Publications on the internet
CORRECTED TRANSCRIPT OF ORAL EVIDENCE
To be published as HC 785-i
House of commons
TAKEN BEFORE THE
Energy and Climate Change Committee
The Impact of Shale Gas on Energy Markets
Tuesday 27 November 2012
Nigel Smith and PROFESSOR Richard Davies
Professor Mike Bradshaw, Simon Moore, Dr Thierry Bros and Professor Paul Stevens
Evidence heard in Public Questions 1 - 92
USE OF THE TRANSCRIPT
This is a corrected transcript of evidence taken in public and reported to the House. The transcript has been placed on the internet on the authority of the Committee, and copies have been made available by the Vote Office for the use of Members and others.
The transcript is an approved formal record of these proceedings. It will be printed in due course.
Taken before the Energy and Climate Change Committee
on Tuesday 27 November 2012
Mr Tim Yeo (Chair)
Mr Peter Lilley
Sir Robert Smith
Dr Alan Whitehead
Examination of Witnesses
Witnesses: Mr Nigel Smith, Seismic/Basin Analyst, British Geological Survey, and Professor Richard Davies, representative from The Geological Society, gave evidence.
Q1 Chair: Good morning and welcome. Thank you for coming in. As you know, this is our second inquiry on shale gas. In fact we had some help from you on the previous inquiry last year, but I think it would be helpful if perhaps you just introduce yourselves very briefly to the Committee.
Mr Smith: I am Nigel Smith from the British Geological Survey; I have been working on shale gas since 2008.
Professor Davies: I am Richard Davies, I am a Professor at Durham University and I used to work in Exxon Mobil before I became an academic. I have been working extensively across Eastern Europe talking to members of the public and to companies about shale gas.
Q2 Chair: Thank you. Before we get on to the interesting question of how much shale gas may be under the ground, I wonder if you would just like to explain the different ways of defining how much shale gas there is-there is a certain amount of technicality here-and how those ways differ from each other.
Mr Smith: The first method would be to compare a basin in America-for example, the Barnett Shale in the Fort Worth basin, which I think you visited last year-with a similar basin in this country, which would be the Pennine basin, and see what the productivity is in America, work out the area that we think has shale gas in the rocks here and produce a figure. That figure would be like a reserve figure in our table that we have provided for you. The companies can even produce a resource figure, which is going to be much bigger. It is the total amount of gas that is in the ground and they can even produce that before they have drilled. They will work out the thickness of the shale, they will guess how much the gas content is, they will have their area of their licence and they will be keen to publish that for the shareholders’ benefit. When they drill, for example IGas have drilled in Lancashire and they have doubled their figure that they had originally after they drilled one well and tested some of the shales. I think those are the critical differences.
When you start to get production going then you can be a little bit more secure as to what the reserve figure is going to be. Mine was just a guess, the original reserve figure, because no drilling had taken place in this country; so you are using information from another country, another continent, which might not be relevant here.
Professor Davies: Just to reiterate some of the points that Nigel has made, there are two key terms-one is resource and one is reserve, and they are entirely different. Just to reiterate for everyone’s benefit, resource is the amount of gas underground. Just like the coal mining industry or any other extractive industry, that is not the same as the amount of gas you could extract. That is called the reserve and that is dependent upon a number of factors, economic, social in the case of the UK and many other parts of the world, and technological. The amount you can produce, which is called the reserve, is usually a fraction of what is there underground.
Companies that are listed on the New York Stock Exchange have to follow guidelines for what they can call reserve, the SEC guidelines. I have been involved in my previous career in industry in booking reserves, defining reserves, and it is a very closely monitored and policed activity in the companies because it relates to the value of their company. Reserves are a different number from resource. Reserves are something you have to be extremely confident you can economically extract from the ground.
Q3 Chair: That includes, therefore, the price as one of the factors?
Professor Davies: To be frank, that is one of the key factors so you can continue producing until you hit an economic threshold. You can look at the decline curve of your production-you usually start with very high rates of production from a shale gas well-and you can extrapolate it to the point where it is economically not viable. Of course, that depends upon the fiscal regime in place, as we know from the North Sea. It is also related to technology and your ability to produce the reserves with the technology you have. There are a number of factors. Most important here is to state that reserves are completely different from resources.
Q4 Chair: Is the New York Stock Exchange definition one that is commonly accepted?
Professor Davies: Yes, the SEC guidelines are followed by companies listed on the New York Stock Exchange and then closely followed by companies who, of course, want investors to be confident in the reserves because the reserves is a critical number that increases the value of your business. If a company was to make a mistake in estimating the reserves that has a huge impact, and we have seen evidence for that in the past-large companies overestimating reserves. You all know, for example, Shell did that around 10 years ago where they overestimated that critical number.
Q5 Chair: Apart from the price, what other key factors would determine what a reserve is?
Professor Davies: At this point geology is a key factor. Very close to the top of the list is how much gas is in the rock and how the rock behaves when you fracture it and, therefore, how much gas can come out of a volume of rock, but what may be a key determinant is the ability to drill wells; in other words the limitations on drilling wells that may be related to how populated a region is, how acceptable drilling is. In the United States you drill a few wells. You can then book the reserves there and say, "We have proven that volume," and the surrounding areas become probable volumes and behind that will be possible reserves and volumes. It spreads out in that way from a central area as you are drilling wells.
It is a bit like a chessboard. You are then proving different areas as you grow the production and that is quite different from how it has been done for conventional hydrocarbons, which is what the North Sea, of course, is. That is a different mechanism. It is proven by drilling wells. You can book 80 acres per well. That is the area you can book and that is what the SEC guidelines say and American companies listed on the New York Stock Exchange will follow them.
Q6 Chair: Is there a further description between recoverable reserves and reserves?
Professor Davies: No, reserves are recoverable. I think for this conversation they are the same thing. Recoverable reserves and reserves are the same thing. The only other term you may hear is "technically recoverable". If you hear the term "technically recoverable", that is saying, "With the present technology what can we get?" That is not the same as reserve. Reserve is about economics and political regime and so on. You may hear the term "technical reserves", which is what technically we can get out, but the key thing is the term "reserve", which means what we can get out in the present economic regime.
Mr Smith: I think at the moment, because the price of gas has plummeted in the US, they are now switching to looking for shale oil. They will stop looking for shale gas because the price is too low. It is the point that you made.
Q7 Chair: Given that the reserves depend on the price, which clearly is unknown more than a fairly short time ahead, and secondly, on things you mentioned like the density of the population, which must be a pretty subjective judgment, even the SEC definition seems to be a fairly moveable feast.
Professor Davies: The SEC definition is if you have a patch of land with nothing on it-and I am basically agreeing with you-you can book that. Every time you drill a well and fracture it and start producing you have proven a certain volume. That becomes far more complicated if there is land and land use issues. In Europe we are in a different regime from the US in terms of land ownership and mineral rights ownership, so it is going to be a bit more complicated and probably slower in taking off-a lot slower.
Q8 Chair: Without being too cynical, the proximity of potential reserves to a council estate in Lancashire and those to Notting Hill might be regarded as having a different order of influence.
Professor Davies: You are probably more expert than I am, but there are probably parts of the UK that have better prospects for booking reserves than others.
Mr Smith: I think, once again, the Americans are pioneering drilling in close to urban areas. They even drill under Fort Worth, Dallas Airport.
Chair: We saw some of that when we were there.
Mr Smith: Yes. In a way, although the population density in America is eight times lower than ours, I think they are still showing us the way-that it could be done without interfering with people’s property, safely and successfully.
Professor Davies: There is a large oilfield in Los Angeles that is camouflaged by buildings and you would not know it was there, but that is the United States.
Q9 Sir Robert Smith: I remind the Committee of my interest in the Register of Members’ Interests to do with the oil and gas industry, in particular a shareholding in Shell. I suppose the one-off Bournemouth is another example of where we are in a sensitive area by long directional drilling.
Mr Smith: Exactly, yes-Wytch Farm. It would be much more difficult to get that approved now. Things have moved on since the 1970s.
Professor Davies: In fact Wytch Farm was a great example of us leading in the technology of horizontal drilling. Those were the longest horizontal wells drilled in the world and, of course, everyone understands a combination of horizontal drilling and fracturing that has opened up this technology. We were leading with that.
Q10 Sir Robert Smith: What sorts of factors make it more uncertain in shale gas than in conventional gas? Is it the fact that you have to prove all the geology with drilling?
Mr Smith: You have to define the source rock area, so that probably requires a lot more drilling, even with pad drilling, compared with conventional exploration. It is a bit like, if I can use the analogy of cooking and kitchens, you are looking for the kitchen because the kitchen has a lot of food in it, it is in the fridge, it is in various places, compared to the dining room, which is just a place where people are sitting. They are the individual oilfields, like Wytch Farm, and you have a timing problem there because your hydrocarbons are migrating from the source rock to the dining room and you have to be able to drill just at the time when somebody is eating their food in order to get the hydrocarbons there. The hydrocarbons in the kitchen should always be there.
Professor Davies: May I add to that? In the last 20 years the industry developed something called 3D seismic data. It is like a picture of this room but the scale bars would be 40 km by 40 km and 5 km, 6 km deep. That 3D seismic data gives clues as to where to find conventional hydrocarbons. You can see it. It takes a picture. It would take a picture of the room and show us where the table is in the middle and you would drill into the table, and the table is well defined. The extent of the hydrocarbons is defined.
Q11 Sir Robert Smith: More potential still?
Professor Davies: Absolutely right, it would be a resource until you drilled it and produced some to prove it could be produced. But with shale gas, the geology has lagged behind. It is a drilling and an engineering discipline to a large extent. The geology is lagging behind. We can’t be predictive quite in the way we have been with conventionals and therefore, as Nigel said, you have to drill wells and you have to fracture them and it is a very empirical process: you learn by experience. You fracture. If it doesn’t quite work as well as you thought. You modify your design. You start again on another well. It is very empirical and not very predictive. Does that help a little bit?
Mr Smith: I think initially the companies will probably go in close to an existing well in order to make sure that the shale is present. If they can’t follow it on the seismic-you can to some extent but it is not so easily defined. The reflectors are not good in shale, so you can’t be absolutely certain if you go 10 km away from an existing well that the shale will be as thick or in the same facies; in other words the same type of mudstone, not a sandstone, not a limestone. It is all coming together to make the companies, initially anyway, drill close to an existing well.
Q12 Sir Robert Smith: Is there more that the British Geological Survey and the Geological Society could do to get on top of some of the uncertainties?
Mr Smith: We can always drill more boreholes. We can always look at more of the legacy data that we have. We are working for DECC at the moment and we are looking at the geochemistry, which I think is a crucial aspect.
Professor Davies: I think it is a wonderful research opportunity. I would say that, I am an academic, but I really do mean it because the oil industry is focused on sands, which usually contain the oil and gas, and limestones, and the shales have been ignored. In fact the shales were the reason that the oil was kept underground. I would say there is a huge opportunity to understand shales-a huge opportunity for UK academics and SMEs and so on to get up to speed and to help our Eastern European colleagues who probably are not quite as advanced as the UK is. There is plenty to be done; lots of things that are not understood.
Q13 Sir Robert Smith: If until you have drilled you do not know what you are going to get, why are so many people so optimistic about the potential?
Mr Smith: There are lead zinc mines, for example, in Derbyshire that started off in the carbonates, the limestone, and went down into the shales and, as soon as they get into the shales, they had methane explosions. There are hydrocarbon shows in shales.
Professor Davies: In the North Sea you drill through the shales to get to the reservoirs and as you drilled through the shale there were indicators as you were drilling through that there was gas that was moving into the well bore. Also the Cuadrilla well in Lancashire drilled an extensive thickness and did a fracturing operation and showed that the right conditions are there. I don’t think the question is whether it is there; it is whether it can be economically, socially and so on produced from underground.
Q14 Christopher Pincher: A number of us went up to Lancashire a year or so ago to visit Cuadrilla and look at their Bowland field shale play, and it was quite interesting to see what they are doing there. I think BGS did a survey of the reserve estimate in the Bowland field and you came up with an estimate of 5.3 trillion cubic feet for quite a large area. Cuadrilla have subsequently said that there is something like 200 trillion cubic feet of, I suspect, reserve that can be exploited. Why are the numbers so very different? Is that because they have done some drilling and their estimate is that much more accurate?
Mr Smith: Yes, essentially. My figure originally was a reserve figure before any drilling had taken place, so it was just a comparison with what was going on in America. Whereas Cuadrilla, by the time they released that figure, had drilled two wells. They have now drilled three, I think, so they have the gas content in those shales. They have also identified a lot more shales. I just took one example and compared it with America. They have a much greater thickness of shales. It is like a stacked sequence, which is more comparable, if you like, with the American basins conventional oilfields where they have stacked reservoirs. The greater thickness of shale, the more gas you are going to get. Their figure, in my opinion, is more reliable than mine.
Professor Davies: I am pretty confident the 200 tcf is a resource. This is not a reserve. Again, to reiterate, they are saying 200 trillion cubic feet underground. They are then saying they could perhaps extract 15% or 20%, which equates to more like 20 or 30 tcf. One of the reasons the numbers are so different is that we are not comparing apples with apples. I am pretty sure in the statement they made it is a resource not a reserve.
Q15 Christopher Pincher: You say they have drilled three wells now?
Mr Smith: They have started the fourth and they have had problems. They are going to have to move the drilling site a few hundred yards away and then start again.
Q16 Christopher Pincher: What I was going to get at is, at what point in the drilling process are you able to accurately estimate what is there and what is exploitable, do you think?
Mr Smith: They have 1,200 square kilometres and they have drilled in about, say, 20 square kilometres. It is still a bit of an exaggeration, if you like, to extrapolate it to the rest of the licence area.
Q17 Christopher Pincher: When can we be clear, as clear as one can be, just what sort of resource is exploitable under Lancashire and under the sea?
Mr Smith: I would like to see the gas content figures published and I would like to see the actual production figures published as well for many of the wells that they have drilled. They have only drilled vertical wells at the moment. The Anna’s Road well that they are drilling at the moment will have a horizontal leg to it. When they drill these and when they are allowed to hydraulically fracture them they will put them on test and we will start to get the first figures, which then will be comparable or more comparable with what has happened in America. You start to get what is called the initial production. You start to be able to put it statistically somewhere on a graph where all the American wells have been plotted and then we can see where it is heading.
Q18 Christopher Pincher: When do you think we can see that? How far forward is-
Mr Smith: When they publish the figures. Hopefully they will be allowed to resume fracking soon and they will also drill these extra wells. I think it will be probably next year, assuming they are allowed to resume.
Q19 Christopher Pincher: I think what we want to understand is just what extent there is there for shale gas in the UK and right now it seems that nobody is very sure.
Mr Smith: I think one of the problems is we have had the 14th round of licensing delayed. If that had been enacted, lots of companies would have taken out licences, probably covering most of the country. There are obviously some places they would not be going, but we would be quite a bit further down the road of knowing how much shale gas we are going to have in this country if the companies had their licences. It has taken Cuadrilla three years to get to the stage of drilling and getting a result, even if they have not published fully what we need.
Q20 Christopher Pincher: Based on what we do know and based on your estimate that there is an exploitable reserve of, let’s say, something like 30 trillion cubic feet, if it is somewhere like 15% of what they estimate is there, how does that compare with conventional reserves of gas under the North Sea?
Professor Davies: I can give you one statistic. The maximum production from the North Sea was around 1999 and it was just less than 4 tcf.
Christopher Pincher: Four?
Professor Davies: Four. Annual production from the UK. I looked it up. And that was our peak. You know we have gone past peak now. It was just less than 4 tcf.
Q21 Christopher Pincher: On that basis, there is quite a lot of potential for shale gas in the UK and under the Bowland field specifically?
Professor Davies: If you made the assumption you have 10% to 20% recoverable from a 200 tcf resource, that is a significant amount but it is not globally significant. The Marcellus is hundreds of tcf and Barnett-all the shale gas provinces in the US are probably a lot bigger than that.
Q22 Christopher Pincher: One last question. If the reserve estimates are what they are, if the price of gas changes significantly could that change the reserve estimates?
Mr Smith: In a sense, yes. It would just delay the actual production, I think, because the more marginal fields would not come into production.
Q23 Christopher Pincher: For that to happen, the price just has to go up?
Mr Smith: I think so, yes.
Professor Davies: As the price goes up things become economic again and people start drilling. When the price goes down it tends to reduce the amount of drilling. In the US they have had a massive drop in the gas price and people are now looking for liquids, which have more value. People are starting to say some of the shale gas is not economic, some of it; depending on the cost related to that development.
Q24 Mr Lilley: I declare my interest. Is it not the case that in many countries you have to reveal to the state authorities the sort of figures you were talking about, the gas flows, your wide-arm log details and all that? Is that not the case in this country? Do not BGS get these figures before they are made public?
Mr Smith: We used to, but I would not say that is the case now. It is normally five years before the well is released, but even then the company can hold that back for a few years.
Q25 Mr Lilley: You mentioned liquids. Have any estimates been made of shale oil potential in this country?
Mr Smith: Not yet, but we are doing it, yes.
Q26 Mr Lilley: Finally, in my experience things like resource estimates are almost like shutting your eyes and plucking a figure out of the air. They vary hugely and the only real thing is just drill a few holes. So why don’t we just drill more holes and then we will know? Why waste so much time speculating when you will not know until you have drilled anyway?
Mr Smith: Exactly.
Professor Davies: Yes. The best way of communicating resources is to do it on a graph, I am afraid, and to have a min and a max and have a whole range. These numbers we have heard are called "deterministic numbers" and it is wrong, of course, because we do not know. It is a range. The best way of communicating resources or reserves is to say, "We have a 99% chance of this and a 1% chance of that and a 50/50 chance of this volume," because there is so much uncertainty. But, as I said in my opening comments, the only way to book your reserve is to drill wells, which is agreeing with what you just said.
Q27 Chair: The suggestion of the Spectator recently that we have 65 years’ supply in the UK is a bit speculative, is it?
Professor Davies: It is totally speculative because it is dependent on a number of factors that I do not think we can predict: the economic regime, the political regime, the social acceptability and so on. That is for reserves. Unfortunately it is only partly about the geology. There is a whole set of other factors.
Mr Smith: You can see how slowly things are going in this country compared with America where they drill thousands of wells. I know it is a continent and we are only talking about a few small islands here, but the speed of activity is so slow in the UK.
Q28 Sir Robert Smith: Given that it is onshore, it is not the cost of drilling that is holding it back. It is the regulation.
Mr Smith: The cost of drilling is higher than it is in America, so that is an additional factor for the companies to take into account, but the gas price is higher as well. I think that would balance out.
Q29 Sir Robert Smith: Even if you drilled, what is the knowledge nowadays of the tail that will come? Obviously when you first drill and you start to get production it flows quite nicely, but then you have to work on keeping it going. How do you build into the estimates that tail?
Mr Smith: You are going to have to keep drilling because there is quite a steep tail to shale gas wells. They decline very rapidly and they may go on for a long time, so you have to keep up the speed of drilling. You have to keep adding wells in order to keep production up.
Professor Davies: You can do infill drilling and refracking. You can do multiple stages of fracking, so you could go back and fill in the gaps between your wells to keep the production going. But my understanding is if the tail goes on and on and on for a long time, the cut-off will be an economic one where the rates are so low and the costs are-
Q30 Sir Robert Smith: But in making your estimates of what you are likely to be able to recover, is there an understanding of that-having drilled and seen the first, can you be more certain?
Mr Smith: I think technology will come into play then. If technology improves, as it has in America-the wells that were drilled in 2005, 2006 had a much lower productivity than those that are being drilled now. The question is where Cuadrilla’s and other companies’ wells in this country sit on this particular graph and that is what we are keen to know.
Q31 Sir Robert Smith: You mentioned Cuadrilla had a problem with-
Mr Smith: Yes, it is a drilling problem on Anna’s Road, according to their website. They terminated in the aquifer and capped it and they are moving to another site.
Sir Robert Smith: There is no more detail?
Mr Smith: No, we don’t know any more.
Chair: Your point about the speed is well taken by this Committee since it is over a year and a half since we recommended the Government should go ahead with approving exploitation of shale gas in the UK, and we are still waiting for a decision.
Q32 Ian Lavery: The issue about reserves and resources concerns me greatly because, being from the coal mining industry, with collieries with millions and millions of tonnes of reserves, if the overnight world price of coal changed then reserves automatically converted to resources and then the colliery became unviable and then they closed it. If we look at it in the same sort of scenario in a reverse order way, we really do not know what we have in terms of resources and reserves because it depends on the economic climate, which is concerning as far as I am concerned. With regard to the estimates, what are the global and European shale gas estimates and how do they compare with the estimates here in the UK?
Mr Smith: There are some massive figures. For Europe, technically recoverable resources 2,587 tcf and that is recoverable 624 tcf. That was Advance Resources, a company in America in 2011. We were talking about recovery factors before. They have assumed 24% recovery for the whole of Europe, but it is based on next to nothing. There are a few wells in Poland now, but where is the released information on the gas content and the production? We do not know it. Exxon have pulled out of Poland after drilling two wells because, they say, the gas flows were not high enough, but we do not know what they were.
Q33 Ian Lavery: Their estimates are based on basically nothing, you say? Does that mean they are probably wholly inaccurate?
Mr Smith: I won’t say they are totally inaccurate but the Advance Resources estimate-when they are looking at the whole world, they can’t devote a lot of attention to any particular one country. They can’t look in detail at all the wells. They can’t look in detail at the thickness of the shales. They won’t know what the gas content of the shales is because that is all held confidential by the companies. There is so much data that could be used to get a better figure that will not have been available to them.
Professor Davies: Drilling a well in Lancashire or in Poland or wherever is like putting a needle into this room. It doesn’t tell us where we are sitting. It doesn’t tell us how many people are in the room. A borehole is eight and half inches wide and it tells you about eight and half inches and a little bit into the rock formation and that is the problem. You can characterise that smaller amount of rock, but you can’t characterise the basin and hence the uncertainty. If you have the right amount of data you can make good estimates but you are always data-poor until you have finished producing your last oil and gas.
Ian Lavery: So it is highly uncertain?
Professor Davies: Yes.
Q34 Ian Lavery: All the figures are highly, highly uncertain. Anyway, moving on, how do the figures for unconventional gas compare to the estimates for conventional gas?
Professor Davies: I don’t have the numbers on the UK total production of oil and gas to date. The only thing I will say is that 200 tcf is highly significant compared to the North Sea. They are comparable numbers, I just don’t have the exact data. If you would like me to respond to that, I can do that and get some detailed data for you. I would say the number 200 tcf is a very comparable number to the resources of the North Sea and the Southern North Sea. They are big numbers.
Q35 Ian Lavery: Thanks. How will developments in other countries around the world and in the EU affect shale gas developments here in the UK?
Professor Davies: I think that is a very good question. I have been around Eastern Europe. I have been to about 10 different meetings. I have met the Bulgarian Government Committee on Shale Gas and a number of other organisations. I would just make a couple of comments on that. I think the UK is respected in terms of our regulatory regime and we have a lot of experience, and other countries around Eastern Europe will be looking to see what we do. We have an opportunity to lead in terms of guidelines and regulations, if indeed we do go ahead. I know there are decisions to be made. I think there is a good opportunity for the UK, firstly in terms of leadership in the regulatory area and also in terms of the science and small companies getting involved and so on.
I just wanted to comment a bit further on that. In Eastern Europe there is real mistrust and a lack of confidence in developing shale gas due to the Soviets and a history of things that have gone wrong and I think they do look to the UK to see what we will do and to get our advice. There is an opportunity there.
Q36 Sir Robert Smith: There is obviously conventional gas and then there is unconventional gas and one of the unconventionals is shale. Is it a discrete silo or is it you are starting in one area?
Mr Smith: It is not in America. There is a giant field, the Sandy Gas field in Kentucky, which has some conventional gas as well as some shale gas. That was discovered in 1914 or about that time. They are combined in some places. It depends on the relation of the conventional reservoirs to the source rock and how far the hydrocarbons have migrated.
Professor Davies: There are continuums as well. Coal and very organic rich shale, geologically these are end members and there are continuums. You can get sands that need to be fractured and that has been going on in the UK, I think, since the 1990s without any issues. "Unconventionals" is a very broad term that captures a lot of different types of rock.
Q37 Albert Owen: If I could just move to the potential offshore. What kind of work have you been doing on that and what kind of figures do we have?
Mr Smith: We haven’t done a lot of work on it. I have just rapidly put together what I included in the notes for you. We put in a proposal to BIS that we hoped would get funded that would have helped some of the assisted areas around Liverpool, but that was turned down. I don’t know whether we are going to take that any further forward. The way I saw it was that we would have to look at everything. It was not just the geology. We would be looking at the economics of it, whether you could start by drilling near the coast and deviating offshore. In the case of horizontal wells, that probably would not be any more costly than drilling horizontal wells totally onshore, but you would not get the full coverage. You would only get about 180 degrees coverage because you would be trying to keep it offshore perhaps.
Q38 Albert Owen: How does this compare to offshore in other countries? Obviously America, as you said, is a continent, but some of the other areas may have produced this. Have they come forward with offshore?
Mr Smith: No, I don’t think any other countries will need to look offshore. I said about the population density here. Maybe some other countries that have a very high population density might be tempted to look offshore, but I think it is the economics at the moment. Certainly within the industry they feel that the economics does not stack up. There is already production in platforms offshore. There is the option, what do you do with those platforms when they come to the end of their life? There is a CCS, carbon sequestration option. You could go out there, perhaps underground coal gasification. There are a lot of competing ideas for the use of these platforms as well as perhaps using them for shale gas.
Q39 Albert Owen: Why do you think there is a lack of enthusiasm from BIS? I am paraphrasing what you said.
Mr Smith: They have a set pot of money to allocate.
Q40 Albert Owen: Fine. It is all about their resource more than anything else. The potential now, we are talking here about vertical and horizontal-something you never had on other gases that you are getting now. We are waiting for this gas strategy. Are there companies who have exhausted their fields likely to be interested in this shale gas revolution?
Mr Smith: Offshore, I don’t know. Once again, it is the economics.
Q41 Albert Owen: It is the economics but, Professor Davies, you also mentioned the drawbacks with onshore and certainly those do not apply offshore, and particularly you mentioned population and socially acceptability. Because we have not developed onshore in the way of America and many others, shouldn’t we take that quantum leap and go offshore and be one of the leaders?
Professor Davies: Yes. One of the ideas I heard from industry is that, believe it or not, some platforms do not have enough fuel sources to power turbines and that is a limiting factor. It could be used as a local support source of energy initially to at least power turbines on the platform. I think probably it is an economic hurdle. The important thing to say is that the window to grab the opportunity is probably in the next 10 to 15 years because decommissioning-I don’t know if you have ever seen a map of the shrinkage of the North Sea as decommissioning takes place and it is relevant to CCS as well, of course-is critical. The economic hurdle may be the key one but, of course, just like wind energy, it is easier done offshore in terms of social acceptability.
Q42 Albert Owen: We are looking at some negatives. Are there any real positives of offshore in comparison?
Mr Smith: Yes, no opposition.
Dr Whitehead: It is a serious one, though, and it is one where we could take advantage, as I say, because it is underdeveloped in this country.
Professor Davies: We also have thousands and thousands of wells. I would say our database is far more accurate offshore. Some of the questions you have asked about the uncertainty I think would be reduced offshore. There is a positive there because it is probably one of the best-studied offshore regions in the world, simply because we have drilled a lot of wells and shot a lot of seismic data. I think the big hurdle is the economics.
Mr Smith: The thickness of shale might be greater offshore as well, so the geology might be better offshore.
Q43 Dr Whitehead: I just wanted to think for a moment about the volumes of water involved in the fracking process. Clearly, if you do that onshore, the perceived wisdom, so I understand, is that you dispose of the water with the chemicals in it by deep injection, or you can do that. That is done to some extent in America.
Mr Smith: It is done in America but it would not be allowed here, I don’t think, by the Environment Agency.
Dr Whitehead: Or it is cleaned up in specialist filtration arrangements. If you drilled offshore, presumably you would have to continue to bring the water ashore or would you just put it in the sea?
Mr Smith: I think you would frack using seawater, but that is a technological development that we would have to pioneer probably.
Professor Davies: What happens offshore, for example if you produce oil that has a lot of water in it, you can reinject the water into the oilfield-there is an analogy there-or you could re-inject it into a sand that doesn’t have any oil in it. It is just a nice unit deep down. The problem with flow-back water, which I think is where your question is coming from, is that in the UK we are not allowed to inject that unless it is going into a depleted oilfield to maintain the pressure in that oilfield. We will be faced with the same issue that Pennsylvania has. It has five or eight injection wells, which is nowhere near enough to handle the flow-back water, and so if it is onshore, the UK will have to process the water and clean it up, as has happened with the Cuadrilla well in Lancashire. We will probably not have enough oilfields onshore to handle the flow-back water. We would have a developing industry in cleaning water, which is what has happened in Pennsylvania. It has led to innovation and it has led to industry and development of an industry around that.
Mr Smith: I think there is a development also in America to recycle the water, to keep it in a closed loop, which means that they have to deal with saline water as the fracking fluid. I think that is an environmentally positive move, which we should encourage.
Q44 Dr Whitehead: Is there a point at which you can’t recycle water any further? Presumably it becomes more and more concentrated with the fracking fluid in it.
Mr Smith: Those are the problems the Americans are grappling with at the moment, yes.
Q45 Christopher Pincher: Water recycling is a challenge, but are the Americans not also experimenting with dry fracking using gases? The US Department of Energy has a specific team looking at that. What do you think the opportunities are there?
Professor Davies: I have heard about that and I have heard of new technology. The honest answer is I don’t know whether that is going to be likely. Already the fracking fluid technology has moved on from gels into what is called slick water. It has already moved on and there is a lot of investment. I don’t know enough about that new technology as to whether it is going to reap dividends. At the moment we have flow-back water and I think what we have to do is be innovative about reusing the flow-back water, possibly using other industrial waste water if we can. I don’t know enough about that technology, I am afraid. If you want we can get back to you.
Dr Whitehead: That would be interesting.
Q46 Sir Robert Smith: Just on comparison, you mentioned earlier how in the North Sea they drilled through quite a lot of shale and had records. That is a positive. What is the difference in operating costs, though, of trying to do a shale production in the middle of the North Sea as compared with near Blackpool? What is the order of magnitude?
Professor Davies: It depends if you have an existing infrastructure in the North Sea. If you had to commission a semi-submersible rig and drill the first well, rig costs have been extremely high: hundreds of thousands of pounds per day. If you had a platform and you were drilling from an existing platform and it was just another well, then the costs are far lower because you are there and established. It is difficult to answer that question because it depends what the starting point is.
Q47 Sir Robert Smith: The existing infrastructure, does it have the potential and is there a particular part of the North Sea that showed promise for shale or is it a general-
Professor Davies: It would be the Kimmeridge clay. Anyone from Dorset will have perhaps been down to Kimmeridge Bay and the Kimmeridge clay is a world-class source from off the North Sea and has been considered and it would be in the report that BGS are doing, no doubt, as a potential. You have to drill through the Kimmeridge clay to get to some of our most prolific conventional resources. The Brent Fields and Piper all had to drill through the Kimmeridge clay on the way through to those reservoirs.
Sir Robert Smith: The Brent is about to decommissioned.
Professor Davies: Yes, but you can see why there is such a huge database, because they have had to drill through these rocks over and over again. They may not have collected exactly the right data but they certainly would have a lot more than we would have onshore.
Q48 Sir Robert Smith: Geological still has the storage of the original cores?
Mr Smith: Yes, we have-if they have taken cores in the shale, of course, which they may not.
Professor Davies: They sometimes do by accident. Spotting where to start coring is a fine art and it is quite easy to core the wrong thing and to get some shale.
Q49 Sir Robert Smith: Originally it would have been just treated as waste?
Professor Davies: Yes. As I said, the industry spent the last 100 years looking at sands and limestones and hence this area is such a fantastically exciting research area because it hasn’t been studied enough.
Q50 Albert Owen: Just before moving on to skills, one last point on economics. Do you recognise the figures, Professor Davies-I know you will because you supplied them, Mr Smith-that five to 10 times higher volumes are available offshore, but that the cost of getting it is 10 times higher than onshore?
Professor Davies: When you say 10 times more, I would say it really depends on what the starting point is, what the water depth is and what the depth of the reservoir is. There are a number of factors.
Q51 Albert Owen: Okay. Do you think they have factored in existing platforms that will be out of commission and can be used?
Professor Davies: Sorry?
Albert Owen: Have they factored in the existing infrastructure?
Professor Davies: I don’t know.
Albert Owen: We will be interested to know.
Mr Smith: No.
Professor Davies: They have not factored it in?
Mr Smith: No.
Q52 Albert Owen: Can we move on to the skills base? Are you happy that the people who work in the North Sea now and the companies could quite easily switch over to shale from the conventional gas that they have been experts in for many decades?
Mr Smith: No.1
Professor Davies: I slightly disagree with Nigel’s answer. I think the large corporations have expertise in the US in shale gas and developing expertise in Eastern Europe and they have the people to do it. It is really whether the size of the prize is big enough. At the moment the general trend in the North Sea is that smaller companies are going in to mop up and to make businesses out of what is left. The large corporations, the super majors and the majors, are less and less interested as a general rule. I think the expertise is there. It is whether the opportunity is big enough for them.
Q53 Albert Owen: You say the data is available, so there would be less need for research.
Professor Davies: I am sure they would say that there is additional data to collect, of course, because the specific measurements you need would not have been taken because they drilled through it-they were not really that interested-but the database is substantial.
Q54 Albert Owen: Is the high skill base offshore unconventional mainly British and could it easily adapt to onshore shale gas in the UK?
Professor Davies: I didn’t catch the first bit.
Albert Owen: The decommissioning of the fields offshore; is the skill base predominantly British and would it easily adapt here or would they be tempted to go elsewhere in Europe and across the world into shale gas?
Professor Davies: Is the skill base offshore British? Was that the-
Albert Owen: Yes, mainly-
Professor Davies: For what part of the business?
Albert Owen: For drilling, for extracting it. We are in very early days. We need to identify whether it is there. It is frustrating for us because a year and a half ago we did this and we collated all this information and passed it on to Government, and they seem to be sitting on it and we are none the wiser than we were 18 months ago. That is why I am asking you very elementary questions.
Professor Davies: Firstly, there is a huge amount of British expertise in drilling, geoscience, all of the above. Because of an industry since the 1960s, we have been training people who are now working internationally and in the UK, in Aberdeen for example. The expertise is there and, if it is not there, it is in the US and in an international corporation and would be brought back if the size of the prize was big enough to make the North Sea viable.
Q55 Sir Robert Smith: In the current climate the problem is the other way. They need more skills in the North Sea at the moment. The recruitment crisis and the retirement-
Professor Davies: There is a demographic issue as a general rule in the oil and gas industry. The number of people retiring over the next 10 years is an issue.
Q56 Albert Owen: If we do not proceed with this there is a danger that some of that skill base in the North Sea will go to America and other places for shale?
Professor Davies: It is a good point. I think eventually that would happen.
Q57 Sir Robert Smith: At the offshore Europe exhibition in Aberdeen last year, which is the main industry showcase, the only people a lot of the majors had on their stands were the global recruitment consultants. They have no other expertise.
Professor Davies: Yes. I think it is interesting that if you look at the UK, the onshore operators are small organisations. If you go to Eastern Europe, you then see some of the bigger companies in there, Chevron and Shell, and that reflects the size of the opportunity as they see it.
Mr Smith: It also reflects the fact that we haven’t had the 14th round, so these other companies have not had the chance to come in. We know they’re interested but they have not had the chance.
Chair: Thank you very much. You have been very helpful indeed and I am sure we will maintain a dialogue with you.
Examination of Witnesses
Witnesses: Professor Mike Bradshaw, Professor of Human Geography, UK Energy Research Centre, Simon Moore, Research Fellow, Environment and Energy Unit, Policy Exchange, Dr Thierry Bros, Senior Analyst, European Gas and LNG, Société Générale, and Professor Paul Stevens, Senior Fellow, Chatham House, gave evidence.
Q58 Chair: Good morning and welcome. You have heard what has gone before. Would you like to introduce yourselves in a couple of sentences, please, starting on the left?
Professor Stevens: I am Paul Stevens, Emeritus Professor at the University of Dundee and Senior Research Fellow at Chatham House. I have been producing a couple of reports on shale gas over the last two years through Chatham House.
Dr Bros: Good morning. My name is Thierry Bros. I am the Senior Analyst for European Gas and LNG for Societe Generale and I have worked in this industry on the research, on the Government side, for 20 years and I have published a book recently.
Mr Moore: I am Simon Moore. I am an Energy and Environment Research Fellow at Policy Exchange and I published a report at the beginning of this year on shale gas and its implications for UK energy policy.
Professor Bradshaw: I am Mike Bradshaw. I am a Professor of Human Geography at the University of Leicester. I also lead a UKERK (UK Energy Research Centre)-funded research project on global gas security, which includes case studies of US shale and also the globalisation of LNG.
Q59 Chair: Perhaps we may start by talking about America and much of the news in connection with shale gas. What was America going to do about the declining gas production before the shale revolution came along?
Professor Stevens: The short answer was build LNG re-gas plants, I think, but then-and I think this is a very relevant point-the US Government put a huge amount of money into research and development on low-permeability operations, funding the sort of scientific research that private companies normally would not do. It was that that made a major contribution to the development of the shale gas revolution in the United States.
Q60 Chair: That research programme was a response to what would otherwise have been a greater dependence on imports?
Professor Stevens: Yes.
Q61 Chair: Does anyone else want to comment? How has the development of shale gas now affected the gas market in the US?
Dr Bros: As you have heard earlier, the price has plummeted. We could say that we even had prices that did not reflect cost in the US in terms of production cost earlier this year. Today it is around $3.7 per million Btu and it could be around the cost of production. The question is, "What is exactly the cost of production?" but we could say that, due to the technology efficiencies and the fact that wells are producing more and more, we are around the cost of production today.
Mr Moore: One of the consequences of that has been a switch in the energy system, particularly the electricity system, away from coal and towards gas as it has been much cheaper and more competitive.
Dr Bros: I may add the US is the cheapest gas market on a worldwide basis. We are paying wherever we are on a worldwide basis, be it in the UK, in Europe or in Japan, much higher prices on gas but also, as you have heard earlier, we are moving from the shale gas to the shale oil and the same thing is happening in the US with WTI, which is the reference price being lower than the Brent reference price for oil in Europe.
Professor Bradshaw: They are also seeking out reserves that have other gas liquids-ethane, propane, butane-again because they have a greater value. What is happening is that the drilling of dry gas without those associated liquids has fallen quite rapidly and the drilling rigs are moving to other areas. When you are looking at the economic viability in this low-price environment, the opportunity to gain value from other sources of liquids is also important and that becomes a critical feedstock into the petrochemicals industry, which also adds to the debate about gas providing the basis for new jobs and the reindustrialisation in the US. It is not just about providing the gas, for example, to drive a power station. It is about the wider impacts of that gas on the economy.
Q62 Chair: The effect of this is to cut costs for those industries in America that are big energy users, with all the competitive advantage that that bestows?
Professor Stevens: Absolutely, and in fact, if you went back five to 10 years the idea there would be a revival in US petrochemical industries would have been regarded as unrealistic, but now it is a very serious-it is not a serious possibility. It is happening.
Q63 Chair: Is there a prospect, however, that the price of gas may fall so far that the revolution will be halted because it becomes uneconomic to produce it?
Professor Stevens: The issue here is how much money you can make out of the liquids that you are producing during the shale gas operations. If the shale gas is fairly wet then, even though the dry gas you are selling is not earning you any money, you will earn a lot of money from producing the liquids and that is the key to the continuation of the revolution in the US at the moment.
Dr Bros: Yes. The amount of gas produced in the US is still growing even this year versus last year. This is happening partly because wells are becoming more and more productive, you have more production per well, but you also have more oil production and with the oil production you get at least 11% gas production.
Professor Bradshaw: The question is about the longer-term sustainability of the system. Obviously there is a balance to be struck between a price that is low, which grows demand either in the power industry, in petrochemicals or even as a transport fuel, on the one hand, but is high enough to encourage drilling and production. Obviously there are changes to technology that potentially drive down cost, but also there may be increases in cost as the regulatory regime in the United States is tightened up. At the moment, the current break-even cost varies depending on where you are, your drilling costs and so on. What the cost in the future will be is uncertain in terms of what the regulatory costs will be. The IEA in their "Golden Rules for Gas" report suggested that the implementation of their golden rules would only add 7% to costs, which does seem low, but they are suggesting that an effective regime will not make gas increasingly expensive. Striking this balance to sustain the future is the question in terms of sustaining the level of output in the United States and perhaps having output that could then be exported.
Professor Stevens: The story of the US shale gas revolution is an astonishing story of technological improvement, and technology has been bringing costs down dramatically over the last five-plus years, a process that is continuing. Even with lower gas prices, the technology is bringing the production costs down.
Mr Moore: I think the point that Professor Bradshaw touched on at the end about people looking for export opportunities is also worth drawing attention to. The difference in prices between the situation in the US where prices are, as we have heard, at a historical low, or have been earlier this year, and markets in Asia and to a lesser extent than Europe where prices are significantly higher, creates these opportunities for arbitrage that are certainly being looked at.
Q64 Mr Lilley: Could you tell us a bit about how the price of gas is determined in the UK and what impact on the UK gas price would significant discoveries of shale and development of shale gas in the UK and indeed in Europe have?
Dr Bros: I would say that the price in the UK is based on a spot level, which has been the case since liberalisation of the UK, but I would like to add that the price of gas in the UK is becoming more and more like the price in continental Europe for three reasons. Firstly, you have interconnectors that allow your gas to be shipped one way or the other. Also, we used to have in Europe some oil-indexation and this is fading, so we have more and more spot indexation. Thirdly, as you have heard before, the UK production, domestic production, is declining. Therefore, you are importing more and more gas and, therefore, you are becoming more like continental Europe even if there the level of spot price is still limited.
Q65 Mr Lilley: What impact would shale gas development have, firstly if we discovered a lot here, and secondly if they discover a lot on continental Europe?
Dr Bros: I think it will do the same as in the US. It will drive competition because, as I said, the price is based on spot but if you are relying on major, whatever you want to name them, foreign producers. If you manage to grow domestic production you will come back to what you had 10 or 20 years ago. You will have more competition inside and the price should go lower. I do not think that the price today is reflecting the cost structure in the UK.
Q66 Mr Lilley: DECC says that even if we find a lot of shale gas here it will not bring the price down. It will merely displace continental supplies and LNG supplies, but the price will be determined by continental supplies.
Professor Stevens: It will depend upon the price in Europe because the existence of interconnectors allows a degree of arbitrage, so the prices will tend towards each other.
Q67 Mr Lilley: None the less, there would presumably be an advantage even if the price remained at the European level in that, firstly, it would be domestic gas displacing imported gas, and secondly there would be the tax revenues generated by that gas, which would mean they would be able to put other taxes down. Knowing Governments they would increase expenditure, but it is supposedly an advantage.
Dr Bros: Exactly, plus I think if you manage to get more gas produced you would increase competition.
Q68 Mr Lilley: There may be enough competition as it is, but even if the price remains at the world level or the European level-I do not know what proportion of the take of gas goes to the state. Is there a royalty? Is it purely corporation tax? Is there any petroleum revenue tax just on the North Sea that does not apply onshore? Am I correct on those things?
Professor Stevens: I do not know what the fiscal system is for shale gas, to be perfectly honest. It is the property of the state and I assume that there will be some sort of a royalty accruing to the state but I am not sure-part of the problem is that shale gas is excluded from the normal petroleum regulations. It is in a world of its own, and until the fiscal system and the regulations begin to catch up, it is not clear to me what the fiscal system for shale gas would be.
Q69 Mr Lilley: It must be in the Cuadrilla licence terms. It must state whether there is a royalty or not.
Professor Stevens: One would assume so.
Professor Bradshaw: Presumably that is one of the key above-ground factors we heard about earlier in determining the actual reserve base. It is a fact for the United States there were and are still tax breaks to get the thing going. It certainly is not just a case of an environmental regulatory regime. It is always a case of the fiscal regime, in terms of providing an attractive enough proposition for people to want to initially make the investment in exploration, but then the decision about commerciality is, in large part, determined by that tax regime. It is clearly something for Government to look at in terms of striking a balance and I would assume that in the Europe-wide context different countries will be competing to attract exploration activity and investment and that is the way of the world. It is something to be looked at in terms of how one might create a regime to attract the initial exploration activity and then the decisions on commerciality can only be made once you have answered many of those questions that were asked. Of course, the levels of uncertainty with unconventionals, with shale, are much higher than with conventional gas in terms of how future production will play out as you are drilling to prove up reserve.
Q70 Mr Lilley: Are you saying there is a special tax regime for shale in the States?
Professor Stevens: The 1980 Energy Act in the States gave tax credits up to 50 cents per million Btu on unconventional oil and gas and that was in place up until 2002. That was at a time when the domestic gas price was around $2.50. A 50 cents tax credit was quite a significant incentive to persuade people to go out and start thinking about unconventionals.
Q71 Mr Lilley: Maybe, Chairman, we should ask for a paper on the fiscal regime in the States and indeed as it currently applies in here.
Professor Stevens: Just to add, in the US it is very different because the subsoil minerals are the property of the landowner and not the state, as is the case in Europe.
Chair: That might produce a dramatic difference in attitudes.
Q72 Sir Robert Smith: What sort of effect has the change in the US gas market had on the UK? Has there been much?
Professor Bradshaw: It is a bit like moving the bits around in a Rubik’s Cube as to how you get the answer in some ways because, as we have already pointed out, the expectation was the United States would start to import gas and much of it would be LNG. They built all these re-gas terminals to receive the LNG, about 150 bcm-plus, of which, at the moment, they are only using about 10% of the capacity. What has happened is the US market disappeared but at the same time there were LNG projects, particularly in Qatar, being developed to meet that demand. That provided a short-term glut of LNG at the time when the UK was also investing in new re-gas terminals itself. The opportunity that we have taken over the last few years to import liquefied natural gas to diversify our portfolio has been realised. The only caveat is that post-Fukushima a lot of that oversupply in the market has been consumed by deliveries going to Japan and continuing growth of consumption elsewhere and also in gas-exporting countries. At the moment we are talking about being in a tight market, having been in a period of relative glut caused by US shale in the first instance. It is the indirect consequence of the loss of the US market.
Q73 Sir Robert Smith: The market would be even tighter without the US shale?
Professor Bradshaw: Yes.
Dr Bros: May I add that, as the witness mentioned, what we are seeing in the US is utilities burning more gas versus coal for power generation, which means that coal is available and this coal is shipped into Europe and in fact what we are seeing, a consequence of that cheap US gas, is the fact that the US is exporting coal into Europe and we are burning more coal to generate our electricity versus gas.
Q74 Sir Robert Smith: It has taken some of the edge off the gas demand in mainland Europe?
Dr Bros: In mainland Europe and in the UK.
Q75 Sir Robert Smith: It always struck me as amazing that when they built the interconnector, people were surprised the gas flowed from the lower price to the higher price. I do not know quite why they were not expecting it. Longer term, quite a lot of the evidence we have received, though, is saying there was always this theory that LNG would mean the end of regional gas prices and you would end up with a global gas market, but then the witnesses are saying that you have the extra costs of liquefaction and the re-gasification and the shipping costs and it is not comparable to just having a long pipeline.
Professor Stevens: Exactly. If you think roughly the domestic price of gas in the US is say $3.50 and the cost of shipping it in LNG to Europe was $3 to $4, then you are getting similar prices. The point being that the cost of transport is so high that this would inhibit the actual physical movement of gas, and a similar story for Asia as well. It is down to the cost of transport as to whether you would get physical arbitrage.
Dr Bros: I think what I have written in the paper is if you add the cost of transport, the cost of liquefaction and the cost of re-gasification, because you have to compare gas to gas at the end for the consuming countries, if it is, as we have heard, between $3 and $4 in the US, I think it could be plus $6 per million Btu; so something like $10 in Europe and something like plus $7, i.e. $11 per million Btu in Asia. It does not mean that it will be the same price all over the world. It will mean that we will have a unique reference and that the oil indexation, which we were using in continental Europe and that the Asians are using, is going to fade. We are seeing, very recently, Asian buyers not willing to go for full oil indexation in their LNG purchase, long-term purchase.
Mr Moore: I was just going to add to that one of the big mysteries is whether what has been seen in the United States can be replicated in Europe, but also whether it can be replicated in Asia where some of these other consumer markets are, because that could, again, have consequences of a demand for LNG subsequently for the balance of supply and demand in that market.
Q76 Sir Robert Smith: Should we be doing anything to make sure that we are still a place where LNG comes to keep ourselves fully flexible in our exposure to the global market?
Professor Bradshaw: It is an important source of flexibility for the UK, but also the UK plays a bridgehead role in terms of, as you mentioned, the interconnector. We were in a position in 2011 of exporting more gas than in 2000 after gas production domestically peaked simply because we were moving LNG through the country into Europe. If we are the port of first call for a substantial amount of LNG, that must only reinforce our security of supply. The issue is how much we would have to pay for it. In the LNG market you are competing globally to attract those cargoes and so in a tight market that is the uncertainty. At the moment, because demand is depressed by the economic situation but also by the high amount of coal being burnt, it is quite fortuitous in some ways because Japan has been taking a lot more of Qatari gas that in the past we were taking. It may be when these things work their way through, maybe when, if, the nuclear power stations come back online in Japan-and Japan is pretty much at the physical limit of how much LNG it can import anyway-as things change in the future then our relative position as an LNG importer will change.
Professor Stevens: Last year something like 15% of UK gas consumption came through the Straits of Hormuz; so one can raise issues of security and other dimensions.
Q77 Sir Robert Smith: In the long term, if we want to see the full benefit of shale gas, we cannot just rely on a global market. We have to develop our own shale gas to its full potential?
Professor Bradshaw: That is one way of looking at it and another way is to say we have already benefited. We have seen the situation that occurred in the US and the impact of the Fukushima disaster. It was a short-term shortage, but if you look at the projects due to come online by the end of the decade we could be back in a situation with a large amount of LNG out there and the United States and shale gas might play their part. Most of the modelling work that is done, certainly the reports done for the European Commission, on shale and its impact globally, suggests that shale increases domestic production in markets and therefore depresses the amount of import, the extreme being the United States where it becomes pretty much self-sufficient and then moves to exports. Say in the case of China, the Chinese demand and their ambitions are so great, but it may reduce, perhaps, the amount of LNG that China wants if there was going to be a shale gas revolution in China. There are other factors at play there, like pipeline gas from Russia.
In a European context, the Commission’s work suggests that what shale gas will do at best is replace the decline of conventional production and therefore they are saying, in the report they produced, that we would still, as Europe, remain 60% import-dependent. I think we have to be realistic and there is a very clear statement that shale gas will not result in the European Union becoming self-sufficient in gas-nowhere near it. We simply do not know, as we have heard earlier, what the reserve base is in the UK but I guess the point is that shale is one of a set of factors that could mean that there is-it is the golden age of gas scenario, if you like-available gas for the UK to import and that may be more cost-effective and environmentally effective than developing our own reserves, but we do not know the answer to that yet because we have not found out the extent of our reserves.
Sir Robert Smith: Do you have very similar views?
Dr Bros: Yes. Exploration is needed to find the resource and to see if it is commercially producible at prices that are acceptable. You were mentioning that DECC was saying the prices could stay around this level. It depends on what the cost of production of the shale gas is in the UK.
Professor Bradshaw: An important part of the story is that about three months ago the head of Exxon Mobil stood up in public and said that basically the technology they had developed in the US was not working particularly well in Europe, which means that the technology would have to be revisited. In other words, somebody is going to have to pay for the research and development to develop the technology to meet the different geology that exists in Europe. Whether that will happen is another matter.
Q78 Christopher Pincher: Some observers say that the British energy policy is outdated because it assumes large quantities of imported gas, gas at a high price and an exposure to international price volatility. From what I think most of you have said, you would disagree with that view. You would think that Britain has the right assumptions around gas pricing and that shale gas will not make much of a difference to our domestic energy prices. Is that correct?
Professor Stevens: I did not know we had an energy policy.
Christopher Pincher: We might have one next week.
Professor Stevens: We might have one, yes.
Dr Bros: I would not comment on this one, but I would say that it depends on the timeframe. If you are talking from now to 2020, yes, I do not think we can go for exploration and production in a big way. Again, we have time to look at what is under the ground, to see if it is cost-effective and, after 2020, to see the kind and the amount we can produce.
Mr Moore: I think one of the key findings from some of the analysis that we have done of the changes that are being made to the UK energy policy is we are very concerned about the inflexibility that is inherent in the EMR process and the inability to respond to change in circumstances. Shale gas has been recently by far the most prominent of these changes that have disrupted what the energy picture looks like and may have far-reaching consequences for the UK, or it may not. We do not really know yet, but this is also a concern potentially for other technologies that could emerge in the future. I think one of the main things that we are worried about is the inability of the system that is being proposed under electricity market reform to respond to this new information as it emerges.
Professor Bradshaw: I think I would say, basing everything on the assumption that gas prices will go up, why would you make that assumption? They could equally go down. There is a strong groundswell of opinion internationally, from the likes of the International Energy Agency for one, that there is a set of conditions that could result in a cheap, plentiful supply of gas. That might not be directly in the UK. It might be elsewhere globally with the knock-on effects that I talked about. We perhaps need to be more flexible. We already have an infrastructure. We have 51 bcm of LNG import capacity. That is much more than we actually need.
There are perhaps other things we could do in terms of domestic storage. Also making our own national transmission system more flexible because it is primarily aimed at the North Sea and they have to realign it to different sources of supply. In that context, shale gas production would be a bonus in a sense but I cannot see a sudden rapid increase in domestic production from shale. Even if it got to 9 bcm, which is a figure that was mentioned in a few studies-Tyndall Centre mentioned a study projecting 9 bcm-that is not a game changer. The other uncertainty here is how much gas we are going to need in 2020 and beyond. That comes back to the wider energy strategy and what role gas plays.
We will need gas because gas is the obvious backup for intermittent renewable supply, but if you look at the projections of the National Grid, for example, in their 10-year statement the range of uncertainty about how much gas we need is huge. Therefore, how do you plan effectively to invest in the infrastructure with that level of uncertainty, but equally to devise policy if you cannot be more certain about how much gas? Once you know how much gas and you have a clearer view of how much shale you might potentially have, then you may reach a decision as to whether you want to develop indigenous shale or not or whether, in fact, the international market and the flexibility you have in your infrastructure is enough and your gas demand might be lower if you pursued low-carbon nuclear and renewables.
Professor Stevens: The timing issue here is crucial. People talk about the US shale gas revolution as though it happened over four to five years. It has been over 20 years in the making. It took a long time to get it off the ground and I suspect it is going to be even longer to get it off the ground in the UK.
Q79 Christopher Pincher: Certainly the experience we have had since we conducted our first inquiry would suggest that. Do you think that DECC has the flexibility and the breadth of vision in its national policy statements and the silos between nuclear and gas, within gas, shale gas and gas storage and the other renewable forms of energy to exploit the opportunity internationally?
Professor Stevens: I think there is a lack of joined-up thinking in energy policy in this country and has been for well over 20 years. Everybody has looked at individual subsectors but nobody has sat down and tried to do some joined-up policy thinking on it.
Professor Bradshaw: I think I would also say gas seems to be the default position when policies fail. When there is concern about building new nuclear the concern is, "If we do not do that we are going to have to import more gas or if we are not making the progress we want on renewables," or, for example, if the efficiency policies do not deliver, the fallback is we will then have to use more gas. There is probably a view at DECC that we will use more gas in the future than we have been saying, for a variety of reasons, and then a concern about where that gas comes from. It is the default fallback when other things do not work.
Mr Moore: One of the policy instruments that has been reasonably useful at bridging those various different silos to some extent has been the EU Emissions Trading System, which sits above all the different specific policy areas, renewables promotion and so forth, and has the potential, at least, to provide more of a steer about the kind of investment decisions that were being talked about earlier, if it can be made more long term, if perhaps the price signal can be strengthened over that period, but that is something that has not happened to date and does not seem to have been as great a priority as it perhaps should be relative to some of the other things that get focused on.
Q80 Dr Whitehead: I am trying to figure out best what the long-term effect of shale gas might be in terms of relative reduction in carbon emissions as we move towards a much lower-carbon economy. It appears to be the case in the US that that is displacing a substantial amount of coal, although the US is exporting coal as a result. There are suggestions that, among other things, the way that shale is extracted in the US, particularly in small fields and transportation and considerable leakage in the process, the actual emissions are about as high as coal. Would that be the case in the UK and, bearing in mind that coal plants are closing anyway, what sort of displacement effect might there be between gas and coal in the UK and what would the emissions difference be?
Professor Stevens: One of the reasons there is so much debate over the shale gas contribution to greenhouse gases is because there is a big debate over the extent of fugitive emissions in shale gas operations. It appears from some of the studies I have seen, this arises from poor well completion rather than other sources and this essentially is a regulatory issue. To answer the question, it is for who has the tougher and the better regulatory system, the UK or the US, to answer that particular one. That is purely in terms of the greenhouse gas emissions from shale operations, leaving aside issues to do with displacing coal.
Mr Moore: I echo those comments on the role of the Environment Agency and local regulation. The part that guides emissions from combustion, particularly within the electricity system as I have just mentioned, is the European Union’s ETS cap. Strengthening that, making it longer term should be our main priority for trying to control emissions from the electricity sector at whatever level we think is appropriate given our carbon ambitions. I think the proposals to try to limit that either by constraining particular technologies like shale or to impose UK-only targets or regulations that end up just steering emissions elsewhere in continental Europe are less useful as a way of conveying the message that this is the amount of gas that we are prepared to put up with given our climate goals.
Professor Bradshaw: I think it is important to look at it in a whole energy system in the sense of the role that a gas plays and then, within that, what shale gas is contributing. The actual emissions profile from shale gas drilling in the United States, as you have alluded to, is a source of great controversy at the moment as to how much the level of fugitive emissions might be and there is a lot of work being done to get answers to that. It is likely to be higher than the conventional simply because, as you have heard this morning, you have to drill a lot more and that drilling consumes energy. The net return on energy invested is lower than in conventional gas production. When you take it back into the UK energy systems and ask the question about gas, it is, "What role is gas playing in that energy mix?" If it is replacing coal for good then that is bringing a decarbonisation effect, but the concerns of many of the environmentalists, when they talk about this second dash for gas, is that that investment in new gas squeezes out investment in renewables and efficiency and prolongs the amount of gas that is in the mix and thus increases emissions.
In a specific context of emissions from shale gas drilling in the UK we do not know the answer because, as you heard this morning and you only know too well, we do not have a large-scale exploratory programme in the UK, let alone test production. We do not know under UK conditions what the emissions would be and that would certainly be part of any future research programme, to get the answers to that question; to know where, for example, burning shale gas versus imported LNG, which has higher emissions than domestic conventional production, versus coal stands in terms of their emissions in the UK. That is the question we need to answer, I think, to come to a decision as to what the climate change benefits are. They may be lower with shale gas than with domestic conventional, but if we do not have any of that, then you are looking at other alternatives of supply.
Mr Moore: Just to touch on the gas lock-in question briefly, we conducted some analysis on this earlier in the year and one of the situations we looked at was reducing ambition on offshore wind; the more expensive of the technologies we are currently trying to mass deploy from 13 gigawatts to 9 gigawatts, about halving the remaining deployment of that and using gas in its stead and then retiring that gas earlier, 2030 or so. One of the conclusions from that report was that the financial savings implied by that, while keeping emissions at the European level exactly the same, would allow you to double energy R&D, insulate 360,000 lofts and buy and retire carbon permits worth six times the emissions implied by the savings from the offshore wind in the first place. The financial savings that are implied by moving from more expensive energy sources to potentially using more gas, be it shale or otherwise, can have a potential benefit for our climate ambitions.
Dr Whitehead: Yes, and this presumably implies a massive state intervention around 2030 of dealing with a large number of stranded assets at that point.
Professor Bradshaw: That is the problem, is it not? A new business model for gas moving forward when you have to retire the plant, and that presumably has to be part of any energy policy that is going to be paying them for the capacity to be there and it is probably looking at the shorter term, gas as this bridge or transition fuel, then to a longer term, but making that switch, as you are implying, suggests state intervention because you have a lot of assets which still have life left in them.
Mr Moore: That is true, but state intervention need not be so heavy-handed in the decision making that it takes all the decisions out of the hand of the commercial players. Again, I emphasise the ETS cap as one of the best ways of doing this. If in 2030 we want to have this level of emissions, individual operators can decide whether they think that their particular gas plant is or is not commercially viable given those constraints.
Q81 Dr Whitehead: I guess you do not often have commercial operators volunteering to remove their plants when they still have quite a lot of commercial life in them unless there are considerable restraints placed around them. I wonder whether the more specific question of investment in shale gas as such is or might be seen to be an issue in terms of investment in other forms of lower-carbon energy. The Tyndall Centre has suggested, I think, between £13 billion and £19 billion of investment in renewables and other forms of low-carbon energy might conceivably be diverted into shale gas. Is that an equation you would recognise or is that something that is perhaps a wider feature of investment in different forms of energy? Is there a specific issue relating to people saying, "Right, we are now going to invest in shale gas exploitation in the UK and we will put those funds in instead of doing other things"?
Mr Moore: I think the most important thing to focus on is the most cost-effective approaches to reducing the carbon emissions inherent in our energy system and if doing that through gas or shale gas is a more cost-effective way than doing it through, particularly, renewable technology then I do not necessarily see that as a particularly bad thing if we accomplish those climate objectives at the end of it.
Professor Stevens: Let us face it, the investment is being done for the most part by private companies and they are basically interested in maximising shareholder returns and whether that will have an impact on greenhouse gas emissions and so on depends on the regulatory framework and the price of carbon rather than anything else.
Dr Bros: To add on this one, what we are seeing with the EU ETS is it is today more profitable to run a coal-fired power plant than a gas-fired power plant and so therefore companies that are investing for the future are looking at what is more profitable and they are not planning any new gas-fired power plants. If they had the choice they would go for more coal-fired power plants in Europe, which is defeating any climate change strategies.
Professor Stevens: That is likely to be reinforced if we are going to see a lot of coal exports coming out of the US as a result of the shale gas revolution.
Q82 Mr Lilley: Our brief gives some ballpark figures for what the scenario might be in 2030 and suggests we might get 40% of our electricity from nuclear, 40% from renewables, largely wind, 15% from plants with carbon capture and storage fitted and 5% with unabated gas. Let us suppose all the 15% with CCS and the 5% is gas. That is 20% of our electricity supplied by gas and 40% largely by wind; so normally 20% supplied by gas. Would anybody really invest in shale if they thought that by 2030 only 20% of our electricity was going to come from gas? Secondly, on the days when the wind does not blow across Europe we will need three times the gas-generating capacity that we have normally. Who would invest in that generating capacity, distribution capacity and storage capacity to enable us to do that?
Dr Bros: I think I can take the first question as to who invests in shale. I think it is not only on the electricity mix. What you are seeing in the US is, because of this huge shale gas production, of shale increase in terms of production, people are trying to find new ways of using it. Ways could be exports.
Mr Lilley: But they do not have these targets that we have.
Dr Bros: I am coming back to targets. They are using gas as a fuel for transport. We are seeing buses and trucks operating on LNG and this could help you in your targets to achieve a greener world.
Professor Bradshaw: I guess the other question would be how much electricity, because one of the consequences of decarbonisation strategies in the UK is via electrification. We need more electricity. That 20% could be quite significant in volume terms. I think you are absolutely right that the evidence suggests substantial amounts of capacity in place as gas-powered backup, but that comes back to creating a regime where you are paying companies for capacity and that has to then be put on to the price of electricity. That becomes one of the consequences of renewable electricity generation. When the wind blows the renewable will always ship first, but when it stops then you fall back. We are all aware of these weather patterns we get in north-west Europe in the winter: a blocking high, the wind does not blow anywhere. Interconnection, for example, with the grid cannot be that helpful either.
There will need to be a substantial amount of capacity for gas-powered generation in place and there will need to be some mechanism to pay for that capacity. Equally, the type of storage that we might need is also likely to change in that we will need short-term storage to provide gas in a relatively short period of time that fills up and empties quite quickly. There is a view that we do not have enough storage anyway in this country. We relied on surge production from the North Sea. That is declining. Equally, it is the view that in an intermittent system you not only have renewable intermittency, you have gas intermittency. That is something we need to manage and plan for because, as has been suggested, when you build your plant you want to utilise it as much as possible, unless someone is going to pay your otherwise. That has to be factored in, I think, into the cost of renewable or low-carbon electricity in the future.
Q83 Mr Lilley: Do you think it has been factored in?
Professor Bradshaw: I have seen plenty of studies looking at scenarios, but I cannot say I have seen a rigorous modelling exercise to tell you what that cost would be, no.
Q84 Sir Robert Smith: What percentage of the gas would be going to direct heating as opposed to electric?
Professor Bradshaw: That again depends on the effectiveness of other strategies. At the moment it is a third into power generation, a third into industry and a third into the household sector and we are supposed to be electrifying heat, for example, so that all our gas-fired appliances, heating systems or whatever in the longer term would be replaced by electricity. We all have them. We are not going to go and rip them up. That will take a while, but then again, it comes back to only if you decarbonise your electricity supply have you achieved your targets. This comes back to the comments earlier about joined-up thinking. You have to join these bits up. There are statements that electricity demand could double by 2050 as a consequence of the electrification path. How do you satisfy that demand? Obviously low-carbon sources include new nuclear and they include a lot of renewables and a lot of that would be wind, which will require the gas backup. That is why it is not a question of gas or no gas. It is how much gas and in what role.
Professor Stevens: The problem with the whole thing is that if you leave it to market forces it simply is not going to work because the energy sector is riddled with market failure and the function of Government is to intervene to offset that market failure.
Q85 Dr Whitehead: Just briefly, looking at the cost that we know about producing shale, one of the issues is that it becomes cost-effective in a fairly high price gas economy, less effective, as we see beginning in America, in the beginning of a low gas price economy. What is the comparative cost of producing a known amount of shale gas compared with, say, producing a known amount of biogas?
Professor Stevens: The view in the US now, it depends who you are.
Dr Whitehead: The ideal gasification.
Professor Stevens: Okay. The general view in the US now is that in many cases shale gas is cheaper than conventional gas.
Q86 Dr Whitehead: We have alongside this the parallel development of AD systems, gasification systems, Prolite systems, which are not cheap but nevertheless could produce a fair amount of volume of gas, for example for injection into the grid. I would be interested to know the relative cost of the two techniques, both of which are at the relatively high end of gas although there are issues on what shale gas is going to look like in the future. Are there, in your view, any known comparisons or figures available that might shed some light on this?
Professor Bradshaw: Not that I have seen. I think it is an interesting point and obviously much of our unconventional production at the moment in the UK is biogas and it is figuring in the statistics and it is growing. It is obviously a local solution in many cases or an opportunity rather than a national programme as such, but it is part of that wanting to stack up all the options. In terms of cost, it is imported LNG and where that comes from. It is what is left of the conventional production. It is domestic shale. It is biogas. Also, the carbon consequences of those will differ.
Q87 Ian Lavery: Getting back to the Fukushima incident, which we seem to get back to in every single inquiry we have on every single issue, what effect do you think the Fukushima incident has had on gas markets?
Professor Stevens: I think the first impact is that it absorbed a lot of the surplus LNG. The Japanese went into the market and started to buy LNG big time and Japan is likely to continue to do that because in the short run, if you have to replace nuclear, the only option economically and technically is gas-fired combined-cycle gas turbine. What it has done in effect is save the global LNG market from a very serious downside. That is the immediate effect.
Mr Moore: One of the less direct impacts that we have seen is with some other countries that have, in response to Fukushima, altered their energy policy strategy, particularly Germany, which has said it is looking to close down all its nuclear power stations on a relatively short time scale. That has consequences for what they choose to replace that with. If that is gas, there will be more gas demand. If it is coal, it will be more coal demand and more emissions. There are those indirect consequences of Fukushima as well as the direct Fukushima consequences.
Professor Bradshaw: I think it has also had a quite dramatic impact on Japan’s attitude to how LNG is priced. I was at a conference on Sakhalin Island in the Russian far east in September, where one of the projects being discussed was an old idea of building a pipeline from Sakhalin to Hokkaido to take pipeline gas into Japan, but a very senior official from METI stood and up said basically that this additional LNG they have had to import and the additional oil and so forth is the major reason why they have had a trade deficit in Japan. They have experienced very high costs to secure this LNG and it has made them think, "We do not want to continue with this form of price formation." The only problem is that no one can come up with a good alternative. As has already been alluded to, they have this gaze towards the Gulf of Mexico and US LNG exports at Henry Hub prices. They think that one of the solutions is that they will want to get access to cheaper LNG from the United States. They have even had meetings with other LNG-importing companies and countries in Asia to discuss this.
One of the consequences is additional pressure on oil indexation on long-term contracts, which we also see in Europe. But the problem for the LNG supply chain, as I think has already been alluded to, is it is expensive gas and therefore one of the benefits of oil indexation is that it provides a return on a very capital-intensive source of gas. A question going forward will be what will happen to the pricing of LNG. There is a growing share of spot LNG available that Japan has used but, for example, I understand from talking to people in the industry that some of the Qatari LNG coming to the UK is in contracts to Japan now, tied up for a long term and paying a higher price. One of the consequences is further pressure on the pricing of gas and oil indexation on long-term contracts.
Dr Bros: I would like to add a few numbers. Gas demand increased a lot in Japan, plus 12% last year due to this, and what you mention is absolutely right. It is still increasing, something like 12% again this year, and we are seeing much less LNG coming into Europe-something like minus 38% of the LNG coming into Europe. That is the first point. The second point is back to competitiveness. We started with saying that shale gas allowed the US manufacturing plant or petrochemical plant back into the US. What the Japanese are feeling, as you mentioned, is the fact that now, due to those high imports in terms of LNG and oil, they are losing in terms of competiveness and there is trade imbalance. This is why they are trying to find new ways of sourcing gas but also pricing that gas. And we are hearing that it is already starting in Japan and South Korea that those oil linked contracts that were built for security of supply, you were adding a premium to be sure to get those volumes, because those were two islands (Japan is an island and South Korea is nearly an island because you cannot build any pipes through North Korea) and they are trying to find new ways of pricing the gas. It could be under, as you mentioned, Henry Hub plus something, and the "plus something" could be enough for those projects in the US to be competitive and to be profitable.
Q88 Ian Lavery: Some organisations, such as No Hot Air and Greystar, suggest now that Fukushima has been extremely significant in terms of the world gas price index. No Hot Air suggests that if it was not for Fukushima we would have seen a collapse in world gas prices. Greystar says that Fukushima has had the effect of artificially keeping the price high. Do you agree with those comments?
Professor Stevens: I do not agree with the first one-that there would have been a gas price collapse. Fukushima prevented significant downward pressure on LNG prices, but do not forget: most LNG prices are contractual and, outside of the US and the UK and a few other places, linked into oil prices. It would have taken some time for the impact to feed through into LNG prices.
Professor Bradshaw: In a European context with the Russian supply oil indexed, it is the high price of oil that is the cause of the problem in the sense that that is what is creating a high price for gas that cannot compete with coal. Fukushima’s impact is on LNG. It is not on pipeline gas into Europe from Russia. As I say, high oil price is the problem.
Q89 Ian Lavery: How resilient do you think the gas market is likely to be if we have another major incident like Fukushima?
Professor Stevens: It depends where. The other fear, of course, is if you get a major LNG accident that might do to LNG what Chernobyl did to nuclear for some time, but that is another issue. It tends to be neglected. Everybody assumes it is going to be swimmingly wonderful and LNG is going to increase and increase. If you get a very big bang somewhere, and then a lot of people are going to be rethinking.
Professor Bradshaw: There is a focus on the Straits of Hormuz as the weak point in the LNG supply chain. People tend to think that if that happens it affects obviously gas and oil in so many countries that it will not be prolonged, but if something happened to the LNG facilities in Qatar, by military action for example, it would take five or six years to rebuild the facilities. That is a very significant impact. One of the things to think about is that the industry, the LNG supply side certainly, has little or no spare surge capacity. In Europe, like it or not, we have the benefit of the pipelines from Russia and Russia has a lot of gas. In that sense what might happen in the UK, you could speculate, if the LNG stopped coming is that the interconnectors would be bringing gas through the continental system, Nord Stream would help by bringing gas into north-west Europe and we would be paying for a lot of expensive continental gas that was coming from Russia.
It comes back to my earlier point that we have resilience in the system; we have diversity of supply. Obviously we have pipelines direct from Norway, as well as our own pipelines and the interconnectors. So our exposure to LNG can be balanced and vice versa. LNG can balance our exposure to what might happen in continental Europe. So compared to many European countries, as we become import-dependent, we are in a much stronger position because of that diversity and it could be that some domestic shale adds to the portfolio and increases the resilience but, given that we do not even know if we have enough at the moment that is worth developing, that can only be speculation.
Dr Bros: A few numbers again, minus 38% in terms of LNG berthing into Europe, is a huge number and we have been able to cope with prices that did not increase and, as the other witness mentioned, we have seen, for example when we had war in Libya last year, the cut off of the Libyan pipe bringing Libyan gas into Italy, this has been managed with more Russian gas coming into Italy. So the European system is flexible and allows all those things to happen.
Q90 Chair: Just one last point. We expect to have the gas strategy published, maybe even next week with your statement. How important will that be in developing the shale gas industry?
Mr Moore: It depends what it says.
Chair: Do you expect it to say something that will directly have an impact?
Professor Bradshaw: The Chancellor has indicated, as he did at the Conservative party conference, the desire to create a tax regime to encourage-to encourage what I am not sure, but perhaps we could speculate it is exploratory drilling. That will also require all the other above-the-ground issues because the other thing it will encourage is a lot of reaction against shale gas drilling. It has to be ready for that. To deal with the uncertainties that were discussed in the first part of this session we need to do some drilling, even if it is just to know that it is too costly or it is too environmentally damaging. I assume the first thing the gas strategy should do is to try and get some answers to those questions.
Professor Stevens: We also, I think, need to imitate the experience of the United States and get some money into research and development into low-permeability operations in the context of UK geology. That, I think, is quite urgent.
Q91 Mr Lilley: I am puzzled by the suggestion that there is any need for a special tax regime. Drilling costs can be written off against corporation tax at present and so, I think, can research and development costs. Why should they require any special incentive? If it is profitable, let them go and do it. If it is not profitable they should not do it.
Professor Stevens: But some research and development is basic science and private companies will not invest in that sort of R&D.
Mr Lilley: They have done in the States, haven’t they?
Professor Stevens: No, it was the US Government that put the millions of dollars into low-permeability operations precisely because the private sector would not, and should not indeed, invest in that sort of basic scientific research. This is the function of government.
Q92 Mr Lilley: So the US Government foresaw the possibility of a shale gas revolution, invested in the relevant expertise and it came about?
Professor Stevens: It did not foresee it, but it was certainly looking around to see what might be done to offset the inevitable decline in conventional gas production in the US.
Mr Lilley: The US Government did not see it but still invested it.
Professor Stevens: No, they foresaw a decline in conventional gas production in the US and thought, "How are we going to get around this? There is a lot of unconventional gas, of which shale is only one aspect. There is a lot of other unconventional gas. Let us put research and development money into low-permeability operations and see what happens."
Chair: Thank you very much indeed for a very interesting session. Your time is appreciated.
 See supplemaentary evidence from BGS ISG 17a