Exploration in Europe: Trends and Challenges

Executive Summary

In June 2014, the European Commission published its European Energy Security Strategy Communication, which aims at improving Europe’s resilience to supply disruptions in the short, medium and long-term. Among other proposals, the strategy states that ‘the exploitation of conventional oil and gas resources in Europe, both in traditional production areas (e.g. the North Sea) and in newly discovered areas (e.g. Eastern Mediterranean, Black Sea), should be developed in full compliance with energy and environmental legislation, including the new Offshore Safety Directive’. The International Association of Oil and Gas Producers (OGP) welcomes this proposed measure and, in this context, would like to make a number of observations specifically relating to exploration for oil and gas – a key part of any successful plan to develop new reserves of oil and gas in Europe. Europe has seen a reduced number of investments in the activity of exploring for new reserves of oil and gas, except in Norway where rates of drilling are increasing. Despite the substantial remaining potential for hydrocarbon discoveries, every year across the EU fewer and fewer wells are being drilled, leading to less indigenous production of energy. Without new discoveries the decline trend is set to continue. OGP has consulted its national oil industry association members across Europe to understand some of the reasons behind the low levels of drilling activity (see annex). This work has been done purely to provide to the Commission an objective and informative depiction of some of the challenges facing explorers in Europe’s memberstates and to emphasise that new regulations from the Commission must not be allowed to discourage investment in new exploration, or undermine existing operations in European waters. The issues contained in this paper are most appropriately left to the member-states working with industry to resolve, and a number of Commission workstreams could negatively impact what is already a complex regulatory environment for Europe’s oil and gas companies. The results of this work broadly show that in the mature basins of Europe, such as the North Sea, the obstacles as expected are mainly associated with the size of prospects combined with their fiscal conditions - which in many cases fail to reflect the significant increase in drilling and development costs and also the price of oil, which determines operational cost structures but which is now around double the price of gas in Europe. Anticipated returns from potential small field developments are often considered too low and this negatively impacts the attractiveness of working in these areas. Other problems – for national governments and industry to resolve – derive from access to finance for smaller operators, as well as fiscal unpredictability and access to infrastructure. In southern Europe and eastern Europe the obstacles are more to do with the length of time it takes to obtain exploration

permits from the authorities, and the complexity of the processes, combined with local protests from campaign groups. The views received from OGP members also highlight the importance of having wellresourced and competent authorities, aware of best practice, who can oversee what is a technically complex industry in a way that achieves the necessary supervision and supports and enables investment at the same time. If Europe is to maximise its economic production of oil and gas, more attention should be paid to fostering a climate that attracts investment and recognises the importance of exploration in ultimately delivering new sources of energy supply. The two graphs below, which show exploration wells drilled in Europe from 20072013, show a general trend of decline. While this exploration activity decline is set to continue, the rate at which new discoveries are made will determine the rate at which it occurs.

Source: Wood Mackenzie

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Proposed steps for the European Commission 

To increase market confidence, there should be much stronger and more visible political support from the European Commission for oil and gas exploration in Europe. In the context of EU security of supply – which has now become an important policy concern - the benefits of lifting the level of exploration activity should not be underestimated, particularly since oil and gas represents around 60% of the energy mix and has a significant role to play in the energy mix for Europe, together with other energy sources like renewables. The table below shows industry estimates of the remaining resource potential in a number of EU member states. Countries of EU

UK The Netherlands Denmark Spain Italy Romania Greece Cyprus Croatia Shale Gas

Estimates of billion barrels oil equivalent (boe) remaining to be discovered 12-14 1.2 1.4 2.0 5.0 ? ? ? ? 20 (125 tcf of gas in the Poyry study best case)

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The Commission, in coordination with member-states, should help to shape the context in which European exploration takes place, including by encouraging member-states to maintain fiscal regimes which are stable and proportionate, and whose regulatory regimes support company access to existing infrastructure.

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The Commission should encourage and assist member-states with creating competent Authorities capable of evaluating and authorising exploration projects within a period of not more than three months following the submission by an operator of an exploration application, which should include an Oil Pollution Emergency Plan (OPEP) and appropriate financial responsibility provisions. The Commission should also encourage member-states to adopt the quick and flexible approach common in other parts of the world of granting exploration licences on the basis of freely submitted work programmes, rather than solely within the framework of licensing rounds.

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Exploration in the southern basins of Europe (Mediterranean) should receive more political backing and public explanation. With the focus now on security of supply, more should be done to explain the benefits of domestic 3

production of oil and gas, in order to prevent initiatives taken by the industry from attracting hostility. The Commission and Member States should work together to help address public acceptance issues that are a challenge facing all energy sources. 

DG Environment has published two tenders for work aimed at drafting a BREF for hydrocarbons exploration and production. It is imperative that this work has a realistic scope and is in line with industry practices; otherwise it is cause for concern. Best practice oil and gas regulation in Europe follows a goal-setting approach, rather than a tick-box, prescriptive one. On the contrary, BREF documents are detailed technical exercises in setting out best practice. Leaving aside the unrealistic aim of capturing best practice across such a vast range of activities in different conditions, a hydrocarbons BREF could introduce significant uncertainty and complexity into day-to-day operational activity, and even the prospect of this happening could be enough to deter investment. Safety will of course always remain the industry’s number one priority. (In this context, it is worth pointing out the growing disparity between ISO, API and OGP standards which has resulted from sanctions regimes and which is preventing harmonisation of safety standards between the US and EU.)

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DG Energy is preparing a report on various aspects of civil liability and financial responsibility for offshore oil and gas operations in Europe, following the recent publication of a study on this subject by BIO by Deloitte. While the content of the Commission’s report is not known at this time, OGP has shared with the Commission its view that at this stage there is no case for further regulation in respect of civil liability and financial responsibility of offshore licensees at the EU level. The study conducted by Bio by Deloitte does not offer an accurate and complete assessment of the relevant aspects that could support a conclusion that further regulation at the EU level is needed. The requirement of demonstrating financial responsibility has been embedded in the EU Offshore Safety Directive (2012) and it has to be incorporated in the national legislation of the individual EU Member States by July 2015. The competent authority in the respective EU Member States is best placed to further implement the requirement to demonstrate financial responsibility, taking into consideration their own circumstances, including the nature of its oil and gas industry (mature or emerging), the geological characteristics of the reservoirs, proximity to environmentally sensitive areas and its legal liability system, etc. A ‘one size fits all’ approach at the EU level in respect of demonstration of financial responsibility is not warranted and would likely have a negative effect on the EU’s ability to attract sufficient investment to maximize the recovery of its natural resources.

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The Commission’s work on subsidies, including the ECOFYS study on levelised energy costs, could have the effect of seriously distorting the important role played by oil and gas to Europe’s economy, thereby exacerbating some of the negative perceptions of the industry. For example, the consultants tasked with this work are adopting a novel concept of ‘fossilfuel depletion’, which implies that consumption of future oil and gas will become very expensive in future – without any sound economic basis or 4

evidence for making this assumption. In addition, they are using a reference price for CO2 which is significantly higher than the current market price. Overall the report risks depicting gas as an expensive fuel for generating electricity when, on a life-cycle cost basis, it is more economic that many other fuels – especially when subsidies to other energy sources are taken into account. In this context, it is worth recalling that the recent NERA study on energy subsidies in Europe found that oil and gas in Europe generates around €430 bn of revenues to the EU 28 per annum. This money will not easily be replaced once lost. 

When the Commission analyses the issues around oil and gas exploration in Europe, it should be recalled that the exploration phase is just one segment in the phasing of oil and gas projects. Projects typically consist of three or four months of drilling activity after which the project can be abandoned or progressed, with subsequent milestones needing to be overcome before the project is sanctioned for development, including the evaluation of opportunity versus risk, environmental impact assessments, community consultation and regulatory approvals. Local support is therefore an important part of enabling significant investments in exploration.

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Annex Country reviews UK The UK is the EU 28’s largest producer of oil, with domestic production meeting around 67% of the UK’s oil demand and 53% of gas demand in 2012. According to Oil and Gas UK (OGUK), the industry trade body, some 42 billion barrels of oil equivalent (boe) have already been produced from the UK Continental Shelf (UKCS) since production first started in the 1960s and it is estimated that a further 12 to 24 billion boe remains to be produced. However, the UKCS is a mature basin where costs are high, and new exploration is increasingly discovering fields that are smaller and more technically challenging to develop than the large fields discovered decades ago. In the past years, a number of discoveries have been made but they remain undeveloped as returns are considered too low. Exploration for oil and gas in the UK is now at an historic low – and according to OGUK, ‘exploration is facing its biggest challenge in 50 years’. Even at a time of relatively high oil prices, never have so few wells been drilled in the UK continental shelf as in the last three years, with only 15 exploration wells drilled in 2013, discovering just 80 million barrels. OGUK states that in 2014 25 exploration wells are planned and ‘even if all the wells proceed, the rate of drilling is too low to recover even a fraction of the potential resources’.

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The graph above shows that an average of 20 exploration wells were drilled in the UK North Sea each year between 2009 and 2013, while the period between 20052008 saw an average of 35 wells drilled per year. Recent data from the UK government show that just 8 exploration wells were drilled in the first half of 2014, compared to 10 in the same period last year. This is cause for concern for both industry and the UK government, which recently passed into law a commitment to maximise economic recovery of oil and gas from the UK North Sea in order to help ensure that the substantial range of benefits associated with domestic oil and gas production, including energy security, are seized. OGUK says that rig availability and access to funding for operators wanting to explore are key reasons for the fall in activity. As part of efforts to increase exploration activity, the UK government also recently opened a major consultation into the North Sea fiscal regime, with industry saying that the current regime is overly-complex. Taking a broader perspective, the UK government and OGUK recently worked together to publish the Wood Review, the conclusion of which underlined the importance of maximising economic recovery of oil and gas from UK waters and proposed a series of measures to help achieve this objective. These proposals provide a good insight into some of the key principles that could underpin similar moves in other jurisdictions to make the most of the oil and gas reserves that exist. The Wood review proposes the following headline actions, which are described in greater detail in the report itself. While the actions are specific to the UK context, they nevertheless convey a wider sense of urgency around the need to increase exploration.     

‘Government should urgently assess the potential to stimulate exploration.’ ‘The Regulator should facilitate the development of regional exploration plans to recover the full resource potential within each area of the UKCS.’ ‘The Regulator should establish why the high demand for acreage in recent exploration licensing rounds has not been converted into more seismic and drilling activity.’ ‘The Regulator, in consultation with Industry, should investigate the rate of exploration drilling, specifically concentrating on drilling costs, improving the supply of rigs to the UKCS, and companies’ ability to access rigs.’ ‘The Regulator should facilitate Industry and the seismic companies to carry out speculative seismic, particularly targeting new plays which lack –up-todate seismic coverage, and, if justified, should support with government funding.’

The central recommendation of the Wood Review was the need for better coordination and collaboration between government and industry, with a proposed new and enhanced ‘arms-length’ regulator performing the duties of licensing, supervision and stewardship. According to the review’s final report - which has been endorsed by the government with implementation beginning immediately - the new regulator ‘must be low in bureaucracy, high in skills and experience, and strong and pragmatic. It will play a vital role in facilitating, co-ordinating, mediating, promoting, and catalysing collaboration, removing barriers, and encouraging more efficient exploration, 7

development and production’. Part of the final report also includes an exploration strategy, the key elements of which are efficient access by companies to well and seismic data (and) an appropriately tailored licensing regime... Measures should also be taken to promote UKCS exploration opportunities internationally’. The Wood Review also noted differences in the approach to exploration compared to Norway and the Netherlands: “In the Netherlands, the state owned non-operating company routinely takes a 40 per cent share in each exploration well and this sharing of risk has undoubtedly resulted in a boost in exploration activity. In Norway, companies without production automatically receive the tax relief in cash from exploration and this measure has been particularly helpful for smaller companies.” In fact, according to the trade association Norsk Olje & Gass (NOROG), exploration levels in Norway have recently been high, with 59 exploration wells drilled in 2013. The next graph shows the recent history of exploration drilling in Norway.

The Netherlands The Netherlands is the largest gas producer and exporter in the EU, having produced 3,600 bcm over the past fifty years. The discovery of the Groningen natural gas field in 1959 - which produced around 54 bcm in 2013 and is expected to produce around 42.5 bcm in 2014 and 2015 - dramatically changed the way The Netherlands met its energy needs, with gas supply infrastructure now a deeply-integrated part of the national energy system. As with other North Sea countries, however, in The Netherlands the average size of fields and prospects that can be explored and developed is becoming smaller, and the infrastructure ageing. 8

According to the Dutch trade association, NOGEPA, the regulatory framework has been successful in encouraging exploration and production of domestic energy, including by introducing a ‘small fields policy’, an ‘investment allowance for marginal offshore gas fields’, and, since 2011, a ‘Fallow Acreage Covenant’, which places an expectation on operators that they relinquish unused exploration licences in order to ensure that more activity takes place to meet the need for new discoveries. Importantly, these initiatives have incentivised companies to develop marginal prospects, rather than simply relying on major fields such as Groningen. NOGEPA states: “Based on current expectations, the Groningen field will continue to produce over the next decades. Although production from small fields is falling, it is expected that they will still account for a significant part of the total in the coming 10 to 20 years”. However, “to deliver the ‘small fields production ambition’ for 2030 (30 bcm), investments have to be stimulated and supported by a reviewed investment allowance by the government”. Yearly gas production from the small fields is as high as 26 bcm. Other recently-introduced tax incentives focused on R&D and innovation are encouraging exploration-oriented research projects. There are other promising signs, including an increase in the total Dutch area covered by exploration licences, from a low of 8,100km2 in 2005 to around 23,000km2 in 2012. This is partly because of recent seismic campaigns offshore suggesting that further discoveries are waiting to be made. NOGEPA points to a shortage of drilling rigs available to the Dutch offshore sector as a possible factor constraining new investment. Denmark According to a recent report commissioned by the trade association Olie Gas Danmark (OGD), ‘there is a significant oil and gas potential left in the Danish sector of the North Sea’, amounting to well over 1.4 billion barrels of oil and gas. As the Danish sector of the North Sea has become more mature, the size of new discoveries has become smaller at the same time as exploration costs have increased. This partly explains why the number of exploration wells being drilled is at its lowest since the 1960s.

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In a fiercely competitive global market, the availability of drilling rigs has decreased and costs have increased significantly in recent years. In Denmark from 2008-2012, the average cost per exploration well was around DKK 445 million (circa 60 million Euros) - which is 57% higher than the total average of the 2000s. The challenge faced by Danish operators wanting to lease drilling rigs is compounded by a lack of harmonisation of regulatory requirements in the EU countries bordering the North Sea. Adjusting rigs to meet the respective national requirements of North Sea countries is a costly business, and a disincentive to companies looking to bring rigs into Danish waters. As OGD concludes, ‘a standardisation of the authorities’ different requirements for rigs across the EUcountries bordering the North Sea, which would mean that if a rig is authorised to enter one national water it is also authorised to enter the others, would have a beneficial impact on the number of rigs available for the Danish oil and gas sector’. As is the case in much of Europe, the licencing regime for exploration activities may benefit from a greater degree of flexibility. According to OGD, this means running more licencing rounds than is currently the case - especially compared with the UK and Norway, where bid rounds are frequent – in order that a greater number of companies can enter the sector to explore, as well as establishing the entire Danish shelf as an ‘open-door area’. OGD suggests that an ‘open door approach’ would ‘give opportunity to freely apply for a licence in all non-licensed areas throughout the Danish shelf’ and, combined with more frequent licensing rounds, ‘both initiatives may have a positive impact on exploration activity’. The Danish association adds that consideration must also be given to whether licences should be returned more promptly in the event that no drilling activity occurs. Spain 10

The example of Spain provides an insight into some of the general obstacles facing companies that want to drill for oil and gas. The Spanish oil and gas association, La Asociación Española de Compañías de Investigación, Exploración y Producción de Hidrocarburos (ACIEP), has studied the issues in detail, concluding that while over the past five years there has been an increase in the granting of exploration permits, seismic acquisition and drilling activity remains at a very low level.

A ‘heavy bureaucratic system, cumbersome environmental permitting’, and a lack of knowledge of exploration techniques, plus a lack of incentives for the local populations are among some of the reasons cited by ACIEP for the lack of drilling. Meanwhile, the Spanish daily demand for oil (1.4 million barrels) and gas (95 million cubic meters) is almost totally met by imports. ACIEP estimates that 2 billion barrels of oil are waiting to be developed in Spain – representing 20% of annual consumption for the next 20 years – while gas resources, including unconventional gas, could meet domestic gas demand for 70 years. The example of the Canary Islands is perhaps illustrative. Two exploration permits were awarded to a company in January 2002 but the permits were shortly afterwards revoked by the Spanish Supreme Court, leading to years of delay. In 2012, ten years after the original award of the licences, a Royal Decree was published reactivating the exploration permits, and in July 2014 the Spanish Supreme Court finally gave the green light to the potential €7.5bn project. The project consortium believes these offshore fields could contain up to 2.2 billion barrels of oil equivalent, which potentially means 110,000 barrels of production per day - enough to meet ten per cent of Spanish annual oil consumption. Currently Spain’s daily domestic production of crude oil is 7,500 bbl/day, which is 0.67% of total annual consumption. For gas, domestic production meets only 0.19% of annual demand. According to ACIEP, seismic acquisition in Spain requires an Environmental Impact Assessment (EIA), the processing and approval of which takes a minimum of two years. Other Spanish fields in the Mediterranean, close to the producing Casablanca 11

field, have been waiting for exploration permits for over two years. As with other parts of Europe, setting more reasonable time limits for the administrative processing of documents would facilitate the exploration process. ACIEP also believes that the local protests in Spain that fuel hostility and legal challenges against exploration of conventional and unconventional resources might be addressed by a focus on distributing the benefits of discoveries with the locality or region where the discovery is located. Italy Over the past ten years, the number of oil and gas companies operating in Italy has decreased dramatically, and exploration drilling has virtually ceased, with only 4 exploration wells drilled in 2012 and none at all offshore. According to a recent report by the Italian government’s Directorate-General for Mineral and Energy Resources (MiSE), ‘the limited exploration activity is mainly due to the difficulty and the time length required for issuing the licenses and the necessary authorization for drilling’.

Assomineraria, Italy’s oil and gas industry association, says that over 700 million tons of oil equivalent remains to be discovered and developed. This would be a significant volume given that Italian domestic production in 2013 was 5.5 million tons of oil, or 110,000 bbl/d (9.3% of consumption), and 7.8 billion m3 of gas (11.2% of consumption). According to Assomineraria, ‘it is possible to activate a wide program of private investments from national and international companies… in order to take the percentage of domestic oil and gas from 10% of 2013 demand to 20% by 2020’. A prerequisite, however, is that ‘the public administration needs to create a more 12

favourable climate for investments’. It takes on average 3.5 years for companies to obtain an exploration permit (and about 9 years for a production permit). One of the main reasons for this cumbersome approach is said to be an apparent lack of procedural consistency between the multiple authorities involved in the licensing process, as well as an unclear division of competence between the local and national governments. Assomineraria states that one of the main obstacles to new exploration drilling is a ban on all new exploration activity within 12 maritime miles of the coast. The map below shows the seven prospective offshore areas which are available for new exploration drilling, but where nothing in terms of new exploration wells is currently happening.

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Romania Romania has historically produced very high volumes of oil and gas and has significant remaining potential both in the Black Sea and with unconventional resources onshore. In 2012, oil production was 3.9 million tons and gas production was around 11bcm. Last year, a consortium exploring in the Black Sea discovered gas reserves in the Neptun Deep Block potentially amounting to 84 bcm, enough to meet domestic gas demand for six years. However, ROPEPCA, the national oil industry association, suggests that a number of obstacles are hindering the efforts of operators to explore and develop new sources of oil and gas. One of these obstacles is the difficulty facing operators when trying to access resource and reserves information, including well and seismic data, as these contrary to the practice in other EU member states - are often classified as confidential or ‘state secrets’ by the regulator. Other barriers include the length of time taken to run bid rounds, the lengthy ratification process for concession agreements – which involves approvals by multiple ministries - and a fiscal regime which is unpredictable and non-transparent.

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As delays occur during the permitting approvals process, companies incur significant capital costs, discouraging investment in exploration. The Energy Policy Group, a think tank in Romania, recently published a paper on barriers to new exploration, concluding that there is no ‘stable framework for the efficient and competitive development of upstream operations’ due to, among other reasons:   

A lack of harmonsation between various laws governing hydrocarbon activities. Recent and unpredictable tax changes. Limited authority for the regulatory agencies and their lack of human and capital resources.

Poland Domestic production in Poland meets around 30% of Poland’s gas consumption (domestic production in 2012 was 5.9 bcm, out of 15.8 bcm of total demand) and 23% of oil demand, making the country largely import dependent. According to the Polish oil and gas trade association, OPPPW, total recoverable gas resources amount to 134.2 bcm The extraction of natural gas in Poland is predominantly carried out by the state-run oil and gas producer, PGNiG, which holds nearly 97% of the 236 oil and gas production licences that have been issued in Poland. Only one foreign company has a production licence for hydrocarbon deposits. At the moment, a further 150 exploration licences (both for conventional and unconventional deposits) are held by a dozen other companies, about half of which are foreign. Since 2008, intensive prospecting for and exploration of unconventional hydrocarbon resources, in particular shale gas, has taken place in Poland. Over 60 shale exploration wells have so far been drilled. However, according to OPPPW, the pace of exploration work has been slowed because of high levels of bureaucracy, convoluted and time-consuming licencing procedures, and difficulty with interpreting the relevant regulations. Poland recently introduced a new law for the upstream sector, though it remains to be seen whether this will speed up exploration activity. The new regulations include joint licencing for both exploration and production activities. However, OPPPW’s members remain wary of the continuing complexity in administrative and fiscal regime (disproportionate to the costs of a project, says OPPPW). Germany The German oil and gas industry association, WEG, reports that production of natural gas has decreased by half over the last decade, to a current level of 10 bcm per annumn. There has been a de facto drilling moratorium in Germany since 2011, with extensive permitting delays and the withholding of approvals. According to WEG, there are still significant potential discoveries of tight gas, shale gas and coal-bed methane, in addition to the already known reserves of around 100

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bcm. The government’s geological institutes estimate further resources: 150 bcm of tight gas, 450 bcm of coal-bed methane and 700 to 2.300 bcm of shale gas. Developing these reources is largely a question of political will. Discussions continue on prohibiting shale gas and coal-bed methane, and well as tightly restricting tight gas. The graph below shows the potential production scenarios over the next ten years, ranging from a continuing rapid decline (in the event of extensive prohibitions) to a significant increase in production if the investment framework is made more attractive.

  Shale gas As with conventional oil and gas, the key factors determining the development of the exploration and production of unconventional gas are the quality and quantity of the resource and the availability of the necessary technology and equipment to develop it; the stability and attractiveness of the broader economic environment, including fiscal issues; and the risks arising from the legal and regulatory system. According to a recent study by the consultancy Poyry, commissioned by OGP, Europe’s has ‘risked’ unconventional gas resources of around 15 trillion cubic meters (tcm). The report concludes that Europe’s ‘gas import dependency could reduce from 89% in 2035 in the No Shale Scenario to 78% in the Some Shale and 62% in the Shale Boom Scenarios’. This last scenario, which would produce 3.5 out of the 15 tcm, would require the drilling of around 60,000 development wells over a 30-year period.

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It remains to be seen which of these scenarios can be achieved in Europe. The productivity of European shale gas wells will be a key element in understanding the economics of shale gas development in Europe. Exploration is therefore imperative and drilling at least 500 wells seems necessary to provide a reliable picture of the contribution that shale gas can make. In Poland, the trade association OPPPW reports that ‘bureaucratic barriers to the greatest extent slow down the (investment) process...’ with an ‘extensive number and unnecessary time burdens for administrative procedures’. The average time needed to obtain all drilling permits is eight months. Exploration drilling in countries like Poland will be vital in establishing the scale and productivity of Europe’s unconventional gas resources. For example, reserve estimates for Poland differ dramatically, with the Polish Geological Institute estimating around 346 – 767 bcm but the US Energy Information Administration in their latest report estimating 4,200 bcm. Since 2011, 22 wells have been hydraulically fracked with hundreds more planned before 2021, and OPPPW estimates that several dozen more exploration wells are needed to credibly assess Poland’s shale gas resources. In Romania, ROPEPCA says that land access issues, including conflicting laws, are creating an obstacle for companies wanting to operate onshore. More broadly, the availability of onshore drilling rigs and a supply chain is low across Europe. According to the service company, Baker Hughes, Europe currently has 50 onshore rigs active in 12 countries with a median count of 2 per active country In Europe, while the US has 1801 available rigs. Aside from outright bans in some member states on hydraulic fracturing – a process that has been used for decades in both conventional and unconventional drilling - the supply chain challenge will be one of the biggest hurdles, along with gaining public acceptance, to establishing a shale gas industry in Europe.

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