1 Introduction

In October 2016, the Polish state-run gas firm PGNiG all but ended the quest for finding economically viable deposits of shale gas in the country. This move followed the retreat of a who’s who of leading multinational energy companies including Exxon Mobil, Marathon, ENI, Total and Chevron over the last several years (Reuters 2016). Undoubtedly, this development had not been anticipated just a few years ago. This is all the more significant, considering the fact that the hopes of the European shale gas industry had been pinned on Poland (Johnson and Boersma 2013). After the failed operations in Poland, only a few companies continue to pursue drilling ambitions in other European countries, e. g. Ukraine and Great Britain. However, Osicka et al. (2016) argue, that the success of the polish shale gas exploration is determined by the local market and investments in infrastructure. The lack of success achieved by companies in Poland provokes the question whether the lack of success in Poland marks the end of broader European fracking aspirations or merely indicates that the potential of Polish shale gas formations was severely overestimated.

Nevertheless, shale gas reserves continue to be considered a potentially vital component of strengthening Europe’s security of supply and bolstering its energy independence. Considering the current geopolitical tensions at Europe’s borders, the issue of import dependency has duly received a heightened level of interest. The Arab Spring in 2011, for example, led to a shortfall of natural gas in the Greenstream pipeline between Libya and Italy for the duration of nearly nine months (Darbouche and Fattouh 2011). In Eastern Europe, the Russian-Ukrainian gas dispute, which began in 2006, flared up again as a result of the political upheaval in Kiev. These episodes of geopolitical wrangling have already been accompanied by several supply disruptions in Southeast Europe (Pirani et al. 2009, 2014). The most recent revivals of the Turkish Stream and Nord Stream 2 projects have on the one hand helped to assuage concerns about future supply shortages but due to the projects’ continued reliance on Russian gas the issue of diversification continues to be of critical interest. Against this backdrop, the paper addresses the question as to whether or not shale gas deposits in Europe exhibit the potential to provide a means of diversification in the foreseeable future. The extant literature remains divided on the answer, with much of the disagreement summed up in a statement made at the Romanian Gas Conference in the autumn of 2014: “We don’t really know what’s down there […]. We see that there are resources to be exploited […] but we don’t have any data to analyze […]” (Natural Gas Europe 2014). Thus, the aims of the analysis are twofold: To assess the availability of shale gas resources and appraise their economic potential.Footnote 1

The paper proceeds as follows: Sect. 2 defines basic shale gas terms and provides an overview of the methods applied in evaluating technical shale gas potential and related cost factors. Sect. 3 conducts a literature review of the extant literature on shale gas prospects in Europe and uses the existing data sources to perform a cost calculation of the economic potential of European shale gas layers. Sect. 4 discusses the results in the current market and societal context. Finally, we summarize our findings and provide an outlook on the policy implications in the context of security of supply.

2 Resources, Reserves and Methods for Estimating Gas Production

This section provides a breakdown of basic terms and methodologies employed in the literature on shale gas potential and production costs. To begin with, the chapter distinguishes between reserves and resources and classifies a shale gas formation into its technically and economically recoverable shares. Subsequently, the prevailing methods used in the extant literature to evaluate shale gas formations are detailed. Finally, the cost factors and the structure of the applied cost calculations are briefly introduced.

2.1 Definition of Resources and Reserves

According to Pearson et al. (2012), the definitions of resources and reserves vary in the literature. An illustration of the terms is provided in the McKelvey box (cf. Fig. 1). The McKelvey box and the following definitions are largely based on McGlade et al. (2013) and some interpretations of Pearson et al. (2012), but have been adapted to the terms and resource descriptions used in this paper.

Fig. 1
figure 1

McKelvey Box for the classification of shale gas resources (own illustration based on McGlade (2013) and Pearson et al. (2012)). ERR Economically recoverable resource, EUR Estimated ultimate recovery, TRR Technically recoverable resource, URR Ultimately recoverable resource, GIP Gas in place

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In a shale gas formation, the maximum available volume share is described by the term gas in place (GIP). According to the definition, it comprises all discovered and undiscovered shale gas resources, including those not economically recoverable at present. In addition, it contains the resources that are not exploitable with current technological means and even those that are not expected to become recoverable in the future by way of technological advancements. Other papers, like TNO (2009) utilize the term gas initially in place (GIIP) for the GIP volume. Again, others describe the volume as the original gas in place (OGIP) resource (McGlade et al. 2013). All terms essentially describe the same volume of shale gas. Frequently, the GIP resource is associated with the recovery factor. This factor allows one to calculate the percentage of the GIP resources that are technically exploitable with current technology.

The ultimately recoverable resource (URR) describes the next largest volume. It comprises the discovered and undiscovered resources that are economically extractable and includes resources that are not economically extractable and not recoverable with current technology. According to Pearson et al. (2012), the term URR is sometimes applied in the literature to entire shale gas fields as well as to single wells. However, this analysis utilizes URR only with respect to large areas like entire shale gas formations or shale gas layers.

The technically recoverable resource (TRR) is one of the most commonly used terms in shale gas assessments and refers to discovered and undiscovered resources that are exploitable with present drilling and fracking technologies. As previously explained, the TRR can be calculated by multiplying the recovery factor with the gas in place resources (GIP) in the respective area.

The economically recoverable resource (ERR) includes all discovered and undiscovered resources that are economically recoverable at current market prices. According to Pearson et al. (2012), it is an unusual approach to add undiscovered resources to the ERR volume, since the economic efficiency of undiscovered and undrilled resources is hardly determinable. However, Pearson et al. (2012) suggests not changing the definition in order to ensure consistency with previous research (cf. Attansi and Freeman 2011 and BOEM 2011) that have also elected to use this definition.

Finally, shale gas reserves describe the part of the ERR that has already been discovered. Reserves can be further divided into reserves that are proven (P90), reserves that are proven and possible (P50) and reserves that are proven, possible and probable (P10). For instance, according to these definitions, P90 reserves have a 90% probability of meeting or exceeding the forecasted reserve volume. In Europe, most geological research institutes have yet to publish data on European shale gas reserves. In their estimation, the geological understanding of European shale gas formations is insufficient to allow for a reliable reserve projection (Slingerland 2014).

The last term in the McKelvey box is the estimated ultimate recovery (EUR). In this paper, the EUR describes the amount of technically recoverable resources that can be extracted from a single well over its entire lifetime. In other words, the EUR represents the cumulative production of a well. Unfortunately, the definition of the EUR in the literature is not as well-developed as it might appear. McGlade et al. (2013) uses the expression EUR nearly identically to the term URR with the only difference being that EUR refers to a single well while the URR describes an entire shale gas formation. According to this definition, the EUR would include resources that are not exploitable with current technology (cf. Fig. 1). Pearson et al. (2012) considers this definition to be unsatisfactory because the EUR volumes are calculated on the basis of active wells that are drilled with current technology and suggests that it is more appropriate to relate the EUR volume to the TRR instead of the URR. Being judicious, this approach is utilised.

2.2 Methods for Estimating Shale Gas Resources

The following section examines the contemporary methods used to study shale gas resources. These include the gas in place approach (GIP approach) and the estimated ultimate recovery approach (EUR approach). The main steps involved in each calculation method are explained to provide an understanding of the difficulties inherent in shale gas assessments. Afterwards, the estimation techniques are evaluated according to their advantages and shortcomings.

2.2.1 The Gas in Place Approach (GIP Approach)

The gas in place approach can be considered a bottom-up analysis, which successively breaks down geographical shale gas data to ascertain final production potential. Drawing on the extant literature, this method has been employed in a significant number of European shale gas studies. Examples include ACIEP (2013), BGR (2012), EIA (2013), TNO (2009), Veliciu and Popescu (2012) and to an extent in Andrews (2013a), Andrews (2014) and Monaghan (2014). According to EIA (2013), the calculation method comprises five steps. These include the description of a shale gas formation according to its geological structure and parameters (I); the definition of a gross shale gas area based on additional seismic data (II); the reduction of the gross area to a prospective area with high shale gas potential (III); the assessment of the gas in place volume in this area (IV) and the calculation of the technically recoverable shale gas share of the GIP volume (V) derived by multiplying it with the recovery factor (cf. Eq. 1).

$$TRR=GIP*recoveryfactor$$
(1)

The recovery factor refers to the mineralogy of the shale formation and contains information on shale well productivity. Typically, the recovery factor ranges between 10 and 30%. Accordingly, a recovery factor of 10% is applied for reservoirs with acute very low pressure and high geologic complexity. A recovery of 30% is only applied for excellent shale formations, exceptional reservoir performance and well-known and established performance rates (EIA 2013). However, the choice of the recovery factor is an integral component of the GIP method. Shale gas studies that aim to provide a conservative forecast typically tend to choose a low recovery factor as has been done in BGR (2012).

In terms of its overall assessment, the GIP approach especially benefits from a well-established geological-based methodology. For this reason, even undrilled and partly undiscovered areas can be evaluated, provided that the geological data is available. On the other hand, the method exhibits inadequacies when it comes to breaking down the comparative amount of total gas in place resources to the technically recoverable resources in the area. This is mainly connected to the estimation of the recovery factor and the prospective area. As described, the recovery factor is mainly defined on the basis of the specific geological setting. Unfortunately, identical geological parameters can lead to different shale gas recovery rates as indicated in TNO (2009). According to this study, US drilling history has demonstrated an inability to identify which geological settings yield a certain shale gas output. Hence, the recovery factor entails a high degree of uncertainty. Using a prospective area is beneficial in that it reduces the large gross shale gas area into a more confined smaller unit. Nevertheless, the approach fails to further distinguish between sweet spots and non-sweet spots contained in the formation. The term sweet spot describes a certain area within the shale gas play which offers a significantly higher rate of recovery and productivity. This differentiation is important for an economic evaluation because the sweet spots offer a higher cumulative production per well (EUR). Last but not least, the fact that the GIP-approach does not rely on drilling data (besides the advantage of reduced data volume) can also be characterized as a shortcoming. This is because the projections are not verified by the experience of drilling operations (Pearson et al. 2012).

2.2.2 The Estimated Ultimate Recovery Approach (EUR Approach)

The estimated ultimate recovery approach (EUR-approach) can be classified as a method that uses the production experience of known wells to extrapolate the data to undeveloped or new shale gas fields. Therefore, wells with a long and reliable drilling history have been selected to serve as data sources for the study. For European shale gas assessments, this method has been applied by Gautier et al. (2013), PGI (2012) and USGS (2012).

The estimated ultimate recovery (EUR) is one of the most sensitive parameters in this approach. It describes the maximum amount of gas that can be retrieved from a single shale gas well. Because the EUR is said to denote the performance of a well, the method is also known as performance-based assessment methodology. A second variable involves the well spacing. It defines the amount of wells per assessment unit that are required to be drilled for an optimal development of the shale gas formation. Furthermore, the success ratio indicates the drilling success rate in the shale gas area and rates the number of successful wells to the number of wells without noteworthy shale gas output. A fourth factor is the potential productive area that further divides the assessment unit (AU) into sweet spots and non-sweet spots. In addition, a so-called AU probability is calculated for areas that are unknown or have yet to be explored. The measure defines the amount of shale gas that is expected to be extractable from an undiscovered AU. For all these variables a probability distribution is set up. These single distributions are combined and evaluated with a Monte Carlo simulation. The output of the Monte Carlo assessment finally leads to the probability distribution of the amount of technically recoverable resources (TRR) in the shale gas formation (Gautier et al. 2014).

One essential parameter of this approach, however, is the dimension of the cumulative production per well (EUR). Overestimation obviously leads to TRRs that are too optimistic while an underestimation of the EUR might be too conservative in the end. According to Mazur (2012), the EUR-forecast is done by the technique referred to as decline curve analysis (DCA). Decline curve analysis is required because the production profile of a well for the most part follows an irregular and declining path. The production profile is characterized by a strong initial production rate during the first two months of well productivity. Subsequently, a weaker and decreasing production flow emerges and persists till the end of the lifetime of the borehole (Pearson et al. 2012). An illustration of an exemplary production profile according to decline curve theory is pictured in Fig. 2.

Fig. 2
figure 2

Typical decline curves of shale gas (own illustration based on Fekete (2014) and Craine (2014))

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A closer analysis of the decline curves shows that the decline rate exponent b is critical to the estimation of the EUR. An exponential decline shows the highest shale gas production, followed by a hyperbolic and a harmonic decline. Because of its significance, an active discussion concerning the correct b-value is currently ongoing in the literature.Footnote 2 Unfortunately, a generally accepted figure has yet to be provided (Fekete 2014). Research conducted by Berman and Pittinger (2011) goes as far as stating that the type curves used in the US shale gas industry often overestimate the recoverable resources of shale gas wells. If proven to be true, the well reserves could be up to 50% lower than alleged by drilling operators and the US shale gas extraction costs would thus be considerably higher.

In the EUR approach, some of the problems of the GIP approach are resolved while other difficulties emerge. A key element of uncertainty, the determination of the b-value, has already been discussed. A further factor of uncertainty relates to the drilling data that is mainly taken from sweet spot regions because more attractive regions are explored and drilled first. The extrapolation of this data to unknown regions might, however, overestimate the well productivity and therefore the technically recoverable resources in the rest of the shale gas formation. The general concept of the EUR approach, to rely on active drilling data, is considered to be a positive feature of the method. Some of the referenced boreholes show a long and well-documented drilling history and provide the best possible insight into the resource potential exhibited at least by small drilling areas (Pearson et al. 2012).

2.3 Cost Drivers of Shale Gas Production

This section provides an overview of shale gas life cycle production costs based on the experience of the US natural gas industry. An aggregation of the results of the cost units for shale gas drilling in the US Haynesville shale gas formation is presented in Fig. 3.

Fig. 3
figure 3

Cost parameters of shale gas production (own illustration based on Gény (2010))

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According to the analysis, life cycle costs of shale gas can be divided into four cost categories: finding and development costs (F&D), lease operating expenses (LOE), administrative expenses and interest expenses. Among these, F&D costs and LOE constitute 80% of total expenditures and thus will be elaborated upon in further detail. Firstly, F&D costs are categorized into investments for land acquisition, land exploration as well as drilling and completion of the borehole. As a rule of thumb, half of the F&D costs pertain to land acquisition and another half to the exploration and the drilling and completion phase. Hence, the drilling and completion costs (D&C) are of special importance, since they account for nearly 100% of the total well costs. The term drilling costs include expenditures for preparing the location, casing and cementing, directional and/or horizontal drilling as well as rig, mobilisation and demobilisation costs. The completion costs comprise expenses for tubing and surf equipment, perforation of the well, treatment of the flow-back water and finally the stimulation of the well. It can be said that D&C costs are split equally between drilling and completion expenses. LOE costs, as the second largest cost block, constitutes the expenses for gathering, processing and transporting the extracted shale gas as well as all expenditures for labour, overhead work, maintenance of the equipment and workover of the gas well. These operational costs vary depending on the specific characteristics of a shale gas formation and its distance to pipelines. Constituting running costs, LOE costs can be considered as a floor price below which producers operate at a loss (Gény 2010).

3 Technically Recoverable Resources and Calculation of Shale Gas Production Costs

In the following analysis, extant literature concerning European shale gas reserves is reviewed and an evaluation of the technical recoverable resources in various European countries, including Turkey und Ukraine, is conducted. Based on this literature survey, shale gas extraction costs are calculated. Hence, major cost parameters are determined and incorporated into a cost calculation. Finally, the respective shale gas production costs calculated are compared with the daily reference price of natural gas to gauge the economic competitiveness of the unconventional gas resources.

3.1 Literature Review on Shale Gas Resources

The first analysis conducted on the extent of shale gas in geographic Europe is relatively recent. Rogner (1997) estimated the European gas in place resources (GIP) to be approximately 16,400 bcmFootnote 3. The assessment is considered to be highly speculative due to the lack of available data. Subsequent studies have largely emerged since the onset of the US shale gas boom. In total, this paper has analysed 24 shale gas studies. Some of them assessed Europe’s overall potential whereas others focused solely on specific European countries. Although the results of these studies vary significantly, a selection of their findings are similar in scale. Nevertheless, the applied methods are for the most part the same. These include the application of the GIP and the EUR approach or a comparative literature review. A comparison of the results of the different studies is provided in Fig. 4.

Fig. 4
figure 4

Range of TRR estimates (bcm) in European countries (own illustration based on EIA (2013), Chew (2014), USGS (2012), Slingerland et al. (2014) and national reports)

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Fig. 4 compares the TRR resources of the Europe-wide studies conducted by EIA (2013), Chew (2014) and Slingerland (2014) as well as the national studies by BGR (2012) for Germany, Gautier et al. (2013) for Denmark, TNO (2009) for the Netherlands, PGI (2012) and USGS (2012) for Poland, Veliciu and Popescu (2012) for Romania and ACIEP (2013) for Spain. The illustration shows that some of the studies yield strongly diverging results for individual countries. The most significant disparities can be seen in Denmark, Germany, the Netherlands, Poland, Spain and Great Britain. Other countries like Bulgaria or Romania show a better consensus across studies. Also particularly striking, the Europe-wide report by EIA (2013), which is often considered in the literature as the latest and most accurate shale gas estimate, deviates from some national studies. Comparing the results from EIA (2013) and estimates of national studies, however, does illustrate that national reports are less likely to overestimate their domestic resources. This is best demonstrated by the example of PolandFootnote 4. Nevertheless, the large spread in shale gas estimates does not present a satisfactory picture of the technically recoverable resources in Europe. Thus, the shale gas data has been further aggregated by choosing the most reliable shale gas study from those depicted in Fig. 4 for each country for further assessment. The reliability of each study used has been evaluated by examining the grade of detail of the underlying geological analysis. Moreover, the forecasted TRR in a specific study has been contrasted with the estimations in other studies for the sake of plausibility. The comparison indicates that, in fact, country specific national reports generally demonstrate a superior assessment quality than assessments that consider the entirety of Europe. For this reason, in the following analysis national reports have generally been selected for further assessment. In some cases, if studies show a strong variation in estimated TRRs for the same country, the data from different papers have been combined to yield additional information. For instance, this has been done for Great Britain, where the GIP value of Monaghan (2014) and Andrew (2013) have been combined with the recovery factor of EIA (2013) in order to estimate the TRR volume. In total, 14 countries are chosen for the following shale gas analysis by utilizing the data above with the exception of TNO (2009) and USGS (2012) due to the fact that the data of the national reports and EIA (2013) are more specific for the respective countries.

3.2 Technically Recoverable Resources and Depth Estimation

The following provides a closer examination of individual European shale gas formations. The assessment assigns each shale gas formation its corresponding amount of technically recoverable resources and depth below surface. The respective data is taken from the shale gas studies that have been identified in Sect. 3.1. The geographical location of the shale gas formations are depicted in Fig. 5.

Fig. 5
figure 5

Location of European shale gas formations (own illustration)

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In total, 14 countries and 29 shale gas formations are covered in this paper. In most cases, an individual shale gas formation can be attributed to a single country. Exceptions include the Alum shale, which is located in Sweden and Denmark, the Posidonia shale that is located in Germany and the Netherlands as well as the Baltic formation, which is situated in Lithuania and Poland. The parameterization of the shale gas formations is summarized in Table 1.

Table 1 Parameters of European shale gas formations (own assumptions based on national and international studies)
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In Table 1, the left hand column lists the names of the shale gas formations in the respective country. The right hand column shows the amount of technically recoverable resources in the formation and the corresponding depth below surface. Furthermore, the depth is divided into a minimum, a mean and a maximum depth. Only in the cases of Germany and Romania has the mean depth been calculated separately due to missing specifications in the studies. For this analysis, the minimum depth will be considered as the shallow shale gas layer, while the maximum depth represents the layer of a formation that lies at the greatest depth. For Austria, the minimum and maximum values are not currently available. Examining Table 1 closer, it should be noted that some formations are further divided into a category I, II and III. This consideration is taken from the EIA study, which divides large shale gas basins into areas with associated gas (I), wet gas (II) and dry gas (III) (EIA 2013). This distinction has been maintained in consideration of the economic shale gas analysis to follow. Knowing that the depth of a formation plays a critical role with respect to drilling costs, a consolidation of the formation shares would be distorting. The French Paris Permian Carboniferous formation represents a good example for illustrating this procedure. While the associated gas area only contains 110 bcm of TRR, the wet and dry gas areas each contain more than 1000 bcm of shale gas. Furthermore, the layers of the formation are all located at different depths. A consolidation of these layers would therefore be misleading. It would suggest that considerably more shale gas can be drilled in a shallow depth region than in reality is available. As a general finding, it can be said that the TRR volume tends to increase with depth. This has partly to do with the fact that thermal maturity increases proportionally with depth and consequently leads to more mature shale gas layers. Accordingly, the analysis reveals that the shallowest shale gas formations are located in Romania. The Western Limit lies a mere 400 m below the surface, followed by the Barland Half and Calarasi formation, both exhibiting a depth of only 900 m. In contrast, the deepest formation is the Dutch Posidonia formation, which reaches 5810 m in total depth. Hence, most shale gas layers show a maximum depth of 5000 m due to the assessment limitations of the respective studies.

To provide a general overview on European shale gas resources, Fig. 6 summarizes the aggregated country based technically recoverable shale gas resources.

Fig. 6
figure 6

Technically recoverable resources in Europe (own illustration)

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According to Fig. 6, Europe contains 15,613 bcm of technically recoverable shale gas. This value ranks only slightly below the first European shale gas study by Rogner (1997), who estimated the European TRR at 16,400 bcm. This analysis further shows that France, Ukraine and the United Kingdom together possess more than half of European TRRs. However, despite a very careful evaluation, the results of this analysis exhibit further uncertainties. For instance, the case of Poland has shown a strong deviation in a short period of time. Nevertheless, the potential of 15,613 bcm of technically recoverable shale gas in Europe presents a strong impetus for the current interest in evaluating the economic viability of the resources.

3.3 Economic Calculation of Shale Gas Production Costs

For the following cost calculation an adapted calculation scheme from the Joint Research Centre of the European Commission (Pearson et al. 2012) has been adopted. The cost calculation mainly comprises F&D costs as well as LOE expenses and, therefore, represents the fundamental operational costs of shale gas drilling. Administrative and interest expenses are not explicitly incorporated into the calculation (cf. Sect. 2.3). This stems from the lack of data and the high situational dependency of these costs. For this reason, the following cost calculation should be viewed as representing a price floor for shale gas in Europe.

According to the “most likely” scenario in Pearson et al. (2012), the calculation of the shale gas price is performed in two steps. The first step involves computing the total shale gas production costs per well, which vary based on the specific shale gas formation. The second step converts these well-specific production costs into energy-specific production costs by assuming different cumulative production rates per well (EUR). Due to the number of European shale gas formations (cf. Sect. 3.2), the cost calculation is demonstrated and explained using the example of the German Undercarbon formation (cf. Table 2).

Table 2 Production cost calculation of the German Undercarbon shale gas formation (own calculation)
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Due to the importance of the depth of a shale gas layer for the production costs (cf. Gény 2010), the calculation of the shale gas production costs is performed for the three different depth levels of the formation which have been described in Table 1 (cf. Sect. 3.2). More precisely, the total production costs per well are calculated incrementally adding the drilling costs, the fracking costs and the field construction costs of the German Undercarbon formation. Accordingly, the drilling costs are calculated in two steps. In a first step, the well duration is calculated by dividing the depth of the formation by the drilling performance. In a second step, the total drilling costs are subsequently calculated by using the following Eq. 2:

$$\text{Total drilling costs}=\text{Site costs}+\text{depth *}\text{depth based costs}+\text{well duration }\mathrm{*}\text{day rate costs}$$
(2)

Using this approach, the total drilling costs for the German Undercarbon range from € 1.0 m to € 4.3 m. After this, the fracturing costs are added, which amount to € 4.2 m. The third cost position is described by the field construction costs. These are considered to be 50% of the sum of the total drilling and fracturing costs and range between € 2.6 m and € 4.3 mFootnote 5. In the end, the sum of the total drilling costs, the fracturing costs and the field construction costs yield the total depth-specific production costs of the shale gas formation. For the case at hand, this means € 7.9 m for the shallow depth, € 10.3 m for the mean depth and € 12.8 m for the great depth layer. This calculation confirms the crucial role that layer depth plays in determining the respective shale gas extraction costs.

The ultimate costs of a well, however, do not solely depend on its depth, but also on the amount of gas that can be extracted from the well during the entire life time of its operation. As noted in Sect. 2.2, the cumulative production is derived from a decline curve analysis and is described by the estimated ultimate recovery (EUR). Admittedly, this is a difficult task for the European shale gas formation, since most of them have yet to be assessed by exploratory drilling operations. Therefore, the decline curve analysis can only be completed for a few active rigs in Europe. According to the Polish Government, the well count on March 2013 lists a mere 42 wells, of which eleven have thus far been fractured (Natural Gas Europe 2013). This is a sparse number of wells, but constitutes the only available information for assessing the EUR. As already stated in Sect. 2.2, the geological conditions vary strongly between the different shale gas formations. For this reason, it is surprising that each shale gas play has its own drilling history. This means that as long as there is no precise data for the individual wells available, it is best practice to use the drilling histories of the largest and best studied wells as a reference (Berman and Pittinger 2011).

In Europe, only a few EUR estimations have been carried out thus far. Depending on the expected well lifetime, the EUR is forecasted to be between 92 and 136 mcm in Sweden, Germany and Poland, between 56 and 62 mcm in Turkey and between 185 and 226 mcm in the Austrian Vienna Basin (cf. Kuhn and Umbach 2011 and Weijermars 2013). Comparing these figures with typical production rates from the United States, they appear to be quite optimistic. According to a study by INTEK (2011), most US shale gas plays show a cumulative production between 10 and 85 mcm with an average of 50 mcm for North America. Another US assessment by McGlade et al. (2013) examines the Marcellus shale gas formation, which is the biggest and one of the most productive shale gas basins in North America. The results are reliable and have been assessed to be between 26 and 102 mcm by Engleder and Lash (2009), 5 and 79 mcm by Coleman et al. (2011), 99 mcm by INTEK (2011) and 44 mcm by EIA (2012). Obviously, American shale gas productivity cannot be inferred for European production. The extensive drilling history in US shale gas plays, however, raises doubts as to European EUR volumes that are on average higher than 50 mcm. This assumption is further supported by the fact that Berman and Pittinger (2011) have appraised the b-values, which are used for the decline curve analysis in the US, as being too high (cf. Sect. 2.2.2). Therefore, lower EUR rates seem more probable, e. g. those already used in the shale gas studies analysed in Sect. 2. Therefore, we will primarily base our calculations on the data from Gautier et al. (2013) and PGI (2012). The EUR valuesFootnote 6 assumed for the following cost calculation are specified in Table 3.

Table 3 EUR volumes for the cost calculation (own assumptions based on Gautier et al. (2013) and PGI (2012))
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The probable recovery scenario assumes a cumulative production of 12 mcm. This scenario illustrates which EUR volumes are to be expected with a high probability. The value has been determined by taking a EUR that ranges between the most likely scenario from the Polish study (11.3 mcm) by PGI (2012) and the most likely case for sweet spots from the Danish study (12.7 mcm) by Gautier et al. (2013). Hence, this scenario serves as an indicator as to whether European production exhibits economically feasibility even at a low recovery rate. Subsequently, the possible recovery scenario is fixed at 32 mcm. Like in the previous case, the data is derived from Gautier et al. (2013) and PGI (2012). This time, the optimistic values for Poland (28.3 mcm) and the Danish sweet spots (36.8 mcm) act as limiting values. A cumulative production of 32 mcm represents, therefore, a scenario with a possible but optimistic underlying average recovery rate. Finally, the preferable recovery scenario is defined at 45 mcm and illustrates shale gas production under optimal conditions, taking into consideration the potential for future efficiency gains. This EUR refers to the average US shale gas EUR, which is similarly seen as an upper average for Europe. In choosing a EUR which is higher than the ones used in recent European shale gas studies, technological progress that would increase drilling capabilities in the future is implicitly assumed. Gusev (2014), for example, shows that the EUR of some wells in the United States has increased from ca. 14 mcm in 1990 to 65 mcm in 2008 on account of efficiency gains in drilling technology.

After having assessed the production costs and the EUR rates for Europe, the total shale gas costs are calculated (cf. Table 4). This involves converting the EUR values into their underlying energy content. However, this cannot be done by using the same formula as the energy content of natural gas varies throughout Europe. For this reason, country specific conversion factors, as published in IEA (2014), are used. For the German Undercarbon formation, the reported calorific value of natural gas is 9508 kWh/m3. Analysing Table 4, it can be observed that the shale gas production costs are strongly dependent on the depth of the formation and the cumulative production per well. Accordingly, a low estimated ultimate recovery yields a cost spread between 62 and 101 €/MWh. The medium recovery rate generates lower costs between 23 and 38 €/MWh. At the highest EUR the price drops to a range of 16 to 27 €/MWh. This clearly indicates that the geological preconditions of the respective shale gas formation play the most critical role in an economically viable production. While a shallow shale gas layer with high EUR might be cost effective, a layer in the same depth can be entirely uneconomical given a low recovery rate. The same is true for the opposite case. While a medium EUR at shallow depth can be market competitive, the same EUR in a deeper layer of the formation can be economically unfeasible due to higher drilling costs.

Table 4 Shale gas costs in €/MWh of the German Undercarbon formation (own calculation)
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4 Discussion of Economic Potential of Shale Gas in Europe

This section concludes the economic analysis of the European shale gas formations with an evaluation of the competitiveness of shale gas against conventional natural gas. For this reason, the calculated shale gas costs of the different shale gas formations are aggregated to cost spreads and are assessed against a reference priceFootnote 7 to determine which countries have economically viable shale gas layers. Subsequently, the shale gas resources are combined with their calculated specific shale gas production costs to provide a cost potential curve for Europe, which we refer to as a merit order analysis.

The reference price for the economic analysis is represented by the daily reference price of natural gas at major European gas hubs. Using published market data as a basis, the reference price for the following analysis is set at approximately 20.3 €/MWh. This price level represents the future natural gas price for 2020, based on data from 2015 (cf. ICE Endex 2015). The reference price is set in relation to country specific shale gas production costs to identify the countries that are able to produce on a competitive basis. In order to do so, the production costs of different layers are further aggregated to country specific production cost spreads. These spreads show the minimum and maximum production price of a specific country. Naturally, the cheapest production prices entail recovery from a shallow layer while the highest prices are realized at a layer situated at a great depth below surface. In case of only one formation being available or no spread being available for a country, the costs are depicted by a single reference price. The cost calculation in Sect. 3.3 has determined the production costs at different production rates (EUR of 12 mcm, 32 mcm and 45 mcm). Due to the fact that 32 mcm seems to be a realistic scenario when anticipating future advancements in production technology and increasing efficiency improvements, the following analysis will concentrate on this production rate. The graphical illustration in Fig. 7 shows the country specific cost spreads at an estimated ultimate recovery (EUR) of 32 mcm. With respect to the illustration, it should be noted that the market price represents full costs, whereas the shale gas costs represent a floor price for unconventional gas in Europe (cf. Sect. 2.3). Additionally, price components, e. g. security margin, profit margin, etc., can lead to an increase in the price level.

Fig. 7
figure 7

Spread of the shale gas costs at a EUR of 32 mcm (own illustration)

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Comparing the shale gas spreads with the current market price of natural gas clearly shows that European shale gas production costs are in general higher and not competitive. Factoring in possible additional administrative expenses, it is quite realistic to assume that, in fact, all shale gas layers analysed are presently too expensive to be competitive with current gas market prices. The overall price spread shows production costs between 21 €/MWh in Sweden and upwards of 50 €/MWh in some formations in Poland. The reasons for the relatively high prices in Poland are twofold: Firstly, higher drilling costs are required due to deep shale gas formations and secondly, the shale formations exhibit a comparatively low calorific value (IEA 2014). Hence, shale gas in Poland is more expensive than in its neighbouring countries.

In order to analyze the capacity of the shale gas layers with production costs below the market price, the price needs to be combined with the specific resource volume of the layer in a merit order analysis. For benchmark reasons, the merit order analysis uses a second reference price in order to show the sensitivity of the cost efficiency of shale gas in relation to the current natural gas price. This second benchmark price is set at 27.6 €/MWh and reflects the average day ahead natural gas price in 2013 (EEX 2013). By using a second reference price, the analysis takes into account the historically low natural gas prices that existed at the time of writing this paper. The merit order analysis for EUR values of 12, 32 and 45 mcm is depicted in Fig. 8.

Fig. 8
figure 8

Merit orders of shale gas layers at a EUR of 12, 32 and 45 mcm (own illustration)

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The amount of economically recoverable resources (ERR) becomes visible at the intersection of the market price and the merit order curve. Obviously, a production rate of (EUR) of 12 mcm would entail none of the shale gas formations being cost competitive at natural gas price levels of 20.3 €/MWh or 27.6 €/MWh. Correspondingly, a EUR of 32 mcm would likewise render all formations uncompetitive This already demonstrates that the amount of economically exploitable shale gas is greatly limited in Europe, at least under current market conditions. Taking into account the historically low natural gas prices, the second reference price would result in a greater competitiveness in Europe. Based on our analysis, the amount of economically recoverable shale would rise to 4006 bcm in this case, comprising ca. 26% of the technically recoverable European shale gas resources. The formations of these additional economically viable resources would primarily be located in the British Midland Valley and Bowland Hodder, followed by the Ukrainian Dniepr Donets and Carpathian Foreland Basin and the German Welden and Undercarbon formation. Other economically viable formations exist in Romania, Sweden, France, Turkey, Bulgaria, the Netherlands and Lithuania. A EUR of 45 mcm further increases the economic potential. Accordingly, at a market price of 20.3 €/MWh, 4832 bcm of shale gas is cost competitive while at a price of 27.6 €/MWh the cost competitive potential increases to 13,440 bcm. It should, however, be noted that the merit order analysis has been conducted under the assumption that the amount of natural gas in each layer is equally distributed between shale gas layers at shallow, mean and great depths. This assumption was necessary due to insufficient data about the real depth specific resource distributionFootnote 8 (Chyong and Reiner 2015). Despite efficiency gains generated by increased drilling experience in Europe or an increasing natural gas price, the paper’s findings indicate that the potential for a strong uptake in shale gas production in Europe is considerably limited under current conditions. In contrast to Europe, shallower average basin depths in the US result in lower production costs, e. g. the Marcellus gas shale lies at an average depth of approximately two kilometres below surface (Lee et al. 2011).

It should be noted, that due to the fragmented nature of the European gas market with eastern European countries such as Romania and Ukraine still lack mature gas hubs and are not connected to the liquid hubs in Northwest Europe. For the most part, natural gas is procured via long-term oil-linked contracts from Russia. Wholesale prices, therefore, tend to exceed the hub prices utilized for the analysis above. Nevertheless, Osicka et al. (2016) argue that given the netback pricing model used and the high margins incurred, the break-even price for unconventional gas operations can be assumed to be even lower than the average European import price. Furthermore, most recently Gazprom has agreed to adopt their pricing policy in EU member states in Eastern Europe by providing competitive benchmarks based on western European hub prices in their contractual supply agreements (Stern and Yafimava 2017). In this respect, the hub prices considered for the economic analysis performed are justified.

Beyond the unfavourable economic conditions highlighted, European fracking ambitions have and continue to be hindered by public opinion in Europe in contrast more favourable sentiments in the US. Bomberg (2017) points out lobby groups supporting the development of shale gas between had much more success between 2013 and 2015, whereas those opposing its production exerted more influence in Europe. This role of public attitudes and political considerations is confirmed by van de Graaf et al. (2017). They find that issues related to resource availability and energy security have a rather limited impact on the regulatory policies adopted in European countries pertaining to shale gas production, whereas public concern strongly correlates with the degree to which fracking has been regulated in the respective countries. This societal and political component poses an additional hindrance to realising the economic shale potential that exists.

5 Conclusions and Policy Implications

The preceding economic analysis of shale gas has shown that a considerable volume of technically recoverable shale gas, 15,613 bcm in total, exists in Europe. These resources are dispersed over 14 countries and 29 geographical locations throughout Europe. There is a high likelihood that even more shale gas formations exist than have been investigated. More than half of all resources are located in France, Ukraine and the United Kingdom. Surprisingly, Poland, which most experts assumed to hold the largest European resources only possesses a mere 500 bcm.

The analysis shows that depending on their location, the identified technically recoverable resources (TRR) exhibit very different economic potentials. A cost calculation of these resources indicates that the most critical parameters include the depth of the shale gas layer and the cumulative production of the individual wells (EUR). Depth represents a decisive factor with respect to drilling costs. In Europe, formation depths predominantly range from 1000 to 5000 m. The cumulative production characterizes the productivity of a well and averages between 12 and 45 mcm in Europe. The cost calculation has yielded operative production costs ranging between 15 €/MWh and 130 €/MWh, depending on the productivity of the wells. A comparison of these fundamental costs with the average market price of natural gas has shown that at current market prices of natural gas none of the European shale gas formations are competitive with conventional natural gas. In general, the cheapest shale gas layers are located in France, Romania and Sweden, whereas the most expensive layers are situated in Austria and Poland. The high costs in Poland stand in stark contrast to the promising projections that have been offered for Polish shale gas formations in previous studies. However, the analysis at hand has highlighted that the poor calorific value of Polish natural gas plays a pivotal role in the findings. Revisiting the introduction to this analysis, these findings substantiate the recent decision to forego further serious drilling operations in Poland. In contrast, the ongoing exploratory drilling activities in Ukraine and Romania are not happenstance: The Eastern European shale gas formations display much better geological conditions for cost competitive shale gas production.

Finally, our results indicate that selected shale gas formations could be competitive with natural gas. However, the overwhelming share of European formations is too expensiveFootnote 9. For this reason, it is highly improbable that the North American shale gas boom will be repeated under current conditions in Europe. This is especially true when considering the considerable drop in oil prices that initially occurred in 2014 and have yet to significantly recover. This certainly discourages investment in shale gas production in Europe (Nick and Thoenes 2013). Even if shale gas production is not competitive under current economic conditions, the questions remains as to whether there are other reasons for exploring and exploiting shale gas basins within Europe. Especially for countries with a high supply dependency from natural gas exporting countries, supply diversification through the production of domestic shale gas could be a logical policy choice, even after taking higher costs into account. Accordingly, Seeliger (2016) points out that shale gas could serve as a strategic reserve or a future alternative for some European countries. On the one hand, this form of supply diversification could be beneficial with respect to supply security and on the other hand, it could weaken the bargaining power of suppliers in economical as well as political terms. However, these countries should also consider alternative supply sources such as LNG imports, since their economic prospects could be superior to those of shale gas.

Moreover, a European shale gas industry would have to overcome additional obstacles of a social, environmental and technical nature. These include the lack of infrastructure and a well-developed service industry for fracking, the absence of sub-surface property rights and higher requirements for waste water management to name just a few examples.

All told, a shale gas boom with significant price impacts as seen in the US gas market is unlikely to take place in Europe. Nonetheless, there could be additional rationales that go beyond economic reasons for a country’s interest in shale gas exploration. In this case, obstacles within the countries would need to be overcome. Financial incentives might also need to be taken into consideration to stimulate private investment.