribution operators, and retailers. This is also because technical solutions are often sought at the expense of exploring organizational possibilities. Unfortunately, it is not mere neglect that has caused our general disregard. There still exists a lack of understanding concerning the concrete relationship between the technologies and organization of infrastructures and its effect on overall system performance or reliability. Moreover, a “thorough understanding of how networks of organizations operate and coordinate their actions to reliably operate complex, large scale technological systems is lacking” (De Bruijne 2006, 72). So, what organizational structures may new renewable energy systems require; and how to know?

This PhD research picks up this challenge and investigates how to establish what organizational structures complement the technological characteristics of new sustainable energy infrastructures (in order to ensure their reliable operation)? It does so by first developing a ‘framework for alignment’ that may pinpoint the organizational requirements of new energy infrastructures and afterwards applying this framework on the case of a transition to hydrogen as a motor fuel in the Netherlands to illustrate its utilization and relevance. As we will see, answering this question serves many practical purposes beyond the immediate for reliability, such as aiding policy makers in overseeing the broader organizational implications of technical choices and assisting industry incumbent to sketch their role and responsibilities in future energy systems. R&D phase

O Diffusion rate

failures in pipelines, wires, pressure stations, generation plants, etc. caused by natural disasters, human errors, (lack of) maintenance work, and capacity overload. Latent causes of accidents were often neglected “if only because the far more subtle ways in which these factors caused accidents went largely unnoticed” (De Bruijne 2006, 52). Over the last decade however, the governance structure of energy infrastructures was dramatically altered because of liberalization, privatization, and unbundling. In the process, “the social network has become much more complex” as the number and variety of actors increased, their interests and responsibilities changed, and operational control was increasingly shared (Weijnen and Bouwmans 2006, 128). At the same time our understanding of infrastructures was altered. Insights about the interdependence and co-evolution of technology and institutions shaped our perspective of energy infrastructures as socio-technical systems (Nelson 1994; Murmann 2003; Perez 2001; von Tunzelmann 2003; Künneke and Finger 2006). In turn, our understanding of reliability changed. It became increasingly clear to researchers and experts that “accidents and reliability issues related to the operation of technologies, although perhaps directly caused by technical or human failures, often have deeper, less visible causes” (De Bruijne 2006, 52). Special attention turned to the impact of the organizational environment on technical failures. The occurrence of massive failures seemed to be largely dependent on adequate coordination among actors to prevent small mistakes from becoming big disasters; and the ability to communicate and coordinate in turn depended largely on the organizational structure within which energy producers, transmission and distribution companies, metering, regulators and consumers interact. Currently, researchers estimate that 80% of disasters in network industries are have human or organizational causes and only 20% are caused by design or other factors (De Bruijne 2006, 52). Contemporary disaster and safety management literature hence incorporates the perspective that organizational reliability is just as crucial to the safety of technical systems as the reliability of the equipment.

Early Market ph ase

Ma ss Market ph ase

Satu ratio n ph ase

Infra Reliable T

Time

Figure 1. The neglect of organizational dimension of reliability in infrastructure planning

Bridging the Techno-Organizational Divide Developing a framework for alignment starts by clearly identifying what is understood by infrastructure technologies and organizational structures. Technologies can be fairly straightforwardly be defined as all the technical assets or artifacts involved in the operation of an energy infrastructure. They are such tangible objects such as pipelines, wires, pressure stations, generation plants, control systems etc. Organization relates to the “context and forms of coordinative structures” among actors (De Bruijne 2006, 74). At its basic core, organizational structures are about the amount of actors involved in the operation of an infrastructure and the nature of their interaction (hierarchical/central or horizontal/decentral). 2 Typically, organizational structures are distinguished based on the degree of vertical integration involved (Williamson 1979, Harrigan 1984). A convenient categorization is provided by Provan and Kenis (2007). First is a form based on private contracting between all relevant actors (3 or more) in a decentralized way. Here, “every organization would interact with every other organization to govern the network” (Provan and Kenis 2007, 233-234). Second is a hierarchically, or brokered, form in which central coordination is done by one participant / single lead organization or an entity external to the network. Third and fourth, Provan and Kenis also hint at two possible semi-brokered forms, where one organization might take some key governance activities leaving others to network members or forms where (various) groups of network members take shared responsibility for certain governance tasks and no one member has any significant leadership role. The next matter to address is how to express technological characteristics in organizational requirements. Here I propose to take four subsequent steps. First, I start by addressing what technical functions are essential to system reliability for a given set of energy infrastructure In economic literature, a third variable is often present: whether actors are 2 public or private.

technologies. 3 A convenient starting point is given by Finger et al. in their 2006 article on the relationship between the degree of coherence between technologies and institutions in infrastructures and system performance. They distinguish between four technical functions that can be considered critical for safeguarding the technical complementarity and functioning of networks: interoperability, interconnection, capacity management and system management. Interoperability focuses on the “mutual interactions between network elements” and as such “defines technical and institutional conditions under which infrastructure networks can be utilized” (Finger et al. 2006, 11-12). Examples are the complementarity between energy sources/carriers and delivery systems, like voltage levels and electricity wires, or energy characteristics and application requirements, like natural gas quality and domestic boilers. Interconnection deals with the “physical linkages of different networks that perform similar or complementary tasks” (Finger et al. 2006, 11-12). Typically, local gas distribution pipelines or electricity grids need to be linked to national and continental transmission networks. This also includes transmission planning, i.e. the design of “system additions to maintain reliability and to minimize cost” (Künneke and Finger 2007, 311). Capacity management concerns the allocation of “scarce network capacity to certain users or appliances” (Finger et al. 2006, 11-12). Issues pertain to the operational balancing (the continuous regulation of energy flows, checking content quality, and real-time disturbance response), unit commitment and capacity utilization (who should get network access when and where, the facilitation of actual access, and deciding starting up and shutting down generation), maintenance scheduling, and the long-term planning of network capacity, production facilities, and energy sources (Künneke and Finger 2007, 310-311). Finally, system management “pertains to the question of how the overall system (e.g. the flow between the various nodes and links) is being managed and how the quality of service is safeguarded” (Finger et al. 2006, 11-12). This mostly comes down to the continuous aligning of supply with demand, both in quantity (over and under production and consumption) and quality (grey or green energy), and ensuring that the energy system is able to adapt to changing conditions (McCarthy et al. 2007, 2157). Technical Characteristics of Infrastructure

Critical Technical Functions

Coordination Requirements

Allocation of Responsibilities

Organizational Structure

Institutional Arrangements

Figure 2: own illustration

After the critical technical functions have been identified, the next step is to allocate who is responsible for each one of them. The entities42 identified for the operation of infrastructure systems (or those that are related to or otherwise influence it) are the general steps in the supply chain: generation, trade, transmission, storage, distribution, metering, retail, and applications. The question to be answered is simple: which entity/entities is/are responsible for the facilitation of a certain critical technical function? For example, operational balancing is the responsibility of the operator(s). Interoperability may be the responsibility of

all entities. To understand who is likely to be responsible for specific technical functions, the infrastructures of the current energy vectors are a helpful reference point. Hydrogen gas pipelines may transport hydrogen instead of natural gas, for example, but despite different pipeline material requirements might be operated very similar to natural gas from a coordination point of view. Once all critical technical functions have been mapped this way, an overall picture emerges that gives us some insights which entity(ies) are key and which relevant to a lesser extent. It also shows us the amount of entities involved per critical technical function. The third step looks at the stringency of the coordination requirements of critical technical functions. Is central coordination required or may control be left to individual entities? Key in answering this question is the work of Künneke et al. (2008) on aligning institutions to technologies in network industries. It is here where the gap between the technical and social or organizational dimension of socio-technical systems is bridged. They start by classifying the control mechanisms required to facilitate critical technical functions into the scope of control (system, subsystem, or component) and the speed of adjustment (the time in which they must be executed: immediate, short term, medium term, long term) they involve. These categories of scope and speed in turn, so they argue, can be related to specific transactional characteristics such as asset specificity, frequency of transaction, and the uncertainty involved. By utilizing these insights from the field of New Institutional Economics, operational requirements of technical systems are translated into their coordination or organizational counterparts. In the end, twelve (3 scopes x 4 speeds) so-called ‘modes of organization’ are distinguished based on a central, top-down vs. decentral, bottom-up divide. Obviously, the larger the scope involved and the shorter the time to respond, the more stringent coordination requirements and necessity for central control. In other words, by classifying the critical technical functions’ control mechanisms into their respective scope and speed, one can derive the degree of central coordination required. Finally, the results of steps two and three need to be brought together in order to generate the overall organizational structure required. Whereas step 2 provides us with an idea of which entities are involved in the facilitation of a particular technical function, step 3 sheds light on the coordination requirements among the involved entities. Two questions remain however. First, which combination leads to what organizational structure? Second, how to combine the outcomes for each technical function into one whole? Regarding the former, and to avoid the immense complexity of all possible combinations, if we simplify the criticality of technical functions into high and low (central and decentral) and simplify the allocation of responsibilities into categories of whether there exists a clear entity that is most involved above others or whether multiple entities are roughly equally involved in the facilitation of a technical function, we may link the four resulting combinations to the Technical functions are inherently different from ‘mere’ technical assets 3 or technologies. While the functioning of assets is a purely technical issue, technical functions focus on how varying assets work together. As this requires human attention, they allow not only a focus on a few key variables, but also the move towards the organizational dimension. I prefer to use the term entities over actors or organizations because we are 4 dealing with them as nodes and links in a technical system, each of which has to perform their task for the overall system to function. I do not see them as actors with their own interests, i.e. or having economic preferences that may be contrary to reliability considerations. Such considerations should not be part of an exercise to find the organizational requirements of technical functions.

Throughout the last decade the Dutch government has repeatedly stated its intention to make a transition towards a more sustainable energy system (NMP4, 2000). Consequently, a plethora of new renewable energy technologies have been developing under its energy transition framework as well as under ‘regular’ energy policy. One possibility in particular, a transition to the use of hydrogen as a motor fuel as developed by the Energy research Centre of the Netherlands (ECN) for the European Union’s (EU) HyWays project, presents an interesting and challenging case for framework exploration because it envisions the use of various hydrogen generation and transportation means, i.e. very different infrastructures, between 2010 and 2050. In the early stage (2010-2030 / 2020), hydrogen is deemed available in three early user centers of Rotterdam, Amsterdam and the ArnhemNijmegen area. Hydrogen is generated from natural gas by small-scale onsite reforming at retail sites and delivered by tanker trucks (after liquefaction) to those urban fuel stations further away from natural gas pipelines or those fuel stations along the main highways connecting the centers. In Rotterdam, industrial hydrogen is also used to fill local fuel stations. The early user centers are independent in terms of network, though hydrogen vehicles should be able to refuel in any of them. In the medium term (2030-2045 / 2035), big changes are estimated to occur with the development of a regional hydrogen pipeline system (starting from Rotterdam) that connects most of the West of the Netherlands (the broader Rotterdam area, The Hague, Leiden, the larger Amsterdam area, and perhaps even Utrecht and Breda-Tilburg, while the ArnhemNijmegen user center is still independent from it. In terms of produc-

Generation

Network

Production/ Conversion

Sources

Trade

Transmission

Storage

Application

Distribution

Retail (fuel station) / Conversion / Metering

Customer: Fuel Cell Vehicle Use

and/or

Niches (small appliances)

Stationary (CHP)

Fuel Cell Vehicles (ICE and Hybrids)

Underground

Metal Hydrides

Pressurized tanks (H2 gas and liquified)

Onsite production

Pipelines (H2 gas)

Electrolysis

Gasification (+ CCS)

Reforming (+ CCS)

Application

Storage

Transport

Production

Trucks (liquefied H2)

Sources

Alternatives (Nuclear, experimental)

Organizing a Hydrogen Fuel Infrastructure in the Netherlands

Hydrogen Infrastructure

Renewables (Solar, Wind, Biomass)

Regarding the second question, we should not simply throw all outcomes together; an eye needs to be kept on the organizational requirements of individual technical functions while the interrelation of entities in an energy system should not be forgotten. Some entities may need to work together for one technical function and not the other. To do justice to both, I propose to adhere to the following logic for putting the overall organizational structure together: those entities charged with the critical technical functions that require a centralized mode of organization should become the core entities in the overall infrastructure and those that deal with less critical technical functions may be vertically integrated with it, separated from it, or even be completely autonomous, depending on the degree of central coordination required. For example, the transmission operator is often the heart of an infrastructure because of the stringent needs posed by operational balancing, while the responsibilities of other entities are often defined in relation to it, though if technically possible they may operate independently from it. With this final step, the framework is finalized and we are ready to illustrate its utilization and practical usefulness.

tion, it is expected that large-scale central facilities replace onsiteproduction as the main means while coal and biomass join natural gas as potential sources. The proliferation of pipelines in and between cities and the necessity of large-scale hydrogen production to meet rising demand changes the role of onsite production and trucks delivery; whereas onsite production is likely to become only interesting in remote rural areas, hydrogen trucks may serve to both support the reach of onsite facilities in rural areas as well as extend the reach of pipelines and act as emergency capacity in case of demand and supply fluctuations in pipeline supplied areas. Finally, in the long term (about 2050 and beyond), a national pipeline network is expected to be in place that connects most of the Dutch cities in the West, South, and East. Only in the North may some onsite-production and truck distribution still be competitive / necessary. This national pipeline network now starts to become more complex however by the possibilities that interconnectivity offers to hydrogen producers wanting to reach markets. Hydrogen trade might be realizable from this point onward. Moreover, the use of renewable hydrogen sources also starts to become economical while the use of fossil fuels in large scale facilities diminishes or is subject to carbon capture and storage.

Fossil Fuels (Natural Gas, Coal, Oil)

four organizational structures. The result can be seen in table XX. Basically, if centralized coordination is required for a technical function and a single entity stands out as the most responsible, then the structure of a lead entity seems fitting. If however centralized coordination is required but many entities are involved roughly equally, then vertical integration seems best suited. Next, if criticality is low and a single entity is responsible for that particular technical function, a completely decentralized structure seems fitting as coordination is likely to be only occasionally required (if at all). Finally, the combination of low criticality and multiple entities that are equally involved seems to be best facilitated through common coordination in a decentralized setting. Of course, this is very black and white, but it nevertheless presents a guiding reasoning.

Figure 3. The hydrogen supply chain

With the technical roadmap presented, we are now ready to execute the framework’s four steps on its three snapshots. So what are the organizational requirements of hydrogen systems in them? A quick look at the 2020 snapshot will help to exemplify its application. In 2020 the critical technical function of interoperability seems the most pressing matter. Standards regarding hydrogen use, production processes (gas purity), and truck delivery need to be in place and upheld. At the same time planning for future production processes and transportation technologies is required to enable the roll-out of the roadmap. Interconnection has similar concerns. While the early user centers are independent, the linkages between onsite production and natural gas pipelines and onsite production and truck distribution need to be facilitated. An eye also needs to be kept on the intended future interconnection of early user centers local networks via the pipeline system to be built. Capacity management seems to be a non-issue at this point in time. There is no need for operational balancing in onsite production and truck delivery. Of course, unit commitment and maintenance scheduling may still be required for truck delivery, but the failure of a truck only has a limited impact on the function of the overall network, unlike with pipelines for example. System management is also of little concern at this point because domestic natural gas supplies and little consumption it should be rather simple to match supply and demand. On the other hand, some consideration should go to facilitating a co-development of demand and supply.

Regarding the allocation of responsibilities, onsite producers and truck distributors (where active) are involved in the daily operation of the infrastructure and responsible for all technical functions, except perhaps capacity management due to the lack of necessity for it. Regulators and retailers (fuel stations) play a secondary role because they do not actively operate the infrastructure, but are involved in setting standards, future planning, or otherwise influence operation. For example, retailers play a role in measuring demand and the planning for future fuel station locations while regulators may try to promote delivery of hydrogen to specific areas and check general compliance to standards. Their involvement in facilitating interconnectivity or capacity management is unlikely however. Regarding the coordination required, compliance to standards (interoperability) and facilitation of linkages (interconnectivity) takes place on the short term and within the entities (component level) and user center (subsystem level) respectively. The immediate term is not required due to the nature of truck delivery in contrast to the more stringent needs of a pipeline system. Regulatory checks of the compliance by entities however are system wide and need to be done on the short term as well. Interoperability is of primary importance at this early stage to ensure that all the various hydrogen technologies are operating complementary so that hydrogen vehicles are able to refuel at any fuel station in all of the user centers. The planning for future developments in contrast is a system wide long term issue for both. Capacity management can be largely ignored and where not involves no coordination; all possible tasks take place within the onsite or truck distribution entity (component level) and on the short term. System management is not much of an operational challenge considering the possibilities that natural gas offers for increasing or decreasing hydrogen production. Nevertheless, some medium-term monitoring and coordination to ensure mutual adjustment among the entities within a user center (subsystem level) might be useful to prevent major mismatches in demand and supply. Summing up, most issues are a matter of either monitoring and corrective action on the component level for daily operations or system wide coordination for long term planning. Both combinations of scope and speed do not necessitate central operation. Only interoperability, where standards need to be ensured across all user centers hints at the need for central coordination under a regulator. But that is corrective in nature; individual onsite facilities and truck companies remain responsible for operations. Finally, putting steps two and three together we may arrive at an overall organizational structure that seems caught somewhere between incidental interaction and common operation. On the one hand, the daily operation of the technical functions seems to involve the efforts of individual entities and do not require coordination as such. On the other hand, setting the standards for daily operations and planning for future developments seems to benefit from regular interaction. In other words, if 2020 would be the end-state for the hydrogen infrastructure, spontaneous coordination may well be sufficient. In that case it can be left to individual entities that occasionally interact to settle incidental contracts. However, since we know that the roadmap intends the interconnection of the early user centers, the switch to pipelines as the main network means, and large-scale production as a necessity to meet future demand, the coordination needs for the planning for this scenario do tend to tip the balance in favour of a form of common operation since it implies regular interactions to operate the hydrogen infrastructure.

Implications The framework of alignment as presented and applied above seems to have established the means to express the technological characteristics of renewable energy infrastructures in terms of their organizational requirements in light of ensuring reliability. This does not imply however that there is no room for improvement. In my PhD research there was considerable testing of the framework on existing energy infrastructures and comparison between the results and actual organizational structure. This led to the identification of a number of features of energy systems that deserved consideration. Matters such as network complexity, intensity of use, benefits of experience and routines, and the stable or rapidly changing nature of networks in which the infrastructure operates and/or expands all needed to be considered. Though they are not technical functions as such, these features affect the parameters of the functions and help shape the necessity and possibility for coordination. Consequently, they were incorporated into the framework, but their exact influence remains open to debate. Moreover, the framework in general seems to be attuned to a more mechanical operation of infrastructures; it remains to be seen how it will manage to incorporate the information management that for example smart grids seem to require. How to incorporate that into the overall organizational structure? Nevertheless, the current framework seems to provide a useful starting point. While the application of the framework manages to arrive at a complementary organizational structure of a hydrogen network anno 2020, the full potential of utilizing the framework only becomes obvious when the other snapshots are added. Without repeating the steps here, but having done them in the research, let me state that the suitable organizational structures in 2035 and 2050 are ‘hierarchical organization’ and ‘lead entity’ respectively. Combined they serve to create an organizational roadmap that complements the technical. This has some interesting implications. First, we can see that the reliable operation of new energy systems may have varying organizational requirements at various stages of development. The question becomes whether these organizational changes can be met. Introducing new technologies might prove to be considerably easier than changing sector organization, i.e. they way in which entities interact to coordinate for reliability. The lengthy and troublesome liberalization and privatization process are a case in point. The notion of organizational lock-in and path-dependency should therefore be included into planning roadmaps towards future energy systems. Moreover, in how far do techno-economic and organizational logic conflict? The HyWays roadmap was based on a desirable technoeconomic picture, but are different hydrogen options or development paths now preferable? Second, because the framework helps to set up an organizational roadmap, it can be used as a tool by policy makers to assess the organizational requirements and broader implications of technical changes in energy infrastructures while sector incumbents may reflect on their changing role and responsibilities (towards reliability) over time. This helps them make investment decisions. Contact details: room B2.170, Jaffalaan 5, PObox 5015, 2600 GA Delft, the Netherlands. Tel: +31-(0)15-2784708. Fax: +31-(0)15-2787925. Email: d.j.scholten@tudelft.nl

Books, reports and conferences Floris van Foreest, May 2011. Does natural gas need a decarbonisation strategy? The cases of the Netherlands and UK. Oxford Institute for Energy Studies. A commonly heard view from European gas stakeholders is that low carbon supply sources – renewables, nuclear power and coal with carbon capture and storage – on the scale necessary to achieve carbon reduction targets over the next decade will be unrealistically expensive, and that gas will inevitably become the “default” choice for future power generation. Floris van Foreest’s study challenges this assumption and asks whether natural gas needs a decarbonisation strategy, and what such a strategy might look like in terms of: carbon capture and storage, “renewable gas” and back-up for intermittent renewable energy. It specifically asks whether the natural gas industry can expect to prosper in a low carbon economy without making any specific decarbonisation commitments. With virtually all national, EU and NGO/academic energy roadmaps and scenarios projecting a declining share for gas in European energy balances, the industry needs to carefully examine both its assumptions and investments in relation to the carbon footprint of natural gas. This paper is available at: http://www.oxfordenergy.org/wpcms/wp-content/uploads/2011/05/ NG-51.pdf

Anil Jain, Anupuma Sen May 2011. Natural gas in India: An Analysis of Policy. Oxford Institute for Energy Studies. In 2010, the Indian government increased the price of ‘administered’ gas to more than double its previous level, in a significant policy change. This move, whilst appearing to signal a reduction in distortions on one side of the policy equation (that is, the price paid to gas producers by marketing and retailing companies), highlights distortions on the other side (the complex subsidy regime for prices paid by some gas users to retailers), essentially pushing the focus onto downstream consuming sectors. This paper argues that the transition in the gas sector is part of the larger movement of the economy from a centrally planned and administered system to one based on market principles. During transition, the situation cannot be understood simply in terms of the conventional paradigm of demand and supply being brought into balance by price. Demand and supply are influenced by different factors, but have been kept broadly in balance by the complex system of administered pricing and quantitative allocation. The resulting distortions have been spread across the gas consuming sectors – notably power and fertilisers. As distortions mount, parts of the system are modified, usually in the broad direction of liberalisation and reform. But partial reform often has the effect of displacing the problems, presenting further challenges, and requiring further changes. Large changes in the pricing and allocation of gas cannot therefore occur without finding other ways of addressing distributional objectives. The paper argues that official forecasts of demand and supply, although optimistic, are based on a ‘planner’s outlook’, and a better assessment of the role of gas may be found in the price competitiveness of gas with alternative fuels in its main consuming sectors. It draws from experience in the oil sector, where prices were liberalised in 2010 for all

but the poorest segments of consumers – thus in gas, the paper argues that there is a case for considering market prices in the gas sector, and providing the subsidy directly to the end-user in the fertiliser sector, where the distributional concerns appear most significant. The paper argues that although reforms are taking place, the current situation is essentially a half-way house, and it suggests ways forward from this through the resolution of specific problems on the supply and demand sides. This paper is available at: http://www.oxfordenergy.org/wpcms/wp-content/uploads/2011/05/ NG_50.pdf

Jonathan Stern, Howard Rogers March 2011. The Transition to Hub-Based Gas Pricing in Continental Europe. Oxford Institute for Energy Studies. This paper by Jonathan Stern and Howard Rogers argue that Continental European gas markets are moving inexorably from oillinked to hub-based pricing. Market prices for gas increasingly reflect a complex combination of national regional and global supply and demand for gas rather than oil products. An increasingly competitive European gas market created by third party access enforced by a combination of EU and national regulations means that any supplier refusing to supply gas at hub prices will lose customers. The commercial risk for utilities which are importing gas at oil-linked prices under long term contracts but forced to sell at market prices has become untenable. The European gas industry is in the early stages of a commercial paradigm shift away from oil-linked and towards hubbased pricing. This is likely to be accompanied by major changes in contractual arrangements including termination of many existing long term contracts probably involving significant litigation. This paper is available at: http://www.oxfordenergy.org/wpcms/wp-content/uploads/2011/03/ NG49.pdf

Clingendael International Energy Programme, April 2011. Seasonal flexibility in the Northwest European Gas Market. An Outlook for 2015 and 2020. Seasonality is a crucial feature of the gas industry. For Northwest Europe, the difference between summer and winter demand is larger for gas than for any other commodity. The ability to meet demand under severely cold weather conditions has been a key success factor in the development of gas markets over the past 50 years. As a sequel to a discussion paper on the European Market for Seasonal Storage, published by the Clingendael International Energy Programme in 2006, a review of the future need for seasonal flexibility has been prepared. This new review focuses specifically on the operational aspect of security of supply for the Northwest European market and addresses the question: “Will Northwest Europe have sufficient supply capacity to meet the cumulative demand over a severe winter in 2020?”

The current outlook for the supply of gas in Northwest Europe under serious winter conditions does not give rise to major concerns. For the Baseline Scenario and similar demand scenarios, supply options in addition to those currently under construction will need to be developed, but LNG may also have to play a role as a potential source for seasonal supply. The outlook is not alarming, but at least the additional contribution from the planned expansions and/or planned new storages will need to materialise if the balance is to shift away from possible discomfort in a severe winter. It should be noted, however, that the small seasonal differences in current forward prices for gas do not contribute positively to the investment climate for new storage, even though these only reflect the short-term market conditions and not the longer-term demand.

generate sufficient public concern to prevent its expansion in much of western Europe and parts of North America, even though the evidence suggests that these hazards are much smaller than in competing industries. Elsewhere, though, increased production of shale gas looks inevitable. A surge in gas production and use may prove to be both the cheapest and most effective way to hasten the decarbonisation of the world economy, given the cost and land requirements of most renewables. This article is available at: http://thegwpf.org/images/stories/gwpf-repoerts/Shale-gas_4_May_11. pdf

Under low demand scenarios such as the New Policy Scenario, there appear to be adequate options for winter supplies in a 1-in-20 winter up to 2020, even if further investments beyond those which we have assumed to be committed do not materialise. This paper is available at: http://www.clingendael.nl/publications/2011/201104_ciep_ energypaper_seasonal_flexibility_gas.pdf

International Energy Agency, May 2011. World Energy Outlook 2011. Are We Entering a Golden Age for Gas? Natural gas is a flexible fuel that is used extensively in power generation and competes increasingly in most end-use sectors. It offers environmental benefits when compared to other fuels. Gas resources are abundant, well spread across all regions and recent technological advances have supported increased global trade. However, there will always be uncertanties like lower economic growth, greater costs or other obstacles to unconventional gas production, higher achievements in energy efficiency, changes that improve the relative competitiveness of other fuels and more. On the other hand, uncertainty can also work the other way. Based on the assumptions of the GAS scenario, from 2010 gas use will rise by more than 50% and account for over 25% of world energy demand in 2035 - surely a prospect to designate the Golden Age of Gas. This paper is available at: http://www.iea.org/weo/docs/weo2011/WEO2011_ GoldenAgeofGasReport.pdf

Matt Ridley, May 2011. The Shale Gas Shock. Global Warming Policy Foundation Shale gas is proving to be an abundant new source of energy in the United States. Because it is globally ubiquitous and can probably be produced both cheaply and close to major markets, it promises to stabilise and lower gas prices relative to oil prices. This could happen even if, in investment terms, a speculative bubble may have formed in the rush to drill for shale gas in North America. Abundant and low-cost shale gas probably will â&#x20AC;&#x201C; where politics allows â&#x20AC;&#x201C; cause gas to take or defend market share from coal, nuclear and renewables in the electricity generating market, and from oil in the transport market, over coming decades. It will also keep the price of nitrogen fertiliser low and hence keep food prices down, other things being equal. None the less, shale gas faces a formidable host of enemies in the coal, nuclear, renewable and environmental industries â&#x20AC;&#x201C; all keen, it seems, to strangle it at birth, especially in Europe. It undoubtedly carries environmental risks, which may be exploited to

Upcoming conferences July 5-6 2011, Beijing, China Smart Grid Security China 2011 http://www.pyxisconsult.com/sgsc/ July 12 â&#x20AC;&#x201C; 13 2011, Bangkok Thailand Energy Efficiency Summit http://www.fleminggulf.com/energy/asia-pacific/energy-efficiencysummit August 22-23 2011, Singapore Managing Energy Price Risk http://www.energychiefs.com/energy-practitioner-series.html

September 22-23 2011, London, UK Financing the future of CCS http://www.eelevents.co.uk/ccs-2011/ September 26-27 2011, Abu Dhabi, United Arab Emirates Smart Grids & Smart Meters Summit 2011 http://www.fleminggulf.com/energy/middle-east/smart-grids-andsmart-meters-summit-2011 September 27-29 2011, Paris, France Gazelec 2011 conference (energy-decision-makers) http://www.gazelec2011.com/

September 4-7 2011, Istanbul, Turkey 10th International Conference on Sustainable Energy Technoliges http://www.set2011.org/ September 6-9 2011, Tianjin, China Renewable Energy & Grid Integration 2011 http://www.opplandcorp.com/grid-integration/ September 13-14 2011, Birmingham, UK The Energy Event http://www.theenergyevent.com/energy11/website/Default. aspx?refer=1 September 13-15 2011, Beijing, China Global Unconventional Gas 2011 http://www.gastechnology.org/webroot/app/xn/xd.aspx?it=enweb&x d=3TrainingConfer/Conferences/gug2011.xml September 19-20 2011, Moscow, Russia International Gas Technology Conference and Exhibition http://www.europetro.com/

EDI Quarterly is published in order to inform our readers not only about what is going on in EDI, but also and in particular to provide information, perspectives and points of view about gas and energy market developments. Read the latest developments in the energy industry, daily published on the website of EDI. Editor in Chief Catrinus J. Jepma Scientific director EDIaal* Editors Leo Hoenders Marius Popescu Nadezda Kogdenko Steven von Eije Jacob Huber 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 5248331 F +31 (0)50 5248301 E quarterly@energydelta.nl

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