UK offshore oil and gas - Energy and Climate Change Contents


Examination of Witnesses (Question Numbers 100-119)

PROFESSOR ALEXANDER KEMP

19 MARCH 2009

  Q100  Sir Robert Smith: The independents who were giving evidence to us last week were highlighting that there may still be concerns amongst some of the new entrants and smaller players that the terms of that negotiation are actually quite difficult. Do you detect whether the Government should be doing any more to make it easier for those negotiations to come to a speedy conclusion?

  Professor Kemp: There was a major review of this a few years ago and, if my memory is right, in 2004 a new Code of Practice was brought in which was designed to speed up the negotiation process and to give guidance on what might be achievable. In terms of the economics, a key element in that substantial document was to say the two parties shall negotiate in good faith for six months and if they cannot agree after that and if one of the parties wants to get the government to intervene then the government would intervene and could set a tariff and other conditions taking into account the risks and costs of the infrastructure, and after having taken that into account would set the tariff which could prevail in a competitive market. That is the present arrangement. I do not think there has been any formal intervention to date. Whether that means it is all going very well I am not quite so sure, but clearly it is an issue that deserves to be made efficient because it can hold up new developments quite a lot.

  Q101  Mr Weir: Just to follow that up. One of the things the independents were suggesting is there should be a common carrier system and they suggested the one in the United States, particularly in the Gulf of Mexico, that was put in place by the US Government because they feared that perhaps the Secretary of State would not want to intervene in these negotiations. Is that something that has been looked at that would speed up the access to infrastructure for smaller fields?

  Professor Kemp: The history in the UK has been that it should be by negotiation between the parties and the government would intervene as a last resort. Clearly there are other models. For example, in Norway there is a regulated tariff that is known to everybody and that is that. The Government here has not wanted to go down that route. Common carrier would be quite a major change. The present system does have flexibility because in different parts of the UKCS there could be different conditions, different requirements and so on, so the flexibility is quite good. To develop a common carrier system would be extremely complicated because we do not have an easy basis for that. We have it onshore, of course, for the national transmission system but that is because it is already there and established on that basis. To do it offshore would involve a lot of complications and whether that would be the right way to proceed I am not so sure. My thought when in 2004 the revised Code of Practice came out was that if the government showed that it really was willing to intervene, and did do so when called upon, then that would reasonably solve the problem.

  Q102  Mr Anderson: Professor Kemp, my understanding is that originally there were six or seven companies operating in the North Sea and now there are something like 60 or 70. Has that made things more difficult or easier in terms of regulating these companies and making sure they do the right things?

  Professor Kemp: The number of companies certainly has grown and I think there are a lot more than that altogether if you include the small licensees and the Promote licences. The advantage of large numbers is that you do have diversity because not everybody sees prospects in the same way and there are different ideas. We do have trading of assets because companies have different ideas of what to do with an existing asset or a block that has not been properly explored. My view is that larger numbers are fine because there will be more players, large ones, medium-sized ones and small ones. At the moment with a lot of small fields the very large players may not find some of them very attractive because the materiality of the expected return in relation to their size would not be very interesting, whereas for a small company it could be perfectly interesting. I think the large number of companies and diversity is good because it is one factor that can help to maximise the economic recovery. It does, of course, mean that the Department of Energy and Climate Change has more work to do in their talking, watching and regulating all of these companies, but that would seem to me to be very much worthwhile doing.

  Chairman: Thank you. If we can just look at the current market conditions next. Professor, it is not easy for anyone at the moment with the global credit crunch, downturn, a fall in oil prices, so there are clearly implications for the industry there and, Judy, I know you wanted to come in on this.

  Q103  Judy Mallaber: Yes, if we could explore that in some more detail. In some of your very early comments you mentioned about the price of oil. Is the low price of oil the single most important factor in the current market conditions facing UKCS companies? Is that the critical factor?

  Professor Kemp: The present position is a very difficult one in the UK Continental Shelf. The price of oil, as you will know, collapsed from $140-odd to just over $40. What was not so well discussed was that the gas price at the wholesale level has also come right down as well. The wholesale price was just over 30 pence per therm this morning. That accounts for 45% of total production. That is a big concern as well. Over the last four or five years the costs have pretty well doubled, or maybe more, so the cost per barrel is now very, very high and there is a kind of pincer movement between the price coming down and the cost per barrel going up. On top of that we have the financial sector problems which make it very difficult for the small and medium-sized companies to get external finance, whether debt or equity. This has come very, very quickly but, of course, the companies have done their budgets—they do them late in the year—so $40 for oil is not a good outlook looking ahead and into next year because it does not look to me as if the price is going to come up much in the next couple of years.

  Q104  Judy Mallaber: I think when you were talking earlier you indicated that there would be a relationship between the price of oil and the amount that would be taken out. Does your research confirm that lower oil prices will lead to lower rates of oil production from the Continental Shelf? I understand you are saying that there is a link between the rising costs of development and the price, but what prospects are there for the long-term price of oil and how significant will it be for the industry and how much exploitation will we get?

  Professor Kemp: On the first point, the amount of investment will certainly be linked to the price, so if a relatively low price continues we will certainly get a significant reduction in investment and that in turn would mean that the economic recovery would be put in jeopardy because some of the infrastructure that we have already mentioned might not become sufficiently used and might have to be decommissioned. Our modelling shows with $80 and more then in the long-term we could recover over 22 or 23 billion barrels, but if it stays at $60 then a fair bit less and at $40 certainly much less. There is a link with long-term price sensitivity. My own view on the oil price is that I fear it may stay relatively low for a while because the world recession and reduction in world demand has been the driver in bringing the price down and that could easily remain the case for the next couple of years. Although eventually it will come up, I fear it may be sometime in the future and that is what has led me to say in my memorandum that for maximising economic recovery from the North Sea then intervention by the Government in the form of a tax stimulus is very appropriate now.

  Q105  Judy Mallaber: What is the timeframe between investment decisions and prices? How sensitive are investment decisions, how long does it take for there to be a change in production either up or down depending on the prices?

  Professor Kemp: Broadly speaking, oil companies are quite cautious in the prices they use for screening investments. I am quite sure that none of them would have used $100 or $140 to screen a long-term investment because we are talking about an investment which would last, depending on how big the field is, 20 or 25 years if it is a reasonably sized field and ten years if it is a very small one. That is why a cautious view is taken given the history of big fluctuations. The time between the investment decision and getting production if it is a very small field could be quite quick, it could be one or two years if it is a very small one, but if it is a big one you and you have to have a big platform constructed then we are talking about several years.

  Q106  Judy Mallaber: You mentioned the problem about getting finance for companies in the current credit crunch. Is there a real distinction between the impact on large and small companies? You also indicated you thought that the Government needed to assist. What kind of assistance would you look for? Is that to all types of companies? What responsibility do you think there is on the Government to give assistance to get extra finance in for investment and exploration?

  Professor Kemp: Oil companies are affected by the knock-on effects of the financial squeeze because that has helped to bring the oil price down so, therefore, all companies' cash flows have come right down. The major oil companies, despite the fall in their cash flows, will still have funds available and could get external funds more readily than small ones but, nevertheless, as we say, they will be rationing their capital as well. The problem with the North Sea is with the new projects being 20 million barrels or less, when it comes to capital rationing they may not stand up too well against offshore Angola, for example. For the medium and smaller companies, their capital rationing problems will be more acute because their cash flows are down and the financial institutions, whether debt or equity providers, are not very enthusiastic. Their problems will be more acute.

  Q107  Judy Mallaber: So should the Government be helping smaller companies or larger companies?

  Professor Kemp: In my memorandum I said there was a very strong case. The Treasury put out a consultation document at the time of the Pre-Budget Report and it raised a particular incentive for new developers called the value allowance that would be an allowance for the supplementary charge. For new field developments we have the corporation tax, which is 30%, and then the supplementary charge on top of that of 20%, so the total for a new development is 50%. They said value allowance is on the table and my thinking is it is very important that a reasonably sized value allowance should be implemented in the Budget this April. If it is of a reasonable size it could make a material difference to investment. I do not think it would stop investment falling a bit over the next two years, but it could certainly mitigate that and incentivise and bring forward some projects which would be of great help not only to the oil companies themselves but to the supply chain which is now beginning to suffer from lack of orders and unemployment. You mentioned exploration. Exploration will actually fall this year because a lot of that does come out of the cash flows, nearly all of it actually, and they are right down because of the low prices. The explorers in the UKCS who have been most active in the last few years have been the medium and smaller players and they are quite hard-hit. In my memorandum I said that for those explorers who are not yet in a tax paying position there are advantages in giving them the same sort of reliefs as would be available to a company that was in a tax paying position. A few years ago Norway instituted a system like that to put the non-taxpayers on a level playing field with existing taxpayers and in effect the government, after expenditure on approved wells and exploration had been undertaken, would pay a share of that cost equal to the tax rate.

  Q108  Judy Mallaber: I think we are going to come on to the tax regime in a bit more detail. On that last point, is that why the Bank of Scotland invested in the Norwegian Shelf recently when companies are telling us they are getting problems in getting them to invest in companies here, or was there another reason why they went for the Norwegian investment?

  Professor Kemp: It certainly is the case that when the Norwegians a few years ago introduced their incentive for new players to come to the Norwegian Continental Shelf there were small companies based here who went to Norway and they could never have done it without that relief.

  Q109  Mr Weir: Just to pick up one point about the value allowance. You mentioned it for new fields but it has been suggested to me that something similar is required to help with the older fields that are coming towards the end of their lives to make them economic to ensure the last drop of oil, so to speak, is taken out of these fields. Is that something you feel the Government should look at?

  Professor Kemp: Yes. We did a study two or three months ago on the mature fields that are still subject to petroleum revenue tax. That means incremental investments in these fields are faced with a tax take of 75% and now that the oil price has come right down that is very high, but it is also discriminatory. It is also clear from our studies that looking ahead the economic recovery that we could get from the remaining reserves to a large extent is from existing sanctioned fields as well as from new ones. All the excitement is on the new ones, but to increase the recovery rate from the old ones, from 45 to 50 or 50 to 55%, something like that, is a lot although it does not get the main attention in the media because that is not as glamorous as developing new fields. We said in our paper that there was a case, and we modelled the potential incremental projects, for removing the PRT altogether from these. There is a scheme in existence where under rather special conditions the PRT could be removed from such projects, but only where the incremental project is clearly separated from the main field, like a satellite, for example, of a main field. We think economically that does not make too much sense based on the physical separation and there is a case for applying it to all incremental investments.

  Q110  Sir Robert Smith: That goes back to the earlier point about the future in the North Sea being small fields requiring the existing infrastructure to stay there, so is there not quite a strong incentive and a national interest for the Government to see ways of making those older fields more exciting to continue in production? Surely some kind of incentive is a bit easier than just stepping out into a new well and being able to build incrementally on that platform? Would that kind of tax incentive not be a double-win because it would not only encourage extra production on the platform but would keep the platform there as a hub?

  Professor Kemp: Yes. The importance of the infrastructure of pipelines, big processing platforms and terminals for maximising recovery at lower cost is very clearly a major point. The infrastructure is getting old in a lot of cases and it has to be maintained and fit for purpose over the longer term and, therefore, will require very considerable investment. The best way to incentivise that is to get as much ongoing business as possible for these pipelines, and incremental projects would play a major role here. We did a study on that a year or two ago which showed initially it would be the big processing platforms that would be coming up to the end of their lives and, of course, the host field would be near the end of its life. If you have got a lot of small incremental projects all tied in, satellites tied in, you could extend the life of that platform and also it would enable investment in the pipeline to be enhanced as well. That was a point I mentioned earlier on, namely the way to maximise economic recovery from the North Sea is to get a very steady stream of investment going. My worry at the moment is if it falls down for two or more years then we could be on a slippery slope and there will not be enough incentive to maintain the infrastructure and then it will be too late.

  Q111  Sir Robert Smith: We should not be complacent either because of past lessons. In the past when the price dropped there was still the attractiveness of reasonable finds to keep that infrastructure in place, but this time around, unless we get an incentive in there, we will not be around when the recovery comes.

  Professor Kemp: The need for incentive is obviously stronger when the remaining fields and projects are all relatively small. In my memorandum I did show a lot of new fields could be brought on-stream with the value allowance even.

  Q112  Sir Robert Smith: What sort of figure do you think the value allowance should be pitched at that achieves the double-win of maximising investment and minimising, I suppose, the Treasury's risk-taking?

  Professor Kemp: That is a difficult one and I was a little coy coming up with one figure. What we did was to test a range of value allowances ranging from a small one of 12.5 million per field value allowance all the way up to 100 and for some difficult situations, like west of Shetland, to 250 million. We found as the size of the allowance went up then you did get more fields brought on-stream. Those fields I termed were contributing to economic production because they were still paying corporation tax at 30%, they were not being subsidised or getting it tax-free. We found the numbers of fields incentivised went all the way up and we stopped at 250. It is a difficult judgment because clearly the Treasury has to look at what happens to its tax revenues. On the tax revenues we found that the evidence was a bit mixed, that sometimes the Treasury would be better off, that it gained more than it lost, although sometimes it was the other way around.

  Q113  Sir Robert Smith: Just one final thing I would like to look at is how the UK regime compares with others. Obviously as a north-east MP I have had fairly strong representations over the years that one of the downsides of the UK regime has been constant change and uncertainty so investors have never quite known how to do long-term planning. How in other ways does the UK regime compare with other provinces fighting for investment?

  Professor Kemp: Around the world we are not the toughest because the toughest ones tend to be in countries with gigantic fields. I think the way to look at is to relate the tax regime we have to the reserves and prospectivity and cost per barrel. We must remember that we now are a relatively mature province with the average size of field of 20 million barrels of oil equivalent. Norway is a bit tougher, but their average size of a new development is probably about 60 million barrels of oil equivalent and they also have a number of very big ones. They are in a rather different position. I would say that the profitability of operations at the moment is not all that high. Of course, it changes if you go to $100 and artificially it looks very high for a short time and that comes out in the ONS data. I think that is extremely misleading and does not affect the longer term potential.

  Chairman: Thank you very much. Linking with the issues of investment and financial regime is this issue of how you develop new fields and a lot of the industry and, indeed, the Government are looking to the west of Shetland. There is a wide range of issues there, not least some environmental sensitivities and, Dave, you want to come in on this one.

  Q114  Mr Anderson: Thank you, Chairman. Professor, what exactly have we got out at the west of Shetland? What reserves are there?

  Professor Kemp: What we have at the moment is in production we have got three substantial fields, Foinaven, Schiehallion and Clair. We have got some others that look promising. There have been some worthwhile discoveries on the gas side. We have two or three significant gas discoveries, quite large ones, and then a whole lot of small ones, over 20 altogether. The problem is to make these gas fields commercially viable has been very, very difficult because of the very high costs. The development costs per barrel of oil equivalent could be 20 or way up there. There is the problem of the infrastructure. If we want to get all these gas fields developed we do need another substantial pipeline and that is very expensive as well. In terms of the economics, that has been a big problem that has been studied for quite some time. In terms of reserves to make a scheme viable, things are looking a bit more promising there but the gas price, the oil price, has come right down. It is a very difficult environment. That was why we thought there was a case for giving a bigger value allowance for projects west of Shetland because all the modelling we have done over the last few years indicates it is extremely difficult with present costs and prices, and even higher prices, and the present tax regime to get a viable cluster development, which is ideally what we would like.

  Q115  Mr Anderson: What is the volume of the reserves out there? Is it possible to estimate that?

  Professor Kemp: Within a very big range. The Department of Energy and Climate Change has some big numbers but they are yet-to-find and quite speculative. I do not have them in my head but they are quite big. It is acknowledged that they are yet-to-find.

  Q116  Mr Anderson: If the development costs are $20 a barrel, what does that equate to what you pay in the North Sea, for example?

  Professor Kemp: Again, there is a range depending on where you are based in the central North Sea. In the southern North Sea it could be $12 or $15 per barrel development costs and operating costs on top of that.

  Q117  Mr Anderson: At the moment I understand the oil that is being pumped out of the three fields is going into tankers. Why could that not be continued if you had the field further out rather than putting the pipeline in?

  Professor Kemp: For the gas you do need a new big pipeline, that is the problem, and tht is very expensive.

  Q118  Mr Anderson: What sort of pipeline length?

  Professor Kemp: Eventually the gas will have to come to market. The kinds of schemes that are being looked at would initially take the gas to Sullom Voe where it would be treated, the liquid separated and then you could have a dry gas pipeline coming down to St Fergus. That is one of the schemes that is being looked at but, as you can imagine, that is very expensive.

  Q119  Mr Anderson: In terms of supporting the Government, do you think that the Treasury's proposed value allowance would help with this?

  Professor Kemp: If we consider that what is on the table at the moment is this value allowance for the supplementary charge then if it was quite a big one for west of Shetland, given the special difficulties and very high costs there, it certainly could make a difference, yes. It is a little complicated because one of the big factors which differentiate the west of Shetland is the need for a very big joint pipeline and the value allowance is not directly geared to that, it is geared to the fields.



 
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