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EDI Quarterly Volume 4, No. 1, April 2012

Editor’s Note

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by Jacob Huber

Welcome to the April edition of the EDI Quarterly! This issue features contributions on gas quality and smart grids. The issue of changing gas quality in the Netherlands is tackled from three different perspectives: the impact on gas turbines, harmonization on a European level, and the concerns of industrial users. The section on smart grids discusses dynamic and time-of-use pricing, perspectives of virtual power plants versus smart grids in Europe, possibilities for cooperation between gas and electricity infrastructure, and power to gas. The themes of the next Quarterly include security of supply and industrial symbiosis (with a focus on eco-industrial complexes). Should any of our readers be interested in making a contribution in either of these areas please contact us at the address that you can find below.

Contents EDI 2 The impact of variations in gas composition on gas turbine operation and performance 5 EU Harmonization of Gas Quality? 9 Gas quality; the orphan of the gas industry? EDIAAL 12 Microgrids or Virtual Power Plants - which way will Europe Turn? 15 The Discovery of Price Responsiveness - A Survey of Experiments involving Dynamic Pricing of Electricity

We hope that you enjoy all of the interesting contributions in this issue.

19 Smart Energy Infrastructure: Synergies between Electricity and Gas

quarterly@energydelta.nl

22 Power-to-gas – storage concepts for renewable energy General 27 Recent Publications

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The impact of variations in gas composition on gas turbine operation and performance As with all natural products, natural gas does not have a fixed composition. Until recently, however, the natural gas delivered to a fixed location tended to show only small variations in properties. With increasing international trading of natural gas, both through pipeline connections and liquefied natural gas (LNG) imports, the variability of composition is increasing. This has implications for the operation and performance of modern low emissions gas turbines. Current efforts to develop harmonised European fuel quality standards will influence the future range of gases that may be delivered.

Introduction

The European natural gas transmission system is made up of the transmission systems of different European gas companies linked by interconnections. Increased gas demand and depletion of traditional stocks are leading to a growing requirement for the transport of gas around the system and import of gas to the system. This has led to increased gas import from Russia and Eastern Europe and the Near East via pipelines, and from around the world in the form of LNG. A key parameter in assessing fuel quality is the Wobbe Index, and typical values experienced within Europe together with national specifications are illustrated in Figure 1.

By David Abbott Technical Consultant (Gas Turbine Combustion), E.ON New Build &Technology Ltd

Gas turbine fuel specifications

There is a common misconception that gas turbines can burn any combustible gas and that fuel variability is not a significant issue. It is true that there are gas turbines firing a wide range of gases including natural gas, syngas (from coal, biomass and wastes), steelworks gases (coke oven gas and blast furnace gas) and gases with high hydrogen content (such as refinery gases). However, individual gas turbines can only tolerate limited composition changes, depending on the gas turbine design and the set-up of the hardware and controls. Before the regulation of emissions of acid gases such as the oxides of nitrogen (NOX), gas turbines typically had diffusion flame combustors. These were very stable and tolerated wide ranges of fuel composition, but produced high NOX emissions. Due to regulation, most European power generation gas turbines installed since the mid 1990s have lean premixed combustion systems, often referred to as Dry Low NOX (DLN) or Dry Low Emissions (DLE) combustors. These systems are significantly more sensitive to fuel variations because their operation has been optimised for a narrow range of conditions to minimise emissions. For gas turbine operators, key issues are: • Efficiency • Operability and flexibility • Reliability • Emissions • Component Life All these may be adversely affected by variations in fuel composition, and gas turbine manufacturers provide operators with specifications of allowable fuels. Typically these are not published in the open literature and are often contractual documents applying to particular installations and cannot be referenced directly. Though these specifications are in principle installation-specific, there is a significant amount of commonality and typical requirements are outlined here.

Figure 1: National gas specifications and typical gas compositions

The Wobbe Index (WI), as used in Figure 1 is the most commonly used parameter for specifying the acceptability of a gas fuel and is typically defined as:

(Derived from References 1, 2 and 3 corrected to common reference conditions)

The range of compositions allowed by the national standards is much greater than the typical variation. The significant differences in national specifications cause problems for international natural gas trading, thus harmonisation of fuel quality standards may be desirable. To address this issue the European Commission (EC) issued a mandate in 2007 for the European Committee for Standardization (CEN) to draw up European Standards for gas quality. It is anticipated that these standards will be published in 2014-15 [4]. Before the EC mandate (in 2002) the European Association for Stream­ lining of Energy Exchange (EASEE) established a group, EASEE-gas, to “develop and promote the simplification and streamlining of both the physical transfer and the trading of gas across Europe”. EASEE-gas produced a specification [2] aimed at maximising the flexibility of gas transfer without compromising gas appliance operability. This formed the basis for the development of the mandated CEN standard.

Unfortunately WI is not a dimensionless parameter and depends on the units and reference conditions used. Different manufacturers and workers in the field use different definitions and reference conditions, thus care should be taken when comparing information from different sources. In this article the Wobbe Index is based on the gross (higher) heating value expressed in MJ/m3 at metering and combustion reference conditions of 15°C and 101.325kPa. For conversions between different reference condition see the ISO Standard [5]. The significance of WI is that for given fuel supply and combustor conditions (temperature and pressure) and given control valve positions, two gases with different compositions, but the same WI, will give the same energy input to the combustion system. Thus the greater the change in WI the greater the degree of flexibility in the control and combustion systems is needed to achieve the design heat input.

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Some manufacturers use modified definitions of the Wobbe Index that take into account the supply temperature rather than the reference conditions. This is useful from an operational point of view, but because the supply temperature is a variable these modified versions of the Wobbe Index cannot be used in fuel suppliers’ specifications. In addition to the WI, manufacturers also often specify limits on the Heating Value and other bulk properties of the fuel.

The fuel composition together with the air fuel ratio, flow properties (e.g. flow speed, turbulence etc), fuel placement and mixing quality have a significant influence on flame behaviour (flashback, blow-out, dynamics and emissions). The details of how these effects influence combustion performance depend on the details of the combustion system design and this is why different gas turbine manufacturers have different fuel specifi­­ cations and use a range of parameters to specify acceptable fuel quality.

Gas turbine manufacturers typically specify that their turbines are capable of operating over a wide range of WI and Heating Value. Ranges in excess of ±10% of mid-range values are normal. However, it is unlikely that this could be accommodated without re-tuning and some combustors may need minor hardware changes. For a particular gas turbine installation a range of ±5% of the tuned value of WI (and/or Heating Value) is typical. For some gas turbines a range as low as ±2% of the WI has been specified.

Considering the key parameter of Wobbe Index, Figure 1 shows the allowable range of Wobbe Index in several European countries; this varies from about ±4% to ±10% of the mid-range value, thus in many locations, fuels can be delivered that are outside the range typically allowed by the manufacturers. Historically this has not been a significant problem because the actual variation (Figure 1) has typically been less than about ±3% at most locations. However, with increasing fuel trading and import the variation is increasing and will continue to increase. This may be affected by the proposed harmonisation of European fuel quality specifications.

The detailed composition also affects combustion performance including flame stability, emissions, flashback and ignition properties. Manufacturers’ specifications account for such compositional changes in different ways, but typically specify maximum levels of higher hydrocarbons (ethane, propane, butane etc), minimum methane and/or maximum inerts. These specifications aim to ensure that the fuel gas is predominantly methane, and that gases which contain both high levels of inerts and higher hydrocarbons, but are still within WI limits, are not allowed. The allowable amount of hydrogen ranges from zero to greater than 10%. This may become important if proposals are implemented to store or transport excess renewable energy by adding hydrogen to the natural gas transmission system [6], [7].

Modern gas turbine combustion systems

Typically modern gas turbine combustion systems consist of a series of lean premix burners/injectors firing into one or more combustors. In the injector, fuel is introduced into a swirling air flow. The fuel injection is widely distributed and an air/fuel mixing zone is provided to ensure even mixing of the fuel and air. High quality mixing is essential to ensure an even temperature within the flame leading to low NOX emissions when operating under lean conditions. The swirling flow enhances mixing and generates the correct aerodynamic conditions for flame stabilisation.

Practical examples of the impact of fuel quality variation on gas turbine operation

Even within existing fuel variations, the impact on gas turbine operation can be detected and can be significant. The following examples are all using fuels within the allowable range for the UK shown in Figure 1. Examples of severe catastrophic damage to combustion components due to fuel issues are rare, but flashback and burner damage as shown in Figure 2 has been linked to high levels of higher hydrocarbons. For the type of burner shown, the gas turbine manufacturer has developed flashback resistant variants to eliminate this problem. However, there is still potential for flashback on some burners particularly with high levels of higher hydrocarbons or if proposals to add hydrogen to the gas transmission system are implemented.

The design must generate acceptable combustion performance by ensuring the flame: • stabilises at the burner exit at the upstream end of the combustor without propagating upstream into the mixing zone (flashback) or lifting from the burner and blowing-out • does not produce excessive combustion dynamics (see below) • has a flame temperature and temperature distribution which does not deviate significantly from design values (to prevent component overheating or excessive thermal stresses) • produces low levels of pollutant emissions Figure 2: Flashback damage to burners has been linked to high levels of higher hydrocarbons

Combustion dynamics (acoustic pressure fluctuations within the combustor) can occur in any combustion device, but lean premix gas turbine combustors are particularly susceptible. Because it is common, different manufacturers and workers in the field use different names such as pulsations, dynamics, acoustics, instabilities, humming, screech and others. Combustion dynamics occur due to the coupling of acoustic pressure oscillations in the combustion system with the energy release within the flame. These oscillations can reach high amplitudes and induce vibration in the combustor components. This leads to increased wear, reduced component life or in extreme cases catastrophic component failure.

A more common problem is the impact on emissions. NOX and CO emissions depend on factors including operating load, ambient conditions and fuel composition. NOX tends to increase with increasing WI and Figure 3 shows base-load NOX emissions over a three month period for four gas turbines at one location. These units are nominally identical, but differences in build-quality, ageing and tuning result in different emission characteristics. Although there is significant scatter due to changes in ambient tempera­ ture, pressure and humidity there is an upward trend in NOX for units A, B and C. The trend for unit D is less pronounced and is not statistically significant. This shows a clear impact of fuel composition on emissions,

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but even for similar machines the response to changes in fuel composition can be quite different.

source 2 eliminated the problem and allowed acceptable operation on both fuels. This illustrates that although it is a key parameter, the WI is not sufficient to properly characterise the fuel. Additional parameters are needed, but have yet to be universally agreed.

Figure 3: Impact of fuel composition on NOX emissions for four similar gas turbines Figure 5: Levels of dynamics as a function of load for two different fuels

Based on similar studies of gas turbines in the UK, estimates have been made of the increase in NOX that would occur if gas turbines tuned on a gas with a WI in the middle of the allowable range (Figure 1) were supplied with gas at the top end of the acceptable range. For properly configured and tuned power generation gas turbines, increases of approximately 10% of target emissions were typical with the range being 5 to 20%. Thus a significant margin has to be allowed for fuel composition changes when tuning a gas turbine, which is a balance between optimising emissions, dynamics and performance. The additional margin needed to guarantee meeting emissions targets may compromise dynamics and performance optimisation. High levels of dynamics can cause hardware damage which ranges from wear of joints and seals to catastrophic failure (Figure 4). Therefore, manufacturers typically specify maximum levels of dynamics.

Even within an acceptable WI range, the gas turbine control system must respond to rapid composition changes. In one example a gas turbine suffered several de-loads and trips due to high levels of dynamics. Further investigation showed that the high dynamics were due to the control system responding incorrectly to rapid changes in fuel properties and incorrectly distributing fuel. High rates of change are a particular problem for gas turbines using measured composition from gas chromatographs for control.

Discussion and conclusions

Manufacturers are increasing the fuel flexibility of new gas turbines and developing retrofit solutions to mitigate the risks associated with fuel composition variation. Operators need to be aware of these developments to ensure that the risks from future fuel variations are properly considered. The examples described show that operators also need to be aware of these issues to ensure existing turbines are appropriately tuned. It is clear from the examples that fuel composition variation impacts on gas turbine operation despite being within the allowed range in the UK National Transmission System and manufacturers’ specifications. Such examples are becoming more common as the variability in gas composition has increased and are likely to become more significant as fuel imports and international gas trading increase and specifications widen. They also show that parameters in addition to Wobbe Index are needed to adequately characterise fuel quality.

References

Figure 4: Burner damage following component failure due to excessive dynamics

Figure 5 shows the variation of dynamics with load for a particular gas turbine. This gas turbine can receive gas from different sources which have similar WI, but different proportions of higher hydrocarbons. Both fuels were within the turbine manufacturer’s specification. The gas turbine had been tuned on fuel from source 1 and operated well on this fuel. However, when operated on fuel from source 2, high levels of dynamics occurred above 95% of full load. To continue operation the turbine had to be de-rated with consequent loss of power and efficiency. In this instance, re-tuning the gas turbine on fuel from

1. W Groenendijk, The Global Gas Quality Perspective: The “European NGC” View, Presentation to Platts 2nd Annual Gas Quality/ Interchangeability Forum, Houston, 13-14 November 2006 2. EASEE-Gas, Common Business Practice, Number: 2005-001/0, Harmonisation of Natural Gas Quality, February 2005 3. EN 437:2003, Test Gases - Test Pressures – Appliance Categories 4. Kristóf Kovács, European Commission, DG Energy, Gas Quality Harmonization –the road ahead, Gas to Power Europe Conference, Berlin, 23 January 2012 5. Natural Gas - Standard Reference Conditions, European Standard EN ISO 13443:2005 6. K Altfeld and P Schley, Development of natural gas qualities in Europe, European Journal of Gas Technologies, Distribution and Applications, gwf-international, Issue 2-2011 7. NaturalHy website: www.naturalhy.net

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EU Harmonization of Gas Quality?

Within the European Union, each country has its own gas quality specifications, as a result of the way in which the gas industry in each country developed. Through the liberalization of the EU gas market, and increasing diversity in the gas supply, these differences in quality specifications are causing interoperability issues at crossborder points in the European transmission grid. Such issues form a potential barrier to the free flow of gases and this has become a subject of interest in the Madrid Regulatory Forum. Since the negative effects of gas quality variations on the behavior of end-use equipment is seen as the largest barrier to adopting uniform gas quality standards the technical association of the European gas industry (Marcogaz) set up a working group to evaluate the technical background of these effects. Initially, the working group examined the situation regarding domestic appliances and suggested that the EU approval regime for domestic appliances, in the framework of the Gas Appliance Directive (90/396/EEC, the “GAD”) that uses standardized test gases [1], could be an appropriate framework for harmonizing gas quality. This suggestion was ultimately adopted by EASEE-gas in 2005 as a basis for their voluntary Common Business Practice (CBP, [2]). The European Commission, desiring transparent and enforceable standards, has asked CEN to derive a harmonized set of specifications for H-gas. Towards this end, Mandate M/400 EN [3] has been issued. Core issues to be analyzed under the Mandate are technical aspects of harmonization of combustion parameters, specifically the analysis of limitations given by end-use equipment, and a cost-benefit analysis (CBA) of harmonizing combustion and non-combustion parameters. In this paper, a number of salient points will be argued regarding the differences in gas quality between countries, the necessity of harmoni­ zation via an EU-wide specification and if rigorous pan-European harmonization is desired, a possible way forward. Note that the arguments are deliberately intended to stimulate discussion regarding the content of gas quality issues and are not intended to represent the position of any stakeholders active in the harmonization effort. However, on occasion the point of view of the end user of gas will be argued. In the following, we shall rely on some of the output from studies performed under M/400, i.e., the GASQUAL study of domestic appliances [4] and the CBA [5] as well as some recent developments in the Netherlands [6, 7].

H.B. Levinsky DNV KEMA Energy and Sustainability And Energy and Sustainability Research Institute Groningen, University of Groningen

of fuel to air [8] vary directly with the Wobbe Index of natural gases. Particularly the fuel-to-air ratio is an important parameter in combustion performance, governing to a large degree combustion stability, ignitability and noxious emissions. However, the detailed composition, especially the combination of hydrocarbons other than methane, also impact combustion performance. Different hydrocarbons themselves have differing combustion properties, regarding among other things soot formation and spontaneous ignition which can manifest themselves in the various mixtures forming natural gases. In this respect the UK Gas Safety (Management) Regulations [9] contain composition-specific parameters regarding incomplete combustion and soot. Additionally, spontaneous ignition, leading to “engine knock” in gas engines, depends on the detailed composition of the fuel [10] and is a well-known limitation on the performance of this type of equipment. Below a few end-use aspects of the harmonization discussion will be identified that have received less attention in the CBA [5]. It will be useful for the rest of the paper to recall the ranges of gas quality considered in the discussion leading to M/400. Figure 1 shows the range of gas qualities in a number of EU countries in 2002 [11]; here, both the official ranges and the range of gases typically distributed are shown1. It has been observed [5] that some countries have wide official ranges, but distribute within a much narrower margin (e.g., Denmark and Germany), while the UK, for example, has a smaller official range, but distributes within the full band officially permitted. These differences were observed to pose challenges for interoperability of gas networks and are considered a potentially inappropriate barrier to the free movement of natural gas. As mentioned in the Introduction, the harmonized approval methods adopted under the GAD were suggested to be a reasonable starting point for harmonization [12]. The range of Wobbe Index proposed by EASEE-gas is also shown in the figure. Note that it is slightly smaller than the EN 437 range, wider than most of the formal Wobbe ranges, and wider than the typical distribution ranges by roughly a factor of two [5]. Since this wider range receives specific attention in M/400 and the subsequent studies performed under its purview, the EASEE-gas range will be considered here.

Technical issues regarding gas quality and end-use equipment General The notion of gas “quality” is poorly defined. The gas industry uses “quality” to denote all aspects of natural gas that are derived from their compositions. Some aspects have to do with pipeline operation, such as the content of corrosive compounds in the gas, detrimental to pipeline integrity, or the propensity to form liquids in the pipeline. Other aspects have to do with the response of end-use equipment. In the EU, the response of end-use equipment to variations in gas composition is usually characterized by the Wobbe Index, the calorific value of the gas divided by the square root of the relative density. The Wobbe Index is an important parameter for gas utilization equipment since, in combustion equipment not having control systems, both the thermal input and ratio

Figure 1. Ranges of gas qualities in a number of European countries in 2002, taken from Marcogaz [11]. Diamonds indicate the official ranges and filled circles typical distribution values, EASEE-gas range blue bar. Horizontal lines denote limit gases EN 437 for the H- appliances.

1 Here the Wobbe Index is taken at 15°C/15°C.

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The key issue is whether installed end-use equipment can accept this range with no deterioration in safety or fitness for purpose. The potential changes in combustion performance, and the possible consequences of these changes for the end-user depend upon the type of equipment. Domestic appliances Given the more than 190 million domestic appliances in the EU [4], it will be clear that guaranteeing the safe and effective performance of equipment in this segment with varying gas quality is crucial. The major issues raised by widening the range of Wobbe Index are related to safety; particularly increased CO emissions caused by an impending shortage of oxygen at high Wobbe Index and increased CO emissions caused by flame lift at low Wobbe Index [13]. The maximum CO emissions of domestic appliances are regulated but the degree to which the response of an individual installed appliance to a change in range of gas quality will result in exceeding the given (safety) maximum depends on its design, installation and maintenance history. Reliably determining the response of the entire installed population is a daunting task and is essentially impossible to do without large-scale field tests. Such field tests are logistically complex and extremely expensive. Instead, two of the recent studies on the effects of gas quality on domestic appliances used comparatively small samples. GASQUAL [4] assessed the robustness of predominantly new domestic appliances towards gas quality based upon the GAD test protocols and attempted to extrapolate the results to the installed base, making assumptions regarding the effects of maintenance. This study identified potentially sensitive classes of appliance for the range of gas qualities examined. Their results [4] suggest that new appliances are relatively robust towards gas quality variations but observe, using “worst case” assumptions, a “moderate” to “high” impact of gas quality on a significant fraction of the population of these appliances in the upper part of the EASEE-gas range. The report notes that much of the impact resulted from combinations of effects, such as high Wobbe Index coupled with varying gas supply pressure, and suggests ways of limiting this impact. Similar studies on used GAD appliances with known maintenance history taken from the field were performed during the UK Gas Quality Exercise (see [14] and references therein). Here it was concluded that widening the range of Wobbe Index outside the existing range (47.20 – 51.41 MJ/m3) would have undesirable consequences for safety and emissions. The costs to accommodate a wider range, i.e. ensuring that installed appliances could continue to operate safely, were judged to be excessive compared to the benefit of accepting it [14]. The additional question arises whether, aside from these empirical studies, the GAD appliances are suitable for such a wide range as a matter of principle. One aspect that should be addressed is that of the “safety margin” between the limit gases used in appliance testing (described in EN 437 [1]) and the range of gases intended for normal use. The range of distribution gases must be smaller than that used in the approval regime to allow for aspects such as production tolerances, the effects of weather conditions and normal wear and tear during the lifetime of the appliance. As an illustration of the magnitude of such effects, an estimate is cited of the effects of variation in atmospheric conditions [15] (air pressure, temperature, humidity) on combustion conditions in an appliance. As noted above, the major effect of gas quality on CO emissions is through the changes in fuel-air ratio caused by changes in Wobbe Index. Atmospheric conditions also affect the fuel-air ratio directly; differences between a warm summer day and a cold winter day lead to a change in fuel-air ratio of 10% [15]2. For the range of Wobbe Index under discussion, this is equivalent to roughly half of the approval band. Thus,

changes in atmospheric conditions “use” roughly 4.5 MJ/m3 of the margin within the band of 9 MJ/m3 between the limit gases. To maintain the fuel-air ratio of installed appliances within the ranges dictated by the limit gases, a Wobbe band of at most 4.5 MJ/m3 would seem warranted, consistent with the traditional distribution ranges quoted in [11]. Much large-scale utilization equipment, which is adjusted to local conditions during installation and maintenance, shows similar variations in performance with atmospheric conditions [16]. The assessment of the safety margin with respect to the limit gases has traditionally been left to the Member States. Different customs regarding installation, inspection and maintenance, for example, may have led to different margins; but there is currently no clear and objective definition of the size of this margin. To the author’s knowledge there have been no systematic studies investigating the actual changes in the response of GAD appliances to varying gas quality during the lifetime of the appliances, and certainly not on a scale necessary to guarantee the safety of the entire installed population in the EU. Since the first generation of GAD appliances is reaching the end of its technical lifetime (15-20 years), this is an opportune moment to examine this aspect. Recent developments in the approval regime [17] are anticipated to make a significant contribution to the explicit determination of the required safety margins, which would facilitate harmonization efforts. Also, harmonization of maintenance regimes, called for in [14], would aid these efforts further. Taken together, the results to date suggest the recommendation that an explicit examination of the procedures for appliance approval, installation and maintenance be undertaken to guarantee equipment performance, unambiguously, for a wide distribution range. Power generation equipment Gas engines and gas turbines are essential components for electricity production in the EU, and both types of equipment have specific sensitivities towards variations in gas quality [5]. For modern leanpremixed gas turbines, designed and optimized for low NOx-emissions, the rate of change during gas quality variations was identified [6] as a potential cause of operating instability, which can result in shutdown and even physical damage depending on the design criteria of the control system. While not seen directly as a safety issue, which is the framework of the discussion regarding domestic appliances, maintaining the stability of electricity production was attributed in the Dutch study [6] as having equal claim to priority. As mentioned above, engine knock is a performance limitation in gas engines and is sensitive to the details of the hydrocarbon composition of natural gas. References [5-7] discuss the consequences of widening the range of natural gases without consideration of the knock propensity of the fuel for stationary engines, including the concomitant decrease in fuel efficiency when engines are adapted to run on fuel with structurally poorer knock characteristics. Similar arguments may apply to natural gas vehicles, which have not been addressed to date. For such fuel-sensitive equipment, the range of gas quality that can be accepted by the installed equipment depends on the range of gas quality that was expected when the equipment was installed, which can differ substantially between the countries in the EU.

Harmonization of gas qualities; ways forward

From an end-use perspective, the CBA and the information cited there shows that there are significant technical and economic hurdles to adopting a wide gas specification à la EASEE-gas. Similar conclusions were reached in the Dutch gas quality exercise [6, 7] assessing the introduction of hydrocarbon-rich gases into the low-calorific-value domestic gas network. There, a more differentiated model [7] was used to estimate the costs involved in preparing the end-use market for a

2 The estimate in [15] neglects the effects of variations humidity; recent estimates [16] indicate that summer/winter variations in humidity can further increase the normal variations in fuel-air ratio caused by atmospheric conditions.

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wider band of composition. Although the assumptions are not entirely applicable to the current discussion, scaling the results of that exercise to the entire EU based only on numbers of appliances yields estimated costs of several tens of billions of Euros. To proceed with enabling harmonization to a wide band of gas quality, replacement equipment and modification schemes must be demonstrated to be adequate for the challenge. For some equipment, such as burners in MW-scale boilers, new control systems and adjustment procedures may be a straight­ forward solution [18], albeit at significant cost. For other large installations (such as industrial power plants, refineries, steel/ceramics plants and feedstock producers), which are often tailor-made for a given local situation, more investigation is necessary. Regarding the domestic appliances, thoroughness and transparency in the argumentation for the guarantee of correct performance during the lifetime of the equipment is required. As discussed above, adequate examination of the changes in performance of installed appliances upon aging, supplemented by an unambiguous exposition of the acceptable range of distributed gases given by the test gases in the approval process, possible adjustment of the test regime for the desired range of gases and harmonization of installation and maintenance practices are appropriate actions to satisfy this requirement. Once the equipment issue is settled, a timetable must be agreed upon for conversion. Logistical problems of individual examination, maintenance and/or replacement of (several tens of) millions of appliances aside, an important aspect of changing the equipment identified in [6] is the associated cost of rapid conversion versus using the normal replacement process (turnover or “churn”). Whereas rapid replacement, i.e. replace­ ment before the equipment is fully depreciated, could result in tens of billions of Euros in extra cost, replacement by normal turnover results in modest extra cost, since appliances must be replaced at the end of their lifetime anyway. This necessarily entails a transition period equal to the time for market churn, usually the order of the lifetime of appliances. However, given the prodigious effort described in [5] and above necessary to achieve harmonization, including any possible permanent deterioration in efficiency, fitness for purpose or emissions, we must return to the CBA to see whether any benefit is to be derived from this effort. Despite the uncertainties in the CBA regarding methodology [5], the modest benefit reported in the study stands out. The study seems to indicate that lack of harmonization does not impact the gas supply to the EU. If further analysis confirms these results (see below), they suggest that the restrictions between countries are overcome by shifts in supply patterns, for example between LNG and pipeline gas, at relatively modest cost. This raises the question: if the market overcomes the barriers due to different gas quality standards, what is the added value of EU-wide harmonization? One possible reason is to resolve interoperability issues. However, a simple analysis would suggest that most of the cross-border issues are intrinsically bilateral issues, which prior to liberalization were resolved bilaterally. Some of these issues could be ascribed to the assumption in the liberalization framework that natural gas is a fungible commodity, which the entire discussion surrounding gas quality shows it is not. Thus, as an example, one may wonder whether the interoperability problems arising from different Wobbe ranges in Belgium and the UK [5], necessitating gas treatment in Belgium even for gas that may not flow to the UK, may be resolved bilaterally by some regulatory flexibility, for example in recovering costs. This seems less unwieldy and less expensive for the individual consumer than rigorous EU-wide harmonization of end-use equipment. Another reason for harmonization is to accommodate “new” gases such as hydrogen. If the EU envisions a serious contribution of hydrogen as energy carrier and mixtures of substantial fractions of hydrogen with

natural gas as a widespread activity, then the harmonization of requirements for end-use equipment could be justified. Here too, the uncertainties involved in the vision of the future and the costs involved in rigorous change must be in balance to secure the willingness of the European end user to pay for this future.

Concluding remarks

Given the far-reaching implications of the benefit analysis, it would seem prudent to focus on refining the analysis of the potential gas flows and associated prices to assess more accurately whether EU-wide harmonization has a concomitant EU-wide benefit. In addition, whether long-term changes to the composition of the gas supply due to the introduction of sustainable gases such as hydrogen warrant large-scale harmonization should be analyzed.

Acknowledgment

The author wishes to thank M. van Rij for illuminating discussions regarding safety margins in the approval regime, and S. Gersen and M. van Essen for helpful discussions and assistance in preparing this paper.

References

1 CEN/TC238 (2006), EN437 Test Gases-Test Pressures-Appliance Categories 2 European Association for Streamlining Energy Exchange, EASEE-gas (2005), Common Business Practice, 2005-001/01 3 European Commision (2007), Mandate to CEN For Standardization in the Field of Gas Qualities, M/400 EN, January 2007 4 CEN-BTWG197 (2011), GASQUAL Deliverable D6.1 Conclusions on Domestic Appliances and Annex 6 “Impact by Country”, No. 308, available from http://www.gasqual.eu 5 GL Noble Denton and Poyry Mangaement Consulting (2011), Study on Interoperability-Gas Quality Harmonization-Cost Benefit Analysis, Preliminary Report for Consultation, July 2011. 6 H.B. Levinsky and M.L.D. van Rij (2011), Gas Quality for the Future, Part 1 (Gaskwaliteit voor de Toekomst, Deelrapport 1, in Dutch), report for the Ministry of Economic Affairs, Agriculture and Innovation, January 2011. Available at http://www.rijksoverheid.nl/ ministeries/eleni/documenten-en-publicaties/ rapporten/2011/03/28/gaskwaliteit-voor-de-toekomst-1.html 7 J. Klooster, E. Metselaar, G. Warringa, H. Levinsky and M. van Rij, Gas Quality for the Future, Part 2 (Gaskwaliteit voor de Toekomst, Deel 2, in Dutch) report for the Ministry of Economic Affairs, Agriculture and Innovation, March 2011. Available at http://www. rijksoverheid.nl/ministeries/eleni/documenten-en-publicaties/ rapporten/2011/03/28/gaskwaliteit-voor-de-toekomst-2.html 8 American Gas Association (1940), Research in fundamentals of atmospheric gas burner design, AGA Bulletin #10. 9 Gas Safety (Management) Regulation (1996), no. 551; available at http://www.legislation.gov.uk/uksi/1996/551/contents/made 10 S.Gersen, M.H. Rotink, G.H.J. van Dijk and H.B. Levinsky (2011), A new experimentally tested method to classify gaseous fuels for knock resistance based on the chemical and physical properties of the gas, 2011 International Gas Research Conference, Paper P3-18. 11 Marcogaz (2002), National Situations Regarding Gas Quality, UTIL-GQ-02-19 12 Marcogaz (2003), 1st Position Paper on European Gas Quality Specifications, UTIL-GQ-03-06. 13 C.E. van der Meij, A.V. Mokhov, R.A.A.M. Jacobs, and H.B. Levinsky, On the Effects of Fuel Leakage on CO Production from Household Burners as Revealed by LIF and CARS, Proc. Combust. Inst. Vol. 25, 1994, pp. 243-250. 14 Government Response to Consultation on Arrangements for Great Britain’s Gas Specifications, November 2007, available at http://webarchive.nationalarchives.gov.uk/20080102110728/ http://www.berr.gov.uk/files/file42425.pdf

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15 Marcogaz (2008), Main Effects of Gas Quality Variations on Applications, UTIL-GQ-05-04. 16 AgentschapNL (2011), Inventory of the Effects of Transition New Natural Gas for H-gas Users (Inventarisatie Gevolgen Transitie Nieuw Aardgas voor H-gas Gebruikers, in Dutch) available at http:// www.agentschapnl.nl/content/inventarisatie-gevolgen-transitienieuw-aardgas-voor-hgas-gebruikers 17 M.L.D. van Rij (2011), Action on (F)prEN 15502-2-1 :2012, New annex to be included related to variations in gas Quality; 24-08-2011, CEN/TC 109/WG 1 N 580 18 B.K. Slim, H.D. Darmeveil, S. Gersen and H.B.Levinsky (2011), The combustion behavior of forced-draught industrial burners when fired within the EASEE-gas range of Wobbe Index, J. Natural Gas Science and Engineering, Vol. 3 (5), pp. 642-645.

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Gas quality; the orphan of the gas industry? Summary

The creation of one harmonised quality regime for all gas applications in Europe is neither realistic nor necessary. Nevertheless, the Dutch authorities did not follow EASEE gas recommendations in 2005 but in fact anticipated them as if they would be in place as a future European regulation. As in other gas regions, gas quality should be user led, not supplier led, and be careful not to become politically led. Measures should result in the lowest social costs and must not infringe the polluter pays principle. Gas quality should not become an orphan to be raised by 80 H-gas consumers. Keeping gas quality issues where they belong, i.e. the TSO Gastransportservices (GTS), will strengthen the position of the Dutch gas industry.

Gas quality is an issue; however is not a new kid on the block

By letter on the 14th of October, 2009 GTS informed its consumers that the composition of natural gas would change in the coming years and requested them to start investigating the consequences and adjust their installations accordingly. In addition, GTS noted that the future composition of natural gas would comply with the legal specification in force. As far as High Caloric-gas (H-gas) is concerned, a new bandwidth between 49 - 54 MJ/m3 was communicated. For the Netherlands, the gas industry plays an important role. Knowing that Dutch gas reserves are in decline and the long term security of supply must be safeguarded, industrial consumers support initiatives to invest in infrastructure such as the GATE LNG-terminal, the Nord­ stream gas pipeline and new gas storage facilities. They also support the conclusions of the Gas Hub Consultation Platform: that a strong gas hub can contribute in a substantial way to lower gas prices1. The Dutch ‘gas roundabout’ can enforce the current gas infrastructure and may contribute to a competitive and affordable energy supply. The Dutch gas industry and its government must meet many challenges, but did they make the right choices regarding gas quality? And further­ more, did they properly examine the consequences and challenges confronting end-users? Gas treatment is normal practice for the gas industry. It enables the supply of gas with specifications related to the technical conditions of the applications of customers. Because the composition of natural gas is different for almost every gas source, the specifications in European countries and regions are therefore not uniform and are related to local or regional conditions. Importantly, it is based on these specifications that gas users designed their installations. It is common practice that the grid operator ensures delivered gas always meets the mentioned specifications at exit points.

Regulations governing gas quality must be set according to the European context

Common rules for the internal European gas market are published in the

Dirk Jan Meuzelaar Advisor for commercial and regulatory affairs at Utility Support Group, Chairman of the ‘Fuels Working Group’ at VEMW

Directive 98/30/EC2 and revised and repealed by Directive 2003/55/ EC3. This Directive aims at efficiency gains, price reduction, higher standards and increased competitiveness. In order to ensure efficient and non-discriminatory network access, the directive indicates that transmission and distribution systems should operate through legally separate entities. Discrimination, cross-subsidization and distortion of competition should be avoided. Apart from article 6 in the Directive, ensuring that technical safety criteria are defined, gas quality is not addressed. Unbundling of trade and transport led to confusion regarding which parties are ultimately responsibility for the gas quality. Thanks to the liberalisation, gas consumers are able to choose their own supplier or can buy gas on exchanges. As far as transport is concerned, entry and exit are decoupled. Consumers have no influence on the quality of gas they are receiving. In 2002 the European Association for the Streamlining of Energy Exchange-gas (EASEE-gas) was set up to optimize interoperability at cross-border points. Different requirements throughout Europe regarding gas quality specifications were considered to be a potential barrier to interoperability of gas networks. In 2005 EASEE-gas published its “Common Business Practice on Harmonisation of Natural gas Quality”4. This CBP recommendation was voluntary and limited to EU entry points for high calorific gas, including LNG import terminals. Among other parameters, the CPB recommended a Wobbe Index value range between 49- 57 MJ/m3(n). Most EASEE-gas members supported the recommendations of EASEEgas, but critical notes were sent by British stakeholders. Based on a study initiated by DTI on gas quality issues, the UK decided to keep its specifications unchanged at least up to 2020. They insisted that, for longterm implementation, several preconditions require safeguarding, such as safety for consumers, minimized impact on environment, optimized fuel efficiency, and appliance standards fit for purpose and minimised cost impact for customers5. French stakeholders, although supporting the CBP, stressed that “a cost-effective solution must be envisaged taking into account the domestic customer’s perspective and safety”. Moreover they mentioned that the treatment of LNG would be a cost-effective solution.6 In the European Gas Regulatory Forum (Madrid Forum, 2005), participants agreed that the CBP should not be applied without additional investigation. In 2007, the European Commission issued a mandate to CEN to draw up standards that define the minimum range to be accepted for gas quality parameters for H-gas7. The results of this study will be published in 2013. The second part of the study referred to the costs and benefits of gas quality harmonization on the whole gas supply chain. In this study it was concluded by GL Industrial Services and Pöyry Energy Consultancy that the “benefit to European consumers of removing the current gas quality constraints are at most € 0.2 bln per annum. However processing costs to meet local gas quality specifications

1 Gas Hub consultation platform, Position paper and recommendations on the role of gas in the energy mix 2 Directive 98/30/EC of the European Parliament and of the Council Official Journal L 204 , 21/07/1998 P. 0001 - 0012 , 3 Directive 2003/55/EC of the European Parliament and of the Council Official, Journal L 167, 15/07/2003 P. 0057-0078 4 EASEE-gas, Common Business Practice on Harmonisation of Natural Gas Quality, Number 2005-001/02. EASEE-gas CBP 2005-001/01 has been approved by the EASEE-gas Executive Committee on 3 February 2005 and published on 7 February 2005. EASEE-gas CBP 2005-001/02 has been approved by the EASEE-gas Executive Committee on 6 November 2008 5 DTI, Presentation European gas regulatory Forum, Interoperability; Report on the gas quality issue, 16 September 2005 6 Conclusions of the 10th meeting of Madrid Forum, 15-16 September 2005 7 Mandate to CEN for standardisation in the field of gas qualities, M/400, Brussels 16 January 2007

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and ensure appliances will operate safely is estimated at €11 bln. Alternatively, replacement of gas appliances would cost an estimated €179 bln8.” Hence, the costs of European gas quality harmonisation exceed the benefits by far.

Decisions and policy of the Dutch Government

The Dutch Government fully supported EASEE-gas recommendations with the remark that, in the longer term, technical adjustments may be needed in installations at customer sites9. At the beginning of 2005 regulated third party access (rTPA) was introduced in the Netherlands with publication of the first gas codes10. The gas quality paragraph in the Technical Conditions of this gas code allowed a range of the Wobbe Index between 47 - 57.3 MJ/m3(n) at the transfer points to the national grid11. This specification is much wider than the existing gas range in the Netherlands with variations between 49 – 54 MJ/m3(n) (except for a few hours in a 5yr period up to +- 54.5 MJ/m3(n) in IJmond and Delfzijl)12. Although there is no formal relation between EASEE-gas and the new legal specifications in the Dutch gas code, there are some remarkable similarities. The assumption that the Dutch authorities were convinced that EASEE gas rules would be implemented is reinforced by the communication of GTS to some large H-gas customers at the end of 2005 about what they called the ‘European EASEE-gas directive’ that would be effective from 2010 for cross border points and LNG-terminals. GTS requested these customers investigate eventual barriers and direct costs for adjustment of industrial applications to the EASEE gas standards. In 2008 the construction of the LNG GATE terminal was started. It is common practice in this capital intensive business that long term commitments are agreed and contracts signed before construction starts. Although these contracts are confidential one can assume that EASEEgas specifications were part of the quality paragraphs. It must be concluded that, for the Dutch authorities, the challenges and interest on the supply side were leading from the start. One might doubt whether the Dutch authorities made the right decisions because most countries that depend on diverse gasses, including LNG, are focused on limitations at the downstream side with the consumers. During the workshop on gas quality on 5th December 2011, organized by the European Commission, consultant J. Klimsta quoted gas expert prof. G.F.I. Roberts: “Gas quality should be user led, not supplier led and be careful not to become politically led”13. In countries like the USA this principle is leading. We observe that it is going the other way round in the Netherlands.

Consequences for H-gas consumers; main conclusions KEMA-KIWA study

Forced by the protest of many end-users, the Ministry invited KEMA and KIWA to inventory all effects for end-users of the new gas quality described on the website “hoezoandergas.nl”. The report ‘Gas quality for the future, part 1’ was published in December 2010 and in the second report ARCADIS investigated the most cost-efficient measures including route maps for the transition14,15. Based on these reports the Minister of EL&I decided not to change the specifications for G-gas for the coming 10 to 15 years for safety reasons (installations of households). Moreover,

the Minister concluded after consultation with ‘Projectbureau Nieuw Aardgas’ that in spite of many uncertainties, adjusting the installations of 80 H-gas customers would be the most cost effective solution16. He did not adopt the recommendation of KEMA and KIWA for a transition period for H-gas consumers on account of the (at least) 5 years required to minimise extra costs by allowing equipment replacement according to the normal maintenance and investment schemes of end-users. In addition, he shortened the period that GATE would adapt its quality range until the end of 2012 with a conditional extension to the end of 2014 and announced that, after the transition period, the Wobbe index would be raised to the ‘expected European standard’ of 55.7 MJ/m3(n) instead of 57,2 MJ/m3(n). It is questionable why the Dutch authorities decided to increase the upper bound of the Wobbe Index from 54 to 55.7 MJ/m3(n) shortly after this extensive investigation. It is very likely that the conclusions of these studies significantly underestimate the effects for end-users after 2014. This also means that one cannot exclude the possibility that end users have to adjust their installations twice. Moreover, a European standard is not yet developed and approved by the European authorities. KEMA / KIWA concluded also that the current legislation with regard to gas quality is insufficient and needs to be extended with application parameters, not only in the interest of the operation of the equipment of end-users, but also to prevent gas producers supplying gasses with various undesirable ingredients (such as higher hydrocarbons (PE), aromatics and inert components). As long as limitations for these ingredients are not legally specified, ‘dirty’ gasses could comply with the limits of the current legal specification, but could be detrimental to the interest of end consumers. End users of H-gas are left with a lot of uncertainty, not only because they have no experience or knowledge about all effects of the new gasses, but also because Dutch authorities cannot and will not give any guarantee about the long term operational bandwidth and speed of quality changes occurring within short timeframes. This has a negative impact on safety. Practical experience and results from the Operator Training Simulator show that an operator is unable to react safely to a change of the caloric value of more than 2%/h. In the case that the caloric value of the announced bandwidth changes, the speed could easily be five times higher. Recently E-ON demonstrated that fuel composition can cause significant adverse impact on gas turbine operation and increasing variation will only make this worse17. They showed that all key combustion parameters, such as flame speed, air/fuel ratio, etc. are affected by fuel composition and affect flame behaviour in the form of flash-back, blow out, increased emissions and a changed combustion dynamic. Besides the impact on safety, changes of the ‘richer’ gas bandwidth will have a negative impact on emissions. More oxygen for safety and operational reasons will boost the NOx and CO2 emissions of gas engines, turbines and burners. Tight environmental permits will therefore be difficult to be met. Fluctuations will have a particularly negative impact on efficiency. End-users will need more gas for the same output not only for combustion but also for use of gas as a feedstock. Uncertainty also exits regarding the appropriate adjustment of equipment. Original Equipment Manufactures (OEMs) indicate that

8 GL Noble Deton and Pöyry Management Consulting, Study on Interoperability-Gas Quality Harmonisation – Cost benefit Analyses, Preliminary report for consultation, July 2011 9 EASEE-gas, Comments and responses from Madrid Forum Participants to the EASEE-gas Gas Quality CBP, 11th meeting of Madrid Forum, 18 May, 2006 10 Regelingen van de Minister van Economische Zaken inzake tariefstructuren en voorwaarden gas, nr WJZ 5001052, 9 januari 2005 11 Technische voorwaarden gas, Aansluitvoorwaarden gas-LNB, hoofdstuk 3.3, gaskwaliteit 12 KEMA kiwa, Gaskwaliteit voor de toekomst, Deelrapport 1, page 41 13 European Commission, Gas Quality Workshop, Brussels, 5th December 2012 14 KEMA, KIWA, gaskwaliteit voor de toekomst, Deelrapport 1, December 2010 15 ARCADIS, KEMA, KIWA, Gaskwaliteit voor de toekomst, 22 March 2011 16 Ministerie van Economische Zaken, Landbouw en Innovatie,. Rapportage inventarisatie gevolgen transitie nieuw aardgas voor H-gasgebruikers., 14 June 2011 17 E-ON, Davidd Abbott, Practical examples of the impact of variations in gas composition on gas turbine operations, Gas and power Europe Forum, January 2012

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they are unable to guarantee or adapt installations as long as they are not provided with the specification of the future gasses, including rates of change. By publishing the quality of the gasses that is injected to the grid, GTS improved its services as far as short term information is concerned, but this is insufficient for the structural measures that need to be taken.

Front end measures will strengthen the position of everybody

The report “gas quality for the future’, part 2, gives some information about costs for upstream, midstream and downstream solutions. Upstream, one could decide to leave the entry specification unchanged in the coming years. Apart from public losses of € 100 – 130 mln p.a. these costs for GATE could be more or less doubled due to contractual losses. These huge costs are not specified in detail and cannot be verified. A midstream option could be placing of some gas treatment installations. A stripping installation at the GATE terminal is estimated to cost € 365465 mln excluding yearly costs of € 25 mln. Adjustments for downstream applications are estimated to cost € 90 mln for gas turbines and € 40 mln - € 190 mln for the industry, based on a Wobbe Index of max 54 MJ/m3(n). Although an estimation of efficiency losses is hard to predict, yearly losses due to lower efficiency, unplanned outages and environment costs would amount much more than € 100 mln and most probably a multiple of this amount. A decision based on

the lowest public costs would have been quite different. We are con­ vinced that a mid stream option such as the installation of gas treatment facilities could be an attractive solution, and the costs should be calculated back into the supply price commanded by the gas producers or at most partly passed through to the customers via transport tariffs. This division prevents the presentation of all costs to 80 H-gas customers and is an infringement of the polluter pays principle. Although GTS communicates they are not able to take care of the “orphan”, we are convinced it is not a proper and efficient solution to hand him over to a small group of net-users and give them little time to get accustomed to the situation. By bringing the “orphan” back to the place it belongs, we are convinced that the Dutch authorities can manage all challenges that the gas industry is facing. Even better!

Biography author

Dirk Jan Meuzelaar is the advisor for commercial and regulatory affairs at Utility Support Group and chairman of the ‘Fuels Working Group’ at VEMW. Over 30 years Dirk Jan has accumulated extensive experience in the energy industry from different angles: large energy consumers in the chemical industry (especially DSM, Sabic-Europe, OCI-Nitrogen), Energie Beheer Nederland, Corporate DSM Public Affairs and DG Energy of Ministry of Economic Affairs.

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EDIAAL Microgrids or Virtual Power Plants - which way will Europe Turn?

The global market for microgrids and other forms of aggregation and optimization for distributed energy resources made some major leaps forward last year. Along with their sister smart grid network platform, the “virtual power plant” (VPP), microgrids will ultimately transform the way power grids are operated and optimized, with broader ramifications for a long list of power issues spanning everything from the long-term viability of nuclear power to the near-term impact of rapidly declining natural gas prices. A microgrid is really just a small-scale version of the traditional electricity grid that the vast majority of electricity consumers in the developed world rely on for power service today. Like today’s power grid, microgrids include generation facilities, distribution lines, and voltage regulators. They can be networked with one another (and the central grid) in order to boost capacity, efficiency, and reliability – and they can also function as autonomous islands of power during times of emergency or to respond to real-time market conditions. Under today’s standard grid protocols, virtually all distributed generation (DG), whether renewable or fossil-fueled, must typically shut down during times of power outages. Thus, they do not feed power back to the larger utility grid. This fact exasperates microgrid advocates, who argue that this is precisely when these on-site sources could offer the greatest value to both generation asset owners and society. Such sources could provide power services, for example, when the larger grid system has failed the mission-critical functions of the military. Owners of various distributed generation systems – including distributed combined heat & power (CHP) units burning natural gas -- could, with additional technology advances and standards, provide ancillary services that would help their host distribution utilities maintain reliability while serving their own power needs. This smart grid network platform is coming of age, especially in the United States, due to two major developments, the first of which addresses the described grid protocols. In July 2011 the Institute of Electrical Energy Engineers (IEEE) approved the P1547.4 safe islanding standards, which should accelerate the shift from pilot validation projects to fully commercial microgrid ventures. Since 2009, a handful of large commercially viable projects have come online, especially in California – as platforms for aggregation of distributed renewable resources and in New York, with combined heat and power (CHP) units as anchor technologies. This guide to the practice of “safe islanding” addresses historical concerns voiced by utilities. Instead of each microgrid representing a challenge to status quo utility protocols that specifically prohibit the fundamental purpose of many microgrids, the IEEE is recognizing that technological advances with smart inverters, smart switches and other forms of distribution automation have rendered safety concerns regarding intentional islanding obsolete.

Peter Asmus Senior Analyst, Pike Research

Interestingly enough, the European Union is also abolishing the standard utility protocol of requiring inverters to disconnect from the grid during a disturbance, which removes one of the largest stumbling blocks to integrating renewables into power grids. The standard utility protocol of requiring inverter based resources to disconnect during a grid disturbance – no matter how small – exasperates potential problems on the grid linked to high penetrations of variable renewables. The second promising development for microgrids in the U.S. is a series of Federal Energy Regulatory Commission’s (FERC) recent Orders -719, 745, and 1000 -- that move toward harmonizing innovation occurring independently at the wholesale and retail market levels. Demand response (DR) is seen as a stop-gap resource whose role will expand in markets characterized by volatility, high demand peaks, and lack of new transmission level generation capacity. Microgrids are now being viewed as the ultimately reliable DR resource, since islanding securely takes load off of the utility grid. For these and other reasons, North America (and especially the United States) still represents the best overall market for microgrids in most application segments – even the most lucrative remote/off-grid segment, thanks to Alaska. Key factors include pockets of poor power quality scattered throughout the United States and the structure of markets for DER. The latter has stimulated creative aggregation possibilities behind the meter at the retail level of power service. Instead of being driven by grid operators, which is the case in Europe, the microgrid market in the United States is customer-driven. Microgrids can offer a quality and diversity of services that incumbent utilities have not been able to offer up to this point in time. Still, due in large part to the superior revenue profiles of remote microgrids, the Asia Pacific region actually leads the world in terms of total revenues.

Chart 1.1

Annual Microgrid Revenue by Region, Average Scenario, World Markets,

2011-2017 (Source: Pike Research)

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As of 2012, however, not a single national government has developed an integrated or comprehensive policy creating a viable, vibrant market for customer-driven microgrids. Such microgrids, which diversify the ownership of supply infrastructure, are the ultimate example of energy democracy. With the exception of Denmark, few other countries are even examining the complex policy issues involved when aggregating distributed energy resources (DER) not owned by utility companies on a broad scale. The impetus to examine these issues in Denmark is being driven by grid operators who are attempting to address the variability of distributed wind power due to penetration levels of over 25%. Adding to the complexity of the issues are distributed combined heat and power (CHP) units. With a goal of 50% renewable generation by 2050 in a very small country, Denmark has become a laboratory of policy and technology reforms. What about the rest of Europe? Given the extraordinary growth in renewable distributed energy generation (RDEG) in countries such as Germany, one might surmise that Europe is also a hot spot for microgrids. Think again. With the exception of Denmark and a few pilot projects in the U.K., most microgrid activity in Europe is focused on islands. For example, ABB’s most noteworthy project came online in 2011 and the site is being billed as the world’s first island to be 100% powered by renewable energy. This island microgrid is on the smallest of the Canary Islands – El Hierro – and features over 11 megawatts (MW) of wind power and 13 MW of pumped hydro storage. Combined, these sources provide roughly 80% of the island’s total electricity. The remainder comes from both solar thermal and solar PV facilities. ABB provided automation and renewable integration services, including meeting the difficult challenge of maintaining stable frequency and voltage by sharing active and reactive power demand in the generators and tie-lines.

(e.g., avoidance of capital investments in grid infrastructure or peaking power plants), as well as the transmission grid operator (e.g., regulation ancillary services like spinning reserves). One such 23MW VPP project in Germany, which has also been deemed a “Regenerative Combined Power Plant,” was awarded the German Climate Protection Prize for 2009. (This experiment has since been criticized for failing to account for logistics and regulations governing distribution and transmission lines.) Even more impressive is a 65MW microgrid/VPP hybrid R&D effort commonly referred to as the “Cell Controller Project.” It consists of distributed wind and CHP units owned by farmers and village heating districts and will be operated by Energinet.dk, the transmission operator for Denmark. Since so many different parties own all these assets, this project is probably the most advanced foray into what a distributed energy future could look like. How does one aggregate and then dispatch these generation services into wholesale markets? The goal is to provide services, such as voltage regulation at the local level, in each cell and for each discrete microgrid.

Virtual Power Plants: Where Are They?

The preferred means of addressing variable distributed renewable energy resources in Europe is a VPP. One reason for this is that Europe has a much more reliable power grid than the U.S. Interconnections between countries are also more advanced, allowing excess wind generation to be shipped either north to Scandinavia or south to Spain or Italy. While DR development is lagging in Europe, efforts to aggregate and optimize RDEG – and perhaps even mega-offshore wind farms – may be looming just over the horizon. At present, no widely acknowledged or precise definition of a virtual power plant (VPP) exists. The very use of the term “virtual” connotes something not solid, temporary, and perhaps even fleeting. In many ways, these attributes are accurate. Yet VPPs can provide extraordinary value and services to transmission and distribution (T&D) grid infrastructure as well as to myriad stakeholders engaged in the provision of electric power. The term VPP is sometimes used interchangeably with “microgrid,” a technology platform that refers specifically to the ability of supply and load within a specific geography to island itself from the larger grid. However, VPPs lack the ability to disconnect from the grid. In fact, they are wholly dependent upon not only a utility grid, but smart grid infrastructure. What a microgrid and VPP share in common is that they are both platforms to aggregate distributed energy resources (DER). Commercial VPPs originated in Europe, where, more often than not, the term refers to aggregating supply-side resources, usually renewable energy resources, though the term can even apply to diesel generators. In short, VPPs represent an “Internet of Energy,” tapping existing grid networks to tailor electricity supply and demand services for a customer, utility, or grid operator. They maximize value for both the end user and distribution utility through software and IT innovations. Without any large-scale fundamental infrastructure upgrades, VPPs can stretch supplies from existing generators and utility demand reduction programs. They deliver greater value to the customer (e.g., lower costs and new revenue streams), while also creating benefits for the host distribution utility

Figure 1.1

Denmark’s “Cell Controller Project” (Source: Spirae)

Denmark’s heavy reliance on wind is coming under attack from bordering Germany, whose wind penetration is also growing rapidly and is concentrated in the same general wind resource region. Past policies allowing firming resources from Germany, Norway, and France to settle “after the fact” is giving way to new efforts to mitigate the variability of wind with local resources. This microgrid/VPP will serve the Danish grid in a dynamic, real-time manner, setting the stage for a subsequent VPP R&D project of a similar size (56 MW). Along with wind and CHP, the latter project also involves PHEV and residential heat pumps on the island of Bornholm.

Renewables Integration and the Role of Natural Gas

The technology that dominates the renewable integration market revenue picture today within the smart grid space is microgrids, capturing more than $3 billion in economic activity this year. And within the microgrid sector, remote microgrids represent approximately 92% of this total, a reflection of the challenges of integrating distributed solar and wind in regions of the world where a reliable utility power grid is lacking. The synergy between smart grids and renewable energy is intuitive and makes a great story, but where the rubber meets the road, much more validation needs to be done. Technologies have come a long way over the past five years. For example, within the smart grid toolbox, microgrids, DR and wind and solar forecasting technologies are all reaching commercial status. As a result, the tools on the grid side to better manage the variability of renewables are now increasingly available. These technologies will begin displacing the current reliance upon gas-fired generation at the transmission level over the next six years. This, in turn, will minimize the environmental impacts of grid integration of solar and wind, reinforcing the value of the smart grid.

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One could make a counter argument that low-cost natural gas networks in Europe could offer synergies with RDEG, and allow countries to help meet their carbon reduction goals more cost effectively. The current low price of natural gas is making large central station coal and nuclear power plants look like bad bets. Whereas many CHP and fuel cells can burn either natural gas or biogas, the flexibility of these power generation technologies will likely continue to play a role in the future. In fact, CHP units make the ideal anchor technology for a microgrid, since they reduce the need for costly energy storage and also provide two forms of energy – electricity and heat – for large institutions such as universities or commercial and industrial (C/I) complexes. Tiga Energy is one of the few U.S. firms to focus on C/I microgrids and on a value proposition linked to today’s low natural gas prices. The company is focused on integrating RDEG, such as solar PV, with fossil fuel on-site combustion, arguing that current low natural gas prices can actually help accelerate deployment of microgrids. What is the rationale? Lower natural gas prices enable more headroom for more expensive solar PV. This is the value proposition it hopes to sell to cost-cautious C/I customers. The company has created a formal joint venture with EcoMerge USA, LLC, a subsidiary of Dentsu Japan and Innovative Energy Group, LLC, with the goal of offering blended renewable and natural gas fired on-site generation facilities of up to 15 MW in scale in Texas and throughout the U.S. In Europe, the business case for natural gas bumps up against mandates

to shrink carbon footprints. Nevertheless, grid operators are seeking a mix of options to help balance variable generation and see-sawing customer loads. Existing natural gas networks (and district heating and cooling systems) are valuable assets that can also be tapped to help smooth out the ramps up and down of wind and solar energy. Whereas natural gas is seen as a competitive threat to renewables (and therefore microgrids and VPPs) in the U.S. due to the uncertainty of available government support, the dynamics in Europe are less clear. Of course, the beauty of both microgrids and VPPs is that they can tie together a great diversity of resources (supply, demand and storage) and optimize them for the customer. These platforms are really agnostic to fuels, and many of today’s microgrids rely on natural gas-fired generation. Whether the current shale gas boom helps or hinders the evolution of smart grid technologies such as microgrids or VPPs remains an open question.

About the author

Peter Asmus is a Senior Analyst with Pike Research, a clean tech intelligence company based in Boulder, Colorado, with offices in Washington DC, the United Kingdom and South Korea. His coverage area is renewable energy, microgrids and other smart grid topics (including virtual power plants). He is author of four books on energy issues, including Reaping the Wind (Island Press, 2001) and Intro­ duction to Energy in California (University of California Press, 2009).

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The Discovery of Price Responsiveness A Survey of Experiments involving Dynamic Pricing of Electricity Abstract

This paper surveys the results from 126 pricing experiments with dynamic pricing and time-of-use pricing of electricity. These experiments have been carried out across three continents at various times during the past decade. Data from 74 of these experiments are sufficiently complete to allow us to identify the relationship between the strength of the peak to off-peak price ratio and the associated reduction in peak demand or demand response. An “arc of price responsiveness” emerges from our analysis, showing that the amount of demand response rises with the price ratio but at a decreasing rate. We also find that about half of the variation in demand response can be explained by variations in the price ratio. This is a remarkable result, since the experiments vary in many other respects – climate, time period, the length of the peak period, the history of pricing innovation in each area, and the manner in which the dynamic pricing designs were marketed to customers. We also find that enabling technologies such as in-home displays, energy orbs and programmable and communicating thermostats boost the amount of demand response. The results of the paper support the case for widespread rollout of dynamic pricing and time-of-use pricing.

Introduction

Electric utilities, which run a capital-intensive business, could lower their costs of doing business by improving their load factor. Other capital intensive industries, such as airlines, hotels, car rental agencies, sporting arenas, movie theaters routinely practice a technique known as dynamic pricing to improve load factor. In dynamic pricing, prices vary to reflect the changing balance of demand and supply through the day, through the week and through the seasons of the year. Congestion pricing, a simpler form of dynamic pricing, is used to regulate the flow of cars into central cities. Parking spaces in most central cities are priced on a time-of-day basis and in some cities such as San Francisco the prices are varying dynamically. In California, special lanes on freeways are priced dynamically and the Bay Bridge charges toll on a time-of-use basis. But it has been difficult for electric utilities to follow these examples. There has always been doubt that electric users can change their usage patterns. To assuage these doubts, in the late 1970s and early 1980s, a dozen electricity pricing experiments were carried out with time-of-use rates in the United States.2 They showed that customers do respond to such rates by lowering peak usage and/or shifting it to less expensive off-peak periods. But smart meters that would charge on a time-of-day basis were expensive in those days and little progress occurred in the ensuing years. Even now, less than one percent of the more than 125 million electric customers in the United States are charged on a time-ofuse basis.

Ahmad Faruqui Principal with The Brattle Group

Jenny Palmer Research analyst at The Brattle Group 1

The Dynamic Rates Time-of-Use (TOU). A TOU rate could either be a time-of-day rate, in which the day is divided into time periods with varying rates, or a seasonal rate into which the year is divided into multiple seasons and different rates provided for different seasons. In a time-of-day rate, a peak period might be defined as the period from 12 pm to 6 pm on weekdays, with the remaining hours being off-peak. The price would be higher during the peak period and lower during the off-peak, mirroring the variation in marginal costs by pricing period. Critical Peak Price (CPP). On a CPP rate, customers pay higher peak period prices during the few days a year when wholesale prices are the highest (typically the top 10 to 15 days of the year which account for 10 to 20 percent of system peak load). This higher peak price reflects both energy and capacity costs and, as a result of being spread over relatively few hours of the year, can be in excess of $1 per kWh. In return, the customers pay a discounted off-peak price that more accurately reflects lower off-peak energy supply costs for the duration of the season (or year). Customers are typically notified of an upcoming “critical peak event” one day in advance but if enabling technology is provided, these rates can also be activated on a day-of basis. Peak Time Rebate (PTR). If a CPP tariff cannot be rolled out because of political or regulatory constraints, some parties have suggested the deployment of peak-time rebate. Instead of charging a higher rate during critical events, participants are paid for load reductions (estimated relative to a forecast of what the customer otherwise would have consumed). If customers do not wish to participate, they simply buy through at the existing rate. There is no rate discount during non-event hours. Thus far, PTR has been offered through pilots, but default (opt-out) deployments have been approved for residential customers in California, the District of Columbia and Maryland. Real Time Pricing (RTP). Participants in RTP programs pay for energy at a rate that is linked to the hourly market price for electricity. Depending on their size, participants are typically made aware of the hourly prices on either a day-ahead or hour-ahead basis. Typically, only the largest customers —above one megawatt of load — face hour-ahead prices. These programs post prices that most accurately reflect the cost of producing electricity during each hour of the day, and thus provide the best price signals to customers, giving them the incentive to reduce consumption at the most expensive times.

1 The authors are economists with The Brattle Group, based in San Francisco. They are grateful to fellow economist Sanem Sergici of Brattle for reading an early draft of this paper. Comments can be directed to ahmad.faruqui@brattle.com. 2 For an early summary, see Ahmad Faruqui and J. Robert Malko, “The Residential Demand for Electricity by Time-Of-Use: A Survey of Twelve Experiments with Peak Load Pricing,” Energy, Volume 8, Issue 10, October 1983. For more recent surveys, see Ahmad Faruqui and Jenny Palmer, “Dynamic Pricing and its Discontents,” Regulation, Fall 2011 and Ahmad Faruqui and Sanem Sergici, “Household Response to Dynamic Pricing of Electricity – A Survey of 15 Experiments,” Journal of Regulatory Economics, October 2010. Faruqui and Palmer also discuss the more common myths that surround legislative and regulatory conversations about dynamic pricing. 3 Most dynamic pricing studies have included multiple tests. For example, a pilot could test a TOU rate and a CPP rate and it could test each rate with and without enabling technology. Thus, this pilot would include a total of four pricing tests. 4 See, for example, the concluding remarks in an otherwise excellent paper by Paul Joskow, “Creating a smarter U.S. electrical grid,” Journal of Economic Perspectives, Winter 2012.

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However, the California energy crisis of 2000-01 reinvigorated interested in dynamic pricing, not only in that state but globally. Over the past decade, two dozen dynamic pricing studies featuring over one hundred dynamic time-of-use and dynamic pricing designs were carried out across North America, in the European Union and in Australia and New Zealand.3 These experiments have yielded a rich body of empirical evidence. We have compiled this into a database, D-Rex, which stands for Dynamic Rate experiments. This contains the following data from each pilot: details of the specific rate designs tested in the pilot, whether or not enabling technologies were offered to customers in addition to the timevarying rates, and the amount of peak reduction that was realized with each price-technology combination. The D-Rex results provide an important perspective on the potential magnitude of impacts with different dynamic rate approaches and should inform the public debate about the merits of smart meters and smart pricing. Across the 129 dynamic pricing tests, peak reductions range from near zero values to near 60 percent values. However, it would be misleading to conclude that there is no consistency in customer response.4 We focus on nine of the best designed, more recent experiments to examine the impact of the peak to-off peak price ratio on the magnitude of the reduction in peak demand, or demand response. Because the amount of demand response varies with the presence or absence of enabling technology, such as a smart thermostat, an energy orb or an in-home display, we separate those pricing tests without and with enabling technology. We find a statistically significant relationship between the price ratio and the amount of peak reduction, and quantify this relationship with a logarithmic model. This relationship is termed the Arc of Price Responsiveness. We find that for a given price ratio, experiments with enabling technologies tend to produce larger peak reductions, and display a more price-responsive Arc.

The Dynamic Pricing Studies

The D-Rex Database contains the results of 129 dynamic pricing tests from 24 pricing studies.5 As shown in Figure 1, these results range from close to zero to up to 58 percent. Part of the variation in impacts comes simply from the fact that different rate types are being tested. Filtering by rate in Figure 2, some trends begin to emerge. We observe that the Critical Peak Pricing (CPP) rate tends to have higher impacts than Timeof-Use (TOU) rates, likely because the CPP rates have higher peak to off-peak price ratios. We can also filter by the presence of enabling technology, as in Figure 3, and observe that for the same rates, the impacts with enabling technologies tends to be higher.

Figure 2. Impacts from Pricing Tests, by Rate Type

Figure 3. Impacts from Pricing Tests, by Rate Type and Presence of Enabling Technologies

Even with the rate and technology filters, there remains significant unexplained variation. In order to understand the cause of this variation, we first limit the sample to only the best-designed studies which have reported the relevant data. We selected studies in which samples are representative of the population and the results are statistically valid. Moreover, we selected studies in which participants were selected randomly, as opposed to volunteers responding to a mass mailing. The nine best-designed pilots, shown in Table 1, include 42 price-only tests and 32 pricing tests with prices cum enabling technology.6 In these 74 tests, the peak reductions range from 0% to just under 50%. The remainder of this paper focuses on explaining the variation in these results.

Figure 1. Impacts from Residential Dynamic Pricing Tests, Sorted from Lowest to Highest

Table 1. Features of the Nine Dynamic Pilots

5 23 of the 24 studies are pricing pilots. The other study is PG&E’s full scale rollout of TOU and SmartRate. 6 OG&E was not included in these screened results because only the draft results are available thus far. When these results are finalized, they will be included in this analysis.

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Figure 4. Impacts from Pricing Tests, by Rate Type and Presence of Enabling Technologies

Figure 6. Impacts from Pricing Tests by Peak to Off-Peak Ratio with the Fitted Logarithmic Curve

Methodology

We can narrow down the model to focus on the price-only observations separately from the enabling technology observations. With this data, the model yields a coefficient of 0.077 with a standard error of 0.012, again significant at the 0.001 level. The coefficient is slightly lower here than in the full dataset, suggesting that the impacts increase more slowly in the absence of enabling technology. In this case, the adjusted R-squared value is 48 percent, meaning the ratio again explains almost half of the variation in response. The logarithmic curve suggests that if the peak to off-peak price ratio were to get as high as 16, the peak reduction would be slightly over 20 percent. With the enabling technology tests, we find that the curve has a steeper slope than the result with price-only tests. The coefficient of the enabling technology curve is 0.130 which has a standard error of .02. The regression successfully explains 53 percent of the variation in demand response. With a peak to off-peak ratio of 16, the peak reduction is expected to be over 30 percent.

The nine best-designed studies in D-Rex include 42 price-only test results and 32 price-cum-enabling technology test results for a total of 74 observations. For each result, we plot the all-in peak to off-peak price ratio against the corresponding peak reduction. As expected, the CPP and PTR rates tend to have higher peak to off-peak ratios than the TOU rates, with some overlap, and those rates with higher price ratios tend to yield greater peak reductions.7 It also appears that that the enabling technology impacts may be greater than those with price only.

Figure 5. Impacts from Pricing Tests by Peak to Off-Peak Ratio, Showing Rate Type and Presence of Enabling Technologies

The plot suggests that peak impacts increase with the price ratio but at a decreasing rate. The logarithmic model would model rapid increases in peak reduction in the lower price ratios, followed by slower growth.8 Figure 7. Impacts from Pricing Tests by Peak to Off-Peak Ratio with the Fitted Logarithmic Curves, Segregated by Presence of Enabling Technologies

Results

When we fit the logarithmic model to the full dataset (n = 74), it yields a coefficient of 0.106 with a standard error of 0.012, significant at the 0.001 level. In other words, as the price ratio increases, the peak reduction is also expected to increase. The peak-to-off-peak price ratio successfully explains 49 percent of the variation in demand response. The logarithmic curve suggests that if the peak to off-peak price ratio were to get as high as 16, the peak reduction could be close to 30 percent.

7 For the PTR rate, the effective critical peak price is calculated by adding the peak time rebate to the rate that the customer pays during that time period. 8 We also considered a logistic growth model that features slow growth at lower price ratios followed by moderate growth, followed by an upper bound peak reduction. The results were not significantly different with this functional form.

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The full regression results for the three different data specifications are shown in Table 2 below. In each case, the coefficient on the natural log of the price ratio is positive and significant at the 0.001 level.

Faruqui, Ahmad and Jenny Palmer, “Dynamic Pricing and its Discontents,” Regulation, Fall 2011. Faruqui, Ahmad and Sanem Sergici, “BGE’s Smart Energy Pricing Pilot: Summer 2008 Impact Evaluation,” Prepared for Baltimore Gas & Electric Company, April 28, 2009. Faruqui, Ahmad and Sanem Sergici, “Impact Evaluation of BGE’s SEP 2009 Pilot: Residential Class Persistence Analysis,” Presented to Baltimore Gas and Electric Company, October 23, 2009. Faruqui, Ahmad and Sanem Sergici, “Impact Evaluation of NU’s Plan-It Wise Energy Program: Final Results,” November 2, 2009. Faruqui, Ahmad, Sanem Sergici and Lamine Akaba, “Impact Evaluation of the SEP 2010 Pilot,” Presented to Baltimore Gas and Electric Company, March 22, 2011.

Biography of Authors

Conclusion

In our view, the results presented in this paper provide strong support for the deployment of dynamic pricing. They conclusively show that customers are responsive to changes in the price of electricity. In other words, they lower demand when prices are higher. Moreover, the results suggest that the presence of enabling technology allows customers to increase their peak reduction even further. These results may be used to quantify the potential peak reductions that may be expected when new dynamic rates are rolled out and to monetize these benefits using estimates of the avoided capacity of energy.9

Ahmad Faruqui is a principal with The Brattle Group. He has been analyzing time-varying experiments since the beginning of his career in 1979 and his early work is cited in the third edition of Professor Bonbright’s canon on public utility ratemaking. The author of four books and more than a hundred papers on energy policy, he holds a doctoral degree in economics from the University of California at Davis and bachelor’s and master’s degrees from the University of Karachi. Jennifer Palmer is a research analyst at The Brattle Group. Since joining The Brattle Group in 2009, she has worked with a wide range of utilities on dynamic pricing and advanced metering projects. For several utilities, she has developed dynamic tariffs, simulated the impacts of these rates on customer consumption patterns, and estimated the resulting systemlevel benefits. She has a bachelor’s degree in economics with a certificate in environmental studies from Princeton University.

Appendix

Sources

Commission for Energy Regulation, “Electricity Smart Metering Customer Behaviour Trials (CBT) Findings Report,” May 16, 2011. eMeter Strategic Consulting, “PowerCentsDC Program: Final Report,” Prepared for the Smart Meter Pilot Program, Inc., September 2010. Faruqui, Ahmad and J. Robert Malko, “The Residential Demand for Electricity by Time-Of-Use: A Survey of Twelve Experiments with Peak Load Pricing,” Energy, Volume 8, Issue 10, October 1983. Faruqui, Impacts from Pricing Tests by Peak to Off-Peak Ratio, Showing Utility Names

9 On the monetization of benefits arising from smart meters and dynamic pricing in the context of the EU, see Ahmad Faruqui, Dan Harris, and Ryan Hledik, “Unlocking the € 53 billion savings from smart meters in the EU: How increasing the adoption of dynamic tariffs could make or break the EU’s smart grid investment,” Energy Policy, 2010.

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Smart Energy Infrastructure: Synergies between Electricity and Gas Smart grids are a popular concept often used in energy scenarios and political statements about energy. One definition used for smart grids is an electricity network that can intelligently integrate the actions of all users connected to it – generators, consumers and those that do both – in order to efficiently deliver sustainable, economic and secure electricity supplies. Smart grids are frequently described in abstract and general terms and articles rarely discuss actual business models, preconditions for financing the implementation and overall costs. Smart grids are being developed in response to the introduction of renewable energy sources (RES) and the new challenges RES present to the stability of the electric network. The added intelligence provided by smart grids will enable efficient usage of energy and reduce the overall investments required to create a sustainable future energy infrastructure. When smart grids are discussed, there is a clear focus on electricity, or smart electrical grids. The efficiency gains from introducing intelligence throughout the electrical grid are significant and there are numerous reasons to focus on electrical grids. The introduction of power generation from intermittent RES on an increasing scale, such as wind and solar, is challenging distribution system operators (DSO) and transmission system operators (TSO) to keep the electrical grids in balance. Smart grids will help balance supply and demand on the DSO and user level by introducing intelligence and opportunities to interact with users and better match demand and supply. However, smart grids are in the pilot stage at the moment and the circumstances influencing power grids and demand and generation differ significantly throughout Europe. Financial incentives to introduce smart meters exist, resulting in benefits for measuring, collecting and analysing energy usage in real time. Financial incentives for introducing smart grids are more difficult to determine because of a lack of standards and proven concepts, an unbundled market and a resistance to innovation. The two energy infrastructures, electricity and natural gas grids, are separate systems that do not cooperate on a system level. However, smart grids could become the linking pin that connects the two energy infrastructures and change the financial incentives to introduce intelligence throughout both infrastructures. The abundant availability of the robust natural gas infrastructure throughout Northwestern Europe (NWE) is often overlooked by the electricity sector. This infrastructure includes several storage means, including the availability of line pack flexibility (the amount of natural gas that can be managed flexibly by controlling the operation pressure levels between a minimal and a maximal level)1, thus reducing the need to balance over a day. Storage of natural gas in empty gas field and salt caverns is another highly cost efficient method to create backup capacity for times when demand is higher than supply. Natural gas transmission is typically also much cheaper (per MW) than electricity transmission.2 Thus, when one considers the natural gas infrastructure as a isolated energy network, there is less necessity to

Milan Vogelaar Energy Analyst, Energy Delta Institute

Martien Visser Vice President Knowledge Development, Energy Delta Institute

make the natural gas network smart. The introduction of green gas in the natural gas network, however, poses new challenges with respect to metering and balancing. This article proposes linking the “smart” power grid with the “robust” natural gas network to create a “smart” hybrid energy infrastructure. Such smart infrastructure can take the full advantage of both worlds, resulting in significant efficiency gains from energy efficiency to the utilization of surplus power in the energy chain.

Gas and electricity

Typically, residential users in Northwestern Europe are connected to both electricity and natural gas grids. In rural area, without adequate natural gas infrastructure, heating oil still represents a significant percentage of total energy used for residential heating purposes. To a certain extent, electricity and natural gas/oil are competitors and can replace each other. For instance, combined heat and power (CHP) installations (including micro CHP) would lead to a decrease in the required supply of electricity to residential users. Heat pumps could replace natural gas/oil equipment and thus would reduce the required natural gas or oil supplies to the residential sector. Natural gas and electricity are also allies. In Europe, 23,6% of the total electricity supply in 20083 was provided by gas-fired power plants. These power stations deliver the flexibility required to create an overall balance between demand and supply. Many see natural gas as an ally of the renewable energy in the effort to balance the intermittent supplies of electricity generated by wind and sun. The development of wind parks in the Baltic and North Sea in combination with an increased penetration of photovoltaics is resulting in temporary surpluses of power. In extreme cases, wind turbines and conventional power plants in Germany produce three to four times the total amount of electricity actually being used. Problems occur most often during public holidays when residential and corporate users use significantly less power4. Storage of surplus electricity is not possible which means that export of overcapacity is the only alternative to manage production levels. Interconnectors facilitating transfer of electricity among power markets exist, but in parts of Europe inter­ connection is limited. However, several interconnections have been commissioned and are being built to connect power markets5. A requirement to implement grid balancing mechanisms due to overloads in the electrical grids is being implemented throughout Northwestern Europe (NWE). These mechanisms may include curtailing wind turbines to maintain stability when the network is overloaded. In the United Kingdom this has resulted in financial compensation of wind farm operators for their losses by the TSO National Grid6. In an electrical power system baseload power plants generate the minimum amount of electricity needed to meet minimum demand for customers’ requirements and are unlikely to be shut off due to high start-up costs and long ramp-up times. With an increasing amount of

1 Keyaerts, N., “Gas Balancing Rules Must Take into account the Trade-off between Offering Pipeline Transport and Pipeline Flexibility in Liberalized Gas Markets” September 2010 2 Clingendael International Energy Programme (CIEP), 2012 3 European Environment Agency – http://www.eea.europa.eu/data-and-maps/figures/share-of-electricity-production-by-5 4 Deutsche Welle – “Wind energy surplus threatens eastern German power grid” March 2011 5 Patel, I., “European power: the future of interconnectors” June 2011 6 Reuters – “UK paid 13 mln pounds to turn off wind farms in 2011” January 2012 http://af.reuters.com/article/commoditiesNews/idAFL5E8CP3LZ20120125

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power generated by RES and limited flexibility to shape demand, temporary surpluses of electricity have resulted in the phenomenon of negative wholesale prices on the power exchange in Germany7. In the future, with an increasing share of total power generation from RES, it may be assumed that such situations will occur more often. The noneconomic storage possibilities of large amounts of electricity are in stark contrast with the economics of storing large quantities of natural gas. This has led to the proposal to use the temporary surplus of power to create synthetic natural gas. Research into this possibility is in the early stages and two pilot projects are being built. If successful, a new “inter­ connection” between the electricity and gas systems will be created.

Energy Scenarios

European energy policy has a clear focus on energy efficiency and longterm investment opportunities. The Energy Roadmap to 2050 outlines an extended look into the future, and by 2050 Europe could cut most of its greenhouse gas emissions. This plan specifies the long-term target of reducing domestic emissions by 80 to 95%.8 The usage of natural gas or heating oil for (space and water) heating by residential users results in CO2 emissions. The energy performance of buildings will be improved in the coming decades, with passive house technology becoming mainstream and the energy performance of existing buildings being improved significantly through refurbishments.9 Electricity consumption will remain a part of everyday life and does not directly create CO2 emissions, depending on the source of primary energy. It goes without saying that most electricity is generated by fossil fuels and in the years to come, the consumption of electricity will also lead to indirect CO2 emissions. In sustainable low carbon scenarios, it is assumed that, ultimately, all electricity will be produced by renewable sources or by fossil fuels using Carbon Capture and Storage (CCS). Given the complex nature of CCS, this technique will only be economically viable if employed at a large scale. Consequently, it is to be assumed that, partly through passive house technology, a minimal amount of natural gas and heating oil will be used in the residential sector, allowing for opportunities in the natural gas market if the gas can be labelled as green gas or synthetic gas, created from CO2 neutral sources. This article deals consecutively with the demand of energy, capacity and storage. It will show that a challenge exists not only to produce sufficient amounts of renewable energy, but to generate enough CO2 neutral energy storage and generation capacity for cold winters.

Energy demand (quantity)

The residential sector consists of a wide spectrum of energy consumers including households, commercial and public buildings, and small and medium size industries. In the residential sector, energy is used for two main purposes: power and heat. Most consumers use substantially more heat than power. For example, the average amount of heat required for a house in Northwestern Europe is around 20.000 kWh per year, while the average amount of power is only 3500 kWh.10 Passive houses and energy efficient appliances will result in energy savings and reduce generation requirements. In the last decades, heat demand has dropped significantly due to more efficient heating technology, while power demand has increased due greater penetration of electrical appliances (consumer electronics and home computing) in households. The replacement of gas or heating oil for heating purposes is usually

done by heat pumps. The heat output of heat pumps is typically much larger than the power input. A typical output/input ratio coefficient of performance (COP) for heat pumps is 3.5. Under such an assumption, the total power demand in the above example would be reduced to about 10.000 kWh per year.

Capacity requirement (quantity per hour)

The residential demand for electricity is more or less evenly spread throughout the year, but the demand for heat in Northwestern Europe is not. On a cold winter day, the demand for heat is much higher than on an average summer day. In residential areas in Northwestern Europe, the required capacity for heating on a cold winter day is about ten times the peak capacity in the electricity infrastructure. The same is true for the economy as a whole. In the Netherlands, almost all heat demand is satisfied by natural gas. Thus, while the maximum capacity for natural gas in the Netherlands equals 190 GW11, the peak electricity demand is 20 GW12. Countries such as Germany and Belgium have a much lower penetration of natural gas in the residential sector and heating oil is still an important fuel. In these countries, the demand for natural gas capacity is about only four times the demand for power capacity. On the assumption that all natural gas and heating oil equipment is replaced by electric heat pumps with COP of 3.5 the maximum power capacity would become four times as high as the current one. This would require significant investment in transmission systems and distribution systems. Moreover, the electricity network in cities will require a major overhaul to be able to satisfy the electricity demand on a cold winter day. The ten year network development plan from ENTSO-E identifies the need to invest € 104 billion in the refurbishment or construction of roughly 51500 km of extra high voltage power lines clustered into 100 investment projects across Europe. 80% of the identified 100 bottlenecks are related to the direct or indirect integration of RES such as wind and solar power. Such massive development of RES is the main driver behind larger, more volatile power flows, over longer distances across Europe.13 These developments underscore the impact and cost of integrating RES.

Seasonal Storage requirement (quantity per year)

Heat demand occurs seasonally, mainly in winter, and is particularly large in a severely cold winter. The latter is often defined as a winter that occurs in 1 out of 20 years. To balance supply and demand, natural gas is typically stored in summer months and used in winter. In a recent study by Clingendael14, it was concluded that in Northwestern Europe, 28% of the energy demand for heat needs to be stored in order to be prepared for a potential, severely cold winter. This implies that an average house­ hold with an energy usage of 20.000 kWh requires a storage volume of about 5600 kWh. Europe possesses many natural gas storage facilities, with a total volume of about 60 billion m3 of natural gas (~ 600 TWh). Natural gas storage in the Netherlands has a capacity (volume) of about 1 bln m3 (~10 TWh). Under the assumption that all natural gas (and oil) heating equipment is replaced by electric heat pumps with a COP of 3.5, the required amount of electric storage capacity would reach 1600 kWh (= 5600/3,5) for this household. Vehicle-to-grid (V2G) is a concept whereby a distributed network of batteries in electric vehicles can store power at off-peak times and help power the grid when demand peaks. In a smart grid, excess energy is stored in electric vehicles connected at times of low demand

7 Brandstatt, C.; Brunekreeft, G., “How to deal with negative power price spikes? – Flexible voluntary curtailment agreements for large scale integration of wind” March 2011 8 EC “Roadmap for moving to a competitive low-carbon economy in 2050” 9 EC http://ec.europa.eu/clima/policies/roadmap/faq_en.htm 10 NIBUD – National Institute for Family Finance Information (Netherlands) 11 GTS - Quality and Capacity Document 2011 12 Tennet - Quality and Capacity Document 2010-2016 13 ENTSO-E Ten Year Network Development Plan TYNDP 2012 14 Meray, N., Wind and Gas, Back-up or Back-out, “That is the Question” CIEP Energy paper, December 2011

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and injected into the grid during times of peak demand15. Often hailed as a means of large scale storage of power, it can only supply limited storage capacity for grid balancing purposes. An average electric vehicle in 2012 may have a total battery capacity of about 25 kWh (Nissan Leaf) to 50 kWh (Tesla Roadster). The conclusion is that car batteries may help to manage within-day differences in demand and supply of electricity, but they would be of little help to cover the seasonal differences between demand and supply. An average household would require 40-50 electric cars and should accept that at the end of a severe winter, all batteries would be empty. V2G is an interesting technology to store and return the power back to the grid in the long term but will not be feasible on the medium to short term.

in theory be covered by battery or pumped hydroelectricity storage facilities. However, this implies that significant investments have to take place in fast-responding generation resource capacity that will only be needed in winter. At a small scale, electricity can be used to replace gas and oil and energy efficiency will reduce overall energy demand. However, severe challenges occur when up scaling is required. The variable and seasonal distributed demand for heat does not coincide with the generation characteristics of the electricity industry. Storage of electricity could solve the problem, but a solution is not yet available at a large enough scale. Moreover, a gradual increase in the production of renewable electricity will lead to more and more situations in which generation of electricity outpaces demand.

Economics

Smart Energy Grids

Above, it has been demonstrated that a full conversion from natural gas and oil to electricity would pose major challenges for the power transmission and distribution networks and generation. Besides the challenge to generate sufficient electricity to meet rising demand, it would require a significant and expensive increase in the electricity transmission capacity. Furthermore, either the issue of electricity storage should be solved or it should be accepted that a significant portion of the electricity generation capacity would only be used in wintertime, when the demand for heat is high. The cost of electricity transmission is high. Typically, electricity trans­ mission costs between three (overhead lines) to ten times (underground cables) more than natural gas transmission16. Thus, the required fourfold increase in the electricity transmission capacity would require a large investment. In this respect, one should also consider that there are issues of public acceptance regarding a major increase in overhead lines. Consequently, it should be expected that a significant fraction of the expansion of the electricity transmission will be via underground cables. The investment costs of large scale storage of electricity in batteries (~100 Euro/kWh) are orders of magnitude higher than the investment costs of large scale storage of natural gas (~ 0,1 Euro/kWh)17. Potentially, a part of the storage requirement can be covered by additional investment in non-baseload power generation capacity to cover the heat demand in average winter days. With baseload power plants and a significant share of power generation from RES, this growing share of generation from RES will result in increasing investment in loadfollowing and peaking power plants in the short term. With higher penetration of intermittent sources the required ramp ranges will increase, which adds additional costs and the need for fast-responding generation resources18. The additional demand on cold winter days could

In the previous section, it was shown that increasing the use of electricity in the residential sector faces some major challenges. These challenges could be solved by combining the strength of the gas sector with those of electricity. It is believed that such a combination of strengths of electricity and natural gas (including Power-to-gas) can significantly support the integration of RES into existing energy infrastructures19 and, probably, also contribute to increased energy security. The strength of electricity is that it can be employed for both power and heat demand. Smart grids will help balance the power grid but the challenge at hand is larger than the benefits to be gained in an electrical smart grid. Moreover, RES like wind and photovoltaics produce electricity and the utilisation of electricity from RES creates no CO2. Increasing penetration of renewable sources does however pose challenges for situations when generated power does not match demand and cannot be stored. Furthermore, investments in either large scale storage or fast-responding generation sources are required to meet demand at all times. Significantly, natural gas infrastructure already exists and is (relatively) cheap to expand, the storage of large amounts of natural gas is no problem, and the introduction of green gas and synthetic gas may add to the flexibility of the natural gas system. Finally, the natural gas infrastructure is flexible, robust and reliable. New thinking is required to combine benefits from both sets of infra­ structure. Rather than competing, natural gas grids and power grids should combine strengths. In this respect, it is important for the society to have the means to transfer gas into electricity (“Gas to Power”) and, in case of oversupplies of electricity, to be able to convert electricity to gas (“Power to Gas”). Visualize innovation, let’s create a smart energy infrastructure.

15 New York Times http://www.nytimes.com/2007/09/02/automobiles/02POWER.html 16 Clingendael International Energy Programme (CIEP), 2012 17 Clingendael International Energy Programme (CIEP), 2012 18 Denholm, P.; Ela, E.; Kirby, B.; and Milligan, M., “The Role of energy storage with renewable electricity generation” (2010) 19 Müller-Syring, G., Power-to-gas – “storage concepts for renewable energy”

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Power-to-gas – storage concepts for renewable energy Development of plant concepts under DVGW innovation offensive Power-to-gas is a technology that can significantly support the integration of renewable energies into existing energy infra­ structures. Beyond this the implementation of power-to-gas will lead to a further merging of the power and natural gas grids, which marks an important step forward on the way to a future energy system. To evaluate the potential of the technology, as a basis for future political measures and as a precondition for successful pilot plants, it is important to develop realistic system concepts. Moreover, the expected costs for the technologies and their products (hydrogen and methane) need to be estimated. These tasks are addressed in the DVGW R&D project “Energy Storage Concepts”. With its climate policy goals the German government has set the course for a fundamental transformation of energy supply systems. By 2050, CO2 emissions in Germany are to be reduced by at least 80% and primary energy consumption by 50%. Higher shares of renewable energies, energy saving and better energy efficiencies are therefore at the top of the political agenda. The gas supply sector has to adapt to this new direction in energy policy and is about to undergo a dramatic change. Natural gas, still the number one fuel on the heat energy market, must hold its own more than ever against alternative heating technologies on a competitive market. Moreover, stringent insulation requirements and enhanced efficiencies reduce demand for residential heat and thus also natural gas sales. The impact of the political requirements is particularly felt in electricity generation. In the field of photovoltaics alone, according to the German Solar Industry Association, another almost 7 GW peak was added to the approx. 10 GW generation capacity already installed and an output of approx. 12,000 GWh of solar electricity was generated in 2010.1 Expansion of renewable energies shows even more clearly in wind power. Currently, wind power plants with a generation capacity of around 27 GW are installed; the German government plans to increase this capacity to 45.8 GW by 2020.2 Already today injection of electricity from wind and solar energy exceeds demand at times, involving the risk of overloading electricity networks and requiring not only conventional power stations to be shut down but also wind turbines and solar plants to be disconnected temporarily from the networks. From today’s viewpoint successful integration of increasing volumes of electricity from renewable sources requires expansion of electricity networks and additional transportation and storage technologies. A promising solution for the energy industry and the entire economy is the conversion of renewable electricity into hydrogen or methane and injection into the

Gert Müller-Syring, Marco Henel, Hartmut Krause, Hans Rasmusson, Herwig Mlaker, Wolfgang Köppel, Thomas Höcher, Michael Sterner and Tobias Trost

gas network as well as the resulting interconnection of the electricity and gas networks. Against this background DVGW, the German Association of the Gas and Water Industries, is examining the role of gas in the future energy system under an innovation offensive. This approach was again confirmed by the DVGW members and welcomed by authorities and politicians at the GAT Gas Industry Conference in Stuttgart in 2010. The goal is to present the potential of natural gas as a suitable partner of renewable energies and expand the technological basis required for this purpose. A key subject in this context is the generation of hydrogen and methane from renewable electricity as well as their storage and injection into the existing gas network: power-to-gas.

Key subject: power-to-gas

There are several arguments supporting the power-to-gas concept: following injection into the existing gas network hydrogen or methane can be re-converted into electricity, heat or motor fuel as required. Germany and Europe have already developed efficient gas networks. The German gas network has a storage volume corresponding to a good third of Germany’s total annual electricity generation and it offers high flexibility at high transportation capacities over large distances. The gas network transports an annual energy quantity of around 1,000 billion kWh and thus about twice as much as the electricity network (approx. 540 billion kWh net)3. Currently, a volume of 20% of the annual gas sendout is held available in underground storage facilities; this value will rise to 30% by 2030. Thus, the natural gas network is not only an extensive energy distribution system interconnected on a Europe-wide level but also offers substantial energy storage capacity; this is an important difference compared to the electricity network where nonsimultaneous injection and withdrawal of energy is not possible. Dena I states that it is absolutely necessary to expand the network by 850 km for the integration of renewable energy. Moreover, an additional need for electricity transportation capacities of up to 2,000 km may be required depending on the share of renewable energies achieved.4 ,5 This would lead to huge technical input costing billions.6,7,8 Around 500,000 km of gas pipelines and storage facilities for 20 billion m³ of gas9 already exist and are readily available for accepting renewable electricity in the form of hydrogen or methane. Hydrogen-containing gases were used technically up to the 1980s. For example, the town gas of the 1950s used throughout Germany usually contained hydrogen concentrations of up to 50%. But modern gas technology is set within a framework of mostly pure methane. Nevertheless, admixing hydrogen to

1 Statistical data of German solar industry (photovoltaics); German Solar Industry Association (BSW Solar), January 2011. 2 Federal Republic of Germany (2010): national renewable energy action plan in accordance with Directive 2009/28/EC on the promotion of the use of energy from renewable sources. Federal Minis try for the Environment, Nature Conservation and Nuclear Safety, Berlin. 3 Federal Ministry of Economics and Technology, www.bmwi.de/BMWi/Navigation/Energie/Statistik-und-prognosen/Energiedaten/gesamtausgaben.html 4 Federal Network Agency (2011): report in accordance with Sec. 63 (4) (a) of the Energy Industry Act concerning evaluation of the network condition and expansion reports submitted by the German electricity transmission system operators. Federal Network Agency, Bonn. 5 Dena and Consentec (2011): network expansion position paper. Top priority of electricity network expansion. Network expert panel. Berlin, 1 June 2011. 6 DVGW German Association of the Gas and Water Industries, scientific / technical association. 7 Deutsche Energie-Agentur GmbH: dena network study II, 2010. 8 Federal Ministry of Economics and Technology, 2011. 9 Federal Network Agency: 2010 data on energy markets and competition, pp. 52 and 54.

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gas to be injected into the gas network is already possible today under the relevant DVGW Codes (G 260 / G 262).10 Results from projects co-financed by the EU (for example, NaturalHY or SES6/CTI 20041502661) confirm that many elements of the existing gas industry are well capable of tolerating hydrogen admixtures of up to 15% by volume. Efficient plant technology and a favourable regulatory framework are required to be able to achieve the climate policy goals set, develop new challenges and tasks for the gas industry and create power-to-gas concepts which are economically viable. The key technology processes in this context are the electrolysis of water to form hydrogen and oxygen as well as subsequent exothermal methanation, if required, to obtain synthetic methane from hydrogen and carbon dioxide. The efficiency of the processes and ancillary systems must be evaluated for their potential and suitability in power-to-gas energy storage concepts. Aside from more specific plant concepts this requires further consideration of, for example, energy network interfaces or the tolerance of the existing natural gas infrastructure with respect to hydrogen. These questions are being examined under the DVGW innovation offensive as part of the Energy Storage Concepts R&D project (G1-07-10). The project is being handled by a DVGW research consortium with the partners DVGW Research Station at Engler-Bunte Institute of KIT, E.ON Ruhrgas AG, Fraunhofer IWES and VNG AG and coordinated by DBI GUT GmbH. The project focus and initial interim results will be presented in the following.

Figure 2. Change in gas properties (Hs, Ws, d) as a function of hydrogen concentrations for three natural gases observing the limit values laid down in G 260. Values below the limit for relative density (d = 0.55) are possible on a case-by-case basis. (E.ON Ruhrgas AG, CasCalc Software, Essen 2011.) 12

Another focal point is to get an idea of how much research input will be required for implementation of the solutions proposed depending on scope of use. Based on the results obtained appropriate suggestions for measures will be prepared and submitted to the gas industry, also covering practical testing of applicability under pilot plant projects. Furthermore, DVGW envisages further developing and promoting the technology approach and, in particular, the required demonstration projects jointly with Federal Ministries. Initial talks were held, which will be continued once new project results are available.

Energy infrastructure interfaces Figure 1. Interfaces of electricity and gas networks and location of natural gas storage facilities (DBI Gas- und Umwelttechnik, Leipzig 2011). 11

Goals and focal points of dvgw energy storage concepts project

An objective assessment of the potential and economics of the storage option is essential to the further development of the power-to-gas approach by the gas industry. Such an assessment will be the basis for discussing the required economic conditions jointly with the persons responsible on the political level and the executing bodies (for example, Federal Network Agency). It is therefore a key goal of the project to provide this assessment and handle the following tasks to establish a basis for further discussion: • Determine the state of the art in electrolysis and methanation. • Make an inventory of the knowledge and experience available with respect to the hydrogen tolerance level of the existing natural gas infrastructure as well as with respect to measures which could serve to improve tolerance levels. • Develop power-to-gas plant concepts for four realistic performance classes and prepare the relevant economics. Also, the power-to-gas methods will be compared with electricity network solutions to be able to assess whether and to what extent these methods may help avoid network expansion on the electricity side.

Storage of renewable energy in the natural gas system requires the network to be capable of accepting hydrogen and methane. Technical compatibility needs to be considered in this context, which exists fully for methane and to a limited extent for hydrogen; but the consideration should also cover potential interconnection points between the networks as well as their capacities. It is advantageous that the two energy networks (electricity and natural gas) have similar basic structures. Large energy quantities are generated or injected centrally and fed into transmission and distribution networks ensuring supplies to most of the final users. When considering the transmission level of the energy networks, it is obvious that there are many interfaces in the process for conversion of electricity into gases capable of being stored. (Figure 1).

Hydrogen and methane as an option for storing renewable Electricity in the natural gas network

Chemical storage of renewable electricity in the natural gas network requires, in a first step, conversion of electricity into hydrogen by means of electrolysis. Today, an average efficiency of approx. 80% of the electrolysis cell may be assumed depending on the technology used (approx. 70% for simple water electrolysis and even more than 90% for modified electrodes and membranes at laboratory conditions). The hydrogen generated can then be admixed to natural gas or converted into methane in a downstream methanation process. CO2 is required for this second conversion step (exothermal reaction), if possible from

10 Yellow paper, DVGW Code of Practice (draft) G 262, 2010.

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renewable sources, so that it is used before being released into the atmosphere. CO methanation is part of the standard technologies for coal gasification; efficiencies are between approx. 75 and 85%.11,12 The reactor temperatures during the conversion process are between 250 and 500 °C. CO2 methanation achieves similar efficiencies and it is the first time that it is used in pilot plants for the purpose of energy storage. 13 A challenge involved in the methanation process is to displace the heat from the reactor in such a way that an optimum reaction temperature in thermodynamic terms prevails over the entire reaction chamber. Aside from the use of suitable catalysts the process is based on fluid streams varying within narrow limits; this requires interim storage of the hydrogen generated in the electrolysis process. The main benefit of methanation is that unlimited volumes of the product gas (methane) may be admixed to natural gas. If renewable power methane is injected into the natural gas network, no technical or organisational adjustments are required in network operations or gas applications. This is not always the case for the injection of hydrogen; but low volumes of hydrogen may be admixed already today without subsequent adjustments being necessary. Larger hydrogen volumes require a more differentiated consideration of the pipeline infrastructure and application technologies. Therefore, when talking about integration of renewable electricity into the natural gas network, a basic differentiation must be made between investments required for integration upstream from the network, in the form of a methanation process, or integration into the network, which means improving tolerance levels towards hydrogen. An assessment taking the technical, commercial and, in particular, economic criteria into account is required as the basis for decision-making. Such an assessment may well identify applications where the admixture of hydrogen is preferable over the admixture of methane, or network interconnection points where the admixture of methane is preferable. The project will provide fundamentals and initial indications in this respect. This also includes an inventory of the knowledge currently available about the tolerance of the natural gas network towards hydrogen. This is important for the German gas industry as the last comprehensive work in this field dates back to 2005 (DVGW research project to examine the potential use of hydrogen in energy supplies and present the position of the German gas industry); more recent work is now available in this field. The following presents initial results from work package 1 (hydrogen tolerance).

Hydrogen tolerance of gas network

Depending on concentration admixture of hydrogen causes a significant change in gas properties. The superior calorific value of hydrogen is about one third of the superior calorific value of natural gas so that an admixture of 20% by volume of hydrogen causes the energy content of the gas mixture to fall by approx. 15%. The Wobbe index, on the other hand, as a measure for characterising the quality of fuel gases, falls only by approx. 5% for the same volume admixed as the effect is partially compensated for by the significantly lower density of hydrogen compared to natural gas (Figure 2). Damage to pipelines which may result from the addition of hydrogen is

only possible where dynamic loading of the materials occurs or where electrolytes are present in the pipeline. Gas transportation pipelines are not or only to a very limited extent subject to dynamic loading. Even if the conditions mentioned exist, admixture of hydrogen of up to 50% by volume is not considered critical based on research results available. Hydrogen concentrations of more than 50% by volume may accelerate crack propagation to a technically relevant extent; this would have to be monitored by appropriate pipeline integrity measures.14 Permeation of hydrogen through steel and plastic pipes, seals and membranes occurs only to a minor extent and may therefore be neglected in economic and ecological respects. From a safety viewpoint permeation does not involve a higher risk than natural gas, if permeated hydrogen can freely escape into the atmosphere. Permeation losses are considerably lower than the volumes escaping through leaks. Both permeation losses and losses through leaks are so low that they may usually be neglected. On the leak rates as such the admixture of hydrogen has two effects: leak volume flow increases while leak mass flow and energy content clearly decrease. In Germany gas pressure regulating systems for inlet pressures from 5 bar are usually designed and constructed in accordance with DVGW Code G 491. The systems are operated with gases in accordance with DVGW Code G 260 except for liquefied petroleum gas. This means the systems are also designed for hydrogen-rich gases (up to 67% by volume of hydrogen). Cavern storage facilities basically offer good conditions for the storage of hydrogen. Injection of hydrogen into porous rock storage facilities is currently considered critical. Further investigation is still required in this respect to clarify under which conditions cavern and porous rock storage facilities can be used for hydrogen storage. Concerning the hydrogen tolerance of gas turbines, manufacturers have no experience as to the combustion of natural gas with hydrogen concentrations of more than 3-4% by volume in turbines designed for natural gas. Solar Turbines Inc. made individual tests at laboratory conditions with concentrations up to 9% by volume of hydrogen in natural gas; but the results cannot be transferred to standard operations. Solar Turbines Inc. therefore limits the hydrogen concentrations for existing gas turbines to max. 4% by volume as laid down in the fuel gas specifications. Comprehensive experience is available with residential gas appliances. No problems occur where gas appliances, in particular modern premixed appliances in domestic applications, are operated on admixture concentrations of up to 20% by volume [16]. It is therefore assumed that these appliances do not constitute the limiting factor for the hydrogen admixture concentration in the natural gas network. This assumption is justified as the manufacturers of gas appliances are required to ensure safe operation of all appliances marketed if operated on gases in accordance with G 260. Moreover, DIN EN 437 applies to all gas appliances operated in public gas supplies; the standard stipulates a test gas (G 222) with a hydrogen concentration of 23% by volume for group H-gas. All marketed appliances must therefore guarantee safe operation on natural gas including this hydrogen concentration at least for a short period.

11 Jurascik, M.; Sues, A. und Ptasinski, K. J. (2008): Optimization of Biomass-to-Synthetic Natural Gas Conversion Technology Based on Exergy Analysis. In: Proceedings of the International Conference‚ 16th European Biomass Conference & Exhibition of EUBIA in Valencia. 12 Müller-Langer, F. (2008): Technical and economic evaluation of bioenergy conversion paths. Expert opinion for WBGU fl agship report: World in Transition – Future Bioenergy and Sustainable Land Use. In collaboration with A. Perimenis, S. Brauer and D. Thrän et al. WBGU – German Advisory Council on Global Change. DFBZ - Deutsches Biomasse 13 Specht, M.; Baumgart, F.; Feigl, B.; Frick, V.; Stürmer, B.; Zuberbühler, U.; Sterner, M. and Waldstein, G.(2010): Storing bioenergy and renewable electricity in the natural gas grid. 2009 FVEE annual conference. Renewable Energy Research for Global Markets. FVEE, Berlin. http://www.fvee.de/fileadmin/publikationen/Themenhefte/th2009/th2009_05_06.pdf. 14 NATURALHY project brochure, October 2009.

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Table 1. Plant concepts examined

Very limited information is available about the effect of hydrogen on industrial processes. Marginal performance losses are expected for low concentrations in combined-cycle power stations. Concentrations from 4% by volume require burners in gas turbines to be adjusted in line with information available. The focus of compatibility tests should be on new residential and industrial gas appliances not yet established on the market. Moreover, potential applications of natural gas as a working and process gas should be identified. In the case of natural gas vehicles and fuelling stations research is still required with respect to cyclic pressure loading of the steel tanks used. Admissible load cycles and use of different materials should therefore be checked. The admixture of hydrogen causes a decrease in knock resistance, which may cause combustion problems in Otto engines for gases with low methane numbers. Motor fuel standard DIN 51624 specifies a minimum methane number of 70. But the influence seems to be unproblematic for low concentrations. Data from literature confirm that hydrogen admixture in the single-digit percentage range (approx. 8% by volume) has positive effects on the combustion in Otto engines because of expanded ignition limits and increased flame velocities. Tests at Graz Technical University and a field test in Malmö confirmed that the pollutant emissions caused by natural gas / hydrogen mixtures are significantly lower than those caused by pure natural gas.15,16 The safety of people and the environment must be ensured also for the admixture of hydrogen (or other gases) to natural gas. The behaviour of a natural gas / hydrogen mixture in closed rooms, for example in the event of leaks in the installation pipework, is very similar to the behaviour of pure natural gas. For hydrogen concentrations of up to approx. 20% by volume, the behaviour of a natural gas / hydrogen mixture is also comparable with the behaviour of pure natural gas with respect to indoor air blending and the probability of an explosion and its consequences.

regional electricity load and absorption capacity (cap) of the electricity network existing at the relevant location. • The wind energy band is the share of electricity or energy from wind power plants or photovoltaic systems which is used for the electro­ lysis process. This share is less volatile but achieves a higher number of full load hours as it is independent of the absorption capacity of the electricity network.

Development of plant concepts and estimated costs

Figure 3. Schematic PtG process presentation [11]

For storing renewable electricity using the power-to-gas approach, plants are necessary which are capable of handling the task in a safe, efficient and reliable manner. The plants will reflect different levels of complexity depending on application and storage approach (hydrogen or methane). But there will also be a large number of components common to all plants, in particular with respect to the generation of hydrogen. Figure 3 is a schematic presentation of the plant structure which will be specified in more detail during the course of the project. Colour identification attempts to allocate the plant elements to the various power-to-gas variants. The allocation will be updated to reflect project progress. Table 1 describes four plant concepts which will be examined in more detail under the current R&D project. The first two plant concepts differ only with respect to operation. The first plant concept is based exclusively on the use of excess wind energy, while the second focuses on the use of a constant wind energy band. The terms excess wind energy and wind energy band were defined as follows: • Excess wind energy or electricity is the share of renewable energy or electricity from wind power plants or photovoltaic systems which cannot be injected into the electricity network because of the

Figure 4. Cost structure for 5 MW electrolysis plant (1,000 m³/h H2; STP) including injection (date: September 2011) 11

15 Stolzenburg, K.: Nutzung von Wasserstoff aus erneuerbaren Energien, DBI H2 expert forum, Berlin 2010. 16 Klell, M. and Sartory, M.: Wasserstoff erdgasgemische in Verbrennungsmotoren, HyCentA Research GmbH, 2007.

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While the first two concepts use several onshore wind parks as renewable electricity sources, the third concept, which is clearly smaller, is limited to the use of excess electricity from a small number of onshore wind energy systems. The gases are injected into a regional transportation or distribution line. The fourth plant concept uses several photovoltaic systems as renewable electricity sources and thus represents a storage / network measure reducing load on the distribution level; it is particularly interesting for southern Germany. The renewable gases are injected into a regional transportation or distribution line. In all concepts excess electricity serves as the starting point for dimensioning the plants, in particular the electrolysis process, taking into account the electricity network in the immediate vicinity as well as the transformers. All four plant concepts are examined with respect to direct injection of hydrogen and methane. The locations will be selected on the basis of freely accessible data. Meetings were held with manufacturers and electrolysis experts to discuss technical questions as well as questions in connection with viability analyses. Initial cost estimates for a power-to-gas system were made and will be specified as the project progresses. Figure 4 shows the percentage capital expenditure shares for a power-to-gas system (direct hydrogen injection) reflecting the current project status. The plant has an electrical electrolysis capacity of 5 MW which corresponds to approx. 1,000 m³/h H2 (STP). The plant concept includes storage (tanks) with a geometric volume of approx. 1,300 m³ for storage of excess hydrogen that cannot always be directly injected into the natural gas network because of the admixture limit. In the present case an alkaline pressure electrolyser is used so that storage is possible up to 30 bar without postcompression. The presentation also contains the capital expenditure for a hydrogen compressor to allow injection into a natural gas transportation pipeline operated above 60 bar. The costs to be incurred for buildings are also included. In the current planning phase it is necessary to add a 30% contingency item to the total of approx. € 10 million. Costs will be estimated more accurately in the further course of the project.

Conclusion

The option of integrating renewable hydrogen or methane into the natural gas network may help to balance situations where the generation of electricity from wind power or photovoltaic systems differs from electricity demand in terms of time and possibly also in terms of space. Load management for electricity networks could be optimised. Aside from network expansion and load management storage facilities will play an important part in the change of direction in energy supplies: in an energy industry increasingly relying on renewable sources weatherinduced gaps in supply of up to two weeks may occur in Germany; this is a situation that cannot be compensated for by the storage technologies known so far. Using the existing gas storage facilities for the power-to-gas approach is currently the only solution to this problem on a national level as these long-term storage facilities have very high capacities. Re-conversion of the renewable gas stored into electricity is possible, for example, with modern combined-cycle power stations or packaged cogeneration systems.17 To implement this promising storage option, technical concepts need to be developed and evaluated with respect to practicability, availability and efficiency. Also, it is necessary to find out where direct hydrogen injection or downstream methanation is the preferable technology approach. Knowledge about the hydrogen tolerance of the natural gas network is as important as an objective assessment of the power-to-gas technology maturity and location requirements. A realistic and economic assessment also includes comparison with solutions on the electricity side; this is necessary to be able to assess comprehensively the economic, social and technical aspects of ways to avoid network expansion by interconnection of the electricity and gas networks. Also, recommendations are necessary for the gas industry to support its position in the regulatory debate. These individual work steps are indispensable for establishing the gas industry’s basic position with respect to this technology. The necessary work will be performed under the DVGW Energy Storage Concepts R&D project (G 1/07/10) within the framework of the gas innovation offensive.

17 Sterner, M. (2009): Bioenergy and renewable power methane in integrated 100 % renewable energy systems. Limiting global warming by transforming energy systems. Kassel University, Dissertation. http://www.upress.uni-kassel.de/publi/abstract.php?978-3-89958-798-2.

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Recent Publications James Henderson, March 2012. Is a Russian Domestic Gas Bubble Emerging? The Oxford Institute for Energy Studies.

Recent forecasts for gas supply in Russia produced by Novatek and Gazprom highlight the large amount of gas available to meet demand in the next 10 years and also point to contrasting views about which companies’ production may be preferred in a potentially oversupplied market place. In light of this potential oversupply situation, it is becoming clear that a number of Non-Gazprom producers (NGPs), including Novatek and some Russian oil companies, are taking the view that the Russian gas market will soon become much more competitive and that access to end consumers will become essential for any company wishing to maximise its gas sales. Rosneft’s announcement in February 2012 that it is to form a joint venture with Itera provides a prime example of this trend. However, this suggests the possibility that Gazprom, which is becoming more reliant on production from remote and relatively high cost fields, may soon find itself at a competitive disadvantage and facing the possibility that it may fail to meet its own production targets by some distance. As a state-owned company, it may hope to rely on political support to achieve its objectives and maintain its dominant position in the Russian gas market, but the Russian Administration then faces a potentially awkward consequence of a higher domestic gas price than might otherwise be necessary, as the lower cost gas owned by Non-Gazprom Producers is crowded out to leave room for Gazprom’s gas. This comment examines this impending dilemma for the Russian government and suggests that one conclusion is that what is good for Gazprom may no longer be good for Russia. This paper is available at: http://www.oxfordenergy.org/wpcms/ wp-content/uploads/2012/03/Is-a-Russian-Domestic-Gas-BubbleEmerging.pdf

Sofya Alterman, February 2012. Natural gas price volatility in the UK and North America. The Oxford Institute for Energy Studies.

Lacking a commonly held definition, volatility is an often overgeneralized term with different meanings to different constituencies. This does not detract from the importance of the subject. To traders volatility is a source of revenue, to energy intensive industrial end-users it is often perceived as a threat. Midstream utilities actively work to riskmanage volatility in order to deliver a ‘dampened’ price offer to end-user customers. In this working paper Sofya Alterman summarises the findings from an analysis of natural gas, crude oil and oil products price time series to answer the questions ‘are natural gas prices inherently more volatile than those of oil?’ and the more interesting question ‘can episodes of markedly different gas price volatility be explained by underlying market fundamentals?’ Sofya’s research involved a painstaking analysis of 14 years-worth of daily price data along with the investigation of the likely drivers of the volatility patterns uncovered. Her results both confirm the relevance of obvious drivers but also show how these can be blunted or offset by other compensating effects, some of which are less widely acknowledged. This paper provides important insights into this key aspect of natural gas traded markets, and is especially relevant in today’s environment as trading hub development continues apace in Continental Europe. This paper is available at: http://www.oxfordenergy.org/wpcms/ wp-content/uploads/2012/02/NG_60.pdf

Howard Rogers, January 2012. The Impact of a Globalizing Market on Future European Gas Supply and Pricing: the Importance of Asian Demand and North American Supply. The Oxford Institute for Energy Studies.

In contrast to the majority of European gas analysis which has tended to concentrate on security issues narrowly defined as dependence on Russian gas supplies, this study shows how changes in North American gas supply and Asian gas demand over the next 15 years can create fundamentally different outcomes for European supply, demand and pricing. Using scenario analysis and a global gas model, Howard Rogers demonstrates that Europeans need to pay as much attention to what is happening in gas markets elsewhere in the world, as they do their own supply/demand dynamics. The study also examines the impact of different scenario outcomes in North America and Asia on Russian gas supply and pricing to Europe, showing that Gazprom may also need to make uncomfortable choices between European export volumes and prices over the next decade. This paper is available at: http://www.oxfordenergy.org/wpcms/ wp-content/uploads/2012/01/NG_59.pdf

Michelle Michot Foss, December 2011. The Outlook for U.S. Gas Prices in 2020: Henry Hub at $3 or $10? The Oxford Institute for Energy Studies. In this paper Michelle Foss concludes that Henry Hub gas prices could credibly be as low as $3/MMbtu, or as high as $10/MMbtu in 2020 but that the balance of likelihoods is for a price late this decade which is significantly higher than the current $3-4/MMbtu levels of 2011. Michelle Foss’ study looks at the past five years of supply, demand and pricing which have been strongly impacted by the unconventional gas – and particularly shale gas – revolution and how different views of its evolution will impact future pricing. The study is a forensic analysis of the huge uncertainties surrounding US natural gas supply and demand which illustrates why both commentators and stakeholders have continuously failed to foresee even the approximate direction of prices, leading to the building of numerous LNG import terminals many of which now seem likely to be converted into export terminals. This paper is available at: http://www.oxfordenergy.org/wpcms/ wp-content/uploads/2011/12/Back-to-the-Future-Electricity-MarketReform-Update.pdf

Malcolm Keay, December 2011. Energy Efficiency – Should We Take It Seriously? The Oxford Institute for Energy Studies.

In this Paper, Malcolm Keay looks at governments’ uncritical reliance on energy efficiency to achieve multiple energy policy objectives. He concludes that most existing programmes are ill-directed, badly monitored and probably ineffective in reducing energy demand and emissions – indeed they may be diverting attention from more effective measures. A more targeted approach is needed under which efficiency programmes are properly designed and monitored and integrated more effectively into low carbon strategies. This paper is available at: http://www.oxfordenergy.org/wpcms/ wp-content/uploads/2011/12/SP_24.pdf

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Nancy Wasserman & Chris Neme, February 2012. Achieving Energy Efficiency: A Global Best Practices Guide on Government Policies.

This best practices guide provides a summary overview of the most effective policy mechanisms that regional, national, state or local governments at the executive, legislative or regulatory level can adopt to achieve significant energy efficiency in buildings, processes and equipment used in the residential, commercial, industrial, public and institutional sectors. By policy mechanism, we mean specific laws, regulations, processes and implementation strategies that foster the development and use of products and services which require less energy input to deliver the same or more productivity and output. Our focus is on how government policies can accelerate and increase efficiency investments to achieve additional savings. We do not address best practices in the design or delivery of efficiency programs that would flow from these policies. Nor do we address tariff structures or energy pricing and financing tools that can be employed to help end users invest in efficiency. This report is available at: http://www.raponline.org/document/ download/id/4781

Jacques de Jong, January 2012. A new EU Gas Security of Supply Architecture. Clingendael International Energy Programme.

As part of a four-party project (with FEEM, the Loyola de Palacio Chair in Florence and Wilton Park) on a new EU Gas security of Supply Architecture, a CIEP-workshop was held in July 2011. The “invitationonly” workshop discussed issues on the global gas market setting and its consequences for the EU gas supply perspectives, on the infrastructure challenges accommodating those (external) supplies, and on the market and regulatory designs that might be needed in that context. Particular attention was given on the South Stream pipeline project, on the regulatory risks for new infrastructure investments and on the ongoing discussions for an EU Gas Target Model. The report of the workshop will be used as a further input into the final publication of the project, together with the outcomes of the workshops that were held in Milan and Florence and the forthcoming one at Wilton Park, which is scheduled for the spring of this year. This paper is available at: http://www.clingendael.nl/ publications/2012/201201_ciep_report_jjong_gas_architecture.pdf

IEA, January 2012.A policy strategy for carbon capture and storage. Information paper.

This guide for policy makers aims to assist those involved in designing national and international policy related to carbon capture and storage (CCS). Covering both conventional fossil‐fuel CCS and bioenergy with CCS (BECCS), it explores development of CCS from its early pilot and demonstration project stages through to wide‐scale deployment of the technology. The report concentrates on the economic and political economy perspective, leaving legal, safety, environmental and regulatory issues to be addressed by other analysis. This paper is available at: http://www.iea.org/papers/2012/policy_ strategy_for_ccs.pdf

IEA, January 2012. The Impact of Wind Power on European Natural Gas Markets.

Due to its clean burning properties, low investment costs and flexibility in production, natural gas is often put forward as the ideal partner fuel for wind power and other renewable sources of electricity generation with strongly variable output. This working paper examines three vital questions associated with this premise: 1) Is natural gas indeed the best partner fuel for wind power? 2) If so, to what extent will an increasing market share of wind power in European electricity generation affect demand for natural gas in the power sector? and 3) Considering the existing European natural gas markets, is natural gas capable of fulfilling this role of partner for renewable sources of electricity? This paper is available at: http://www.iea.org/papers/2012/impact_of_ wind_power.pdf

Rick Bosman, Februery 2012. Germany’s Energiewende: Redefining the Rules of the Energy Game. Clingendael International Energy Programme.

German energy policy is increasingly being influenced by a diverse and growing group of renewable energy supporters. They pursue a transition towards an energy system predominantly based on renewable energy. After the Fukushima nuclear disaster, these actors became dominant in Germany’s energy policy arena. Consequently, the Energiewende, as the transition has been coined, has been taken up as a broad societal challenge, pursued by parties across the political spectrum and actively supported by a large part of the German public. Germany’s nuclear sector has been the first victim of the recent developments, yet pressure is building up on the coal sector as well. Natural gas has so far remained below the radar, but its importance in the German electricity mix might actually increase in order to bridge the gap created by the nuclear phase-out. The German renewables supporters will likely be able to continue to use their newfound clout to tilt their country’s energy playing field in their favour. However, in order to maintain the momentum of the energy transition it will be beneficial for them to involve other European partners in future. This paper is available at: http://www.clingendael.nl/ publications/2012/20120215_ciep_briefingpaper_rbosman_germany_ energiewende.pdf

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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. ISSN: 2212-9669 Editor in Chief Catrinus J. Jepma Scientific director EDIAAL* Editors Jacob Huber Nadja Kogdenko Steven van Eije Klaas Kwakkel EDI Quarterly contact information Energy Delta Institute Laan Corpus den Hoorn 300 P.O. Box 11073 9700 CB Groningen The Netherlands T +31 (0)50 5248337 F +31 (0)50 5248301 E quarterly@energydelta.nl

* 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.

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EDI Quarterly Vol. 4 No. 1 Smart Grids and Gas Quality