House of Commons Energy and Climate Change Committee

UK offshore oil and gas

First Report of Session 2008–09

Volume II Oral and written evidence

Ordered by The House of Commons to be printed date 17 June 2009

HC 341-II Published on date 30 June 2009 by authority of the House of Commons London: The Stationery Office Limited £16.50

The Committee Name

The Energy and Climate Change Committee is appointed by the House of Commons to examine the expenditure, administration, and policy of the Department of Energy and Climate Change and associated public bodies.

Current membership Mr Elliot Morley MP (Labour, Scunthorpe) (Chairman) Mr David Anderson MP (Labour, Blaydon) Colin Challen MP (Labour, Morley and Rothwell) Nadine Dorries MP (Conservative, Mid Bedfordshire) Charles Hendry MP (Conservative, Wealden) Miss Julie Kirkbride MP (Conservative, Bromsgrove) Anne Main MP (Conservative, St Albans) Judy Mallaber MP (Labour, Amber Valley) John Robertson MP (Labour, Glasgow North West) Sir Robert Smith MP (Liberal Democrats, West Aberdeenshire and Kincardine) Paddy Tipping MP (Labour, Sherwood) Dr Desmond Turner MP (Labour, Brighton Kemptown) Mr Mike Weir MP (Scottish National Party, Angus) Dr Alan Whitehead MP (Labour, Southampton Test)

Powers The committee is one of the departmental select committees, the powers of which are set out in House of Commons Standing Orders, principally in SO No 152. These are available on the Internet via www.parliament.uk.

Publication The Reports and evidence of the Committee are published by The Stationery Office by Order of the House. All publications of the Committee (including press notices) are on the Internet at www.parliament.uk/parliamentary_committees/ecc.cfm.

Committee staff The current staff of the Committee are Tom Goldsmith (Clerk), Robert Cope (Second Clerk), Francene Graham (Senior Committee Assistant) Luisa Porritt (Committee Assistant) and Estelita Manalo, (Office Support Assistant) and Hannah Pearce (Media Officer).

Contacts All correspondence should be addressed to the Clerks of the Energy and Climate Change Committee, House of Commons, 7 Millbank, London SW1P 3JA. The telephone number for general enquiries is 020 7219 2569; the Committee’s email address is [email protected]

Witnesses

Wednesday 11 March 2009 Page

Steve Jenkins, Chairman, Oil and Gas Independents’ Association, Alan Ev 1 Booth, Chief Executive Officer, Encore Oil, Martyn Millwood Hargrave, Chief Executive Officer, Ikon Science

Martyn Harper, Head of Sustainable Development and Dr Sharon Ev 9 Thompson, Senior Marine Policy Officer, Royal Society for the Protection of Birds

Thursday 19 March 2009

Professor Alexander Kemp, University of Aberdeen Ev 16

Malcolm Webb, Chief Executive and Paul Dymond, Operations Director, Oil Ev 22 and Gas UK

Wednesday 25 March 2009

Mike O’Brien MP, Minister of State, Simon Toole, Head of the Energy Ev 32 Development Unit Licensing, Exploration and Development, and Jim Campbell, Director of the Energy Development, Department of Energy and Climate Change

List of written evidence

1 ABB Ev 45 2 AMEC Ev 47,49 3 BG Group Ev 50 4 BP Ev 54,56 5 British Rig Owners’ Association Ev 57 6 Carbon Capture and Storage Association (CCSA) Ev 60 7 Centrica Ev 60, 64 8 Department of Energy and Climate Change Ev 66, 83,84 9 Joint Nature Conservation Committee Ev 91 10 Professor Alexander Kemp Ev 93 11 Oil and Gas Independents’ Association (OGIA) Ev 101,104,107 12 Oil and Gas UK Ev 108, 115 13 Royal Society for the Protection of Birds (RSPB) Ev118 14 Scottish Council for Development and Industry (SCDI) Ev 121 15 Shell Ev 129,133 16 Total Ev 134

Energy and Climate Change Committee: Evidence Ev 1 Oral evidence

Taken before the Energy and Climate Change Committee

on Wednesday 11 March 2009

Members present: Mr Elliot Morley, in the Chair

Nadine Dorries Paddy Tipping Miss Julie Kirkbride Dr Desmond Turner Anne Main Mr Mike Weir Sir Robert Smith Dr Alan Whitehead

Witnesses: Mr Steve Jenkins, Chairman, Mr Alan Booth, Chief Executive OYcer, Encore Oil, and Mr Martyn Millwood Hargrave, Chief Executive OYcer, Ikon Science, Oil and Gas Independents’ Association, gave evidence.

Q1 Chairman: Good morning, gentlemen, welcome Mr Jenkins: They are largely due on discoveries, and to the Select Committee for Energy and Climate also an estimation from the geology and geophysics Change. We are pleased to see you. As you know, we of what prospects might contain. We risk those are having an inquiry into oil and gas reserves in the prospects, and those are the risk numbers that are North Sea and west of Shetland, and we very much being quoted—but really it is less than 10 billion welcome your evidence. For the benefit of the barrels it has got commercial plans to develop. Committee would you say a word about who you are and your role in the organisation? Mr Jenkins: I am Chairman of the Oil and Gas Q4 Chairman: What are the restraints on those Independents’ Association. We have got commercial developments? Is it the price of oil; is it approximately 30 members. It is the smaller the overall costs of the exploration; or is it the companies in the UK, mostly non-producers. We technical challenges? have representatives from foreign companies who Mr Jenkins: Currently,we are faced with a very high- have UK subsidiaries operating here. We are mostly cost environment. The North Sea is a very high-cost interested in the exploration and appraisal. Some of environment to work in. We have got prevailing our members are developing hydrocarbons but most costs from last year, when oil was $147 a barrel; and are appraising and developing. those costs as far as drilling is concerned, have not come down yet. We are still looking at perhaps Mr Booth: I am Alan Booth, a director of the Oil and $400,000 a day for a rig. We are seeing some coming Gas Independents’ Association and also the CEO of down, but most of those are long-term contracts. a small UK oil and gas exploration company called Companies such as ours rely on taking one or two rig Encore, which we established in 2005. slots to drill, and we are having to pay very high Mr Millwood Hargrave: I am Martyn Millwood prices for that. As far as development is concerned, it Hargrave. I am a member of the OGIA. I run a is access to infrastructure—the UKCS infrastructure company called Ikon Science, which is a technology with EAG. It was not designed to last this long and provider and service provider to the business, so from a smaller company point of view we have to get really representing that part of the business. access to that infrastructure, to put the oil in to bring it ashore. Q2 Chairman: Thank you very much. If I could kick Mr Booth: If I could add to some of Steven’s oV, gentlemen, it was very interesting to look at comments, the main issue, as you quite rightly point some of the suggestions about what could be out, is the price of oil, which is a global commodity available within the Continental Shelf in terms of oil and is the same pretty much around the world. What and gas. Presumably, over the years there has been a is specific to the UK increasingly, in terms of finding certain degree of work done on mapping and seismic these new reserves, is access to capital to explore for analysis; how much confidence do you have in terms them. We have put in our submission that the nature of what you know is on the Shelf, both in terms of of the companies prepared to explore has changed your current reserves and also the potential for the significantly, simply because of the nature of the future? basin. We are of course reliant on getting equity from Mr Jenkins: At the minute we have less than nine the capital markets now, and when we do find things billion barrels that have got commercial plans to getting debt, debt markets—and, as you know, that Y develop. You probably have heard numbers of up to is very di cult at the moment. What all investors 25 billion barrels. like to see is stability and predictability in any regime in which they invest. The UK has not always been an area where they have had a great degree of comfort. Q3 Chairman: Yes, quite significant numbers, yes, in The oil price is obviously very important, but it is some of the briefings, yes. about access to infrastructure when you do find Ev 2 Energy and Climate Change Committee: Evidence

11 March 2009 Mr Steve Jenkins, Mr Alan Booth and Mr Martyn Millwood Hargrave hydrocarbons. Your investors want to know that if is not really why it was put in place, but that is the you find them you can develop them, and they are nature of—a direct example of what is happening going to get a return for the risk they take. Those are right now. the principal issues that drive activity here. Q9 Chairman: If there were going to be some changes to this code, what would be your priority? Q5 Sir Robert Smith: I must first declare my interest: Mr Booth: I think you have to understand before as a shareholder in Shell, which is in the Register of you start exploring for hydrocarbons and wanting to Members’ Interests; and Vice Chair of the All-Party develop and appraise hydrocarbon accumulations, Group for the OVshore Oil and Gas Industry. In that what the terms and conditions will be to go across role, we went on an oVshore northern seas visit, and that infrastructure. What you do not want to do is accommodation was sponsored by various oil find your hydrocarbons and then you find someone companies. On access to infrastructure, is there a who owns the infrastructure wants to take what they crucial message that if we are going to see the rosy might regard as a fair share, and what I might regard picture, then whatever happens that infrastructure for my shareholders as a disproportionate share of has to be seen to be worth maintaining so that it is the risk I have taken. My view is that that happens still there; because you could not from scratch—the quite a lot. finds you are now finding would not be much use without that infrastructure? Mr Booth: It is vitally important that infrastructure Q10 Paddy Tipping: We have a Government that is is there. Increasingly, we are finding smaller becoming increasingly interventionist; is this an area accumulations in the North Sea, and they cannot in which it ought to be more involved? support their own dedicated infrastructure, so we Mr Booth: I think they should seriously consider have to be able to tie them back to existing that. I am not a great fan of intervention myself, but infrastructure, which has to be there. Ultimately, it we have an extensive infrastructure in the North Sea drives exploration. If you are expecting to find and we do need to make sure that it is made available relatively modest pools, you have to know there is an for those who wish to produce hydrocarbons that eYcient way of getting it to the shore. It is vitally still need to be found and still need to be produced, important that it stays there. I guess you have and there is a role there for Government. touched upon the issue of the infrastructure code of practice, which came out in 2003 or 2004. As we put Q11 Mr Weir: Perhaps I should mention my interest in our submission, we are not convinced that is as another vice chair of the Oil and Gas Group, but working eVectively. We would like to see changes in you say in your submissions that there should be a that regard. common carrier status for infrastructure. Can you explain to us what you mean by that? Mr Booth: It means that there is eVectively Q6 Sir Robert Smith: More intervention by the guaranteed access to major infrastructure. It is Government? something that is quite common in the Gulf of Mr Booth: The Government does have the ability to Mexico. The US is not known particularly for intervene on tariV arrangements; however, it needs interventionist policies, but it is the way you ensure to be invited to do so, and certainly the you get access to that infrastructure, and you pretty infrastructure code, which was introduced a few much understand the terms under which you do. years ago, requires all companies to issue an invitation to the Government to participate. I can Q12 Mr Weir: But who imposes the common carrier tell you from first-hand experience that that is status? Is it a— perhaps not happening as often as it should do, or at Mr Booth: I believe it has to be a regulatory event. the time it should do. It is quite clear from the North Sea that there is one pipeline system that eVectively has a monopoly over Q7 Sir Robert Smith: So what should change? large parts of the North Sea. Mr Booth: It is diYcult. It is still a voluntary arrangement, and until the industry decides it wants Q13 Sir Robert Smith: On the role of the to apply those voluntary arrangements, it is really Department, have you got views on how eVective the not going to happen. I have always had a bee in my Department has been in the past in general towards bonnet about this issue, and it is still there. My own the industry, and have you noticed any impact of the company is in the middle of trying to get access to merger of the new Department yet in a positive or infrastructure, and without naming names— negative way on resources? Mr Jenkins: It has been in a positive way. It is nice to see the word “energy” being mentioned. It is good to Q8 Paddy Tipping: Go on! have a Secretary of State for Energy because we Mr Booth: We only have one development under believe it is very important to the UK, sustainability consideration, so it is very easy to find out! The issue of energy. We from the OGIA and smaller is that the companies concerned did not want to companies’ point of view have been able to engage issue the automatic referral notice, which is the directly with ministers now, and we find them very invitation to Government, because our operator approachable and very interested in what we are told us, “we didn’t want to upset the other side and doing. Recently, with the PBR, we have had we want to agree the terms before we put it in”. That opportunities to submit suggestions to the Treasury, Energy and Climate Change Committee: Evidence Ev 3

11 March 2009 Mr Steve Jenkins, Mr Alan Booth and Mr Martyn Millwood Hargrave reacting to their request for comments, and that has relation to activities that may be proposed by you on had various receptions. We can speak to the MPs carbon capture and storage? For example, is the involved and also the members of the Department, structure you have identified one that might be so we are engaging probably at a higher level. How viable as far as that sort of process is concerned? it was set out previously on a day-to-day business, it Mr Booth: One of the issues around injection of CO2 worked very well, but now we are feeling that we can into reservoirs is that primarily it enhances recovery engage at a higher level in government. of oil—the carbon, the CO2 does come out and has Mr Booth: One of the important things that should to be re-injected, so there is a limited amount you can come out of this, and I think we are starting to see it put in on a long-term basis. However, in large parts working, is that obviously a lot of North Sea assets of the world it is an eVective way of recovering more and structures could be used for carbon hydrocarbons and disposing of CO2. The issue we sequestration, and it is nice to have a department have in the UK is that once you move that project where that communication is more eVective than it oVshore, it is increasingly expensive to do so. The was in the past. structure we are looking at is an old depleted gas field, which has the characteristics necessary to Q14 Chairman: Has your industry given some inject, we and our partner believe, large amounts of thought to that potential? CO2 so there is no hydrocarbon recovery going to Mr Booth: My company is examining that particular come from it, it is just a way of sequestering that CO2 issue. We have identified a structure that we believe into a long-term structure that should remain there is very suitable for carbon storage. The issue we have in geological time. at the moment, which I talked to the Department about yesterday, is how we get a licence to use that structure for carbon storage. All I can be oVered at Q17 Dr Whitehead: You mentioned that you had no the moment is a hydrocarbon licence, but I do not clear idea about how a licence might be obtained for want to extract the minimal amount of remaining that infrastructure. Are you therefore not satisfied hydrocarbons in there; I simply want to examine its with the early moves that have been made, for use for storage of carbon. That is where we need to example in the Energy Act, to establish a licensing progress. How do I do that? regime, and do you think a lot more needs to be done Mr Jenkins: It is worth mentioning too, if you like, in terms of clarifying who is the first mover and how the full cycle approach to reservoirs, right the way a licence might work over a period of time? from exploration through to storage. The Mr Booth: A little more clarity would be useful, and information increases as you learn more and more a timescale would certainly be useful. My particular about a reservoir, so you are instantly high-grading issue at the moment is that there appears to be some the things that can be used, and it can be very useful European funding available, and I need fairly for storage. That is a factor. That is something you quickly to understand how I can acquire—my get for free, if you like, from doing hydrocarbon company used to own this licence under a exploration, the knowledge of how things may work. hydrocarbon licence, because we thought maybe we There are quite a number of studies, both in could exploit the remaining gas, but as it turned out academia and some semi-commercial, building up there was not suYcient gas to exploit. We then now and giving us a shape of where this next stage considered its use as gas storage, but the work we did will come. As Alan says, the big unknown is the suggested that this particular structure was not regulatory environment that will create this new suitable for that. However, it was eminently suitable business. In this country we have a tremendous for storage of CO2 because you need certain specific academic and technical infrastructure in the conditions to make it worthwhile. However, I could universities—naming a few names, obviously not retain the licence because it was a hydrocarbon Imperial, Cambridge, Durham, Edinburgh. There is extraction licence, and I did not want to extract a fantastic skill base there—probably world-class— hydrocarbons from it because it was not worthwhile. and we ought to start making use of this. Currently, This is the dilemma I am in at the moment: I have there is a blockage right at the sharp end, which is, had to give it back to DECC because I told them, “I “how do you do it?” There is a lot of knowledge do not want to exploit for hydrocarbons; I would about how we might do it, but turning it into some like to use it for CO2” and we are at a bit of a loss to kind of commercial arrangement, however the know how— industry is structured and whether there are subsidies or whatever, needs to be thought about. Dr Whitehead: So you think the break arrangement is the present diYculty of the fact that you have to— Q15 Chairman: There are opportunities there at some point. Q18 Sir Robert Smith: There is no regime! Mr Booth: Yes. Mr Booth: There is no regime eVectively,yes. I would happily take it as a hydrocarbon licence. We have Q16 Dr Whitehead: On the subject of the spent nearly a million pounds on shooting brand relationship between carbon capture and storage, new seismic data for this structure, principally with licensing and further exploitation of reserves, the a view to gas storage. As it turned out, it was not suggestion is that carbon capture and storage, as a suitable, but perhaps now for CO2 sequestration. I by-product, enables further reserves to be recovered. have invested significant capital in this, and I do not What analysis have you been able to do of that in know how I can progress it further. I requested Ev 4 Energy and Climate Change Committee: Evidence

11 March 2009 Mr Steve Jenkins, Mr Alan Booth and Mr Martyn Millwood Hargrave

DECC yesterday—I am not saying they are not Mr Booth: Prices will fall. There is obviously a helping because they are trying to help me, but I am reluctance from drilling contractors to see those sure there is not a regime that allows me to. rates fall, and at the moment that is where we are in Chairman: Tell us a little more about the current the industry. The drilling contractors quite like market conditions that you are operating in. Anne charging $300–400,000 a day for a rig rather than will ask questions on this. $70,000, but the industry does not want to use rigs at £300–400,000 a day, so it will correct. The costs Q19 Anne Main: You have touched on it in your related to drilling rigs, or steel, whatever, will opening remarks. I would like to explore further necessarily fall. The issue has been that as an about what the dramatic decline in oil prices is industry there has been a shortage of people. Now having on your industry. the cost of people has risen significantly, and it is Y Mr Jenkins: The decline in oil prices is making some extremely di cult, if not impossible, to see those fields uneconomic to produce. We have a cost-base costs come back significantly. that has increased with the oil price, and as I said previously it has not decreased. A lot of these Q25 Anne Main: You are painting rather a contracts are very long-term, so the break-even in depressing picture, if I might say so! You have the some UKCS fields is $40 a barrel. Some of the older inability to access the necessary infrastructure; you fields—yes, they can be produced for a lot less, and are disadvantaged in drill rig prices; you appear to they are making good profits, but new fields—$40 or have lack of access to funding, and possibly because $50 is the oil price that is needed in this current you are smaller even more so: what is the point? pricing regime to develop the field. The fact is that it Mr Booth: Of? is not economic to develop. Q26 Anne Main: You being in the market. Q20 Anne Main: Surely, you expect prices to rise Mr Booth: Well, we are not in the market at the significantly once the global economy comes out of moment. As an example, for the last 15 months my recession, so can you not build in an allowance for company, which is a small listed British company, these fluctuations? drilled seven wells. Next year we will likely not be Mr Jenkins: It is a long-term plan. You decide, when drilling any wells. you are going to develop a field, that it could be four or five years until that field comes on-stream. Q27 Anne Main: A small British company being Contracts are awarded at that time. Economically- brought down by the economic recession or just by wise there are a lot of oil companies that—the the big boys crowding you out? submissions we put in to this Committee and the Mr Jenkins: It is not the big boys. It is—okay, Treasury are based on $50 oil, so even above where contractors. It is the fact that usually there is a six- we are at the minute. month lag in cost. If you have oil at $140 a barrel and Mr Booth: Perhaps I can give you an actual example it has fallen down to $45, there is usually a six-month of how costs have moved. In 2004 in my previous lag until costs catch up. We have not seen that company, we were drilling exploration wells in the happening. A lot of these rigs are on long-term North Sea, and a suitable rig cost $60–70,000 a day. contracts, so therefore they are not coming back on That same rig now costs upwards from $350,000 a to the market until summer time or in the autumn day. Now that the oil price is back to where it was in time. 2004, we cannot aVord to pay $350–400,000 a day for a rig. It is not economically viable. Q28 Anne Main: What can be done to help? What are you asking for in terms of financial support or Q21 Anne Main: The balance sheet you are intervention or alteration? describing—is this all contributing to why you are Mr Booth: I do not think we are asking for support. having trouble accessing funds? In our submission we have the example of my own Mr Booth: It is definitely a part of it, yes. The cost of company. We have¨ 25 million of tax pools, which are exploring—the risk that you put into drilling a well, costs we have sunk into the North Sea. If we were a is too high, given the cost environment we are in— producer we could claim those back straight away, V the ability to make returns. o set against our income; however, I cannot get into a cash-flow producing situation because I cannot either borrow money or get more equity to develop Q22 Anne Main: Why are your drilling rates for rigs the fields I have found. so much? Mr Booth: These are not our rigs; these are rigs Q29 Chairman: We are going to look at the fiscal owned by drilling contractors. regime. Mr Booth: It is a fiscal regime issue. I guess I am just Q23 Anne Main: Why have the drilling rig rates asking for those funds to be brought back to me so not reduced? that I can reinvest them in the North Sea. Mr Booth: Because there has been a lot of demand for them. Q30 Anne Main: If there was some sort of conversion, like a planning conversion, for change Q24 Anne Main: So you feel that you are over the of use for the field that you found to go to carbon proverbial barrel! capture storage, something like that would be— Energy and Climate Change Committee: Evidence Ev 5

11 March 2009 Mr Steve Jenkins, Mr Alan Booth and Mr Martyn Millwood Hargrave

Mr Booth: That is certainly one issue, yes. Mr Jenkins: Alan has already quoted that his company is probably not going to drill any wells this Q31 Anne Main: Change of use for the licence. year. We have plans to drill wells because we farm Mr Booth: Yes. The other one that I mentioned is out—are you familiar with that term? We get that I have money tied up eVectively with the companies in to share our fiscal and technical risk, Government, which if I were a producer would come and they will pay a premium to get into the well; so straight back to me, as an oVset against my tax bill. we have been fortunate enough to farm this out, so I cannot achieve those funds because I cannot get our exposure as a company is quite low. Quoting into a position to produce cash, because the banks from Oil and Gas UK, there were 110 wells drilled do not want to lend me money to develop the fields last year in the North Sea; this year there are 30 I have found. So my equity investors can see that something wells that have got rigs; next year it is 10. V investing in smaller companies like this is not So we are seeing a drop-o of activity. We have not eYcient, because half the money—we are on a 50% had very many field development plan submissions; tax regime—gets stuck until I can get the cash flow, in fact I cannot think, after Don and South West but I cannot get the cash flow because the banks will Don if we have had any; so therefore no new fields not lend me money to develop the field that we are being developed. found. That is exactly where I am right now. Mr Millwood Hargrave: It is this small, Chairman: I know that Mike wants to touch on this entrepreneurial end of the market, if you like, that and also the investment strategy. has provided a lot of the “get up and go” that has changed the business over the last five or six years, and they are disproportionately hit by this lack of Q32 Mr Weir: You say in your submission that the either equity or— Royal Bank of Scotland has pulled out completely, and that was one of the main lenders in the North Sea. How many banks are now lending in the Q37 Mr Weir: There is going to be a significant North Sea? downturn in the amount of exploration and work in Mr Booth: One. the North Sea if this continues: is that fair comment? Mr Booth: Absolutely fair comment, yes. Q33 Mr Weir: That is a monopoly of lending. You Q38 Mr Weir: Scottish Enterprise last week say you cannot get lending. What impact is that published a report on the supply chain for the North having, and what can be done to alleviate that? Sea, which showed a rosy picture of the last few years Mr Jenkins: We would like more banks to lend. At of an increasing supply chain and business. What the minute the only one lending in the North Sea at impact will the downturn have on that and the the minute is the merged Lloyds/HBOS. It has a very number of jobs in the North Sea? Is that going to be good oil and gas franchise. It built it up. I represent significant? a small company, and we have relationships with Mr Jenkins: We have already seen contractors laying HBOS which we built up. We have a facility with oV staV. As Alan previously said, there was a great them, which we are just going to roll over, which is skills shortage, and now we are heading towards a going okay at the minute, but if we came in as a new skills surplus. The oil industry is an integrated borrower the door would be closed. We would like business—okay, the oil companies provide the more banks to lend in the North Sea—we have one, money to drill the wells and develop the fields, but and there may be a few French banks—but really we need a robust supply chain to help us do that. You banks that have large businesses here lending to are going to find links are being broken or weakened. small oil companies to develop the fields. It usually takes the oil industry in the North Sea something like four years to recover from a price- Q34 Mr Weir: One of the complaints that onshore down. businesses make is that even when they can get credit it is now dearer than it used to be. Is that something Q39 Mr Weir: Obviously, there is a problem with the you are finding as well? banks lending; and the Government and the Mr Jenkins: First of all, you have to get the banks’ taxpayer is in the driving seat of most of these banks interest that they are going to lend you any money now. What do you think is the one thing the whatsoever; then you are finding that the up-front government should be doing to facilitate investment fees and the known drawing fees are higher than we in the North Sea and ensure that development have experienced. The cost of lending has not really continues? come down because of the up-front fees. Banks are Mr Jenkins: It is to make the North Sea an attractive tending to make their money now on the fees, place to do business. At the minute, you can spend rather than— your dollars in any basin in the world. Oil is priced relatively the same throughout the world, so Q35 Mr Weir: It is happening oVshore and therefore the UKCS has to be competitive, so that happening onshore. when companies are looking where to spend their Mr Jenkins: Yes. dollars they are going to choose the North Sea.

Q36 Mr Weir: Does that mean the companies have Q40 Mr Weir: You are talking about changes—and started to scale back their investments, and how do we can talk about tax decisions later—but is it you see that trend over the next couple of years? investments or the tax regime? Ev 6 Energy and Climate Change Committee: Evidence

11 March 2009 Mr Steve Jenkins, Mr Alan Booth and Mr Martyn Millwood Hargrave

Mr Jenkins: It is the tax regime. from the gas basin. There is significant gas west of Mr Booth: It also comes down to this issue of access Shetlands, but that is not something our members to infrastructure. Your investors want to know that are particularly addressing. We need to have an if you do find something you can economically and eVective view of how we are going to fund and eVectively develop it—you are not being held develop gas storage in the UK, because we are “hostage” is the wrong word, but you do not need woefully short of it. that degree of uncertainty as to how much of that are you economically going to keep. Q44 Paddy Tipping: You told us at the beginning of your evidence that you had been to see the Treasury Q41 Mr Weir: Regulation of the infrastructure is recently. The Budget is on 22 April. What are you already there. looking for in the Budget? Mr Booth: Absolutely, yes. That would attract more Mr Jenkins: We would look for the value allowance investment because you have greater certainty. It is that has been mentioned, and that has to be all about certainty, or certainly predictability, that significant. you need to encourage investment. Mr Jenkins: And transparency,the costs of accessing Q45 Paddy Tipping: Some of us are amateurs, so that infrastructure. explain that to us! Chairman: Paddy, perhaps you can draw out what Mr Jenkins: I think it is probably going to take all the fiscal regime can do in relation to encouraging three of us to explain it. The value allowance will be investment. targeted. We have echoed the Treasury’s paper on that. It is small fields, because the average field size Q42 Paddy Tipping: When oil prices were really high in the North Sea is 50 million barrels or less now, so last summer, the Prime Minister and the Chancellor we have taken 25 million barrels, say. Heavy oil and came to Aberdeen to see you, but you are telling us high pressure, high temperature: heavy oil can a really depressing picture now because oil prices are contribute probably another billion barrels; HPHT, relatively low but security of supply remains an issue 1.5 billion barrels. What we are asking for is an for the UK. If the Prime Minister came back to see allowance of £10 per barrel, on which the oil you, what is the message? companies will pay corporation tax not SCT; so they Mr Jenkins: The message is, again, Oil and Gas UK will pay 30% not 50%. in 2020—we could either, at current levels of Mr Booth: I think the detail of how it may work is investment, say five billion a year, be producing nine subject to some further discussion, but eVectively it million barrels of oil a day; if things go on the way is an allowance that you can oVset against your they are going, it could be 0.5. Taking into account supplementary corporation tax allowance, not your renewables, we could either be providing 65% of the corporation tax allowance. UK’s oil needs, 40% or a lot less than that; and we Mr Jenkins: It will encourage the development of would be beholden to non-UK sources of energy. It fields that are undeveloped—they do not pay tax and is serious. It is going to get a very big problem. they do not create jobs; the oil is just sitting in there. They will be a catalyst for field development, and again contributing to the supply in the UK. Q43 Paddy Tipping: We have focused on oil so far, but gas prices follow oil prices. There was some discussion in the press that the gas market and the oil Q46 Paddy Tipping: So there are a lot of people market are becoming disengaged. Will it always be knocking on the Treasury door just now! What is the the case that gas prices follow oil prices? compelling case? Why should the Chancellor help Mr Jenkins: My company does not produce gas, so you out rather than other sectors? maybe Alan can answer. Mr Booth: I do not think we see it as being helped Mr Booth: Historically, there has nearly always been out. If we developed a field— a general link between the two. From time to time it does detach, and it is because gas generally is a local Q47 Paddy Tipping: I think the Chancellor might! commodity. You do not take it out of the North Sea Mr Booth: I am sure he would! If we develop a field and send it to South East Asia, which you could do that is not otherwise economic to develop, then we with oil. There are more local market influences get income and the Government gets tax they would upon it. The current cost of gas is $30 a barrel not otherwise have had; it is a win/win—so I do not equivalent cost, so this is quite low. We do have a lot think we are asking for a bail-out or a subsidy; we are of gas resources in the North Sea that need to be just asking that we be allowed to eVectively produce developed. My own company has made a fairly the nation’s resources when we both get a return. We significant discovery, and myself and my co- are not asking for repositioning of taxes on existing venturers, to be frank, cannot in its current state production. develop that, because we do not have access to funds to develop something of that size, so we obviously Q48 Sir Robert Smith: The other interest I have to have to look at how we move that forward. The UK declare is that I am an MP for the North East of is particularly reliant on gas. It particularly needs Scotland, and when you see the downturn—if you gas storage, because that helps us in times when gas look back to the eighties and the rows of “for sale” supply, in the broader European market, is times when the big downturn comes—maybe the disrupted. There are two things we need to do: make measure for the Treasury—Steve Jenkins talked sure we extract the maximum amount of gas we can about the four years it takes the North Sea to recover Energy and Climate Change Committee: Evidence Ev 7

11 March 2009 Mr Steve Jenkins, Mr Alan Booth and Mr Martyn Millwood Hargrave from previous experience, but that was before we Q53 Sir Robert Smith: It is the country’s oil and gas peaked. Is not the very important message now that that is in the ground, and without your skills and the Government has to join in with nurturing the activity, it will stay in the ground and we won’t pay industry through this trough so that it is still there any tax, and we won’t get the jobs, and we won’t get when the price comes back, because this time round the security of supply. there are not necessarily the attractive big prospects Mr Booth: That is absolutely the case. to pull people back in on their own merits? Chairman: Perhaps we could ask your opinions on Mr Booth: It is fascinating—in my career this is the “wild west frontier” of the west of Shetland, probably the third cycle I have seen, and what is which is a greater unknown. I know that it may not diVerent about this one is the speed at which it came be a very high priority in relation to a lot of the along, and the nature of who is exploring in the independents at the moment, but Alan wanted to basin. The big companies do invest significant raise something on this. amounts of money in the basin—and that is absolutely the case on existing facilities. The danger Q54 Dr Whitehead: The key initial question is: what of this one is that if this is a prolonged cycle and are the barriers, in your view, to exploitation west of some thought is not given to what will happen when Shetland? You mentioned the existence of fair we come out of it, the smaller companies simply will reserves of gas, presumably known reserves of gas, not be there to re-start that exploration and but because of what we all understand in terms of the appraisal campaign, which they have been doing general conditions, they are very diYcult to exploit; over the last three years. Oil and Gas’s own figures but what are the other issues as far as west of are that up to 80% of all exploration appraisal wells Shetland is concerned? are drilled by these smaller, new entrant companies. Y Mr Booth: The main issue is that it is a very hostile If they are not there, it is a bit di cult to re-start. environment, being on the Atlantic seaboard. The geology is not as simple as the rest of the North Sea, Q49 Sir Robert Smith: So you want a good value and it is very expensive to drill. It is often deep water. allowance decision from the Treasury; and you It does remain the remit of the larger companies that would add that something that has come up since the can aVord the costs, the risks associated with consultation is the credit crunch and the shortage of developing reserves out there. There is very little cash flow. The Treasury could perhaps assist the cash infrastructure there, and of course one of the most flow by giving you early access to your tax-relief recent debates is: what size should that funds. infrastructure be? Do you size it for a particular field Mr Booth: Absolutely. Certainly, our submission or do you size it for the greater good of the basin? It from my own company was: “Do not just give us the is not something we get closely involved in, but I am money back to invest somewhere else in the world; aware that that is a significant issue. Do you size a the condition is that it has to be reinvested within a pipeline just to suit a field at the end of it, or other certain time frame within the UK.” fields that may be found in the future? In that case, who provides the capital to over-size it? Q50 Sir Robert Smith: Going back to the issue of maintaining these big platforms that you are tying Q55 Dr Whitehead: Is it suggested that the reserves back to, is there an argument for extending the value west of Shetland are at the larger end of numbers per allowance to incremental developments within the field? You have mentioned the reduction from larger platform, because at the moment it has to be a new fields of 500 million barrels to the 15 or 20 there are well tied back? at the moment. What sort of size are we talking Mr Booth: I think there almost certainly is. However, about? if I were the regulator—which fortunately I am Y Mr Millwood Hargrave: From what I have seen— not—I would make that allowance, albeit di cult to and you have to make comparisons and analogies apply because of the nature of the field, conditional with similar provinces in what is called the Atlantic on suitable infrastructure access rules. If you are Province. A good example would be north-eastern prepared to grant access, then maybe you could have Canada. If you look at the scale and size of fields that a value allowance or tax credit for incremental have been found there, I think there is a very good investment in your field. There has to be a quid pro chance there may be some billion barrel fields out quo for that. there, which is the kind of scale you need to start this infrastructure going. There are existing billion barrel Q51 Chairman: Is there an arbitration process on the fields out there—BP’s Clair field, for example, which access charges? has not been developed for various reasons over the Mr Booth: As I said, there is not an arbitration last twenty years or thereabouts. It needs these process per se. The Secretary of State, as was— kernels, or centres, to start going. From what I have seen, the major companies that have the technical Q52 Chairman: You would have to appeal to the capabilities to operate in those hostile environments Secretary of State, would you? are looking elsewhere in the world at where they can Mr Booth: Has to be invited to arbitrate. There is, I put that capital and get similar returns, or get think it is fair to say, a reluctance on behalf of the returns. It is the options that the larger companies Secretary of State to want to do that, and obviously have, where they work in a more international a reluctance by many of the players in the North Sea sphere, which persuades them that maybe west of to go into that regime. Shetlands does not stack up against Angola or Brazil Ev 8 Energy and Climate Change Committee: Evidence

11 March 2009 Mr Steve Jenkins, Mr Alan Booth and Mr Martyn Millwood Hargrave or Nigeria or West Africa or the other parts of the would like to see that if areas are established that are Atlantic Province. A lot of that may be down to “no go” that they are “no go”, and then we can move things like tax, again. on. Some of the issues that have arisen recently include people applying for licences and then they Q56 Dr Whitehead: Is there a critical mass that needs are told that they cannot be awarded because they to be developed before further things follow? You may or may not have some environmental sensitivity mentioned not just common access to pipelines, but around them. It would be nice to know if there are also landing infrastructure, diYculty of working the “no go” areas but please tell us where they are going terrain. Is there a point at which the critical mass of to be and we will stay clear of them. infrastructure allows those various things to be Anne Main: I think that is part of the problem. overcome, and do you see, for example, the value Someone who was on the Marine Bill was a little allowance being of relevance in development that concerned that it was very hard if there was going to critical mass, or are there a number of other factors be a “no go” area around Scotland, because over and above financial stimuli? Scotland is doing its own thing on that one. Mr Jenkins: It is very risky. That part of the world is very risky. To drill a well west of Shetland takes, Q60 Sir Robert Smith: To clarify, that is only up to because of the weather down-time, a great deal more the 12-mile limit; beyond the 12 miles it is UK where time than a well, say, in the Viking Graben in the most of your operations are. north of the North Sea. As we said, the geology is Mr Booth: Yes. more diYcult, and trying to see reservoirs underneath and within basalt is very diYcult from a seismic point of view. We are in the same situation Q61 Anne Main: It is a migratory path. Best practice that we were in the North Sea. There are discoveries is sometimes questionable, in terms of leading the out there, and they need to come on stream at about industry to follow best practice, surely! Are you the same time. Maybe the oil is there and it just has happy that there are enough guidelines on this? to be exploited in parallel rather than one hub being Mr Booth: Absolutely. When we get awarded a established, then other fields being added in. There licence we get a document this thick to say what the needs to be a concerted eVort to develop the fields environmental rules are around that specific licence, that already exist. I think that has been mooted in and we have to follow them, otherwise we do not get regard to the gas out there, and as small companies, permission to drill. We do not make the rules up as I say, are not really involved in that part of the ourselves; we follow the guidelines given to us. The world because of the cost. UK is one of the most heavily environmentally regulated hydrocarbon provinces in the world. Q57 Dr Whitehead: In addition you have a number of potential question marks concerning the marine environment, the Hebrides and St Kilda and Q62 Chairman: In some of the submissions there was possibly exclusion areas that may follow around a claim that some of the promises, particularly on those environments. What eVects might they have environmental monitoring, made by the companies, on the kind of development arrangements you have have not been kept to. Is that a fair criticism? been hinting at? Mr Jenkins: I do not think it is. As Alan said, it is Mr Jenkins: We are not familiar—we would be just very highly regulated. We have to make reports on echoing what has been written in the press and the any activity whatsoever. From a small company journals about that. We would refer you perhaps to point of view, we tend to employ experts to represent Oil and Gas UK for that. us, specific Health and Safety Executive experts— and that is all they do. When we apply for a licence, they would carry out our environmental assessment Q58 Chairman: There are some very sensitive of the wildlife and flora and fauna in that licence, habitats in the North Sea generally. and help us monitor. We will not get permission to Mr Jenkins: Yes. drill if, for instance, our Health and Safety Executive Chairman: You will be aware of the debates in the policies are found lacking by, say, Lloyds, who Marine Bill and the potential for designating endorsed and approved them. We not only stick to protected areas. I know that Anne wanted to come the letter of the law but we probably exceed that. The in on this. oil industry operates within the guidelines, and in fact is very careful when it comes to any operations. Q59 Anne Main: It is quite interesting that Scotland is not participating in the same way as England on the Marine Bill, so there is a particular issue of Q63 Dr Turner: To what extent are the sensitivity. What have you learnt from the Sakhalin environmental constraints placed on companies a Island situation where there was much concern over factor in deciding where to invest? Does it happen migratory whales and breeding whales on the impact that requirements in the UK are so stringent that of cetaceans and the disturbance you could cause if companies move elsewhere? you start making multiple explorations in smaller Mr Booth: No, I do not think so, because once you fields? know the rules you know what your operating Mr Booth: At the end of the day, oil and gas environment is so it will not put oV companies, companies follow the regulator’s advice or direction because it is very straightforward to operate within on where we should or should not be exploring. We those guidelines—it is being a responsible citizen. Energy and Climate Change Committee: Evidence Ev 9

11 March 2009 Mr Steve Jenkins, Mr Alan Booth and Mr Martyn Millwood Hargrave

Q64 Dr Turner: What are the challenges facing the Q68 Dr Turner: What would you wish to see the industry when it comes to decommissioning in terms Government do to make it easier for your industry of satisfying environmental requirements? to invest in CO2 storage, in your hydrocarbon Mr Jenkins: Decommissioning is not something that reservoirs or your saline aquifers? What does our members are really familiar with. Government need to do to facilitate it? Mr Booth: It needs to have a regime that is in place. Q65 Chairman: There would be a cost, presumably, How do I get a licence? I do not know. Hydrocarbon that you have to factor in! or gas storage is diYcult to fund at the moment. I do Mr Booth: There is clearly the issue of the cost and not think there is much the Government can do what we are supposed to do. As I say, it is not about that—it is just the nature of the market. something we are deeply familiar with, and perhaps it is more a question for Oil and Gas UK. There are Q69 Sir Robert Smith: On the gas storage, could they a couple of things here: tell us what the rules are; tell not charge you tax on the cushion gas? us what the playing-field looks like, and we will live Mr Booth: Thank you, Sir Robert! Absolutely, yes. within it. As the North Sea is changing its make-up That was not pre-ordained! Our company has also we need to better understand a predictable, tried to develop gas storage, and the issue is that you transparent environment in which to work. That have to put gas into the reservoir to maintain a comes down to decommissioning or funding our pressure, which you never produce, except we are share of decommissioning. What is it we are expected to pay tax on that. It could be helpful that supposed to fund? Is it the entire cost or the after-tax because the gas has come from somewhere it has cost, because of course the pre-tax cost in the current paid tax when it is produced so why have to pay tax regime is at least twice what it is actually going to again when it is put in the ground? It is eVectively a cost, so we have to put up security for the whole lot. piece of the infrastructure. That would be extremely helpful. Q66 Dr Turner: You have to carry out an environmental impact assessment specific to any Q70 Dr Turner: If the Government is serious about project that you are seeking consent for; but it has exploiting CCS, it has got to put a proper regime in been put to us by the RSPB that there should be a place and it has not done so. strategic environmental assessment over the whole Mr Booth: And quickly, or at least get us a bridge to area. How would this aVect you? when that is in place. Mr Booth: I think the SEAs have already been done. Mr Millwood Hargrave: That is a very good point. We have had a number of years, five or seven years, There are some pilot schemes going on, as the where each area has been out of bounds until that Committee will know, but no-one has done this—is strategic environmental assessment has been done, it a commercial business? To what level is it and each area has been released through time. I commercial and to what level is it public service? would be interested to know what they mean by that. What is the interrelationship between the two? That is not clear at the moment. Probably the first number Q67 Dr Turner: That is my understanding. of times this will be done in the UK, there will Mr Booth: SEAs have been done for each area. In inevitably—and there is certainly talk among the addition, once we have a licence we then have to academic community of large amounts of money demonstrate that what we want to do is acceptable. around there, but it is just not clear what the rules are In certain areas, because there is not any data they and the focus. Getting a focus and policy would be tend to assume the worse, and then we have to go extremely useful. and demonstrate that either it is like that, or perhaps Chairman: Thank you very much. There are it is not quite as bad as they envisaged. That gets fed certainly some issues there we would like to give back in to the system. some thought to.

Witnesses: Mr Martin Harper, Head of Sustainable Development, and Dr Sharon Thompson, Senior Marine Policy OYcer, Royal Society for the Protection of Birds, gave evidence.

Q71 Chairman: Welcome, Dr Thompson and Mr marine team. I am the Senior Marine Policy OYcer. Harper. We are very pleased to see you here from the I tend to focus on areas such as the Marine and RSPB. We certainly welcome your input into the Coastal Access Bill, international marine policy such Committee’s inquiry. I should start by saying I am a as the Marine Strategy Framework Directive; but I long-standing member of the RSPB myself, and also also provide advice on issues such as the strategic a former member of the governing council of the environmental assessments of oVshore energy, so oil RSPB. I wonder whether you would like to and gas and renewables. introduce yourselves and say a word about what areas you cover. Q72 Chairman: You will be aware that the Mr Harper: I am Head of Sustainable Development Government is very strongly committed to tackling at the RSPB, and my responsibilities cover our climate change and reducing emissions, and then of policy and advocacy in relation to climate change, course moving towards a low-carbon economy. marine and land-use planning, and also our work on However, realistically we have to accept there is economics. going to be demand for oil and gas for some time, Dr Thompson: I work in Martin’s department in the and there are issues of security of supply and the Ev 10 Energy and Climate Change Committee: Evidence

11 March 2009 Mr Martin Harper and Dr Sharon Thompson economy.Do you feel there can be a balance between whereas we are charting new territory with the extraction of oil and gas, and particularly the renewables, because we are not clear what the development of new oil and gas fields, and nature impacts are; hence why we are saying we need to find conservation in what is a very important area with a more about it. Perhaps CCS would fall into the number of globally protected species in our waters? second category, being a new activity. Mr Harper: If I may, it might be helpful to provide a bit of context on where we are coming from with Q74 Chairman: It is an important point that oil and our evidence. From the RSPB’s point of view, gas developments in the North Sea are long-standing climate change does risk a mass extinction event and have been there for decades, and therefore there which threatens millions of species across the world, has been an opportunity to monitor their impact on putting the survival of our own species under threat. the marine ecosystems. Apart from oil spills—and, To a certain extent therefore, that is why we are so of course, there is no argument about the eVect of oil concerned about reducing emissions as quickly as spills—in terms of infrastructure has it been very possible. Our particular concerns with regard to the V detrimental? marine environment, particularly o the UK, partly Dr Thompson: At this stage in development of oil emanates from the fact that, as you rightly say, we and gas, particularly in the North Sea, as I said many have particular international importance for many of the regulations have taken into account the populations of seabirds. The UK holds over 50% of environmental impact; so discharges of oily waters the European population of four species, and indeed and oily muds are being reduced or done away with; we are already experiencing the impact of climate so those impacts have been recognised, regulated change on marine eco-systems. It is now and dealt with. On the whole, the impact on birds, unfortunately becoming an annual seasonal event which would be our primary interest, is not great, that we are having very poor breeding seasons for and tends to be limited to the potential risks from oil many of our seabirds, particularly in Scotland, home spills. I would say in the context of looking west of to over three million sea birds, and over 80% of the Shetland, because that comes under this UK’s breeding sea birds. The context for our conversation, we are chatting about areas where we engagement in the climate change debate is that we know less about the environment and, as you absolutely do want to see climate change mitigation pointed out, there are sensitive environments that we as quickly as possible, while at the same time we would like to see avoided. Perhaps in the wider want to make sure that we are intervening to support context of marine biodiversity, there are other nature conservation measures in the marine groups of flora and fauna that could be more environment. If I may say a word about where we are susceptible to oil and gas exploration, such as coming with regard to the energy debate, the cetaceans, so whales and dolphins, to the issue of research that we undertook a year ago with WWF marine noise. This is not obviously an area that we and the IPPR looked at how we would get 80% focus on, but we would hope that you are speaking reduction of emissions by 2050, while at the same to NGOs such as the Whale and Dolphin time putting in place some environmental safeguards Conservation Society that are greatly concerned and not resorting to nuclear power. We ran the about this issue. Government’s own models, the MARKAL-Macro model and the Anderson Model, which are cost minimisation models, and we found that it was Q75 Dr Turner: Can you summarise what you see as possible to meet those targets; but what was critical the main environmental impacts of North Sea oil was that we massively reduced the amount of energy and gas extraction, and can you add to that, because we used; we ended our dependency on unabated you have referred to the question of marine coal-fired power stations such as coal and we renewables? What impacts do you anticipate from stabilised emissions from aviation. When it comes to marine renewables? oil and gas, I suppose what DECC is looking at now Mr Harper: Just picking up a question you asked the is its twin objectives of trying to guarantee energy previous witnesses, there is currently an oVshore security, while at the same time reducing emissions. SEA being carried out for oVshore oil and gas and What we hope is that the Department for Energy indeed oVshore renewables, which we welcome. We and Climate Change looks at how it can reduce argued in previous rounds of oVshore renewable emissions while keeping the lights on, without deployment that there should be an SEA, and in relying on foreign imports, and at the same time round 2, belatedly the DTI did undertake an SEA. safeguarding the natural environment. That, in a We now know, through discussions with oYcials, sense, is the context for today’s conversation. that they are pleased that they can now explore the Dr Thompson: It might be worth adding that many alternatives, because that informs good decision- of the comments we have made here in relation to oil making. Obviously, from a wind farm point of view, and gas are equally applicable to renewables and there are specific impacts in relation to the direct other activities in the marine environment. impact of wind farms on birds, displacement from habitat and cumulative eVects of various developments at sea. I should say that we are, Q73 Sir Robert Smith: Some renewable schemes particularly as we enter into round 3 of oVshore might take up even more marine space. renewables, more confident that the measures that Dr Thompson: Yes, and the issue in this context is have been put in place by Government will enable that the impacts of oil and gas are now known them to be able to find the areas that are at least risk because we have been doing it for 30 or 40 years, for the sensitive species of birds we are concerned Energy and Climate Change Committee: Evidence Ev 11

11 March 2009 Mr Martin Harper and Dr Sharon Thompson about. We are of course hampered by a lack of data rather than this current system where we are all kind in the marine environment, which is one of the major of working in the dark. It is not a system that we things I wanted to talk to you about today, but we favour either. are reassured that in the zones that Government is V likely to come forward with in regard to o shore Q77 Dr Turner: You are very concerned about renewables there will be flexibility to be able to put strategic assessments. How satisfied are you with the what we probably expect, about 7,000 wind farms, in progress being made on those assessments, and do places that will not cause direct damage to you feel there is any likelihood that it is going to take internationally important populations of wildlife. too long and be too expensive, and not only hold up Our own experience, for example, in engagement V and be a barrier to sorting out where marine with the London Array project, the biggest o shore protected areas should be, but will inhibit reasonable wind farm in the UK, is that when you have exploitation of marine resources? developers who are prepared, as is the case with the Mr Harper: I think the principle of SEA is that you London Array guys, when they identify essentially try to explore the options and at the same internationally important populations, in this case time you understand the impact, direct or the red-throated diver, they are prepared to adapt cumulative and you are prepared to take their wind farm to be able to deliver significant precautionary measures as appropriate. It is fair to elements of wind—1 gigawatt in the case of London say that DTI and DECC, in its various SEAs which Array—and at the same time minimising the risk to it has been conducting over the years—it has two live that internationally important population of diver. at the moment, oVshore energy and tidal power in the Severn, and it will have another on wave and Q76 Dr Turner: It is an expensive business, gathering tidal soon—each time they appear to be learning as data on the marine ecology; and, as you say, it is in they go. They do some things well and they do some very short supply. Does the oil and gas industry things less well. We are pleased, for example, that make a fair contribution to funding that work? they have through the oVshore energy SEA, Dr Thompson: It has in the past. There was a accepted our recommendation that they should now programme—I probably will not be able to be taking aerial surveys. We think that is an remember what the acronym stands for—called important improvement. We would prefer there to AFEN—I think it was Atlantic Frontier be more opportunities for stakeholder involvement Environmental Network, where the oil industry through the process. With reference to this being helped supplement data collection. Let us call the deemed to be an overhead in terms of time and cost, Atlantic a Frontier area—the industry has provided we would say that that is patently not true. It is an a lot of the historic data we have for these areas, and appropriate investment to understand the nature of we refer in our submission to what is known as the impact, particularly to safeguard and satisfy the European sea birds at sea data. A lot of the oVshore Government’s other aspirations for looking after the sea bird data was collected opportunistically by natural environment and its own public service observers going out on industry vessels and doing agreement target on the natural environment; and at the sightings there. It is great that we have that, but the same time it is much better from an industry it is limited in age—it is at least 10 years since any of point of view that they know the likely impact of any these surveys were carried out in this way. They are development before they start. Going back to the not systematic surveys with a scientific approach; London Array example, if there was data made they are opportunistic focusing on areas of interest available about the red-throated diver population in to the industry, plus there are gaps because people the North Sea, it may well have been that they would tend not to go out into the Atlantic in the winter, so have circumnavigated some of the negotiation they there are gaps as well. We have this data, but it is a had to do with ourselves and the agencies to relocate bit holey and we would like to see it filled in. One of that wind farm. It does provide certainty. One can the figures we have is from the impact assessment on determine the relative importance of diVerent the draft Marine Bill, where the Government populations at sea, and that in turn can determine proposed that to collect data for the new system of the pace at which energy projects are rolled out. marine conservation zones could cost between £9-10 million. On the Marine and Coastal Access Bill that Q78 Dr Turner: Would you like to comment on the is currently in Parliament, they are saying, “we do progress towards defining marine protected areas, not think we need to go and collect that data”; but in and do you see any opportunities, in fact, for synergy the grand scheme of things, £10 million is not really a between marine protected areas and energy great deal of money if you consider the benefits that exploitation of the North Sea, because both in the it would deliver in our current climate; so this marine protected area and in, say, an oV-shore wind information would be used for not only oil and gas farm or a tide farm you are not going to be allowed but renewables, designating marine protected areas fishing, so there is a great conservation of various sorts, and helping marine planning. These opportunity there? are all things we think need to be put in place, to Dr Thompson: Starting at your last point there, our remove any of the barriers not only to the oil and gas primary focus is looking for marine protected areas industry but other developments that are happening to be designated, where the primary concern is the oVshore. It kind of echoes what was said by the biodiversity issue, but that is not to say that areas previous evidence, where it would be better to know that are closed to activities because something else is where the important sites are and have that certainty, happening there do not have an additional Ev 12 Energy and Climate Change Committee: Evidence

11 March 2009 Mr Martin Harper and Dr Sharon Thompson biodiversity or conservation benefit. The reason I Q81 Miss Kirkbride: Obviously our inquiry is about am making a distinction between the two is that if oil and gas, but I just wonder what you think the something changed within the wind farm or around environmental impact of energy production is: the oil or gas platform for reasons of industry because it would seem from what you are saying that development, the biodiversity benefit could be lost oil and gas is not quite so damaging except for the because it is not the primary concern. So that is why fact that it is a fossil fuel that burns and does climate I am making the distinction between the two. The change, but the impact of wind farms and other stage we are at with marine protected areas is that renewable energies have, potentially, a bigger impact there are two pieces of legislation that will be on the environment in the production of it, albeit important, and one is the international legislation with, obviously,much less impact on climate change. that will designate what are known as the Natura I just wonder how you assess those two things. 2000 sites for habitats and species and seabirds Mr Harper: I think that is a fair assessment, but not oVshore and the other that we hope will come neglecting Sharon’s point about cetacean impacts, through is the Marine and Coastal Access Bill, on which, of course, we are not competent to really sooner rather than later, for the nationally comment I think, because there is a real deficit of important marine conservation zones. We are at the knowledge about what is going on in the marine stage where government is proposing a process of environment, on land we have 30 years of records. For example, looking at the Breeding Birds Study, stakeholder workshops around the country, so that thanks to enlightened members of the BTO 30 or 40 it has divided the UK seas into four areas and it is years ago we now have trend data looking at how going to have stakeholder projects running to populations of birds on land are faring, and there has determine networks of marine protected areas and, been a huge investment by government in things like running parallel to that, the statutory agencies are the Countryside Survey, which, again, has allowed designating the European sites because there are us to look at the changes in biodiversity over time, more specific rules that have to be met in that and, I think, in a sense for any activity in the marine process. So we are probably at the beginning of the environment, I suppose there are some building process of designating our network of marine blocks which we hope will be in place. We want good protected areas. data collection to be able to inform the identification of protected areas, outside of those protected areas we want a good planning system, again, to be guided Q79 Paddy Tipping: You have mentioned the by data that we have at our disposal, and at the same Marine and Coastal Access Bill, and you have been time we want to be able to understand the impacts of fundamentally involved in that. various forms of development. For example, in the Dr Thompson: Yes. case of wind farms we have argued for two years pre and two years post construction monitoring to determine impacts, and that feels appropriate to us Q80 Paddy Tipping: How helpful is it really going to because as a new sector, a new form of development, be that the oil and gas licensing regime remains we are trying to understand what the impacts are and outwith the provisions of the Bill? we think that is the right approach to proceed. So in Dr Thompson: This is one of the areas where it is a sense in the marine environment where there is a good to be completely clear, in that, although the shortage of data, we think there is a strong argument licensing consent and regulation process is outwith for sustained investment in research and, the reform of other marine licensing regimes, oil and unfortunately, at the moment we have some gas licensing will still be subject to the new planning concerns that that data collection strategy is being system and the new marine policy statements and all held and not necessarily joined up between two bits the other elements within it, the same as any other of government, obviously, DECC on the one hand industry or regulated activity, and that the Secretary keen to determine what the data is to guide the roll- of State for DECC will also be subject to the duty to out of energy development and on the other hand protect marine conservation zones, so they are not Defra to inform the development of marine completely outwith. Our favoured view in an ideal protected areas. We would like to see a joined up world would be that, if you are going to reform the strategy which delivers the possible win-wins that licensing regime, you should reform all of it, but in a Sharon referred to earlier in the evidence. system where bits are staying as they are, as long as everybody is subject to the same planning system, I Q82 Miss Kirkbride: You are happy that the think that gives us a good strategic overview to the information is being collected; it is just not joined up. whole process. I think, on the whole, we would say Who is collecting? Who is paying for it? we are positive about the processes that are coming Mr Harper: At the moment there is data being through the Marine and Coastal Access Bill; I think collected through the oV-shore SEAs. they are long awaited and long needed. We, obviously, have some tweaks that we would like to Q83 Miss Kirkbride: Who is paying for that? see to make it much better, but we are working on Mr Harper: That is being paid for by DECC. There those as best we can. is also, we hope, more investment in survey to Chairman: Maybe one of your objectives is to determine the selection of marine protected areas. protect and monitor the eVects on wildlife, and Julie We think that there has been some progress made in wants to ask a question on this. the sort of data being collected to inform this round Energy and Climate Change Committee: Evidence Ev 13

11 March 2009 Mr Martin Harper and Dr Sharon Thompson through oV-shore renewable consents and indeed for marine wildlife or birds? This is especially important oil and gas. What we do not yet see is a long-term in the West of Shetland, where you are getting into strategy for data collation. some very important areas for seabirds. Dr Thompson: I suppose that is very much the question that we are asking and have been asking Q84 Miss Kirkbride: It will not be on-going? since the first Strategic Environment Assessment for Mr Harper: Indeed, it should be. In the same way it oil and gas, which was in 1999, when we highlighted is on land, to underpin decisions that we make about specifically the gaps in seabird data information. So activities on land, we should be looking to do the it is not that we turned up yesterday and said, “Oh, V same o -shore. by the way, we would like you to start doing seabird Dr Thompson: It is probably worth just clarifying surveys.” We have been saying this since 1999. We that the surveys that DECC are currently have known about these gaps in the seabird data, but V undertaking for the o -shore renewables do not it took a desk study that was finally published in cover the whole of the UK Continental Shelf, they 2006, which, was sponsored and paid for by the then are specific to the areas of search, so it is the long- DTI, to confirm what we already knew. So we took term data collection and full coverage that we are seven years to get to the point where we already were, advocating. like, “Yes, we know that. We have been telling you that. Now what are we actually going to do to fill Q85 Miss Kirkbride: How long do the present those gaps?” So we are asking the same question as searches take? Over what time period have they you, because I think this does come back to the point taken place, the present data collection? What time that, although we have some data and we have some periods are we looking at for that—a year, two years information, it is that lack of data and the or six months? uncertainty that is the barrier rather than knowing Mr Harper: The interesting thing in this area is we sit where the important sites are. We would love to be in on a number of research groups which are set up by the situation where we had all the information and DECC to inform roll-out and we have obviously we knew not to be worried about certain engaged with the SEA process, and we have read the developments in certain places. That would be great environment report which has been produced by the for us too. SEA and we have produced a long list of eight or nine research requirements which we have been Q88 Mr Weir: Have I picked up correctly, it would talking to DECC about, and they range from the be at least a two-year study for two seasons of birds, comprehensive survey of requirements that we have is that correct, to do it? just talked about through to the mixture of aerial Dr Thompson: Yes. and ship-based surveys to guide the round three collection over a two-year period. We have argued Q89 Mr Weir: Who would you be looking to pay for for two years’ worth of data collection, both in terms such a survey to fill in the gaps? of winter and summer season, to determine the likely Dr Thompson: I think we are going to say the same. importance of sites for breeding and wintering sea We are canvassing government. This needs a birds. The issue for us in a way is it has been quite strategic approach, because, as you say,there are bits diYcult to critique the research plan because it is not and pieces going on funded by diVerent published, so it is very diYcult for us to actually see departments, diVerent bodies and for diVerent exactly what is being proposed, and so that for us places and it would be great if there was a strategic makes it quite hard to scrutinize as the information approach to collect this data once and use many is presented in a piecemeal fashion. times.

Q86 Miss Kirkbride: They do not tend to publish it? Q90 Chairman: Who do you think should give the Why not? lead on that data collection? Should it be the JNCC, Mr Harper: I am not aware that they are intending should it be the new marine organisation, should it to publish a research plan, no. We would argue that be another body? would be beneficial, because then, in a sense, we Mr Harper: It probably does make sense for it to be could all look to see whether the research plan is the JNCC. They have in the past done a number of adequate. these surveys and I think they ought to have responsibility for co-ordinating data across the UK environment. I think they have long argued for Q87 Mr Weir: Perhaps just on that point, the last greater resources coming their way. Of course there witnesses from the industry made it clear what they are other nature conservation organisations— wanted for certainty to know where they could go Natural England and others—but, I think, in order and develop, where the marine protected areas were, for us to have this co-ordinated UK research eVort, where there were areas of particular importance there is logic for JNCC to be at the heart of that perhaps for migrating birds, or whatever. From what eVort. you are saying, it seems research is going on. It seems Dr Thompson: Particularly when the MMO is a little piecemeal and it seems to be taking quite a unlikely to be up and running until 2012, which is long time. What sort of time scale are we talking also our target date for establishing the network of about before the industry can be certain as to where marine protected areas. I think it should be JNCC it can go and explore, which areas are oV limits for for now anyway. Ev 14 Energy and Climate Change Committee: Evidence

11 March 2009 Mr Martin Harper and Dr Sharon Thompson

Chairman: The industry were telling us that the UK Dr Thompson: Again, I would say that we do not oV-shore oil and gas sector is one of the most heavily have any empirical data. You do hear the rumours, regulated in the world, and part of that, of course, is and I am not being specific to oil and gas here, about to reduce the environmental impacts. Robert may activities that are licensed with certain conditions have a few questions. and those conditions not being fulfilled. I think, from our point of view, if there are conditions put on licences and they mitigate environmental damage, Q91 Sir Robert Smith: I just wondered if you somebody should be monitoring that to make sure accepted that premise, that the UK is one of the most that they are fulfilled and that there are heavily regulated in terms of environmental consequences if those conditions are not being met, hydrocarbons. and, hopefully, maybe some of the enforcement Dr Thompson: I am afraid I honestly do not know. elements that are being proposed in the new Marine I think, from our point of view, it is not how much V and Coastal Access Bill will help improve that regulation as long as it is appropriate and e ective situation, if it needs improving, but, as I say, again, regulation, and that is just the same for new activities I have no empirical evidence. coming online such as CCS, and there are probably Sir Robert Smith: Thank you very much. many activities out there that need to be more heavily regulated than oil and gas. I cannot give you any more opinion than that. Q94 Chairman: The issue of west of Shetland, of Mr Harper: Can I add, I was partly assured by that course, is bound to be of environmental concern answer to that question actually, Sir Robert. They because it is potentially a new development area, did say that the regulation was not going to there are some very sensitive areas out there, and I discourage them from exploration. In a sense, what notice that in your submission you suggest that there they want is clarity and I think most businesses we be a protected zone around St Kilda. Is that because speak to want clarity and they want certainty and of the importance of breeding seabirds on St Kilda they want a level playing field—that old adage. We or are there seabed issues there as well? would encourage a race to the top in terms of Dr Thompson: From our point of view, it is environmental standards rather than the other way particularly in relation to the breeding seabirds, and round, but I was quite encouraged by their response the same with the Hebrides. From our point of view, to that earlier question. a traditional stance has been that, if oil spill modelling shows that the oil would reach shore Q92 Sir Robert Smith: Going back to the earlier within 24 hours, because west of Shetland that is a questions, the clarity requires the Government to very short period of time to be able to react and deal have clear priorities, but, of course, it has competing with the oil spill at sea, that would be a concern for priorities in the end—it has the security of supply, it us. West of Shetland our concerns would be in has the carbon. Carbon sequestration and relation to the breeding and feeding seabirds in that renewables are two parts of trying to tackle the area, but there are other sensitive seabed areas that global impacts on the environment, but nothing is have been found in surveys. I think we would be without a price, in a sense. I suppose at times you concerned about the footprint on those habitats of could have an area designated as a no-go area and new infrastructure. then say, “Hang on a minute, the balances in society Mr Harper: May I add, we have got some reserves that we have to weigh up in terms of our competing out in that part of the world and one of those at goals”. Can it be that certain that you draw a line Sumburgh Head. Many of the guillemots have had a and that is it? very hard breeding season. I think that nine out of Mr Harper: I think we would say, and we would say the 10 guillemots that did actually manage to breed, this, would we not, that too often the environmental only one of them managed to successfully fledge a impacts are an after-thought and they are not chick, and I think one of the diYculties that we have thought of earlier on in the process. I am thinking got in the lack of investment in data collection has particularly about a lot of policy measures coming meant that new information, in terms of the impacts out of DECC at the moment. I suppose we remain that we are seeing happen on our seabird unconvinced, for example, that they are linking their populations now, is not being brought to bear to energy security concerns with their CO2 reduction inform some of the decision-making. So it is another targets, and we would then add that we would want justification for sustained and regular collection of to make sure that the natural environment does not data, particularly in some of these most sensitive become collateral damage in pursuit of those two parts of the United Kingdom. public policy objectives. I suppose that is where we are coming from. Q95 Chairman: The breeding values of seabirds are well-known and are linked with the sandeel stocks in Q93 Sir Robert Smith: One other thing that was particular, but how much is this associated with the related specifically. Each development has its own oil and gas industry? impact assessment and its commitments as to how it Dr Thompson: I suppose it is more that it is is going to mitigate or avoid damage to the associated with climate change, so, therefore, the environment. How well after those have been output of CO2. We are coming back to why is it we accepted do you think they are actually want oil and gas? It is because we want to burn it. It implemented? is a fossil fuel. So that is the connection there. Energy and Climate Change Committee: Evidence Ev 15

11 March 2009 Mr Martin Harper and Dr Sharon Thompson

Mr Harper: There is circumstantial evidence that and, obviously, the next stage would be the warming seas, plus a crash in zooplankton sequestration of CO2, and, of course, the oil and gas populations, plus a crash in forage fish such as is not just for burning, it is for chemical feed stocks? sandeels, those complex interactions are causing Mr Harper: I am sure that the gas will play an significant problems for our marine life, and seabirds important role in terms of those really highly in particular, and the data that is coming through at eYcient CHB power stations which, hopefully, will the moment is extremely worrying from that point be rolled out at a local and industrial level in the of view. future. Adair Turner, quite rightly, has argued that we need to decarbonise the electricity sector by 2030. There will be a desire to move towards low-carbon transport networks and we want sustainable heat Q96 Sir Robert Smith: On the CO2 thing, I suppose sources. In a sense, that is the policy context of any from this country’s point of view the impact of fossil fuel development that will be taking place. global CO2 emissions was greatly reduced by the Chairman: Thank you very much for your North Sea, because, of course, the gas replaced coal contribution, it is very helpful to us, and thank you and, therefore, a quick fix in the early stages of CO2, for your evidence. Ev 16 Energy and Climate Change Committee: Evidence

Thursday 19 March 2009

Members present: Mr Elliot Morley, in the Chair

Mr David Anderson Sir Robert Smith Judy Mallaber Mr Mike Weir

Witness: Professor Alexander Kemp, Schlumberger Professor of Petroleum Economics, University of Aberdeen, gave evidence.

Q97 Chairman: Good morning, Professor Kemp. It actually have the equipment and expertise to is very good to see you. Thank you very much for develop these fields? Is it just a question of the coming along to our session this morning. You will regulatory and fiscal regimes? be aware of the Committee’s remit and what we are Professor Kemp: Broadly speaking, the technologies looking at in relation to the production of oil and gas have evolved extremely well since the late 1960s, so in the North Sea and associated issues around the by and large the technologies are available or could industry, the fiscal regime, environmental controls, be adapted to deal with even the very diYcult skills, all of those kinds of issues. Can I start by situations, say, in the Atlantic Ocean. I am a saying, Professor Kemp, oil and gas has been a very petroleum economist and we tend to see the important contributor to the UK economy. diYculties from the economic side as well. It is worth Production is falling, as we know, and it is a finite emphasising that of the remaining potential of 20–25 resource, but there are clearly undeveloped reserves billion barrels of oil equivalent, the average size at in both the North Sea and west of Shetland. I was the moment is about 20 million barrels of oil quite interested to see that the estimates of those equivalent with the most likely being less than that reserves vary wildly,I would say.I have seen a DECC because, to use a little technical language, the figure of around about 25 billion barrels of oil distribution of fields left by mother nature is equivalent and some of the figures we have seen lognormal so there will be a lot of small ones below range from lows of 11 billion to highs of 37 billion 20, 15 or 10 In the 1970s the average size of a field was over 500, so this is what makes the eventual barrels. Do we have any kind of clear idea of what recovery from an economist’s point of view a little reserves we have left which are exploitable? diYcult and why we have a big range. We have got a Professor Kemp: The range of figures you have lot of very, very small fields, some moderately sized mentioned is consistent with the published figures ones and the occasional big one and that makes the from the Department of Energy and Climate economics diYcult even with technologies that could Change. Their central estimate is about 20–21 billion physically do the job. barrels of oil equivalent. For what we call the sanctioned fields we are reasonably confident what Q99 Sir Robert Smith: One of the things you could be producible for the probable and possible. mentioned there was that the size of the new fields is The certainty increases with age but there are much smaller, so in terms of the economics of discoveries although there are doubts whether they production is it quite important to understand that will all be economically recoverable. For the yet-to- they do not get produced by putting a big platform find, which is a big element in the optimistic total of on a little tiny field, they require the existing over 30, 35, there are clearly a lot of diVerences of processing and infrastructure to be available? How opinion on what might be discovered and that has do you assess the quality of the regime for new always been the case. We do a lot of economic entrants finding small fields actually being able to modelling. We have our own independent views on access that infrastructure? what could be producible using our economic Professor Kemp: First of all, to develop a lot of small modelling, which is diVerent from what reserves are fields you would hope that it is not far from existing actually there but could be extremely remote or high infrastructure. If it is not far from existing cost. All being well, that is with a higher price than infrastructure then typically the most economical we have at the moment and a receptive regulatory way to develop the field would be by a sub-sea and fiscal regime, we think that we could certainly system which would be tied back to an existing big recover over 20 billion barrels of oil equivalent. Our platform. One of the diYculties is not all fields are in independent modelling shows that, and it could be that happy position, some are what we call stranded, 23 or 24 in the long period up to 2040. a long, long way away from any infrastructure. Examples would be some of the gas discoveries in the west of Shetland region. Access to infrastructure is Q98 Chairman: Some of these fields are deepwater clearly important and the majority of new and there are the west of Shetland fields. You developments now does use existing infrastructure. mentioned the fiscal regimes as well as the price of One of the issues to expedite the speedy progress in oil, which are clearly drivers in terms of whether or developing new fields is to ensure that access to not these reserves are exploited. Does the industry infrastructure, which involves negotiation between Energy and Climate Change Committee: Evidence Ev 17

19 March 2009 Professor Alexander Kemp the user field and the asset owner, takes place in an complications and whether that would be the right expeditious manner because delays are the worst way to proceed I am not so sure. My thought when thing. In our modelling of the future of the North in 2004 the revised Code of Practice came out was Sea we see the need to get a large number of fields that if the government showed that it really was coming on every year, up to 20 fields per year is just willing to intervene, and did do so when called upon, possible all being well. If that slips because of delays, then that would reasonably solve the problem. for whatever reason, then the production profile goes down more sharply. Q102 Mr Anderson: Professor Kemp, my understanding is that originally there were six or Q100 Sir Robert Smith: The independents who were seven companies operating in the North Sea and giving evidence to us last week were highlighting that now there are something like 60 or 70. Has that made there may still be concerns amongst some of the new things more diYcult or easier in terms of regulating entrants and smaller players that the terms of that these companies and making sure they do the right negotiation are actually quite diYcult. Do you things? detect whether the Government should be doing any Professor Kemp: The number of companies certainly more to make it easier for those negotiations to come has grown and I think there are a lot more than that to a speedy conclusion? altogether if you include the small licensees and the Professor Kemp: There was a major review of this a Promote licences. The advantage of large numbers is few years ago and, if my memory is right, in 2004 a that you do have diversity because not everybody new Code of Practice was brought in which was sees prospects in the same way and there are diVerent designed to speed up the negotiation process and to ideas. We do have trading of assets because give guidance on what might be achievable. In terms companies have diVerent ideas of what to do with an of the economics, a key element in that substantial existing asset or a block that has not been properly document was to say the two parties shall negotiate explored. My view is that larger numbers are fine in good faith for six months and if they cannot agree because there will be more players, large ones, after that and if one of the parties wants to get the medium-sized ones and small ones. At the moment government to intervene then the government would with a lot of small fields the very large players may intervene and could set a tariV and other conditions not find some of them very attractive because the taking into account the risks and costs of the materiality of the expected return in relation to their infrastructure, and after having taken that into size would not be very interesting, whereas for a account would set the tariV which could prevail in a small company it could be perfectly interesting. I competitive market. That is the present think the large number of companies and diversity is arrangement. I do not think there has been any good because it is one factor that can help to formal intervention to date. Whether that means it maximise the economic recovery. It does, of course, is all going very well I am not quite so sure, but mean that the Department of Energy and Climate clearly it is an issue that deserves to be made eYcient Change has more work to do in their talking, because it can hold up new developments quite a lot. watching and regulating all of these companies, but that would seem to me to be very much worthwhile Q101 Mr Weir: Just to follow that up. One of the doing. things the independents were suggesting is there Chairman: Thank you. If we can just look at the should be a common carrier system and they current market conditions next. Professor, it is not suggested the one in the United States, particularly easy for anyone at the moment with the global credit in the Gulf of Mexico, that was put in place by the crunch, downturn, a fall in oil prices, so there are US Government because they feared that perhaps clearly implications for the industry there and, Judy, the Secretary of State would not want to intervene in I know you wanted to come in on this. these negotiations. Is that something that has been looked at that would speed up the access to Q103 Judy Mallaber: Yes, if we could explore that in infrastructure for smaller fields? some more detail. In some of your very early Professor Kemp: The history in the UK has been that comments you mentioned about the price of oil. Is it should be by negotiation between the parties and the low price of oil the single most important factor the government would intervene as a last resort. in the current market conditions facing UKCS Clearly there are other models. For example, in companies? Is that the critical factor? Norway there is a regulated tariV that is known to Professor Kemp: The present position is a very everybody and that is that. The Government here diYcult one in the UK Continental Shelf. The price has not wanted to go down that route. Common of oil, as you will know, collapsed from $140-odd to carrier would be quite a major change. The present just over $40. What was not so well discussed was system does have flexibility because in diVerent parts that the gas price at the wholesale level has also come of the UKCS there could be diVerent conditions, right down as well. The wholesale price was just over diVerent requirements and so on, so the flexibility is 30 pence per therm this morning. That accounts for quite good. To develop a common carrier system 45% of total production. That is a big concern as would be extremely complicated because we do not well. Over the last four or five years the costs have have an easy basis for that. We have it onshore, of pretty well doubled, or maybe more, so the cost per course, for the national transmission system but that barrel is now very, very high and there is a kind of is because it is already there and established on that pincer movement between the price coming down basis. To do it oVshore would involve a lot of and the cost per barrel going up. On top of that we Ev 18 Energy and Climate Change Committee: Evidence

19 March 2009 Professor Alexander Kemp have the financial sector problems which make it Q106 Judy Mallaber: You mentioned the problem very diYcult for the small and medium-sized about getting finance for companies in the current companies to get external finance, whether debt or credit crunch. Is there a real distinction between the equity. This has come very, very quickly but, of impact on large and small companies? You also course, the companies have done their budgets— indicated you thought that the Government needed they do them late in the year—so $40 for oil is not a to assist. What kind of assistance would you look good outlook looking ahead and into next year for? Is that to all types of companies? What because it does not look to me as if the price is going responsibility do you think there is on the to come up much in the next couple of years. Government to give assistance to get extra finance in for investment and exploration? Professor Kemp: Oil companies are aVected by the Q104 Judy Mallaber: I think when you were talking V earlier you indicated that there would be a knock-on e ects of the financial squeeze because relationship between the price of oil and the amount that has helped to bring the oil price down so, that would be taken out. Does your research confirm therefore, all companies’ cash flows have come right that lower oil prices will lead to lower rates of oil down. The major oil companies, despite the fall in production from the Continental Shelf? I their cash flows, will still have funds available and understand you are saying that there is a link could get external funds more readily than small between the rising costs of development and the ones but, nevertheless, as we say, they will be price, but what prospects are there for the long-term rationing their capital as well. The problem with the price of oil and how significant will it be for the North Sea is with the new projects being 20 million barrels or less, when it comes to capital rationing industry and how much exploitation will we get? V Professor Kemp: On the first point, the amount of they may not stand up too well against o shore investment will certainly be linked to the price, so if Angola, for example. For the medium and smaller a relatively low price continues we will certainly get companies, their capital rationing problems will be a significant reduction in investment and that in turn more acute because their cash flows are down and would mean that the economic recovery would be the financial institutions, whether debt or equity put in jeopardy because some of the infrastructure providers, are not very enthusiastic. Their problems that we have already mentioned might not become will be more acute. suYciently used and might have to be decommissioned. Our modelling shows with $80 and Q107 Judy Mallaber: So should the Government be more then in the long-term we could recover over 22 helping smaller companies or larger companies? or 23 billion barrels, but if it stays at $60 then a fair Professor Kemp: In my memorandum I said there bit less and at $40 certainly much less. There is a link was a very strong case. The Treasury put out a with long-term price sensitivity. My own view on the consultation document at the time of the Pre-Budget oil price is that I fear it may stay relatively low for a Report and it raised a particular incentive for new while because the world recession and reduction in developers called the value allowance that would be world demand has been the driver in bringing the an allowance for the supplementary charge. For new price down and that could easily remain the case for field developments we have the corporation tax, the next couple of years. Although eventually it will which is 30%, and then the supplementary charge on come up, I fear it may be sometime in the future and top of that of 20%, so the total for a new that is what has led me to say in my memorandum development is 50%. They said value allowance is on that for maximising economic recovery from the the table and my thinking is it is very important that North Sea then intervention by the Government in a reasonably sized value allowance should be the form of a tax stimulus is very appropriate now. implemented in the Budget this April. If it is of a reasonable size it could make a material diVerence to Q105 Judy Mallaber: What is the timeframe between investment. I do not think it would stop investment investment decisions and prices? How sensitive are falling a bit over the next two years, but it could investment decisions, how long does it take for there certainly mitigate that and incentivise and bring to be a change in production either up or down forward some projects which would be of great help depending on the prices? not only to the oil companies themselves but to the Professor Kemp: Broadly speaking, oil companies supply chain which is now beginning to suVer from are quite cautious in the prices they use for screening lack of orders and unemployment. You mentioned investments. I am quite sure that none of them exploration. Exploration will actually fall this year would have used $100 or $140 to screen a long-term because a lot of that does come out of the cash flows, investment because we are talking about an nearly all of it actually, and they are right down investment which would last, depending on how big because of the low prices. The explorers in the the field is, 20 or 25 years if it is a reasonably sized UKCS who have been most active in the last few field and ten years if it is a very small one. That is why years have been the medium and smaller players and a cautious view is taken given the history of big they are quite hard-hit. In my memorandum I said fluctuations. The time between the investment that for those explorers who are not yet in a tax decision and getting production if it is a very small paying position there are advantages in giving them field could be quite quick, it could be one or two the same sort of reliefs as would be available to a years if it is a very small one, but if it is a big one you company that was in a tax paying position. A few and you have to have a big platform constructed years ago Norway instituted a system like that to put then we are talking about several years. the non-taxpayers on a level playing field with Energy and Climate Change Committee: Evidence Ev 19

19 March 2009 Professor Alexander Kemp existing taxpayers and in eVect the government, after because it would not only encourage extra expenditure on approved wells and exploration had production on the platform but would keep the been undertaken, would pay a share of that cost platform there as a hub? equal to the tax rate. Professor Kemp: Yes. The importance of the infrastructure of pipelines, big processing platforms Q108 Judy Mallaber: I think we are going to come and terminals for maximising recovery at lower cost on to the tax regime in a bit more detail. On that last is very clearly a major point. The infrastructure is point, is that why the Bank of Scotland invested in getting old in a lot of cases and it has to be the Norwegian Shelf recently when companies are maintained and fit for purpose over the longer term telling us they are getting problems in getting them and, therefore, will require very considerable to invest in companies here, or was there another investment. The best way to incentivise that is to get reason why they went for the Norwegian as much ongoing business as possible for these investment? pipelines, and incremental projects would play a Professor Kemp: It certainly is the case that when the major role here. We did a study on that a year or two Norwegians a few years ago introduced their ago which showed initially it would be the big incentive for new players to come to the Norwegian processing platforms that would be coming up to the Continental Shelf there were small companies based end of their lives and, of course, the host field would here who went to Norway and they could never have be near the end of its life. If you have got a lot of done it without that relief. small incremental projects all tied in, satellites tied in, you could extend the life of that platform and also Q109 Mr Weir: Just to pick up one point about the it would enable investment in the pipeline to be value allowance. You mentioned it for new fields but enhanced as well. That was a point I mentioned it has been suggested to me that something similar is earlier on, namely the way to maximise economic required to help with the older fields that are coming recovery from the North Sea is to get a very steady towards the end of their lives to make them stream of investment going. My worry at the economic to ensure the last drop of oil, so to speak, moment is if it falls down for two or more years then is taken out of these fields. Is that something you feel we could be on a slippery slope and there will not be the Government should look at? enough incentive to maintain the infrastructure and Professor Kemp: Yes. We did a study two or three then it will be too late. months ago on the mature fields that are still subject to petroleum revenue tax. That means incremental Q111 Sir Robert Smith: We should not be investments in these fields are faced with a tax take complacent either because of past lessons. In the of 75% and now that the oil price has come right past when the price dropped there was still the down that is very high, but it is also discriminatory. attractiveness of reasonable finds to keep that It is also clear from our studies that looking ahead infrastructure in place, but this time around, unless the economic recovery that we could get from the we get an incentive in there, we will not be around remaining reserves to a large extent is from existing when the recovery comes. sanctioned fields as well as from new ones. All the Professor Kemp: The need for incentive is obviously excitement is on the new ones, but to increase the stronger when the remaining fields and projects are recovery rate from the old ones, from 45 to 50 or 50 all relatively small. In my memorandum I did show to 55%, something like that, is a lot although it does a lot of new fields could be brought on-stream with not get the main attention in the media because that the value allowance even. 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 Q112 Sir Robert Smith: What sort of figure do you PRT altogether from these. There is a scheme in think the value allowance should be pitched at that existence where under rather special conditions the achieves the double-win of maximising investment PRT could be removed from such projects, but only and minimising, I suppose, the Treasury’s risk- where the incremental project is clearly separated taking? from the main field, like a satellite, for example, of a Professor Kemp: That is a diYcult one and I was a main field. We think economically that does not little coy coming up with one figure. What we did make too much sense based on the physical was to test a range of value allowances ranging from separation and there is a case for applying it to all a small one of 12.5 million per field value allowance incremental investments. all the way up to 100 and for some diYcult situations, like west of Shetland, to 250 million. We Q110 Sir Robert Smith: That goes back to the earlier found as the size of the allowance went up then you point about the future in the North Sea being small did get more fields brought on-stream. Those fields fields requiring the existing infrastructure to stay I termed were contributing to economic production there, so is there not quite a strong incentive and a because they were still paying corporation tax at national interest for the Government to see ways of 30%, they were not being subsidised or getting it tax- making those older fields more exciting to continue free. We found the numbers of fields incentivised in production? Surely some kind of incentive is a bit went all the way up and we stopped at 250. It is a easier than just stepping out into a new well and diYcult judgment because clearly the Treasury has being able to build incrementally on that platform? to look at what happens to its tax revenues. On the Would that kind of tax incentive not be a double-win tax revenues we found that the evidence was a bit Ev 20 Energy and Climate Change Committee: Evidence

19 March 2009 Professor Alexander Kemp mixed, that sometimes the Treasury would be better indicates it is extremely diYcult with present costs oV, that it gained more than it lost, although and prices, and even higher prices, and the present sometimes it was the other way around. tax regime to get a viable cluster development, which is ideally what we would like. Q113 Sir Robert Smith: Just one final thing I would like to look at is how the UK regime compares with Q115 Mr Anderson: What is the volume of the others. Obviously as a north-east MP I have had reserves out there? Is it possible to estimate that? fairly strong representations over the years that one Professor Kemp: Within a very big range. The of the downsides of the UK regime has been Department of Energy and Climate Change has constant change and uncertainty so investors have some big numbers but they are yet-to-find and quite never quite known how to do long-term planning. speculative. I do not have them in my head but they How in other ways does the UK regime compare are quite big. It is acknowledged that they are yet- with other provinces fighting for investment? to-find. Professor Kemp: Around the world we are not the toughest because the toughest ones tend to be in Q116 Mr Anderson: If the development costs are $20 countries with gigantic fields. I think the way to look a barrel, what does that equate to what you pay in at is to relate the tax regime we have to the reserves the North Sea, for example? and prospectivity and cost per barrel. We must Professor Kemp: Again, there is a range depending remember that we now are a relatively mature on where you are based in the central North Sea. In province with the average size of field of 20 million the southern North Sea it could be $12 or $15 per barrels of oil equivalent. Norway is a bit tougher, but barrel development costs and operating costs on top their average size of a new development is probably of that. about 60 million barrels of oil equivalent and they also have a number of very big ones. They are in a Q117 Mr Anderson: At the moment I understand the rather diVerent position. I would say that the oil that is being pumped out of the three fields is profitability of operations at the moment is not all going into tankers. Why could that not be continued that high. Of course, it changes if you go to $100 and if you had the field further out rather than putting artificially it looks very high for a short time and that the pipeline in? comes out in the ONS data. I think that is extremely Professor Kemp: For the gas you do need a new big misleading and does not aVect the longer term pipeline, that is the problem, and tht is very potential. expensive. Chairman: Thank you very much. Linking with the issues of investment and financial regime is this issue Q118 Mr Anderson: What sort of pipeline length? of how you develop new fields and a lot of the Professor Kemp: Eventually the gas will have to industry and, indeed, the Government are looking to come to market. The kinds of schemes that are being the west of Shetland. There is a wide range of issues looked at would initially take the gas to Sullom Voe there, not least some environmental sensitivities and, where it would be treated, the liquid separated and Dave, you want to come in on this one. then you could have a dry gas pipeline coming down to St Fergus. That is one of the schemes that is being Q114 Mr Anderson: Thank you, Chairman. looked at but, as you can imagine, that is very Professor, what exactly have we got out at the west expensive. of Shetland? What reserves are there? Professor Kemp: What we have at the moment is in Q119 Mr Anderson: In terms of supporting the production we have got three substantial fields, Government, do you think that the Treasury’s Foinaven, Schiehallion and Clair. We have got some proposed value allowance would help with this? others that look promising. There have been some Professor Kemp: If we consider that what is on the worthwhile discoveries on the gas side. We have two table at the moment is this value allowance for the or three significant gas discoveries, quite large ones, supplementary charge then if it was quite a big one and then a whole lot of small ones, over 20 for west of Shetland, given the special diYculties and altogether. The problem is to make these gas fields very high costs there, it certainly could make a commercially viable has been very, very diYcult diVerence, yes. It is a little complicated because one because of the very high costs. The development of the big factors which diVerentiate the west of costs per barrel of oil equivalent could be 20 or way Shetland is the need for a very big joint pipeline and up there. There is the problem of the infrastructure. the value allowance is not directly geared to that, it If we want to get all these gas fields developed we do is geared to the fields. need another substantial pipeline and that is very expensive as well. In terms of the economics, that has Q120 Sir Robert Smith: Just two quick questions on been a big problem that has been studied for quite west of Shetland. One is what sort of contribution some time. In terms of reserves to make a scheme would it be making to our security of supply, getting viable, things are looking a bit more promising there more gas from our fields rather than having to but the gas price, the oil price, has come right down. import from abroad? It is a very diYcult environment. That was why we Professor Kemp: Do you mind if I look at my thought there was a case for giving a bigger value research paper on that? We produced a paper on the allowance for projects west of Shetland because all contributions of the diVerent regions a little while the modelling we have done over the last few years ago. Take the case where in our modelling we Energy and Climate Change Committee: Evidence Ev 21

19 March 2009 Professor Alexander Kemp recovered by two or three fields 20 billion barrels of the banks would not finance a pipeline unless there oil equivalent, so on west of Shetland in our was pretty well guaranteed large throughput from a modelling 3.4 out of 20 from now to 2035. very big field and that was not going to be the case, so the second North Sea gas pipeline did not emerge Q121 Sir Robert Smith: So quite a substantial bonus under private sector arrangements. If you want to for the country. think more radically then there could be something Professor Kemp: Yes. That gives you a feel for what like a government guarantee to enable the banks to the potential would be. That is taking a high price take a very generous view of things. That kind of case. On the low price case a lot of these west of thing is possible but brings in the question of State Shetland contributions are not viable. That was at Aid and all of that and that would be quite complex. an $80 price case, 3.4 out of 20 billion. Q124 Mr Weir: Given we are hopefully opening up Q122 Sir Robert Smith: It is meant to be a hard- large new fields west of Shetland but we do not know nosed financial business making judgments, but yet how much oil and gas is in there, as I understand confidence and psychology seem to play a part in the it, it is mostly the big companies that are currently instincts of the industry. How much would looking there. Independents told us few of them were unlocking the west of Shetland be a boost to the involved west of Shetland at the moment. If we are morale of the province of the UKCS in terms of the talking about a hub and common structure, surely it supply chain, the critical mass, the idea that there is is essential that it is made at a size that will allow for still something bigger to play for? future development otherwise you are going to get a Professor Kemp: The way I put it is this: if we did a situation where you are doubling your infrastructure significant development going on the gas side with a causing extra costs in the long run. I appreciate what reasonably big pipeline, that would be a great you are saying, but is there anything the stimulus to all the small fields round about and even Government can do other than giving them the exploration round about because the knowledge money, which they are not likely to do, that would that there was a joint pipeline there would make a allow this to go ahead as a common resource, if you very big psychological diVerence to how people like, for developing the fields in the future? would view acreage, prospects and everything. It Professor Kemp: There are things that the would have a very strong knock-on eVect. That is Government could do. For example, if you want to be radical, they could guarantee bank loans relating certainly a reason why from the national interest to the construction of a pipeline, but that would point of view some special consideration might be involve a lot of heart searching and there would be given to west of Shetland. On my 3.4 out of 20 to questions of State Aid under the EU rules and these 2035, I would just like to add one point. That is on kinds of things to be clarified. the assumption of past trends in exploration success. If the Department of Energy is right in that there Q125 Mr Weir: One final point on west of Shetland. could be a lot more, it is just that we have not been We had the RSPB give us evidence raising looking in the right places, then that 3.4 could environmental concerns about some of the activities become much bigger. west of Shetland and also calling for areas to be closed to exploration that are important for marine Q123 Mr Weir: You have talked about the cluster life. What is the industry’s view on this point? development and this common pipeline, but, going Professor Kemp: I think the next witnesses will tell back to our earlier discussion about common you that. My view is that when it comes to licensing carriers and access to infrastructure, what needs to the environmental obligations for licensees are really be done to develop that common pipeline and to quite strong. Studies have to be done before a licence ensure that everyone developing or looking west of is given out by DECC under the EU Habitats Shetland can get access to that should they be Directive and when a company makes its proposal it successful? has to have environmental statements on how its Professor Kemp: A common carrier could be done activities would interact with marine life, porpoises, by investors themselves acting on their own and whales and all that kind of thing, and how the over-sizing it from the first fields if they were problems that might arise would be dealt with. My reasonably confident that later on more gas was view is that we have quite strong legislation in place going to be coming in from new ones. They are very to deal with that as things stand and it has actually cautious about that and that is quite risky and been strengthened over the last few years. involves a lot of upfront money. In the past we had Chairman: Thank you very much, Professor, that is lots of discussion about common carrier gas very helpful and interesting. We very much pipelines in the North Sea that were studied at appreciate you taking the time to come here and for enormous length and eventually did not go ahead. the very thorough and detailed replies to our The one in the North Sea did not go ahead because questions. Thank you very much. Ev 22 Energy and Climate Change Committee: Evidence

Witnesses: Mr Malcolm Webb, Chief Executive OYcer, and Mr Paul Dymond, Operations Director, Oil & Gas UK, gave evidence.

Q126 Chairman: Good morning, gentlemen, it is that? Do you think the voluntary Code is working very good to see you. You will be aware of the terms well? How would you feel about greater government of reference of the Committee and the work that we involvement through a common carrier principle? are doing. It might be useful for the record if you say Mr Webb: Shall we deal with that in two parts and a little word of introduction, who you are and who look at the Code of Practice first. I am lucky to have you represent. If we start with you, Mr Webb, please. to my left here one of the authors of that Code of Mr Webb: I am Malcolm Webb. I am the Chief Practice and someone who is very engaged in its Executive of Oil & Gas UK. Oil & Gas UK is the development at the moment. If I may, I will hand trade association that represents the North Sea over on the Code of Practice to Paul who can tell you industry. something of the history and what we are doing at Mr Dymond: I am Paul Dymond. I am the the moment to try and make sure that it does work Operations and Supply Chain Director at Oil & in a better fashion than it has done in the past. Gas UK. Mr Dymond: The Code of Practice was an attempt in 2004 to get the various parties together who recognised that the future of the UKCS very much Q127 Chairman: Thank you very much, gentlemen. depends on those smaller fields coming in and As you know, the Committee is looking at the making use of the existing infrastructure and all potential future reserves of the North Sea and the parties are in agreement with that. The Code of wider areas in relation to the Continental Shelf and Practice has worked well in a number of the parts factors which relate to the industry, including fiscal that we put together, in particular in terms of regimes, training and what the industry needs in providing technical information and, indeed, relation to encouraging future development and providing commercial information from deals that exploration as well as our potential reserves in have already taken place so that people have a relation to the Continental Shelf. I was very benchmark by which to assess what they might get if interested to see there are estimates from Oil & Gas they should knock on the door. The one piece of the UK that you could provide 65% of the UK’s oil Code that has not been working particularly well, requirements by 2020. That seems a very ambitious and we all recognise that, as all access to figure. How confident are you that this is achievable? infrastructure is negotiated access between the Mr Webb: It depends upon the business climate in parties we put in place a mechanism to give a which we work. backstop to that negotiation in the event that it did not come to a conclusion on its own. The backstop was eVectively for the party wanting access to make Q128 Chairman: I thought you might say that. use of the existing legislation and ask the Mr Webb: Given the right political and business Department for a determination from the Secretary climate, of course, we can achieve that. That is not a of State. It is that piece that is not working blue-sky number. That is not something we picked particularly well. I think the key issue there was if out of the sky but is actually a number that comes you were going to ask for that you needed to have from sustained investment of the sorts of levels that confidence that you were going to get an answer that we have been seeing over the last few years. It is not was both workable in the longer term and available an overly ambitious target in that sense. It does, to you within a useful timescale and it was however, depend upon the right business and comprehensive enough that you could make use of economic climate and, as you know, at the moment it. There have been question marks over all of those this industry, like all other parts of British industry, things, which we have been working on. I have to say is facing some particular challenges. We have the we were actively looking at this over the course of the double-whammy of the global recession and the back end of last year and still are looking at how we banking crisis and that is causing some problems at can move this forward. It is very much a work in the moment. As you heard from Professor Alex progress. There is a broad spectrum of companies Kemp just a moment ago, it is important that some involved, members of Oil & Gas UK but also OGIA steps are taken rather urgently now to maintain the and obviously the Department, looking at how we pace at a reasonable level over the next few years can make use of the legislation to have a backstop to otherwise those targets could become unachievable negotiations that people can have confidence in. and that would be disastrous for the country. That is not just about how does the process work, Chairman: We will be coming on to the current although it is very much about that, but it is whether market conditions in a moment and exploring what we think the legislation is eVective and may or may your views are on that. not need amendment. As you are aware, the Energy Act made some amendments to the legislation and Q129 Mr Weir: You heard the discussion we had tightened up some of the holes that were in there, but with Professor Kemp regarding the question of the whether it needs further amendment, that may come shared infrastructure and Oil & Gas Independents out of the discussions. told us they felt they faced problems accessing infrastructure controlled by the larger companies Q130 Mr Weir: Have there been any negotiations and the voluntary Code was not working that have stalled and are unable to get to a particularly well. Do you have any comments on conclusion? Energy and Climate Change Committee: Evidence Ev 23

19 March 2009 Mr Malcolm Webb and Mr Paul Dymond

Mr Dymond: Yes, there are a number. There are a and the Government is working determinedly on number that have gone forward, deals are being this too, to work together to make this existing done, but at this current stage in a mature province system work better. I think we can do it. there are both complex technical issues associated with some access requirements and commercial Q132 Mr Weir: How about the new fields west of issues. If there is very little value in the field and you Shetland? Has thought been given to the hub system have to provide a service then there is maybe not that Professor Kemp mentioned and the common very much money in terms of whether that is pipeline to allow development of those new fields? suYcient to make that work well and incentivise Mr Webb: Again, it is a complex issue. There are people and keep the infrastructure going for the some developments that could go forward there. Do period. There is a commercial issue in terms of where you saddle those developments with the incremental the boundary is in terms of sharing the rent of a new cost of a common carrier pipeline that could sink the field coming in, but there are also technical issues economics of those developments? I think the that have to be addressed as well. It is a very answer to that is no. There is a gap there that needs complicated area, which is why it depends on where to be filled if you want to do the common carrier. that negotiation stalled as to how you view it. Who is going to pay for that? I do not think the Government is going to pay for it in the short-term. The best answer for the west of Shetland is to go Q131 Mr Weir: Is that not likely to become an back to look at some of the fiscal incentives that we increasing problem as the smaller fields that are can put in place to make sure we get as much as we being developed are trying to use the existing possibly can on the back of the existing infrastructure? Is that problem not going to increase development, which means improving the unless it is sorted out fairly quickly? economics of the development. Mr Dymond: Yes, but how do you sort that out. If you look to the Secretary of State to do the Q133 Chairman: You emphasised the cost of a determination then you need to be assured that potential common carrier development west of process can happen and will come out with a fair Shetland, but is there not an advantage if you had answer at the end of the day for all concerned. As I some kind of hub system where you may share some say, the small independents have been part of the of the services those could be shared amongst V conversation and everybody is in agreement that if di erent companies and the costs could be shared, somebody is providing a service then there needs to and also other companies could possibly go into the be remuneration for that and coverage of the hub and the costs would fall on them but bring down incremental costs. It is a matter of that balance. In the overall cost of exploration? Is it all one way? Are some instances there is no deal to be had and in some there not cost benefits from this? instances there is but it is very diYcult to get to a Mr Webb: In the long-term you can see the conclusion. That is what the Code is meant to do. advantages of scale that could come from that, it is a question of how you get there and who is going to Another piece that has been working in the Code, finance that capital until those other fields come in and we are working very hard within Oil & Gas UK, because, as Professor Kemp said, there is an awful is about behaviours, responding when people ask, lot of exploration activity that needs to go on in the being responsive in terms of progress. The Code very west of Shetlands yet, it is still in the frontier areas, much talks about behaviours. We created guidance so who is going to bridge that gap. If you put the cost notes on how all the parties can make the Code work of that down on to the first developers past the post best for them and we are running a series of training they are likely to sink and then we will not get those courses to allow negotiators to get a better feel for either. It is a question of who finances that. V that. All of this is making a di erence. It certainly Chairman: Can we look at some of the issues of the V made a di erence very quickly in 2004 and there are current market conditions and explore those for a indications that it is making a diVerence with the moment. extra focus that we have put on it over the last six to nine months. Q134 Judy Mallaber: If we can look in broad terms Mr Webb: I think it is fair to say that everybody is at market conditions before we then move on and determined this Code should work and work better look at the fiscal regime. In broad terms is the price than it has done. There is no denying it has not of oil in your view the single most important factor worked as well as we hoped it would when we put it in the current market conditions faced by your in place in 2004. In part that is because of the sort of companies? regulatory back-up available and a lack of Mr Webb: I do think it is a very important issue, but conviction within the industry, frankly, that it would it is not the only one. As I said before, right now the ever be operated. I think these new amendments we industry as we speak is beset by a double-whammy are putting through will be to the good and that is the of the recession which is feeding through into this right way forward. You mentioned the common lower oil price and also the banking crisis which is carrier system and retrofitting common carrier causing problems of finance throughout the industry arrangements onto these existing pipelines is going at all levels. By the way, there is another thing I to be hugely complicated, hugely expensive and I would like to say in parenthesis, and I hope we get cannot believe is the right way forward. The best round to it eventually: this industry is not just about thing to do is for the industry and the Government, producing oil and gas, it also is about a fantastic Ev 24 Energy and Climate Change Committee: Evidence

19 March 2009 Mr Malcolm Webb and Mr Paul Dymond engineering success story that is based here in the right now I do not see too many of the super-majors north-east of England that is doing six billion a year that have got a problem on cash flow; they are in export business across the globe and has got relatively well financed. At the other end of the scale, fantastic potential for growth. That is the other side however, you have got the small companies that the of this industry that we can sometimes forget about Government’s policies over the last ten years have and we really must not forget about it. To come back very laudably brought into this basin and we to your question, the price of oil is definitely a very certainly need them. One little factoid: last year 80% important factor at the moment but so is the seizing of the exploration expenditure in the North Sea up of the banking system and the fact that small came from small companies. They are part of the companies, for example, find the equity markets important lifeblood of this basin now. Those small closed to them. It is not all about debt, it is about companies have real problems in accessing debt and equity as well and they are finding the equity markets that is all to do with the banking crisis and the fact closed to them. They are also finding the debt that equity markets were shut. You do not, by the markets closed to them for their development work. way, finance exploration wells with debt, you cannot That is feeding through into very conservative get anybody to lend you the money for that, they attitudes necessarily by some of the medium-sized would be mad and you would be mad to loan money players as well. In previous recessions when there has on that, you have to do that with equity capital, but been a problem on the price you may have been able those markets were closed to these small companies. to look at the banking system as a sort of back-up Also, those small companies are finding it and support but, unfortunately, it just is not there at exceptionally diYcult to get project financing now the moment it seems and, therefore, people are from the banking system and we saw, for example, adopting very conservative attitudes towards their only last month RBS announcing that it had capital investment programmes in that knowledge. withdrawn from project financing. There is a If you like, they have to live oV their kill, they have problem there for those companies and that is access to live oV their cash flow and have to take a to debt and access to capital. That is where our conservative attitude towards that cash flow. The proposal for those small companies is that the banking crisis is causing this problem and then you Government can do something, it can release equity have this low oil price which is depressing the cash capital to them by releasing this pool of exploration flows and all of that is repercussive, it interacts with reliefs which, by the way, are accruing on the one another, and therefore we have quite a serious Government’s books at 6% per annum which I situation facing us at the moment on which the would have thought is massively in excess of the Government really needs to act. The final part of the Government’s cost of capital, so the release of this equation is costs. As you heard from Alex Kemp could almost be of benefit to the Government. They earlier on, over the last four years we have seen an could release those exploration reliefs to those small explosion in the costs in our industry and that is a companies, give them some capital to get on and drill global phenomenon, not something that is just in the some wells and also give them some capital to UK. It will take some time for those costs to come leverage some debt for the development as well. That down but that is the other area we need to work on. is what should happen for them. That is the problem I would not want you to think that this industry is they have got. If you go to the medium-sized looking just to the Government for help on this; the V V companies, they have a di erent problem. They have industry is going to do its own stu with some self- a little problem that I would say is lack of confidence help measures that it definitely needs to pursue in the that the banking system is there for them. These are areas of cost and also needs to make sure it does not well-run, conservative companies so they are not make the banking crisis worse, but we do need some going to take risks with their finance and, therefore, help from the Government now as well and rather they are living within their cash flows. Their cash urgently, frankly. flows are constrained because the price of oil and gas, importantly gas as well as we have heard, is Q135 Judy Mallaber: Can we unpick a few of those down at the moment so they are living issues before we move on to what the Government conservatively within those cash flows and the result might do? What you are saying reflects very much of that is capital expenditure is being cut. There the what the Oil & Gas Independents’ Association told solution is trying to unfreeze and bring more us about the problems smaller companies are having confidence back into the banking system for those in getting access to finance. You also mentioned companies and I guess the answer for them is no medium-sized companies. What kind of diVerence is diVerent from the rest of British industry, it is what there in the factors that are aVecting larger large parts of British industry are calling out for. companies from the smaller and medium-sized That is their problem. The majors do have a problem companies? Is there a diVerence again in relation to and so do some of those medium-sized companies those companies you are talking about in relation to and in typifying these companies in this way there exports and the supply chain? Are they aVected are cross-overs. There are some small companies diVerently or are the factors very similar in relation that have got very strong cash flows and are not so to access to finance? reliant on the banks and there are some medium- Mr Webb: They are aVected diVerently. In terms of sized companies that have got very strong positions oil companies, and I do not wish to be over- as well, but there is a contagion problem. As you simplistic, we should divide them into three know, in the North Sea we work in joint ventures groupings. The first is the super-majors and, frankly, everywhere, that is the way we share risk, so if you Energy and Climate Change Committee: Evidence Ev 25

19 March 2009 Mr Malcolm Webb and Mr Paul Dymond have got a party who is a small party, maybe a field international competitiveness. The UK oVshore has development, who cannot get the access to the no God given right to development finance, it has to finance that, if you like, is a contagion to the whole compete with other basins around the world, project and the project is slowed down and does not including the Norwegian basin. The issue for this go ahead. Even the projects in the companies that basin is to stay competitive and as a mature oil can aVord to do things are being slowed down at the province that presents a number of particular moment because of this problem in the capital challenges for us. Yes, financiers and investors will markets. I am sorry, that is rather complicated. look right across the globe for opportunities to invest in oil and gas and what we have to do is make Q136 Judy Mallaber: No, that is very helpful. Some sure that the UK has got a compelling case for them of the problems you have described there very to come and invest here, but at the moment I am not graphically, which I understand, are very similar to sure that is true. those that, as you have said, are common to small and medium-sized companies in my constituency, at Q138 Sir Robert Smith: I should declare my financial least one of which is in your own supply chain as it interest in the Register of Members’ Interests that I happens. Is there any reason why your industry am a shareholder in Shell and also as Vice-Chair of should be given special treatment as compared to the All-Party Oil and Gas Group we visited ONS in other sectors I have where the equivalent to the fall Stavanger funded by the oil industry. On that point in the price of oil, which is your additional problem, about the engagement of Government and the for them might be a fall in general trade? Overall, is industry, perhaps you could confirm the big there any reason why your companies should be V V di erence between this industry and many other treated any di erently or more favourably than, say, industries is the product, the oil and gas, belongs to companies in any other sector? the nation and, therefore, by definition the nation Mr Webb: I think this sector has got some particular and the Government are going to be tied together issues around it that do deserve and warrant special because without the industry the nation gets no attention, yes. Again, it goes back to what you heard benefit from the oil and gas and without access to the from Alex Kemp in his evidence today. Frankly, we oil and gas the companies get no benefit. In a sense, are on something of a treadmill in the North Sea. when you are calling for assistance to see you Unless we keep the projects coming through and, as through the crisis it is assistance for the benefit of the he mentioned, it is about 20 a year that we need to country and your members, is it not? keep coming through as a minimum, that Mr Webb: Absolutely. I do believe that the industry infrastructure which Mr Weir was talking about will become decommissioned because it will not have a and Government has got a common cause here, we useful economic life. If that happens then we have both want the same end, which is the maximum ultimate recovery of reserves for the nation from the got a major problem in recovering what we think is V up to the last 25 billion barrels of oil and gas yet to UK o shore areas. be got from the North Sea. We have to keep this industry going forward. If there is a sudden and Q139 Sir Robert Smith: You represent the supply dramatic collapse now that could have an impact chain as well as the actual investors. Are those of upon the infrastructure and it could also have an your members who are still in a reasonable situation impact upon the capability of this industry as well. with their cash treating their supply chain in any way You could well see capacity exported from Aberdeen to keep them going through the crisis by paying Y and once it is gone it might be di cult to get it back quickly or anything like that? here. It is hugely important we keep it going. The Mr Webb: Yes. I am aware of individual cases but I other point I would like to make is this industry is could not go into those now. There is a responsible not asking for any cash handout, bailout or subsidy attitude there. As a trade association we are taking from the Government, it is not asking for that at all, steps to make sure that we do approach this in a but it is asking that the fiscal regime is readjusted, responsible way. For example, one way we can make and it does need to be readjusted in any event in our the credit crunch worse is to lengthen credit periods view, for this mature oil province in general terms within our industry. We have adopted a Code of but there are some specific things that need to be Practice for all invoices to be paid within 30 days. It done now and we have made them very clear to the Treasury. is absolutely vital that people stick to that at the moment. Shortly we will be launching a new helpline to reinforce that point and make sure the industry Q137 Judy Mallaber: We are going to come on to does stay there. There are a number of self-help that. The money that the Bank of Scotland was measures that we are taking within the industry at prepared to put into the development of the the moment to make sure we do not make matters Norwegian bank, was that just to do with their worse, which I am afraid is happening in other parts financial regime or were there other factors as well? of the industry. Why were they prepared to put money in there when, as I understand it, some of your companies are finding it extremely diYcult to get any money? Q140 Mr Weir: One other point we have not covered Mr Webb: I could not comment on the individual in this is as well as the problem with credit there is the business decisions of the Bank of Scotland but I rising cost to the industry. You say that last year the think you make a very good point here. The issue is cost of developing and producing a barrel of oil or Ev 26 Energy and Climate Change Committee: Evidence

19 March 2009 Mr Malcolm Webb and Mr Paul Dymond gas rose by 12% compared with 2007. Why have and you need to do it urgently now with the fiscal costs risen so dramatically over the last few years system and with regard to helping these smaller and do you expect them to start falling? companies. Mr Webb: With regard to the second point, yes, I do expect them to start falling and there are signs that Q142 Mr Weir: Is the pressure on the oil companies they will fall. We need to be careful about not to reduce cost feeding down to the supply chain and believing that is going to happen overnight, it will be what eVect is it having? The SCDI and Scottish a slowish process and that is what history tells us, Enterprise produced a report a few weeks ago saying that when we have been through these periods of the supply chain was £14 billion but that was only up recession before it will take some time for the costs to the end of 2007, if memory serves me correctly. I to come down, and we are working on that. The just wonder what impact the decisions taken by your whole of the industry is taking a responsible attitude members in exploration and development are going towards that. Why did they go up? They went up to have on that supply chain within the next couple because there was a global pressure on the system to of years given the current economic situation. find and bring more oil on to production. Mr Webb: There are two issues there. Is the supply Furthermore, you will recall a few years ago V chain reacting to cost? Yes, I think it is as best it particularly for the o shore oil and gas industry we reasonably can. Remember, a number of these rates had some particular events in the Gulf of Mexico are locked in and it would be a noble thing for some with hurricanes taking out an awful lot of capacity people to give up contractual entitlements on rates, there as well. It was a mixture of global pressures and so it will take some time for some of these rates to a need to go and find oil and gas combined with some come down. I am seeing a lot of responsible actions physical problems that happened that took out an within the supply chain on that. You are right, there awful lot of capacity. Those two things combined is also pressure from the employing companies on gave rise to inflationary pressures on the industry costs and everybody is doing what they can to get and that was where we saw a great increase in the that message across within the industry,that we need costs, particularly in the costs of mobile drilling to get to a diVerent place on cost, but it will take us vessels, for example, supply boats and support time to get there. On the worst case, if we saw capital vessels which were in short supply. investment fall by two and a half billion over the next two years we are going to see 50,000 people lose their Q141 Mr Weir: That takes us on to future jobs, that is one of the impacts on the supply chain investment particularly in the North Sea. Have the that will happen and that will be very, very serious. companies you represent begun to scale back investment in view of the current economic situation Q143 Mr Weir: I was going to ask you what the and what do you expect the trend to be over the next Government could be doing to facilitate investment couple of years? but I think you told us that pretty comprehensively Mr Webb: That is a very good question and it maybe earlier on when you talked about the tax regime. goes to the heart of our discussion today. In some Mr Webb: Yes. It needs to do three things and they ways this is quite a simple business. The success of are all sort of interlinked in some way. It needs to the North Sea or the UKCS oVshore generally help these small companies by releasing these comes down to attracting and spending capital. You exploration pools that are accruing at 6% cost to the will have seen from our report that we believe, going Government, so that should not be too much of a back to the Chairman’s original comment about the problem for them I hope. The second thing it needs 65% of our oil supplies in 2020, if we can keep capital to do is really take supplementary corporation tax investment coming through at the sort of levels that oV new developments. As you heard from Alex we have been having of late, round about five billion Kemp, we need some very clear messages on that. It a year, then that is achievable. That is the core of it. is quite clear that Government recognises the What is happening at the moment, for the reasons I problem here. This value allowance is not the explained a moment ago, is across the basin there is industry’s suggestion, it is the Government’s a problem in getting that capital through the system. suggestion, that was where it came from. It came out For the first time ever, in our activity survey this year of discussions we had at the beginning of this year we gave a range of possibilities on the capital when the oil price was in a completely diVerent place, expenditure for this year and that reflects the so if it was valid at that oil price it is doubly valid uncertainty within the industry as to what is going to now and needs to be much more potent now than it happen and on the worst of those range of was then to help with these short-term problems. possibilities we are saying that over the next two The third issue is there is a problem around years capital investment could halve to two and a decommissioning costs and the securitisation of the half billion from the current five billion. We think the decommissioning costs. Because of the way that it answer, hopefully, is not going to be as bad that, that has set up the tax regime, the Government is is an awful lot of jobs lost if we get there besides the eVectively requiring companies of all sizes, small, impact it will have upon the ultimate recovery medium and large, to make security provision for picture. We hope that can be mitigated. I am sorry to 100% of the eventual decommissioning costs of these sound like a chipped record but that is why we are fields. That is an unrealistic number because that is saying to the Government strongly there are things a tax deductible expenditure, therefore why are that we in the industry need to do but there are things companies being asked to make security for 100% of that you, the Government, desperately need to do the cost when actually at least 50, if not 75% of the Energy and Climate Change Committee: Evidence Ev 27

19 March 2009 Mr Malcolm Webb and Mr Paul Dymond cost is going to be a tax deductible event. That is and now we are seeing things that were being putting strain upon the industry.By the way,it is also discussed in a calmer environment being needed as putting strain upon the banking system right now. tools to rescue things in a really quite serious As a little aside on that, we have got, and our situation. Do you think there needs to be that extra Association has been at the forefront of developing incentive to get those hubs protected by encouraging this with then BERR, now DECC, decommissioning incremental investment on them? arrangements or agreements and those set out how Mr Webb: Yes, I think there is a case for saying all we can cope with all of these problems and they rate new projects is what we should be stimulating now. the securities that can be provided. Bankers’ letters If we go back to that point, we need to be sending a of credit seem to be the instrument of choice of the very clear signal that this mature UK oVshore Government and also of parts of the industry as well. province is a competitive place to come and invest in Unfortunately, the number of banks that now pass and it is active and open for business. The industry the credit rating for those bankers’ letters of credit can do its part on that but, frankly, as we said in our has fallen, including the market leaders in that area, submission, we have a fiscal regime that is no longer and people are seeing the credit rating of the Royal fit for purpose and it needs to be changed rather Bank of Scotland has fallen and it has taken them urgently. out of the banks that qualify for that. That whole area of security for decommissioning also needs to Q147 Sir Robert Smith: We are a new Committee be looked at and needs to be looked at urgently. because there is a new Deprtment and all sides have Chairman: This is clearly all part of the fiscal and welcomed the fact we now have a Secretary of State regulatory approach. who is a champion for energy and climate change and that is bringing together two departments that Q144 Sir Robert Smith: You have made a strong case should be together. that with extra incentives there is a rosier future, Mr Webb: We lobbied for it. I cannot say that we more jobs sustained, more energy supply and more aVected the result of it! long-term tax revenues. Have you thought about what level that value allowance should be pitched at Q148 Sir Robert Smith: You have expressed concern to make a meaningful diVerence to future about it being under-resourced and you think the 60 investment? million from the licence fees should be doing more to Mr Webb: High. As high as possible. I think it give resources to the Department. What are the should be set at such a level that it takes problems you are experiencing because of what you supplementary corporation tax oV. There is a see as under-resourcing? problem here as well. You may have heard some very Mr Webb: I have to be careful here. We deal with a big numbers being floated around and you need to lot of very dedicated, hardworking civil servants and be careful about that. You need to set the value I would say we see them working too hard these days allowance so high to produce an after-tax eVect that really. The system feels like it is under strain and is quite restrictive really. I would not want anyone to under stretch. There are a few people we deal with think that when Professor Kemp was talking about and we see them having to deal with everything more 100 million or whatever that means there is 100 or less and I do think there is a problem. I cannot million of value allowance going to be paid to oil quote you figures, but I think there are unfilled companies, it does not work that way. I think 100 vacancies within the oil team and I have concerns as million produces an after-tax eVect of about ten to the resources that are available to that team. I also million. That is another issue. We did say to the have another concern that with the splitting out of Government that the value allowance is not our this new Department we are now going to have preferred way of dealing with this because we think another departmental bureaucracy put on top of it adds further complexity to the taxation system, that Department and I hope they are not playing the but they have persuaded us that is the only game in zero sum game and we find more resource is taken town and that is why we continue to talk to them on away from the front facing people within the that and we want to be as constructive about it as we Deprtment and goes back into the bureaucracy. You can, but it should be big. mentioned the 60 million number and I do not know if you saw it but last year The Guardian produced an Q145 Sir Robert Smith: You are engaged in excellent chart showing what total Government negotiations on bringing forward the exploration expenditure was on a departmental basis, a total of relief to try and get the cash flow to smaller 586 billion for the year 2007, and when you looked companies sorted. at BERR, the Department for Business, Enterprise Mr Webb: We certainly are, yes. and Regulatory Reform, which was where energy was before, the total spend was 8.3 billion but 7.3 Q146 Sir Robert Smith: On the narrow question of billion of that was going to nuclear whether there should also be incentives for decommissioning. When you looked further down incremental developments on existing hub you saw that energy supply and clean energy was a platforms, a lot of this tax consultation discussion total of 0.068 billion, which is 68 million, which did started in a diVerent climate where there was a not seem to me to be an awful lot. That is why we are recognition by Government and industry that there interested in that 60 million number. It looked like were smaller fields, cost challenges and so on, but the the licence fees being paid for the North Sea were snowball increased in size as the credit crunch hit financing the whole of the energy section of BERR Ev 28 Energy and Climate Change Committee: Evidence

19 March 2009 Mr Malcolm Webb and Mr Paul Dymond and I do wonder what is happening within DECC. them, so we believe up to a billion barrels of oil and We support DECC, but DECC has got to be able to gas are threatened by this. However, there is some deliver and has got to have the right resources to good news. As you may know, the EU has a trade do that. intensity test linked to the carbon leakage and it is very clear, and we have agreement with DECC on V V Q149 Sir Robert Smith: One other thing on the new this, that these o shore installations of the o shore Department and its role. One of the jewels in the oil and gas industry qualify for that. That resolves crown of the North Sea has been the huge expertise some but not the entire problem. It resolves half of built up there that has now earned a worldwide the problem because the emissions relate in part to reputation and a big export market, so there are the electricity generation but also to other direct power V jobs that have come on the back of the North Sea, uses o shore, so we are still left with half of the we get the security of supply and the tax revenues problem and we believe we need to find a solution to and the jobs, but do you have any concern that when that other half too. To use that carbon leakage term, energy was in BERR it was in a department that was this is pure carbon leakage. If we do not produce this also thinking of economic development and jobs? oil and gas from areas around our shores we will Do you still feel that there is a champion within have to import it from elsewhere and assuming we Government for that export, skills and jobs side of achieve all of the Government’s renewables targets, the industry and the benefit that brings to the which we hope we do, we know, for example, we will economy? still be reliant on oil and gas for 70% of our primary V Mr Webb: That is a very good point and I am not energy supply in 2020. The UK o shore, I am sorry sure that we have linked up correctly with that yet. I to say, will not be able to meet 100% of that but it is think it is in BERR, but we have not found it yet and vital we close that gap as much as we can, both in we should find it. You are right, there could be a terms of energy security and also for the economic diVusion of attention there as well. I was surprised to benefit of this country because that is an awful lot of see the other day that there is an energy section still expensive imports. within BERR, I am not quite sure what it is doing but maybe that is the section we go through and look Q152 Chairman: It certainly is. for some help on that. Mr Webb: That is the issue there. We have no problem with ETS, no problem with a sensible cost Q150 Chairman: Can I press you on one point in of carbon, that is going to be vital to drive some of your submission about the EU ETS? You expressed the environmental investment that needs to happen, concern that the next phase could reduce and no problem with CCS, CCS is an area of production, presumably because of the auctioning? opportunity for our industry, particularly the supply Mr Webb: Yes. chain, but there is a specific problem around ETS Phase III which the Government is fully aware of. Q151 Chairman: First of all, do you not think Chairman: Can I just touch upon the issue of auctioning is the fairest way? Secondly, do you not environmental impact. The industry is well see that there are potential benefits from a rise in established and, generally speaking, its record has carbon prices, particularly in terms of driving a been pretty good on environmental management number of changes in production methods and also but, of course, as you push out into the undeveloped the potential for CCS storage in the future? areas, particularly into the west of Shetland, Mr Webb: Yes, yes, yes, and yes. I agree with deepwater, extreme weather, there are concerns everything you have said. ETS is a good mechanism about the potential environmental impact and also for dealing with this sizeable problem we have and in relation to sensitive areas. David wanted to ask a we need a fair price on carbon. If you do not get a question on that. fair price on carbon then you can forget the CCS because it is only a fair price on carbon that is going Q153 Mr Anderson: The various environmental to drive the CCS. We have no problem with that and bodies have told us that regulation control is as an industry we have never had any problem with generally good but sometimes compliance is not, do ETS. Gas flaring, for example, is within the ETS system and we have no problem with that either. We you accept that? are not anti-ETS. This is a slightly more diYcult Mr Webb: I would have said that levels of industry-specific issue. There is no alternative but to compliance within our industry on environmental generate our electricity oVshore in these platforms issues are pretty sparklingly good, frankly. and using the resources that are at hand, which is the gas and the production on the platform. It is Q154 Mr Anderson: What procedures have you got impossible to think of retrofitting new equipment on in place to make sure that they work? V to these old platforms. If the o shore industry is Mr Webb: Do you mean self-policing it from an required to buy all its allowances for that electricity industry viewpoint? generation then on our estimation operating costs are going to increase by between 20 and 40% on platforms oVshore and that will give rise to the Q155 Mr Anderson: Yes. premature decommissioning of some of those Mr Webb: We do not double up on the work of the platforms. When those old hub platforms go then regulators, we help the regulators who are doing that will take out satellite production from around that, but we do keep an open dialogue with Energy and Climate Change Committee: Evidence Ev 29

19 March 2009 Mr Malcolm Webb and Mr Paul Dymond regulators right across the piece and try and make Kemp said, we are not too sure what is out there. We sure that we are as constructive as we possibly can be carry a number that is remarkably similar to his. We in these areas. think there is potential for about four billion barrels out there, which is a substantial prize. There have Q156 Mr Anderson: Is complying with regulations a been some developments out there and there have burden on the industry? Is it driving people away also been setbacks. After the initial discoveries I from investing in the UK? think people thought we were going to be into the Mr Webb: Is it a burden? Of course it is a cost, but I new Klondike and there would be discoveries made do not think there is anything we would point to everywhere but progress has been somewhat slower where we would say because we have got these than that. In terms of barriers, I think we have got environmental regulations people are not coming to to look at challenges on the one side which are all to invest in the North Sea, no. do with geology, physical location, the engineering challenge, the volatility of the commodity price Q157 Mr Anderson: In terms of the itself, the skills and development challenge. All of decommissioning process, what challenges do you those I think the industry can manage. Currently face there? there is something of a barrier that can be lifted, and Mr Webb: The challenge is to try and postpone it for it is a fiscal barrier, and that is within the purview of as long as we possibly can actually and keep this the Government and that is what we need to see infrastructure in place so that we can get the 25 happen, positive encouragement for people to get in billion barrels recovered. That is the first and and take the risks in the west of Shetland, the foremost challenge. As to the other challenges, I exploration and development risks. think we are well up to them. We have got a magnificent supply chain here and we have the confidence and capability to do it. Some of this Q162 Mr Weir: Given the volatility of the price of oil decommissioning is already going on, by the way, we at the moment and its level at $40 a barrel, does that are not complete novices on this and I have every make development west of Shetland currently confidence that we can deal with the issue. The economic? problem around decommissioning is the way that— Mr Webb: As Alex Kemp said, this industry has to I do not want to sound like I am kicking the take a medium-term view upon oil price. I can assure Government all the time on these tax— you nobody did their economics at $140 and people do not necessarily always do their economics at $40. Q158 Mr Anderson: We are used to it! $40 can have an impact upon cash flows, it can have Mr Webb: —the decommissioning regime is based that sort of immediate impact and, therefore, knock upon some false premises. It is relying upon two through on capital that is available for development. things. It is relying upon corporate governance and You can take your view upon the oil price, and I bankers’ letters of credits. If the banking crisis would love to give you my prediction for it but it is teaches us anything it is that is not where we should very personal. be and we need a new system whereby we can have properly established retirement funds for these assets financed on a post-tax basis. Q163 Sir Robert Smith: It is also the gas price. Mr Webb: You are quite right. As Alex said, please Q159 Mr Anderson: The RSPB have told us that they look at the gas price, 30 pence a therm, and the would like a better survey of seabirds and wildlife, forward price is not much better either. Those sorts particularly west of Shetland. Is that something the of levels would not be good but I personally do not industry would support and, if it supported it, would think that is the long-term view and that is also why it help to fund it? it is hugely important that this country does unlock Mr Webb: The industry has had a good track record those reserves. Frankly, I think the oil price will rise. of working with the RSPB upon surveys in the past. I do not think the world is replete with immediately We have got a lot of data and we would be very available sources of oil, therefore I think the price happy to share it with them and talk to them about will rise and people will be planning accordingly. that issue. You did say support it and not fund it.

Q160 Mr Anderson: I said support it and fund it. Q164 Mr Weir: When we heard from the Mr Webb: We are not the only users of the oVshore environmentalists they were suggesting that there and I think that is probably the sort of thing we should be certain excluded areas, for example should talk to all oVshore users about. around St Kilda and the Hebrides. Do you think Chairman: Can we just turn to west of Shetland and there is a case for doing so? the potential that there is there? Mr Webb: We would have to look at every case on its merits, but hopefully what we can come down to Q161 Mr Weir: What is the potential to exploit is there is a question of balance here. We are looking reserves west of Shetland and what are the main for a sustainable future for our economy and that barriers to exploiting these reserves? involves issues that are economic, social and Mr Webb: I am not sure they are barriers, they are environmental, so it is a question of looking at challenges. This is in deeper water, more hostile particular cases and drawing the right balanced territory. It is exploration territory as well. As Alex judgment. Ev 30 Energy and Climate Change Committee: Evidence

19 March 2009 Mr Malcolm Webb and Mr Paul Dymond

Q165 Sir Robert Smith: Do you share Professor base for people solely employed in decommissioning Kemp’s view that if you could unlock the west of the infrastructure rather than using the workers who Shetland the psychological boost is quite an do it now? important added bonus for the whole province? Mr Webb: I think on that point it is diYcult for me Mr Webb: Yes, I do. The industry is looking for a to think that we should construct a separate industry signal from the Government at the moment. Both called the oil and gas decommissioning industry. west of Shetland and generally they need to pass a That is a question for the supply chain. I think the clear signal that it does value this industry, that it supply chain has got the ability to expand into that sees the need for it and it will do the things that are and deal with that. My view on that would be it is a needed to make this basin competitive. question of building on the expertise that is already there and going back to address this market. Mr Dymond: There are also a lot more jobs involved Q166 Sir Robert Smith: I suppose one other thing is in maintaining and operating than there are in there is a certain economic value out there in the decommissioning. Decommissioning is very much a North Sea and some profits to be made by the non-productive spend, whereas if you were taking companies and tax revenues to be gained by the that same money and putting it into new investment country. There are also costs to be put on because of then you would be developing new reserves, with environmental, welfare and safety concerns. In the more jobs and more tax revenues. end, is this a simple trade-oV that if we as a society recognise the need to put more costs on the industry we have to accept that we take less share of tax out Q168 Mr Anderson: It has got to be done eventually, of the industry? has it not? Mr Webb: Yes. Mr Webb: Yes. Also, I think that we as a society have to understand that getting those extra barrels is going to be a more diYcult and costly event Q169 Mr Anderson: In a sense it will be probably a generally in the economics of the basin too and, relatively less skilled job. therefore, I do not think we should have overblown Mr Dymond: Not necessarily. The technical aspirations as to how much practically we can get challenge for decommissioning is actually to do out. I think that is part of the problem. I fear we are what we need to do cheaper because it is a non- in a regime at the moment that is looking to productive spend. That is where the challenge is and maximise short-term fiscal revenues and may be that is what we are looking for the supply chain to overlooking the potential for long-term economic develop, the capabilities to be able to reduce the cost benefit. The economic benefit here is very of doing what we need to do. That is the challenge substantial. We say there are 25 billion barrels of oil there. and gas yet to be won. Plans that we can see in place at the moment have got around ten billion of that Q170 Chairman: And the skills situation? within their view, but there is another 15 billion Mr Webb: Somebody said the other day, and I think beyond that. If you valued that at, let us say, $100 a we have to bear this in mind, that tomorrow has not barrel, which in the future may not be such a silly been cancelled, and this industry has got a huge thing, that is $1.5 trillion of economic benefit to tomorrow ahead of it. We must keep up our eVort on this country. skills and training. We must continue to bring new Chairman: I would like to conclude on the issue that people into this industry. I think it is almost you raised on the skills and the exports, £6 million of inevitable we are going to see some job losses over exports, the skills centres that we have in Aberdeen the next year or two, that is almost bound to happen, and, indeed, other parts of the country. I will just but I do not think that should be an excuse for us to take questions from Judy and Dave and you might say, “Well, hold on, we are now going to stop like to answer them together. training people, we are going to stop investing in Judy Mallaber: I am slightly curious. Your written skills and bringing new talent into this industry as evidence refers to skills shortages in the industry but well”. I know that is a diYcult equation at times but now we are told it is turning into a skills surplus. A we must keep it up. I think if there was a lesson that few years back I recall after 9/11 when Rolls-Royce we learned from the last time we went through in Derby, near my constituency, was going through a something similar to this, although it was not the bad time it was suggested to me that there had not same because we did not have the banking crisis, it V been enough training in the oil industry and it would was that some of the skills loss that we su ered as a be an ideal place for the skilled Rolls-Royce workers result of that took us several years to overcome to get jobs. Was it unfair that there had not been the afterwards, so I think there is a new resolve in the training at that time and have you had to set up industry for that not to happen. That is why we do OPITO to deal with that? Where has it left you now take this very seriously and why we did back OPITO in terms of skills shortages or skills surpluses? Does and are financing OPITO and it is why we run one of it leave you with a good base for export of skills and the most impressive modern apprenticeship schemes so on? with hugely successful retention and employment rates and with very well paid people coming out of that too, by the way. That is the other point about Q167 Mr Anderson: Is there any potential for this industry. The average salary in our industry is expanding the skills, coming back to £50,000 a year paying £20,000 NI and tax as well. decommissioning, that you could build up a skills The people who come out of our modern Energy and Climate Change Committee: Evidence Ev 31

19 March 2009 Mr Malcolm Webb and Mr Paul Dymond apprenticeship scheme aged 22, highly qualified be a slacking oV from the industry in that regard but, technicians, are earning £46,000 a year as their as I said, it is almost inevitable we are going to see starting salary. These are high-tech jobs, this is a some job losses. high-tech industry and we must keep on investing in Chairman: Thank you very much, Mr Webb and Mr the skills, it is absolutely imperative that we do. I can Dymond. Thank you for your submissions, which assure you that OPITO will be doing all that it can will be very helpful to us, there is an awful lot for us to make sure that happens. I do not think there will to consider. Thank you. Ev 32 Energy and Climate Change Committee: Evidence

Wednesday 25 March 2009

Members present: Mr Elliot Morley, in the Chair

Mr David Anderson Sir Robert Smith Colin Challen Paddy Tipping Charles Hendry Dr Desmond Turner Miss Julie Kirkbride Mr Mike Weir John Robertson Dr Alan Whitehead

Witnesses: Mr Mike O’Brien MP, Minister of State, Mr Simon Toole, Head of the Energy Development Unit, Licensing, Exploration and Development, and Mr Jim Campbell, Director of the Energy Development Unit, Department of Energy and Climate Change, gave evidence.

Q171 Chairman: Good morning, Minister, and of good. We also have quite large reserves which welcome to the committee, yourself and your team. have been depleted to some extent but which, with It might be useful for the record if you would like to new science, pumping in carbon or some changes in introduce your oYcials. the way in which production takes place, could be Mr O’Brien: On my right I have got Jim Campbell, exploited further. There are a number of factors who is the Director of Energy Development at there and one of the key things for us is how can we DECC (Department for Energy and Climate identify new potential reserves and also exploit that, Change), and on my left, Simon Toole, who is the and also do it, of course, in the face of the economic Head of Oil and Gas; so both of them are greater problems that we currently have. experts than I am in this field! Q173 Chairman: It is really in our interests Q172 Chairman: Welcome. Perhaps we could start nationally to develop those reserves, because it oV, Minister, by having a look at what DECC’s reduces our dependence on fuel imports, and there is views are in relation to the current reduction levels a very clear economic issue of energy security. Does on the UK Continental Shelf. They have been the Department have any kind of strategic approach falling. We were very interested to hear from the to this? For example, do you have any kind of industry, when we were in Aberdeen, that they indicative targets about what you would like to see thought there was a potential on the UK’s coming from our own Continental Shelf? Continental Shelf to produce 65% of the UK’s oil Mr O’Brien: As far as energy security is concerned, requirements up to 2020, which struck me as quite a oil and gas is a key component and, as it depletes significant figure. Of course, that does suggest over the coming two or three decades, probably opening new fields and exploiting new resources, but beyond that, we will still have oil and gas reserves. what is your own analysis of the reserves and the Energy security will become an increasingly potential? important factor, we will have to increase our Mr O’Brien: There is a sort of common view in the imports of gas and, indeed, oil and we will have to media that we passed our peak on oil and gas make sure we have more gas storage. The way in production on the UK Continental Shelf and that, which we manage our energy security will change therefore, it is all downhill from here. We estimate substantially, but we have a number of decades to do that there is about 20 billion barrels of oil equivalent that—two, three, possibly more—and we need to left, including very large reserves of gas. In terms of make sure that we exploit, to the reasonable extent countries in the world with gas reserves, we are that we can, the reserves and the ability to get at the probably about the eighth and, therefore, we have a oil and gas on the UK Continental Shelf. We set lot of potential. We have used 39 billion barrels of some targets back in 1999 for going up to 2010, and oil, so we have got about a third or so of what we those targets were indicative. We were not going to could still exploit there. I think you are right to say force anyone to do it, but they gave some view to the that it all depends on the amount of investment. It oil and gas companies as to what we would like to does, and it depends on a number of issues around achieve. We have been talking to some of them about accessibility, the science and the extent to which the whether we ought to go back to that and have new frontier licences, particularly to the west of further indicative targets. It is fair to say, as with oil Shetland, will prove beneficial. Quickly running and gas companies, each of them have diVerent through those, we may come on to it later, but there views, and I think there is an argument for having a has been a lot of argument about peak oil, and my target as to what we would like to achieve, but it view generally on it is the key thing here is needs to be clear that in the end there are a number investment—how much money is going in, what of variables on this, including the ones I have already reserves there are and how accessible they are, how described around investment and accessibility of large the reserves are, because we can have oil, but if reserves, science and the frontier licences. Whether it is in small reserves that are too expensive, we are going to be able to hit any target, a lot of this uneconomic to access, then it is not going to do a lot is down to investment and the decisions that people Energy and Climate Change Committee: Evidence Ev 33

25 March 2009 Mr Mike O’Brien MP, Mr Simon Toole and Mr Jim Campbell are going to take, but the Government does have a industry is very well served by a national view that we want to create the conditions in which organisation called PILOT, which ministers are we continue to encourage investment in North Sea members of. We meet with them regularly, it has oil and gas. It is a matter of energy security; it is functioned extremely well now for quite a few years important to us that we get the maximum benefit as and, when I was Energy Minister last time, I a nation, as a United Kingdom, out of this. remember attending a number of PILOT meetings. The last one was in February. It is attended by the Q174 Paddy Tipping: You have just told us that there chief executives and chairmen of the main are 20 billion barrels in reserve there. Your evidence companies. What we do is basically agree the way in suggests there are 11 to 37, which is a big range. Why which we will ensure that that level of benefit to the have you put the pitch at 20 today? UK comes from the oil and gas industry.So, in terms Mr O’Brien: Because I am going for the middle of determining targets, what we would do is talk to measurement. There is a maximum and a minimum, PILOT about what those targets ought to be, what and that is where you have got the diversity. All these is realistic. I always think it is best to have realistic things are, in a sense, estimates as to the amount we targets. Aspirational targets are all well and good think is likely to be there. If you talk to someone in and have their place, but we need to be reasonably the oil and gas industry, they will say 25 billion realistic about what we can get. We would then have barrels. We say round about 20 billion, but it is to agree with them whether that was the best way of between about 11 and 37, and until, in a sense, we going about things—I will come back to what some have exploited it, we are not going to definitely know of the problems are in a minute—and also what because you may, as I said earlier, have reserves there those targets should be, and we would probably but if they are not commercially accessible, then they work through that process in terms of talking to the are not going to do a lot of good. Probably 11 is industry. Some of the issues that we face that we did round about what is the pessimistic view as to what not quite face in the same way in the past: we have is likely to be commercially accessible. The 37 is the got a lot more smaller companies involved, maximum view as to what (a) we could potentially particularly in exploration of some of the new areas, find and (b) potentially exploit, if we were very lucky, than we had in the past, some of the small American, in terms of being able to access those reserves. Canadian and other companies that have come in, and they are less tuned in, perhaps, to our domestic PILOT mechanisms and the engagement with the Q175 Paddy Tipping: Forgetting the top end there at Government than was the case five or ten years ago, the moment and just supposing we are pessimists— certainly when we were dealing with larger, often I think it was 11 billion—what then are the UK-based or international companies that were implications for security of supply? Does the talk of used to dealing with us. So we have got a lot of two decades to make adjustment come in closer? smaller companies in. The engagement is actually Mr O’Brien: I think it would probably still be two very good, but reaching agreement is not always decades. If it were the more pessimistic position, then quite as easy as perhaps it was in the past. we would have to import more, so we would be much more dependent on the world market for oil and gas. We have good import facilities, so that in a sense is Q177 Paddy Tipping: The point about the 2010 not going to cause a massive problem. It would be targets. Were they realistic? Are they being met or are regrettable, because we want to see if we can they aspirational? maximise the extent to which the UK can benefit Mr Toole: There was a series of targets, some on from its Continental Shelf, but we have created gas exports, which have been met and exceeded. The one and oil import facilities. We have just expanded, for on production, which was three million barrels a day example, at South Hook in South Wales, in 2010, looks unlikely to be met. One of the features Pembrokeshire, where we had a ship come in only of targets is that it is very important to make sure last week from Qatar. As the Qatari Minister duly that people are responsible for them, and one of the told me when I was over in Vienna at the OPEC diYculties with overarching targets, such as the three Conference: “We have got a ship and it has come in million barrels a day by 2010, is who is actually now!” So it was quite a significant event. We would responsible for that. In fact, the Minister has be able to cope with the lower end of the spectrum recently written to the industry on behavioural we have discussed, and it would not massively targets of getting things done within a certain period damage us, but it would be regrettable because we of time, of doing procedures properly, and those can want to see the UK Continental Shelf be of benefit actually be pinned on managing directors or other to the UK and if we can maximise that benefit, all people and they are then responsible to do them, and the better. many of the things we need to do in the North Sea are about behaviours rather than about geology. So Q176 Paddy Tipping: I wonder if you would tell us a there is space for those big aspirational targets, but bit more about the indicative targets up to 2010. Are it is diYcult to say who is responsible for them, and they being met? I think there is a case for indicative we are trying to make sure we have at a lower level targets into the future. How would you go about targets that people can actually be held to account future indicative targets? for. Mr O’Brien: What we would do, what we did last Mr O’Brien: That is, again, particularly diYcult time and what we did this time, and we have not been given the make-up of the industry as it now is too far oV it, is talk to PILOT. The oil and gas compared to what it was. Ev 34 Energy and Climate Change Committee: Evidence

25 March 2009 Mr Mike O’Brien MP, Mr Simon Toole and Mr Jim Campbell

Q178 Chairman: I think the committee would find it the Energy Minister I signed the treaty to bring the of interest, Minister, if we could have a note from the Langeled Pipeline into the UK from Norway, which department about the target for 2010 and how things brings in about 19% of the gas that we need at the are worked out basically. That would be quite moment. We have also got connections to Europe interesting. which we use. What we need to do is make sure that Mr O’Brien: We can do that. we have a variety of gas sources so that we do not Chairman: Thank you. become overly dependent. Thankfully, in terms of the crisis that occurred in February, we only get about 2% of our gas from Russia, so we certainly do Q179 John Robertson: The way various things have not want to become dependent on that source given been done is to cut back now to save for later. We the diYculties that arose in the dispute with the have got this crisis coming in the 2015 area of where Ukraine. In terms of energy security, we are we are going to be importing all this gas. Should we watching that with a great deal of care. I certainly do not be cutting back on our production today for not deny it is an issue, and I am certainly not tomorrow so that we are not as dependent on gas complacent about it. I think there is a lot of hard imports round about 2015, when we are talking work for government and, indeed, for the industry to about 70% of our gas needs might come from do to make sure that we have suYcient gas capacity imports from other places? I would like to know and gas storage. We have about 20% of gas storage what you think about that. It is like the fish stocks, now for the level of imports that we have; about the really. We do not keep fishing, otherwise the fish will same as Germany,except Germany imports an awful disappear; we try to keep it going. In the case of lot more than we do. We have got about 20% storage fishing, obviously, they procreate and there is more capacity compared to the amount of imports they of them, but in the case of oil we cannot do that, so have. We need to ensure that we substantially we have one shot at this. increase our amount of gas storage so that, if there Mr O’Brien: I think, John, you are right about the are problems that arise, as arose in February, and fact that we basically have one real shot at making they cause shortages in Europe, we have actually got sure that we get the maximum benefit from UKCS. suYcient storage capacity to be able to at least Exploiting gas, in particular, in the North Sea is not cushion ourselves in dealing with that. like switching taps on and oV, it is making sure you have got the rigs and the equipment in place, and they are enormously expensive. In order to have Q180 Charles Hendry: Can I take you back to the them there and exploiting the benefits of UKCS, the issue of targets. Mr Toole said that for some of the gas in particular, we need to ensure that they are targets it is not clear who is responsible for delivering paying for themselves. They do not get put in there them. Would you agree that in general a target really over night, and so the idea of leaving the gas in the only has merit if it has a clear line of responsibility, ground and then suddenly being able, if you had a that there is a method of measuring progress towards problem, to restart it very quickly is, as you know, that target and, indeed, there is a road map for how not really something that we can do. We are that should be reached? dependent on making sure that commercially it is Mr O’Brien: No, I would not agree fully with that. I going to be worth the while of companies to put think if you have targets, they ought to be realistic those expensive pieces of kit out in the ocean to do and they ought to be deliverable, and you have got the drilling, to do the accessing. What we do know, to know how you are going to deliver them, but what and we would have to look at the extent to which this we were talking about here in terms of the oil and gas was feasible, but there is a lot of talk about it, is that industry is something slightly diVerent. It is not like some of the large gas reserves which have been an NHS target or an education target, or something depleted, there is still a lot of gas in them, they have like that, where the Government has clear just been depleted to the level at which it is responsibilities, has levers of power, has the ability to commercially feasible to do so. Could we, by intervene and do something about that and is pumping carbon into them, get more out? Would responsible for the funding going in. What we are that science become much more deliverable in the dealing with here is an industry that says: “Look, longer term? Would we, therefore, be able to get Government, we want to work with you, we want to much greater exploitation of UKCS in five, ten identify what you would like to see us do over the years, 20 years than we have now? That is in a sense course of the next decade and we would like to agree an open question for (a) the science and (b) the with you how we would go about achieving that, and commerciality of that sort of proposition. We do face in doing that we will agree some targets with you”, an increase in imports. A lot of people talk about an which was done back in 1999, “but they are not energy gap. Actually, there will not be an energy gap going to be enforceable. You are not going to be able in 2015. There would be if we did not do something to deliver them, Government, we have got to deliver about it, but we are doing something about it. What them.” Some of those companies will say, “We agree we need to do is make sure we have suYcient that we will do something”, but then those capacity in 2015 and beyond in order to deliver companies may be only there for five years rather energy, and we are in the process of doing that, but than 14 years and then have withdrawn from the UK over the next 20 years we will see a depletion of gas Continental Shelf and are working elsewhere; other on the UKCS, we will need to import more, that is companies have come in that were not a part of that why we are putting in place the Isle of Grain, and process. So I think targets have some merit if they are Milford Haven is key,LNG imports. When I was last agreed; sometimes they may not be as enforceable Energy and Climate Change Committee: Evidence Ev 35

25 March 2009 Mr Mike O’Brien MP, Mr Simon Toole and Mr Jim Campbell and deliverable by government as we might perhaps Chairman: Can we perhaps explore the potential for like or perhaps would have the ability to deliver in maximising new opportunities and, indeed, other sectors. I think they have got some benefit, as maximising recovery of what is already available. long as we recognise that these are no more than Mike. indications to the industry as to what we would like to achieve. I had a discussion, for example, with Q182 Mr Weir: You mentioned smaller companies some people in the industry recently about gas in the North Sea, and in the course of our evidence storage, and they said, “Do you want to give us an we have heard from the Independents’ Association indication as to what you would like?” It became and others. To what extent do you think the eVect of quite diYcult, because, as I pointed out, “This is a extraction of remaining reserves will be dependent Labour minister talking to some people in the on smaller companies operating in the sector? private sector and you are asking for more Mr O’Brien: We have had a lot of interest in the government intervention, are you?”, and they said, recent round of licences. Much of that interest has “What we would like to know is really what you come from smaller companies. I say smaller want, because we can then go back to our board and companies: these are oil companies, so they are a decide what part of that we can deliver”, which is reasonable size anyway. perfectly reasonable. So, in terms of indicative targets, I think they have got some merit, but I do Q183 Mr Weir: It is a relative term. not think we need to have all the levers you describe Mr O’Brien: It is a relative term. We are not talking in order to give them that level of merit. We must not about SMEs here. They are not the big Chevron put more weight on them in terms of deliverability Texaco’s, and so on, although they are all still than they can stand. engaged in various diVerent forms in the UK in exploitation, but it is the case that we have recently seen a lot of interest from the smaller explorers, who Q181 Charles Hendry: Can I broaden that out say that they want to see if they can identify slightly into the way in which the Government tries resources, and some of those will look to go and drill to encourage the North Sea development? In the and discover resources, and then, if they find them, nuclear sector you have established, obviously, they will sell them and somebody else will exploit nuclear development. A very proactive body looks them. Others will to look to exploit over a longer at where the protected barriers are, looks at how they term. So, yes, it is the case that we will increasingly can remove those barriers. You have also got the see these smaller companies become much more New Build Forum. PILOT, perhaps, is relatively important in developing the UK Continental Shelf, similar to the forum because it brings the key figures and that is why, in terms of engagement with them, Y together, but there is not a similar body to look at it is important that we have o cials who can work where the obstacles to development are and how you with them and talk to them, but we still have the big can be more proactive in making that happen, so players who play a substantial role in PILOT, and we can see, in terms of the way in which the oil and gas there is no similar equivalent to the OYce of Nuclear industry is developing, that because there is a strong Development for the oil and gas industry. Do you institutional structure there, the small companies do think there should be? Do you think our see it and do get engaged with it, so we can work with Government should have that greater degree of them quite successfully. engagement there? Mr O’Brien: The Government has a very substantial degree of engagement. I do not think we need to Q184 Mr Weir: One of the issues that seems to be create a particular oYce in order to achieve that. The coming through in the evidence we have heard is the question of the use of existing infrastructure which is industry has had, and continues to have, a close and basically owned by the larger companies and also the good relationship with government. Indeed, I future infrastructure that may be needed, particular sometimes think that I wish that some other sectors west of Shetland. One of the things the smaller were so straightforward to deal with, because these companies say is the voluntary infrastructure, the are people who are investing long-term, they talk to Code of Practice, is not working and they are finding us regularly and many of them are still involved in it diYcult to access infrastructure. What is your view UKCS, are big companies who are used to dealing on that and what is the Government doing to ensure with government and, therefore, in terms of the way that access to infrastructure is fair? in which they deal with government, they are used to Mr O’Brien: You are right that there have been Y dealing with a group of o cials that they know. Both concerns expressed by some of the smaller Jim and Simon are well-known to the oil and gas companies that the large companies have the oil industry and so are some of our other oYcials. I have pipeline and gas infrastructure, they have already not come across them suggesting that they got it out there. The question is, if the smaller necessarily want a new oYce. If they did, we would companies are exploiting an area, can they get access be very happy to talk to them on PILOT and see to that infrastructure and get their oil and gas out? whether there is a way of developing some further Back in 2001, I think, we had the guidelines, which institutional relationships with them that help were agreed with the industry, about accessibility, further exploit UKCS. So we are not opposed to the and essentially the processes is that they are whole idea; I think if they come to us and talk to us supposed to negotiate. If they do not reach a deal, about that, we will engage with them, eVectively. then they come to the Secretary of State and the Ev 36 Energy and Climate Change Committee: Evidence

25 March 2009 Mr Mike O’Brien MP, Mr Simon Toole and Mr Jim Campbell

Secretary of State can then intervene. We have to companies do not really want to get into what is a look at the issues. It takes about ten weeks to look quasi judicial situation with the Secretary of State, through the issues, on average, and to identify what and that is why, as the Minister says, we are trying to the price of access ought to be. So we have agreed work with them at the moment to refine some of the that process. Some of the smaller companies get guidance that has been given to make it clearer what frustrated because they feel that ten weeks is a long the eventual outcome would be so that, again, the time; they want a decision now (I understand that) negotiations can take place in that area rather than and they want a decision that is in their favour (I at some area that is simply unreasonable. So the understand that). They are also concerned that some short answer is that there has never been a of the larger companies are now putting additional determination, but that does not mean that that premiums on to the access, premiums around process and the guidelines that have been set up are security and whether there will be suYcient material not influencing what is going on in the day-to-day going into the infrastructure, whether it will be done negotiations. in a particular way, in eVect requiring insurance policies from the smaller companies. They are not only paying for access, which may be on the Q186 Mr Weir: One final point for the Minister. One generally agreed rate, but now they are being asked of the things that was suggested to us about for certain premiums, and they are getting a bit independence was the idea of a common carrier worried about that, so what we are looking to do is system for the infrastructure to make sure that to engage with the larger companies who have got everybody— the infrastructure and say, “Look, we have got some Mr O’Brien: A sort of national grid type of thing? guidelines going back to 2001. They have actually worked reasonably well, they have solved the worst Q187 Mr Weir: That is right. I believe it works in the problems, but they are not perfect, they are still Gulf of Mexico, so they told us in any event. That raising issues”, and, of course, in any dispute, might be diYcult with the existing infrastructure, particularly over price, you will have people with obviously. West of Shetland, for example, new two diVerent views, and if the price does not turn out infrastructure will be required because nothing exists to be the view that one of them wants, they will be at the moment. I just wonder if the Government has dissatisfied and they will come and complain. I think given any thought to such a system in our oil and gas we have got a situation which works a lot better than fields, or granting access through legislation or it did before 2001, is not perfect—some problems regulation if it is not prepared to go that far. have arisen in recent years which we need to engage Mr O’Brien: We think that the exploitation of the with the industry on—but most of the big players benefits of this will bring large returns to companies, want to do this, I think, in a reasonably and if the state were to intervene and fund such a straightforward way. They want, of course, to common carrier, it is diYcult. Although we would maximise their profit, because, after all, they have get taxation from it, we think that this is the sort of put this infrastructure in at great cost and they are thing that the private sector really ought to do. The not going to give it away to the smaller companies infrastructure system has worked reasonably well, and the smaller companies say, “Look, we could do not (as we have just discussed) perfectly but far more if we could do it a lot cheaper.” There is reasonably well, in the North Sea. Moving into west always this sort of tension, and there always will be, of Shetland, obviously we have an area which is we are not going to get away from that, but if we can going to be diYcult to exploit, it is much more resolve some of those issues around the additional diYcult than the North Sea, but the state intervening premiums, that would be very helpful. to tell the companies how we are going to lay the infrastructure out, making decisions for them about Q185 Mr Weir: Has the Secretary of State been it and then, presumably, charging them substantial asked to intervene in terms of the Code of Practice? amounts for access to it, seems to me to be not the If so, how often, and what is the outcome of that way to go. I would suspect it will mean that many of intervention? the companies who would otherwise be looking there will say, “Look, if we could go there and decide Mr Toole: Has there ever been an actual how we want to do it, we would go, but if you are determination by the Secretary of State? No, there going to decide, Government, how to do it, we are has not. Have there been cases taken towards that not going to go.” direction that have then been settled out of court, so to speak? Yes, there have. Has the guidance that the Secretary of State published as to how he would Q188 Mr Weir: I do not think the idea is necessarily determine something if it came to him had an that the state would pay for laying the infrastructure impact? It has, because it has set out what the and then charge people for access to it, but to ensure parameters for a second hub would be, and there is that we do not get into a situation where one no point negotiating in a way too far away from company controls the infrastructure and controls those parameters if you know that the backstop is subsequent access to it; a form of legislation or not going to be where you are negotiating. The regulation that would ensure that whatever way the Minister has recently set out a letter challenging the cost has been put to the company, once the industry to be more timely in the discussions, infrastructure is in place, there is no barrier to because that is one of the main problems, that things anyone else who is exploring in that area to get just last too long. There is still a barrier that access to bring the oil and gas ashore? Energy and Climate Change Committee: Evidence Ev 37

25 March 2009 Mr Mike O’Brien MP, Mr Simon Toole and Mr Jim Campbell

Mr O’Brien: At the moment, west of Shetland we creating hubs here, we want to engage with you have got a number of companies interested, Total, about what they are going to be like”, and it is not Chevron, BP. They are all looking at various just a planning issue here, it is an infrastructure issue. permutations of putting in infrastructure if they Are these going to be adequate? Are they going to decide to carry out their exploitation there, and there provide the opportunity for others to come in at a are issues about whether there should be connections later stage? It is more of a dialogue rather than a from Sullom Voe, whether it would then go down to diktat, and that is the way we have successfully St Fergus or whether it would go across to the Total operated in the North Sea up to now, and I think pipeline at Frigg. These are all issues which I think, with west of Shetland, in order to exploit it, that is in the end, are commercial ones more than ones that probably the better way of engaging, unless we have you want to determine by regulation. As far as access to do it some other way. to infrastructure is concerned, we have got the guidelines. Those guidelines have worked Q191 Sir Robert Smith: Do you share Professor reasonably well since 2001, not perfectly, but Kemp’s view to us, or his agreement with us, that reasonably well. Do we now want to go into a west of Shetland is not just about more reserves, but situation where we put in place regulations which psychologically, if we could unlock the west of oblige larger companies (and it will be by and large Shetland, it would make a material diVerence to the them) to put in infrastructure and then oblige them psychological approach in the market to the to put particular links in for the smaller companies investment in the UK Continental Shelf? by law? In which case, they will simply say, “All Mr O’Brien: I think that must be right. There is a lot right, if you want us to do that, we are going to of interest, in fact unprecedented interest last charge for that and those charges will have to go November when we had our latest round of licensing somewhere or we will decide not to carry out that job So there remains a lot of interest in the UK as an because it will not be economic any more.” I think exploration area, but, of course, if we can develop you are intruding into areas where I do not think the west of Shetland and if we can commercially identify Government necessarily needs to go at the moment. reserves there that we are able to exploit, then that is I think we need to monitor it and make sure it is a really positive message, and that is why there is a working properly, but I am reluctant to go there at west of Scotland taskforce looking to unlock some the moment. I would not say it was impossible if of the potential there that will enable us to get the things went very wrong, that would mean we would interest from international companies, including get involved, but we have not got any demand to do many of the smaller ones, to go and work west of it at the moment. Shetland. I think Professor Kemp sounds to me to be Chairman: Robert, I know you wanted to raise a few right. It is both psychologically and economically issues particularly west of Shetland. going to be good news for Britain if we can, as a whole, ensure that we get access to good reserves Q189 Sir Robert Smith: Yes. I first remind the west of Shetland. committee of my interests on the Register of Chairman: Clearly, opening up those reserves Members’ Interests as a shareholder in Shell and depends on the current markets, which, of course, as that, as Vice Chair of the All Party Oil and Gas we know, have changed quite dramatically. Colin. Group, I visited the ONS and Stavanga funded by various oil companies for the exhibition and Q192 Colin Challen: Given the recession, how is the conference. You have highlighted that for the industry managing? Is it getting the borrowing that smaller fields, the hubs are crucial, the it requires? Has any state intervention been infrastructure, you have talked about access, but the necessary or been considered? most crucial thing at this time for the industry is that Mr O’Brien: There are clearly problems. For unless those hubs remain economic all these small example, two of the key banks that have invested in fields will remain undeveloped for ever. the past in the North Sea are RBS and HBOS, and Mr O’Brien: Yes. both of them have had problems. That is a good English understatement, so do not laugh. Yes, it is Q190 Sir Robert Smith: West of Shetland, because the case that there are some diYculties. So far, you did engage with the industry to try and get some because we are dealing with, by and large, the larger kind of collective understanding, because there is all oil companies and gas companies, we have not seen this tantalising availability west of Shetland, various any major problems. We have seen OILEXCO get gas fields—no one of them really stacks up, but if one into diYculties—one of the companies—but I am of them were willing to take the risk, then the others pleased to say that, as of this morning (nothing to do could tie together? with my appearance before the Select Committee), Mr O’Brien: Total are saying that they are looking at they have been bought by Premier Oil, so that is very Laggan and Tormore at the moment and that they good news. Premier Oil is a company which is well- are thinking about putting a gas hub in at Sullom known to us and will, I am sure, do a very good job Voe, and we are looking possibly at a decision on and, hopefully, will secure the future of OILEXCO. that in the autumn, and then Chevron are looking at So we have had that diYculty. What I am concerned Rosebank and Lochnagar and BP at Clair; so we to ensure, and we have been engaging with BERR, have got a lot of interest. There is a diVerence the Treasury and also with the banks, is that between jumping in and regulating and engaging investment remains still available. We do not with the industry and saying, “Look, if you are envisage any serious problems for the large Ev 38 Energy and Climate Change Committee: Evidence

25 March 2009 Mr Mike O’Brien MP, Mr Simon Toole and Mr Jim Campbell companies. Many of the smaller companies are not last year happen again; they saw it as damaging to UK based and get their finance from elsewhere in the world economy.So I am hopeful that OPEC, and any event, but where there are companies that have investment more generally, and particularly in the used RBS and HBOS, we have seen the Bank of North Sea and UK Continental Shelf, will be able to England interventions in January, and to some be sustained during this downturn. If you say, “Am extent in October, and we have also had the work I watching it carefully and am I concerned?”, the that is being done by UKFI to manage our answer is, yes, I am watching it very carefully and I involvements in those, and it is clear that the North am concerned. We are not picking up at this point Sea and the UK Continental Shelf more generally significant or substantial problems, but it would not has been an area which has brought great profits and surprise me if at some point we did start to pick benefits, by and large, so they tend to be good those up. investments. The diYculty is they also tend to be long-term investments, and at the moment many of Q194 Colin Challen: I understood you to say earlier the banks are concerned about their liquidity and are on that gas storage facilities can act as a cushion less anxious to tie up money for long periods. Is there Y against market volatilities. You also mentioned that likely to be a di culty round this? Yes, but let us not the industry had asked you for some guidance, but exaggerate it, in the sense that the bigger oil you did not tell us what the guidance was. It varies companies and gas companies will be fine. The as to the size of our need. We only have 13 days smaller ones, by and large, will be the ones that have Y apparently, according to the press. Germany has di culties, but not all of them are going to be reliant over 100 days, France has 80 or 90 days—I know the on UK banks. So there is a sort of niche around there conditions are diVerent, but do we have an indicative where we do have some concerns—OILEXCO is an target of how many days storage of gas we should example—and we have been engaging to ensure that have access to when this can be achieved? we monitor very carefully what is happening in the Mr O’Brien: By and large, I think that the industry, who have got problems (some of them are description of gas storage in terms of days is a bit reluctant to tell us whether they have or not) complete nonsense. The access to gas storage is and what the problems are, and we have also been not—. We have got so much and we just pump it out. engaging, not ourselves but through the Treasury Some gas storage is fairly well instantly accessible, and BERR, with the banks in order to ensure that some of it is medium-term, some of it is long-term the importance of the UK Continental Shelf is at the storage. In other words, it takes quite a while to forefront of the minds of the banks. access it; it does not just come out. Therefore, what you have (and I cannot remember the figures oV- Q193 Colin Challen: The recession has had a hand in hand for last week) is about 19 days mid-term depressing the oil price because the high costs of the storage, I think, and probably 30 days in long-term industry do not go down as well. Do you see that in storage and you have by now, probably, about two the longer-term that will be a self-correcting thing, or three days in short-term storage. It varies that when the recession ends the oil price will rise substantially, and at this point in the year we would again? Do you see that as being a suitable way for the expect there to be very low stocks in storage. Why? self-correcting balance to return to the industry? Because we have just got through the winter and we Mr O’Brien: We certainly do not want the spike we have used it. That is what it is there for. So I have no had last year to return, and that is my main concern problem with the level of storage falling at this point at the moment. If you look at the World Energy because they then stock up during the summer and Report, which came out last November, it says that use it during the winter. That is the way we use there is likely to be a long-term shortage of energy. It storage. What you cannot predict is when a crisis does not buy the arguments around peak oil or might arise internationally, a Ukraine/Russia anything like that, but it just says, inevitably, as dispute. If it arises in July, there are all sorts of economies expand there will be constraints. What I implications. Probably less demand for gas is said to the Vienna Conference of OPEC last week probably one, but it is probably a bad time from was that it was enormously important that we Russia’s point of view to have a crisis, but it is the sustained, through the recession, the level of case that the level of storage varies considerably at V investment necessary to put in place the di erent points of the year. What we need as a nation infrastructure that would be needed when economies is to recognise that as we become more dependent on begin to expand again: because if we get cut-backs imports, so we need more capacity for storage, and on that level of infrastructure investment, we are if all the storage that we envisage comes to pass and going to face the problem that there will be greater various companies are saying they are going to bring capacity constraints when the economies expand forward storage in the coming years, then we will more than they would otherwise have. Therefore, we have a very substantial amount of storage, and are likely to face problems around spikes if we do not certainly in excess of the 20% of imports by 2020 that get that investment sustained. The OPEC countries we currently have. said that they recognised the problem, they saw that their investments were long-term, they saw that Q195 Colin Challen: All these volatilities are not recession was temporary, they saw that there was going to go away,even when the recession is over and going to be substantial demand, that the very low other circumstances change. Does the Government price of oil at the moment was something that was actually the have concept of a strategic reserve for temporary. They did not want to see the spike from gas and for oil so that we can weather passing Energy and Climate Change Committee: Evidence Ev 39

25 March 2009 Mr Mike O’Brien MP, Mr Simon Toole and Mr Jim Campbell storms? Is that just down to the market to hopefully “Our bank says normally okay. This is a good fill in the gap, or does the Government employ this project, but at the moment we would like to get some concept? The Americans do. security here.” In terms of some of the storage stuV, Mr O’Brien: They do. I am somewhat sceptical of it, big enough projects to go to the EIB and engage with but I would not dismiss it. We have not for several them, in terms of, say, renewables and wind projects, decades now had to have that concern because we not really of suYcient size to go to EIB by have had access to very large quantities on the UK themselves, but if we bundle a number of those Continental Shelf in any event, so we have not had projects together they will probably go to EIB to have a concern that we needed to keep, as I was because EIB only deals with very big projects; and talking to John about earlier, large amounts of oil EIB, we are hoping, will give some indication about and gas in the ground just in case. I discussed earlier their receptivity to energy projects because we need the practicalities or not of that. What the Americans to ensure that we get the access to the capital that do is they have known reserves which they just do EIB can provide to ensure that projects which ought not exploit, and they will then go in to exploit them to go ahead, which would in normal circumstances at some point in the future. During last year there go ahead, which would have otherwise have gone were various calls upon President Bush, as he was ahead, are able to go ahead despite the recession. then, to release the security reserve that the US has. You have got to be a little bit careful here, because We were not in that position because, by and large, certainly from what I have seen in the market there we have had North Sea oil and gas and, therefore, is a certain amount of delays and game playing, for that has just been there. We are now moving into a all sorts of reasons, in terms of prices lowering new era where that will be depleted. It is not perhaps on the infrastructure so people will delay for immediate, we will be moving over a number of a few months to see whether a project will go ahead. decades, and therefore there is now a greater level of Some of these projects will still go ahead and people discussion about whether we should have some sort are committed to them and the money is there, but of concept of a security reserve. Increasing gas there are now delays in terms of people’s gaming storage provides us with some element of a cushion. around infrastructure. So you have just got to be I would not describe it as a security reserve, for the careful about what really is a problem and is a reasons I have explained, that it goes down at business saying, “Actually, if I delay this three various points of the year. Would you just lock up months, prices will go down a bit and I will be better large amounts of gas in storage? Who is going to pay oV”, and that is a commercial judgment. for that—that is enormously expensive—and who is going to construct the storage, maintain it and adjust Q197 Miss Kirkbride: You said that the big it: long-term artificial storage, not underground? companies were fine. How are you going to do that? I think there are a Mr O’Brien: By and large, yes. number of issues around that that probably need a greater degree of exploration. At the moment my Q198 Miss Kirkbride: Why are they getting access to answer on a security reserve is somewhat sceptical. money more easily? Certainly that is not what we need now. Whether we Mr O’Brien: What happens with the banks, the need it in the future I think we can talk about, and I major investment banks, is if they have got a want to listen to the arguments on it: I want to know relationship with a big successful client that they who is going to pay for this and are we going to pay have dealt with over a long period where there is a some oil gas companies, pay them as a state, a large known relationship, the bank has a large amount of amount of money for holding it? information about what that client does, how it deals with things, how successful it is. That is a strong Q196 Miss Kirkbride: Can I take you back to what relationship, a long-term relationship. If, on the you were saying about investment and just maybe a other hand, you get a company that you barely know little bit more detail. As you will be aware, almost come to you about which you do not know very every business is anxious about the banks’ ability to much, the banks are then less likely to immediately lend them money at the moment and it does not help say, “All right here is a bundle of dosh.” the banks that were involved are the ones that are the most troubled. You said that you had been talking to Q199 Miss Kirkbride: So you are optimistic that the BERR and others about what help might be Government schemes so far that have been available. Can we be clear what that is and whether announced and hopefully will be producing some any has been forthcoming so far? goods in the not too distant future. There is enough Mr O’Brien: What we know is that for SMEs, for the money in those schemes, given the size and the level smaller companies, there is the Enterprise Finance of investment we need in the North Sea that the Scheme (£1.3 billion), for larger companies there is North Sea oil companies, the smaller ones, will be the Working Capital Scheme, and also, not able to access those schemes alongside every other particularly in terms of oil and gas companies but on business in the country that also wants to access gas storage, as Colin was raising with me, we have these schemes at the moment. been talking to some of the companies about looking Mr O’Brien: I do not say I could say that I could to the European Investment Bank. What we know is guarantee to you that what we have done so far will that the European Investment Bank has be enough. I think what we need to do is monitor the considerable reserves and we have been talking to a situation. We are, as you know, in a situation now number of energy sector companies who have said, economically which is probably unprecedented, Ev 40 Energy and Climate Change Committee: Evidence

25 March 2009 Mr Mike O’Brien MP, Mr Simon Toole and Mr Jim Campbell probably the nearest precedent goes back to the reason. That has worked quite well. We also give 1930s, and that was not even the same in the sense particular tailored licences to companies so that if that we have now got a global economy, and they have got a particular problem, let us say they certainly in oil and gas it is very global. So we are are going into an area that has not been explored trying to manage our way through something which before, we will give them a longer time to do the is new for leaders and I think the UK have done well. work needed to analyse the infrastructure, the strata, President Obama is trying to encourage other the geology.We have taken a number of initiatives to countries to follow the way in which the UK has try to ensure that people get the sorts of licences that sought to put more money into the economy and he, enable them to carry out the work they want. I do obviously, is trying to do the same. You heard his not think we are facing a crisis. I do think that we speech yesterday. I think we have got to work our need to watch this with care because it is way through what is clearly an economic problem of unquestionably the case that at this stage of global and domestic importance. Working our way development of the UKCS, particularly with the through this does not mean that we can say, “Well, economic situation, problems can and are likely to we’ve done all we’re going to do now and that’s it”. arise. So this situation needs careful monitoring. I do not think we are in that position. We are going to have to keep monitoring this situation and adjust Q202 Mr Weir: Obviously one of the concerns about our policy to ensure that we do the things that need any downturn is the eVect on jobs within the to be done to make sure this country gets through industry and indeed retaining skills within the North these economic problems and out the other side in a Sea. Is there anything the Government can do about good state. this to ensure that jobs are retained and particularly Chairman: I want to turn to the issue of investment skills are retained in the North Sea area? levels and the supply chain. There are many Mr O’Brien: You are right that jobs are enormously thousands of jobs downstream of the oil and gas important. It is 350,000 jobs in the oil and gas sector and they are a very important part of our industry in the UK, it is very important, plus a economy. further 100,000 jobs in UK companies that work abroad. In total in the oil and gas industry that is Q200 Mr Weir: UK Oil and Gas predict that the 450,000 jobs. That is a lot of employment. There number of wells drilled for exploration and have been concerns about the nature of the skills in appraisal will drop from 109 in 2008 to just ten in the industry. I have looked at this. We have been told 2010. Do you consider that to be a crisis in there is an aging workforce and so on. Certainly investment? oVshore on some of the rigs there are issues around Mr O’Brien: As far as the numbers of wells are that, but by and large the average age is about 41. If concerned, the issue is the quality of those you consider that we are looking at people by and explorations. You cannot just work it on the large between 20 and 60, 41 is not a bad average age numbers like that; that is not a good way of looking to have in an industry. I do not think there is a crisis at it. What we are aware of is that there has been a in terms of skills. OPITO, the very good oil industry- slowdown in the extent to which companies are based finance training system, which is currently starting to exploit their licences. You are talking training about 350 young people, not all of them that about oVshore here, are you? young, is really a very good skills academy for the industry. So they are carrying out training. They are Q201 Mr Weir: Yes. quite good at it. The issue is whether a downturn will Mr O’Brien: And the way in which the various start to reduce the number of jobs. We have got two licensing rounds have gone. I have just delayed the things happening. One, we have got the economic next licensing round until the start of next year with downturn and at the moment there is not a the agreement of the industry. There was a lot of substantial problem there. We were worried about interest last November, the maximum amount of Oilexco but, as I have already said, Premier have interest, far more than we had anticipated in the come in and bought that now. There is also the fact twenty-fifth round. I have delayed the twenty-sixth that we have got a depleting level of reserves and round to give some opportunity for the licences that inevitably that is going to have a long-term impact we have already dealt with to be absorbed in the on the number of jobs. industry. I have also indicated that, as far as the twenty-fourth round is concerned, I am prepared to Q203 Mr Weir: SCDI and Scottish Enterprise did a relax some of the licensing conditions on application report recently which showed the supply chain was and to try to ensure that we have companies who worth some £14 billion to the Scottish economy. plan to do work but who are perhaps delaying it for Obviously we need to make sure that that remains a while because of maybe finding some issues around robust if there is a downturn in the North Sea. That finance or who just want to look at their liquidity for ties in with what you mentioned before about having a while. They will continue to hold the licences a base for companies to use these jobs in other areas. providing we are satisfied that they are companies That report only goes up to the end of 2007. It has that will exploit and do intend to exploit it. We have not taken into account the current recession. Have still got a series of initiatives, as I am sure you are you any indications of the eVect that the current aware, such as the Fallow Field initiative, whereby economic situation is having on that supply chain? Is we say “Use it or lose it”. You get three years and you there anything Government can do to ensure that it lose it if you do not use it unless you can show a good gets through it? Energy and Climate Change Committee: Evidence Ev 41

25 March 2009 Mr Mike O’Brien MP, Mr Simon Toole and Mr Jim Campbell

Mr O’Brien: There are some indications that there industry but the Treasury were not necessarily in the are problems in the supply chain but they are loop. Perhaps one of the reasons we did not reach variable. They are mostly where we are looking for our targets was that the Treasury started to see a investment and it is a bit slower coming than we had short-term cash cow in the North Sea rather than a hoped. I think I would have to say that there are long-term investment. potential problems brewing there but at the moment Mr O’Brien: There were changes in the tax regime in they are not massive. What I am more concerned 2005. The Treasury does not envisage during the about in the longer term is that the Scottish oil and course of this Parliament making a substantial gas industry recognises and adapts, recognises that it increase in the tax rate and the regime is in place, but can service, as some of it does now, globally the oil we have agreed to look at a certain number of and gas industry, and that it provides rigs and adjustments that have been asked to be made by the equipment and kit that has a global market, not just industry and the Chancellor in due course will no a UKCS market. So they have to be helped to ensure doubt take a view on them. that they develop that international market as the supply to the North Sea and west of Shetland in due course over a longer period starts to reduce. We are Q206 Sir Robert Smith: That dialogue was taking dealing here with an industry which is very self- place in the maturity of the province and the aware, well-organised and capable of helping itself Government’s wish to see security supply through diYcult times and also is used to dealing maintained in maximising the North Sea in that with depleting energy sources, so it goes to various climate. Since then it has snowballed with the parts of the world, exploits it and moves on. We find economic crisis. Is there a dialogue that you are part that they are reasonable to work with. of to encourage the understanding that maybe on the Mr Campbell: You mentioned targets previously. cashflow side there is a thought that the early release One of the pilot targets was for a certain amount of of tax credits for exploration to those companies exports and that was exceeded two or three years ago that have not got any profits yet to put them against, in that the UK industry was exporting several billion so that they could assist their cashflow by the early pounds-worth of kit. A good share of the £14 billion release of tax credits, and also that recognition that you mentioned now comes from the world market. the current value allowance was looking at If we compare what has happened this time with the incentivizing new fields west of Shetland, high last time that UKCS went through quite a deep temperature, high pressure? Is there not an argument reduction in activity in 1999 in the oil and gas now that any incremental development on the hubs industry, the oil and gas companies in the supply themselves will also need to be incentivized to make chain chopped jobs very radically in a short period sure the investment is there so they are not of time. We have not seen that this time round which decommissioned? I think is a very positive sign. That is not to say they Mr O’Brien: There are various ways of incentivizing. are at all complacent about what is happening, but As far as the tax regime is concerned, no minister V it is a di erent approach that is being adopted by the outside of a Treasury minister will discuss it, as you industry this time—dare I say, a much more mature know, and beyond saying what I have said, I do not approach this time. As the Minister says, we will propose to do so here. However, there are ways in have to wait and see what happens in the future. which through non-tax means we can look at the issues around the best exploitation of hubs and the Q204 Sir Robert Smith: I want to reinforce that sense creation of hubs and also making sure that the of jobs dispelling in my constituency in the north- industry continues to benefit. We are working east of Scotland. You can see how important the through pilots to ensure that we develop those industry is, it has been through previous downturns, methods of helping them and providing the and how depressing it is to see the rows of For Sale infrastructure that they need and the advice and signs going up across the north-east if it is not guidance that they need. In terms of what the handled right. You have said the crucial thing is to Chancellor is going to do, we will have to wait for sustain investment. You recognise the importance of the Budget! the hubs. Given that this downturn is in a mature phase of the industry,it is even more important to get that right. The Treasury has honed in on this value Q207 Sir Robert Smith: The one key thing you could allowance to assist the industry. How do you see the do then is, if you cannot tell us anything, make sure value allowance working? Have you had any that the Chancellor hears the evidence we have heard thoughts about at what sort of rate it should be set about how crucial these issues are to the North Sea. to be eVective? Mr O’Brien: I can certainly pass on that evidence to Mr O’Brien: Issues around this will be best dealt with the Chancellor. Not only that, I can reassure you by the Chancellor in due course. It is a perfectly that the industry has talked to us, as you would legitimate question, Robert. I think our engagement expect, at some length and with very precise wishes with the Chancellor on these issues needs to be one and those have been passed on to the Treasury and that happens within government. they are aware of them, as they are about the demands and wishes that are coming from all sectors Q205 Sir Robert Smith: That goes back to the targets of the economy. and the failure maybe to meet the pilot target. There Chairman: Another aspect which is crucial to was great engagement between government and development is the regulatory regime. Ev 42 Energy and Climate Change Committee: Evidence

25 March 2009 Mr Mike O’Brien MP, Mr Simon Toole and Mr Jim Campbell

Q208 Dr Whitehead: Do you think the DECC position where we want to create a new registry. If Energy Unit is adequately resourced? the industry is prepared to finance it then we are Mr O’Brien: By and large, yes. What we are doing at prepared to work with them in creating it. We would the moment is we are looking at the resource also want to ensure that if there were errors, as the available and we are determining as a new Land Registry has to cover itself with insurance, so department where that can be best deployed. Have too that registry would have to do so given that an we overall got the right numbers? By and large, yes. error in that registry could well have very, very costly Have we got to adjust the deployment of where we implications for somebody who relied on it. best want the staV that we have got? We want to look Mr Toole: We do keep our own record of who we at that and make sure that we are content. We have have given licences to and we are working hard to come from two diVerent departments. We are make sure that the industry can see that and tell us anxious to ensure in the new department we do not of any errors that are in it. So we are working with continue the divisions that previously existed them, but as the Minister says, the liabilities that the between oYcials in those two departments and so we Land Registry takes on are very high and very costly are trying to integrate the structures of DECC so and the Minister does not want to accept those. that we prioritise the staV where we feel as DECC we most need them. If you are asking if we are just going Y Q212 Dr Whitehead: As far as the regulatory impact to perpetuate the number of o cials that previously on the oVshore sector is concerned, how do you operated in BERR in the same roles, no, because we think the emergence of Phase III of EUETS is going need to redeploy. to impact on particularly the oVshore sector’s role in Dr Whitehead: Is there congruence between the auctioning and the extent to which it could be argued money that is raised from licence fees and the money that auctioning may simply drive investment that is allocated to the work of the Energy Unit, or elsewhere? does some of that money disappear elsewhere? Mr O’Brien: There is a lot of concern, as you would expect, in the industry, as there is across other Q209 Chairman: It is £60 million comes in from that. industries, about the introduction of ETS. There Mr O’Brien: I do not think the answer is that there have been various predictions about big problems, is congruence. We get quite a lot of help from the some of which we think are just wrong and some of industry. which we think may have some merit. Mr Toole: The £60 million of licence fees goes into the consolidated fund. Q213 Dr Whitehead: Which ones do you think are Mr O’Brien: So it then comes back out but not as we wrong? know it! Mr O’Brien: One example would be that the oil and gas industry says that the carbon price would be Q210 Dr Whitehead: We could not say it was around ƒ45. The predicted carbon price for 2013 at hypothecated? the moment is about ƒ20. We would work on an Mr O’Brien: No. I was a bit surprised because I had assumption for our predictions that it would be never heard anyone suggest that. As you have just round about ƒ30 at some point during Phase III of heard from Simon, it goes into the consolidated the ETS. We are just concerned that some of the V fund, so it does not have any direct e ect on the doom and gloom messages that have come out from V number of sta we have. some parts of the industry are based upon statistics that they need to look at very carefully. For example, Q211 Dr Whitehead: For example, the Unit might be they have also said that for the small companies this employed in producing a reliable registry of oVshore will be very, very damaging. Well, I think they have production licensing holdings, which certainly the got to show how. For some companies it will have an industry suggests could be a very good way of implication. It is clear that if they are generating then making sure that a number of costs and development they are going to be paying for the EUAs, the issues are sorted out, including the title, et cetera. It allowances. If they are not generating then there is an may be the case that it is simply not within the issue about whether, with carbon leakage being one capacity of the Energy Unit to produce such a thing. of the key factors round the oil industry and we have Mr O’Brien: I think it is within the capacity of the still got quite a way to work through in terms of the industry, if it wants such a registry, to create one and extent to which particular rigs and the oil industry ensure, of course, that it has insurance policies, as will be able to show that it has got an element of the Land Registry does, to cover any errors and carbon leakage, that enables them to look for non- ensure that it has got all the administrative capacity. generation free allowances. In terms of where it is We have got a record of where we have issued generating electricity or energy or flaring, then it is licences. As to creating the sort of facility that the clear that they are going to be covered by this and industry says would be beneficial to it, I am sure it not only covered by the ETS as it currently is, but it would. I am very happy to work with the industry if depends to some extent what happens out of they want to fund the creation of it. What they are Copenhagen and where the cap is on the ETS further saying at the moment is, “Government, will you down the line. There are a lot of issues around this please go and create this for us just like you did the that we are working through with the industry. I am Land Registry?” to which my reply is, “Yes, and the concerned that there are fear levels about dealing Land Registry costs an awful lot of money to run”. with global warming within the industry that are It was created in 1925. I do not think we are in the greater than they need to be. I have no doubt there Energy and Climate Change Committee: Evidence Ev 43

25 March 2009 Mr Mike O’Brien MP, Mr Simon Toole and Mr Jim Campbell will be an impact. The question is the extent of that decommission, because that is where we get many of impact and I think that needs to be determined. The the problems around environmental issues. We have industry is very concerned at the moment and we are 40 environmental statements, six appropriate trying to work through those concerns with them. assessments under the Habitats Directive and 40 One of the diYculties is that the various rigs generate screening and scoping documents currently electricity at diVerent levels. Some of them use their reviewed, around 3,000 permits issued around turbines to mechanically work the engineering on chemical use and oil discharge permits, drilling the rig. Okay, that is not generating electricity as approvals and permits under the EU Integrated such and therefore they may qualify for free Pollution and Control and Emissions Trading allowances in relation to that and some of them are Directives. We investigated and examined problems generating up to 90% of their eVort through around 386 oil spill plans, so they plan what they do generating electricity and that is what is doing a lot when there is an oil spill and we have to approve their of work on the rig and they may end up having to plans. We conduct inspections and investigations of buy carbon allowances for that. There is a the various projects both onshore and oVshore. distinction between the generating side and the non- There were 55 inspections done last year to check generating side which is important to identify. The whether the various kit is performing at the standard industry is concerned about both sides, but it is that environmentally is adequate. We report cases probably more concerned about the generating side where there have been breaches to the Procurator than about the non-generating side. Fiscal in Scotland. Since 1998 we have reported 11 incidents to the Procurator Fiscal resulting in nine Q214 Dr Whitehead: Bearing in mind you have said prosecutions. There are issues around spillage. Let that the oil and gas industry is now very much an me give you some figures. There are about 366 integrated global concern, do you think that the million tonnes of oil which has been produced charge that actually, however eVective and benign between 2002 and 2005. During the same period 362 those regulations may be, the eVect of driving tonnes of oil was spilt. This equates to 0.00009%. exploration and investment into regimes where there That is a pretty good record. is perhaps not that regulation could be a real issue? Mr O’Brien: Let me be very cautious in the way I Q216 Dr Turner: Small percentages of a very big answer you because we are obviously having amount can be significant. discussions with the Commission about the issues Mr O’Brien: Yes, 362 tonnes is significant but not around carbon leakage. Let me say that there is a given the sheer amount. It does suggest they are criterion around the Directive which defines the doing fairly well. sectors at risk as those with a trade intensity of around 10%, so there is a likelihood that they will Q217 Dr Turner: Having said that, the strategy just go oV. At that point questions then need to be consultees such as the Joint Nature Conservation asked about whether they are likely to be part of a Council have identified some issues. They tell us that big problem of carbon leakage. The industry argues there is “scope for improvement” in operators’ that there is a big problem of carbon leakage. We are compliance with the Environmental Impact investigating the detail of this to see the extent to Assessment process and that you should consider which we will need to make representations around reviewing the current system. Will you do that? carbon leakage to the Commission and indeed take Mr O’Brien: The compliance level we have just a view ourselves about the level of carbon leakage discussed in terms of the level of spillage and so on. that is likely to occur. There is much more work to There are issues that concern me about west of be done before I can give you a definitive answer to Shetland and how we would deal with those some that. We want to work through with the industry quite sensitive environmental areas. There are some their arguments as to how, both in terms of areas like St Kilda and so on where there are generation and no generation, they will be able to particular issues around the environment that we demonstrate that they are potential victims of need to address, questions about whether there carbon leakage and whether individual companies, should be no-go areas. I think around that there are whether big ones or small ones, can justify us taking issues which we do need to examine and take a view a view with regard to allowances or justify the on. Because this is a continuing process of trying to Commission, whether we do or not, taking a view ensure that we have an industry which not only with regard to allowances in the ETS. carries out its work of exploitation but also decommissions properly we have just got to ensure Q215 Dr Turner: How does your Department ensure that all of this is done in a way in which we keep it that companies who claim they will follow under constant review. Am I planning a review environmental best practice actually do so once they beyond the areas that I have already identified? Not have got consent for projects? a substantial one. Am I conscious that we need to Mr O’Brien: We have a number of means by which keep watching this all the time? Yes, I am. we ensure that we cover the work of these. They are subject to licensing conditions as to how they can Q218 Dr Turner: Your comments about west of carry out their work and we have got control over Shetland chime very much with the concerns of the the terms on which licences are issued. They will RSPB who tell us they feel there is a need for a better, normally ensure that they not only comply with up-to-date survey of seabirds and other wildlife in those but that they are able to show that they will areas aVected by exploration. The knowledge base is Ev 44 Energy and Climate Change Committee: Evidence

25 March 2009 Mr Mike O’Brien MP, Mr Simon Toole and Mr Jim Campbell not what it might be in terms of that area of marine Q220 Mr Anderson: We are all interested in seeing ecology. Will you be doing anything to support CCS become a success, but we have been advised by such surveys? those involved in the industry that what they need is Mr O’Brien: We do look at things when we get a clear licensing regime because at the moment they applications for particular areas to see what the are not quite sure what they can and cannot do. Can impact will be. What I think the RSPB want, if I you help them with this? What have you done so far? understand their demand correctly, is a general Mr O’Brien: We want to ensure that for carbon survey.We are looking at all the areas so that we then capture and storage there is a clear licensing regime have a view about what the impact would be across and that they are able to get a licence to carry out the whole of the potential oil and gas fields. Our view carbon capture and storage. As we develop our is that we are content to look at the environmental commercial capacity to do that that will need to impact on birdlife and crustacea, et cetera, when we happen. As you know, at the moment we do not have have an application. These things are not fixed. You a project here or indeed anywhere in the world which could not just do a survey and say, “Okay, we’ve is of a substantial commercial nature involving done the survey,” because migratory patterns and all carbon capture and storage. What we want to do is sorts of things do change over time. The result is that put in place a regime which will enable carbon you have to keep the thing constantly rolling. If you capture and storage to take place, issue licences to had infinite resources you would like to do all sorts enable it to take place, ensure that it is properly of things, but I think the better way of dealing with inspected, that it is safe and that we have a system it with the resources that are available is to carry out which will encourage the development of an industry clear impact assessments where we have applications in the future. I believe that in 20 years’ time we will to carry out work that is likely to be done. see a worldwide industry involving carbon capture and storage. We know the science is good. The Q219 Dr Turner: This comes back to a question we commercial potential of it is yet to be assessed. If we have considered before, which is whether you should can get it right, because it will deal with some of the be doing project-by-project environmental problems we have around coal, which is important assessments or whether you should have a strategic not just in the UK but important in much of the assessment of a larger area so that you build whole developing world, oil and gas and deal with some of patterns. the issues around global warming, the potential for a Mr O’Brien: We do undertake larger strategic environmental assessments of larger areas, but when massive industry to develop 20 years’ time from now you have got a particular project which comes around carbon capture and storage is great. I am forward it will have a defined impact in a particular certainly very optimistic that it will happen, but in area and you need to look in much more detail at order to ensure it develops properly in the UK we what that impact is. need to have the legal base and the creation of a Mr Campbell: It is fair to say that the Department is licensing system and we want in due course to the single largest funder of bird surveys in the consult on how we are going to create that. country and since 2005 has spent £3 million on bird surveys, so it is a very significant amount of money. Q221 Mr Anderson: I am not sure I have understood Prior to that we have undertaken over the last seven you correctly. Are you saying we have got to get the or eight years strategic environmental surveys which demonstration project up and running first or would were, when they started oV in 1999, world leaders in the licensing regime come first? The advice we are determining the environmental scene that we have getting is that people could be getting on with the found round about the UK. I think it is fair to say work but the licensing regime is not there to help that we are in quite a good position with regard to knowledge of not just the benthic colonies but also them. of birds around the UK. Whilst it is understandable Mr Toole: There is a licensing regime coming into RSPB would quite like a bigger survey and they have place early next year, but the Crown Estate is already estimated something like £10 million, we believe if preparing and will have the power from 6 April this you were to do that across the whole of the UK it year to start issuing leases for the areas. If your would cost considerably more and somebody has concern is that people who want to get hold of an got to pay for it ultimately.We think we are in a good area on which to do studies and work on carbon position as regards our environmental record and capture and storage are being frustrated by the the information we have around our waters. licensing regime, we have been working very closely Chairman: There is one very important issue which with the Crown Estate and very shortly they will be came up in our discussions in Aberdeen in relation able to get into a dialogue with the Crown Estate to to transferable skills and resources and such things get hold of the territory that they might wish to use. as the potential of carbon capture and storage using Chairman: Thank you for your attendance and your the infrastructure of the oil and gas industry. evidence. We appreciate the time you have given us. Energy & Climate Change Committee: Evidence Ev 45 Written evidence

Memorandum submitted by ABB

1. About ABB

1.1 ABB is a leader in power and automation technologies that enable utility and industry customers to improve performance while lowering environmental impacts. ABB in the UK operates from more than 20 locations nationally and employs around 2,300 people. The ABB Group of companies operates in around 100 countries and employs about 120,000 people. 1.2 Technology plays a key role for ABB with our nine research centres, 6,000 scientists and 70 university collaborations across the world, of which several are in the UK. ABB is a one of the largest providers of transmission grid plant and equipment to connect Round 2 and proposed Round 3 oVshore wind farms to the UK and European Grid systems.

2. Executive Summary

2.1 Developing and innovating in oVshore automation and electrification technology is the key to extending the life of the UK Continental Shelf and the North Sea oil field. Such innovation can improve the exploitation of the UK’s remaining oVshore oil and gas reserves while at the same time reducing the harmful impact on the environment. 2.2 In order to encourage investment in technology development and innovation, the UK Government needs to foster a long-term co-ordinated oVshore strategy that will give clarity to the industry and supply chain. The strategy should be both UK-wide and connected to existing strategies in Europe. 2.3 OVshore oil and gas platforms should where appropriate and where environmental and financial benefit can be realised, be connected to a North Sea Electricity Transmission system. 2.4 The UK Government should work with industry and universities to address the skills issues in advanced engineering and to take full advantage of the opportunities that the UK Continental Shelf and the North Sea oil field present.

3. How can the UK’s remaining oVshore oil and gas reserves be exploited most eVectively? What barriers are there to exploiting such reserves?

OVshore electrification

3.1 OVshore electrification can become instrumental in providing solutions for projects with space constraints and low weight budgets but where improved system performance is essential. ABB has been at the forefront of the industry’s drive to develop electro-technical solutions compliant with existing requirements for energy eYciency, control and safety enabling remote and unmanned operations. Current ABB solutions in operation around the world include HVDC Light and subsea power transmission. These can be applied successfully to some of the challenges presented by the location and depth of some of the UK’s remaining oil and gas reserves.

OVshore automation

3.2 Increasingly innovative solutions in oVshore automation can also help meet these challenges. ABB has developed a number of internationally used solutions, including enhanced control over flow, level, temperature and pressure measurement. Where fully implemented—for example Ormen Lange on the Norwegian Continental Shelf and De Ruyter on the Dutch Continental Shelf—greater control over oVshore automation has increased production and extended the lifetime of assets.

The need for a co-ordinated approach

3.3 The issue for the UK is whether the fiscal and regulatory framework can provide the long-term vision to empower the supply chain to confidently innovate in oVshore electrification and automation in the same way as being proposed elsewhere in the world. Ev 46 Energy & Climate Change Committee: Evidence

4. What can be done to minimise the environmental impact of exploiting the reserves? How should this be encouraged and/or financed?

Practical solutions: a case study

4.1 ABB’s HVDC Light has been successfully applied on the Troll A platform in a Norwegian Gas Field in the North Sea, 70 kilometres oV the coast of Norway. Troll A is the tallest construction that has ever been moved to another position, relative to the surface of the Earth, and is among the largest and most complex engineering projects in history. It can produce up to 100 million cubic metres of gas per day. The gas is driven to a processing plant by compressors, before being transported through pipelines to the European continent. HVDC Light is one of the ABB solutions being used to deliver electrical power to the oVshore installations, 2 x 40 MW compressor units. As well as doing that eVectively it has both lowered operating costs and reduced environmental impact by using renewable electricity from Norwegian hydro stations rather than fossil fuels to operate gas compressors.

5. How eVective is the current fiscal and regulatory regime in which the industry operates?

The importance of a co-ordinated approach

5.1 ABB is observing a growing demand for subsea electricity transmission systems to connect very large quantities of oVshore wind. This will result in the creation of HVDC links far out into the North Sea. Currently no UK plan exists to co-ordinate the construction of this electricity transmission system with interconnectors and electrification of oil and gas platforms. The current Regulatory regime for oVshore transmission does not consider the wider system requirements for a North Sea transmission system and as such is likely to result in sub-optimal transmission solutions for any future integrated North Sea Grid.

Observations from across Europe

5.2 ABB has observed that other European countries particularly Scandinavia endeavour to define longer term intergrated plans that consider oil and gas, renewables and electricity interconnectors to other European countries, to best serve their energy requirements and eYciently provide power to oVshore oil and gas installations. No such co-ordinated long term strategic view for an oVshore electricity subsea grid system appears to exist in the UK.

6. How are the skills needs of the sector being met? How transferable are those skills?

ABB’s involvement in developing skills

6.1 ABB is delighted to be involved with several UK universities, the Power Academy and the Power Sector Skills Steering Group on skills development and has recently reinvigorated its apprenticeship programme.

Meeting the UK engineering skills challenge

6.2 The UK is not alone in having a shortage of skilled engineers; it is a problem that exists across the world. ABB believes that the UK can gain competitive advantage in the new green economy if it invests in science and engineering. ABB believes that in order to deliver the innovative changes necessary for securing our energy future, a new breed of engineers is needed who are multi-skilled in a variety of disciplines. There is already an identified shortage of skilled engineers. It is important that government works with industry to provide the leadership and direction for improving the training and certification of our future workforce. ABB believes that industry and government need to work together to develop a fit for purpose skills and training strategy. This requires that industry and university establishments are much more closely aligned so that academic and theoretical learning is tuned to the needs of industry. It may also require that greater financial support—both public and private—is provided to engineering undergraduates and post-graduates. March 2009 Energy & Climate Change Committee: Evidence Ev 47

Memorandum submitted by AMEC

Introduction and Executive Summary 1. This evidence is being presented by AMEC plc to the Energy and Climate Change Select Committee for their forthcoming inquiry into UK oVshore oil and gas. The evidence covers three questions in the Terms of Reference. 2. AMEC plc is a focused supplier of high-value consultancy, engineering, and project management services to the world’s energy, power and process industries. With annual revenues of over £2.2 billion, AMEC designs, delivers and maintains strategic and complex assets for its customers. AMEC’s Natural Resources, Power and Process and Earth and Environmental businesses employ approximately 23,000 people in more than 30 countries globally. 3. AMEC is a leading provider of asset support to the oil and gas industry. Our engineers service more than 200 facilities each day in almost a dozen of the key oil and gas industry locations worldwide, including the Caspian Sea and south-east Asia as well as the UK North Sea. We have been providing innovative and high-quality project management, engineering and design for major oil and gas projects for more than 40 years. 4. We are leaders in “front-end” and project management services, using innovative technology and world-class engineering services to consistently deliver major projects successfully, safely and sustainably. We have a strong reputation for balancing global excellence with local delivery. 5. AMEC’s recommendations arising from this submission include: — Support to operators for development of marginal fields. — Support to operators on the integrity of ageing assets. — A proactive and, probably collective, approach to decommissioning.

How are the skills needs of the sector being met? How transferable are those skills? 6. The last two to three years have been challenging times in our sector. In the bid to attract and retain individuals with the skills and competencies required AMEC has tackled this from several diVerent angles. 7. Apart from the challenge of resourcing for immediate needs, AMEC’s approach included looking to the future needs of the sector. AMEC has been working with and partnering schools, colleges, universities and the Engineering Construction Industry Training Board (ECITB) to raise the awareness of the industry and oVering careers guidance, day in the workplace, work placements and year in industry opportunities to recruit apprentices and trainees. 8. Each year, AMEC set and meet targets for graduate intake to ensure that we grow talent for the future. 9. The immediate skills needs are met through a combination of recruiting from the existing resource pool, investment in developing existing talent, attracting talent from like and similar industries and recruitment from the global resource pool. 10. AMEC invest in training, employee development and upskilling the existing workforce by supporting sector initiatives and utilising in-house programmes. Working with the ECITB technical groups and recruiting trainees for Design and Draughting, Project Controls and Project Management qualifications. 11. In addition to supporting external initiatives, AMEC has invested in and developed a comprehensive suite of in-house programmes covering technical, project management, management and leadership development to build talent and capability for our future. This has also allowed us to recruit from other sectors including ex-forces, nuclear and downstream personnel by having the programmes available to bridge gaps in skills and knowledge. 12. Where there have been immediate skills shortfalls in the UK these shortfalls have been met by looking outside the UK and we have managed several successful recruitment drives overseas to supplement our UK workforce. 13. There is no doubt that the skills developed are transferable to other sectors and within the AMEC group we have successfully redeployed employees into other divisions.

What are the implications of an ageing existing infrastructure on the security of supplies from the North Sea? 14. According to Oil and Gas UK, the UK oil and gas industry will supply 70% of the nation’s energy needs in 2009 and if certain assumptions are met the UKCS could satisfy 65% of the country’s needs for oil and a quarter of total UK gas demand in 2020 (aggregate of 40% of total energy needs). Key assumptions are that investment in exploration and development activity will lead to the development of new fields contributing around 0.5 million barrels of oil equivalent per day (boe/d) by 2014 and that the ageing infrastructure will remain in operation to meet the processing and transportation requirements of the industry. Ev 48 Energy & Climate Change Committee: Evidence

15. Much of the North Sea oil and gas infrastructure, which currently enables the production of some 2.6 million boe/d, is at least 30 years old and has passed its original design life. To cope with this, industry has invested heavily in the past few years to upgrade facilities but it is forecast that over the next five years, in addition to the £10 billion investment already committed in sanctioned and existing projects, a further £16 billion will need to be invested to keep the facilities in service and maintain average unit operating costs at their current level of $14 per boe. Should this not be achieved, and unit operating costs begin to escalate it is likely that field operators will intervene by fundamentally changing their business focus to lower cost oil and gas basins and accelerating the decommissioning process in the UK. 16. Fundamental to the continuing success of the UK oil and gas industry is the availability of the infrastructure. This comprises the onshore terminals such as Sullom Voe, St Fergus and Bacton, main pipelines such as the Forties pipeline and the Brent pipeline and the oVshore facilities of which there are 288 fixed and floating production installations the majority of which are more than 20 years old. Not only do these facilities support the production for the fields that they were first intended for but they also act as infrastructural hubs and also process and transport petroleum from satellites tied into the host through sub- sea facilities. 17. The ageing process is common to all the component parts of the infrastructure. It takes the form of structural fatigue of pipelines and platforms, accelerating pipe and vessel corrosion brought about by increasing levels of carbon dioxide and hydrogen sulphide in production fluids and a lack of reliability and availability of rotating equipment such as pumps, power turbines and compressors. To combat these issues, increased levels of maintenance, operating expenditure and investment coupled with longer periods of facilities shutdown will all be required. Without such action, security of supply will be compromised. 18. A key aspect of the ageing production facilities are that many of the component parts are being operated on near to their design limits. For example, export pumps originally designed to handle 100,000 barrels of oil per day are being used to ship less than 10,000 barrels per day on some installations. This makes for ineYcient usage, higher costs per barrel shipped and a propensity to failure of internal components. 19. A key risk to the security of supply would be the impairment of a major pipeline such as the Forties Pipeline which currently transports around a third of the 2.6 boe/d produced in the UK. Another risk is that should the pace of reserves replacement not keep up with the overall reservoir decline rates (estimated to be around 15% per annum without further capital investment) unit operating costs could rise to levels that bring about the onset of the decommissioning process thus losing the opportunity to develop and produce up to nine billion boe using existing facilities. The consequences will be, that unless oil prices are significantly higher than the current $50/bbl, much of the known and as yet undeveloped oil will be declared non commercial. 20. In conclusion, whilst it is apparent that the ageing existing infrastructure will have a bearing on the security of petroleum supply from the North Sea, the eVects can be mitigated by ensuring that a balanced approach to the Exploration and Development of the basin is maintained. This will involve ensuring that wells are drilled in suYcient numbers to prove and produce the petroleum, new “fit for purpose” facilities are designed and installed and suYcient resources are expended to retain key elements of the infrastructure in a safe, eYcient and environmentally compliant working order.

Is the right policy framework in place to manage the decommissioning of that infrastructure as resources are depleted? 21. From AMEC’s perspective there are two key areas within the decommissioning guidance notes issued by DECC that are of particular interest, these being the timing of decommissioning projects (ref para 5.18), and industry co-operation and synergy (ref para 17). 22. The industry has, for a number of years, been predicting a large wave of decommissioning projects coming to market. However during that time the start dates for these projects has steadily slipped back, and the market has not developed as expected. A number of factors have caused this slippage; new entrants being able to maintain production at lower costs, new technologies increasing oil recoveries, and increased oil prices keeping marginal fields economically viable. The uncertainty of when the decommissioning market will develop has resulted in limited investment in technologies and capabilities, and it is a concern that this low level of development will continue until the wave of projects is upon us, whereupon demand will likely exceed supply, especially if DECC requires removal of redundant installations as soon as practicable after cessation of production. 23. To address the potential problems of inflationary cost pressures in the decommissioning market, and large numbers of decommissioning projects being delayed due to lack of resources, a collaborative approach would be very beneficial. At present operators are looking only at their own portfolios, and do not appear to be actively working with DECC and other operators to develop a consolidated predictable programme of projects. If such a structured programme of work were made available to the industry, investment and innovation would be greatly enhanced, and costs would be driven down. Particularly new entrants with more cost eVective marine heavy lift technologies would be better able to justify major investment decisions, and the industry would reduce its reliance on the current limited (and ageing) heavy lift vessel fleet. Energy & Climate Change Committee: Evidence Ev 49

24. Looking at potential synergies with contractors’ business models would also be beneficial. There are growing capabilities by contractors such as AMEC to become Duty Holder for production facilities, which if taken on at late life of an asset, prior to cessation of production, would allow the contractor to prepare more eVectively for the decommissioning work, reduce uncertainties and minimise costs. March 2009

Supplementary memorandum from AMEC Thank you for your recent invitation to oVer our view on the 2009 Budget changes in relation to the oil & gas industry and their likely eVectiveness in stimulating economic activity. As you will no doubt be aware, AMEC is a significant player in the supply chain of this industry and a substantial employer both in the UK and worldwide. Ours is a people business (employing over 22,000 globally—7,000 of them in the UK) and as such we have a keen interest both in the wealth and jobs created by a healthy industry. We oVer the following comments in relation to Budget Notes BN09 & BN10 which pertain to the North Sea Fiscal Regime.

1. BN 09—Facility Change of Use We applaud the changes in relation to RFCT & PRT intended to stimulate change of use of existing facilities. We trust this will remove some of the obstacles our clients currently face in such a change in business case. In relation to the objective here (which we understand address the questions of both security of supply & economic activity) we would highlight a related practical consideration—that being the physical condition and integrity of oVshore installations which have operated in a hostile saline environment, many for in excess of 20 years. Most of these installations therefore face a substantial maintenance cost burden. We believe that the measure suggested in point 3. below would act in a complementary manner to the current fiscal changes in pursuit of these objectives by encouraging re-investment in the longer term integrity of existing facilities.

2. BN 10—Incentivising Production Again we applaud the initiative to introduce a Field Allowance provision to encourage developments— clearly such relief will oVer some encouragement to develop certain technically and economically challenged fields. The eVectiveness of this stimulation on the real economy remains to be seen and we trust that DECC, HMRC and the government will remain open to considering extending the scope of the allowance to other marginal developments. We note also that whereas certain other UK developments remain economic without the Field Allowance, they compete for finance in a global market. The limited scope of the allowance has done nothing to improve favourability for UK oil & gas developments in a completely transferable and comparable business.

3. Cessation of Production (CoP) Optimisation—Late Life Field Allowance It is clear that stimulus eVect of measures BN09 and BN10 will have some time lag before any benefits are felt in the real economy. However it is clear that the industry (and its underpinning fiscal regime) must urgently address the question of low oil price and cash flow in this mature basin if irreparable damage to future reserves and security of supply is to be avoided. The following suggestion is a prompt tactical response which, if implemented, will quickly serve to increase activity, safeguard the long term integrity of facilities and thereby safeguard the ability to produce future reserves through existing infrastructure. Critically, it will have no adverse impact on the exchequer (beyond that already being felt through low oil price). We recommend that the 2009 Field Allowance provision be extended to include Redevelopment Plans for existing operating fields scheduling CoP. In the current environment, protracted low oil price oVers an unhealthy cash flow situation whereby the predominating consideration in CoP scheduling is deferral of decommissioning cost rather than facilitating production of adjacent or infill reserves. The value allowance for a specific field could simply be determined based on the incremental cost (both capex & opex) required to achieve a redevelopment production profile. CoP strategies submitted to DECC could form the baseline cashflow position and therefore there would be little extra workload on either operating companies or government bodies. Ev 50 Energy & Climate Change Committee: Evidence

Fields which would otherwise have permanently terminated production would make a continuing Corporation Tax contribution while simultaneously extending infrastructure life for adjacent reserves. Available cash could then be re-invested in UK developments. Up front capital investment for such redevelopments will be comparatively small, thus project value/ investment ratios will stand healthy comparison with international project ranking.

4. Decommissioning We note the government/HMRC decision not to act upon Oil & Gas UK’s recommendations in relation to decommissioning security (letter dated 3 April 2009). We also reiterate AMEC support for the proposed industry body Decom North Sea and look forward to participation in the dialogue to achieve a world leading decommissioning industry—clearly the fiscal regime plays its role in this. We believe that improved preparedness for decommissioning within this basin is essential if an expensive and ineYcient decommissioning phase is to be avoided. Indeed, uncertainty around the decommissioning process and caution towards cost provision may very well be tying up cash unnecessarily and inhibiting the development investment we all want to see in the UK industry. We trust you find the views above helpful and constructive. March 2009

Memorandum submitted by BG Group

Executive Summary — One of the most active companies in the UK Continental Shelf (UKCS), BG Group believes that the UKCS continues to oVer significant upstream opportunities but hydrocarbon production from the province will only be maximised, if there is the right fiscal, regulatory and investment climate. — Hydrocarbons that amount to as much as 25 billion barrels of oil equivalent (boe) could still be produced from the UKCS—compared to 37.5 billion produced to date. — Liquefied natural gas (LNG) imports can contribute significantly to the UK’s security of gas supply. — Once two new LNG terminals are operational, the total capacity of the UK’s three LNG import terminals will be equivalent to one-third of the country’s current gas demand. — HM Treasury’s outline proposal of a Value Allowance, allowing relief from Supplementary Corporation Tax (SCT) for certain kinds of fields, could lead to security of supply benefits with oil and gas volumes that would not otherwise have been produced becoming commercially viable. — BG Group believes that high pressure, high temperature (HPHT) fields that are expensive to drill and technically challenging and small field discoveries close to existing infrastructure could benefit in particular from a Value Allowance and the company has submitted to HM Treasury a worked proposal, outlining how this might work. — In the medium to longer term, HM Treasury might want to consider abolition of SCT—a move that would bring tax treatment of the oil and gas industry more closely in line with that of other industries—though this would require safeguards around capital expenditure relief. — Uncertainty around the legal and regulatory framework for decommissioning is restricting commercial activity. — There is a need for the obligation for industry to meet all decommissioning liabilities to be coupled with a legal and regulatory framework, which is both clear and demonstrably fair to all licensees and which will facilitate the process of licence transfers in future.

Background BG Group is an international natural gas company, active in 27 countries across the world. The company’s centre of gravity lies in upstream exploration and production but it works right along the gas- chain and aims to link equity and contracted gas resources to high value markets. The strength of its position in liquefied natural gas (LNG) means that BG Group has considerable flexibility in where and when it can deliver volumes. Despite the rapid internationalisation of the company’s business over the last two decades, the UK is still responsible for around 25% of total Group production. BG Group is one of the most active players in the North Sea, responsible for the equivalent of around 7% of UK gas production. Its total oil and gas production in 2008 was 61 million barrels of oil equivalent (boe). The company’s combined capital Energy & Climate Change Committee: Evidence Ev 51

investment and operating spend in the UK upstream were in excess of £650 million last year and are expected to be around £675 million this year. Despite the fact that the UK Continental Shelf is now a mature province, BG Group believes that its levels of investment in UK and Norwegian waters will enable it to continue producing at least 50 million boe per annum from the North Sea out to 2013 and beyond. BG Group is one of the most active explorers in the UKCS, drilling around eight major exploration and development wells on average per year and establishing a strong track record of discovery successes. For example, BG Group is the company that drilled the exploration well, which led to the discovery of the Buzzard oil-field—the largest discovery in the North Sea for a decade. BG currently has a 22% equity share of Buzzard. This field, which came onstream in 2007, is producing in excess of 200,000 boe on an average day. The company has also found oil and gas in its last three drilling operations in Norway and, over time, those hydrocarbons are likely to come to the UK or Continental European markets. BG Group’s Dragon LNG import terminal, which it shares with Petronas, will be open for business at Milford Haven in West Wales in the next few months.

The Extent of the UK’s Oil and Gas Reserves and the Contribution these can make to the UK’s Future Energy Needs In our view, the best estimates of the remaining potential of the UKCS come from the upstream industry’s umbrella body, Oil & Gas UK, which pools information from across member companies. Their calculation is that the province has produced 37.5 billion boe over the last 40 years. Their estimate is that it is capable of producing another 25bn boe of oil and gas. Company business plans already suggest that the first 10 billion should be accessible—just over 6bn from existing fields and sanctioned projects and around 3.5 billion from new fields and brownfield projects. The ability of upstream companies to produce the remaining 15 billion is more questionable and will depend on the degree to which exploration activity is encouraged and sustained and the climate for investment that prevails. Too often the impression that has been given has been that there is little left in terms of North Sea reserves. The figures we quote above make it clear that this is not the case. The UKCS still produces around 70% of the country’s natural gas requirements with imports accounting for the rest. It is the case that that figure will decline significantly over the next decade or so—the former BERR forecast that the figure would be between 20% and 25% of demand met by indigenous gas by 2020— but the pace at which UKCS production decreases will be highly dependent on the investment climate. The graph below shows the Oil & Gas UK view that production could amount to as little as 12% by 2020; in contrast, with the right incentives, production could continue to meet around 40% of demand.

An energy crunch may be coming: Maximising UKCS recovery has never been more important

3.5 The future of the UKCS: a tale of two futures DTI Energy Review Forecast 2006 3.0 UK Oil & Gas Demand Minus BERR Renewable 2.5 Energy Target

2.0

The Better Future 1.5 ~40% UK demand in 2020

million boepd UKCS Oil & Gas Production 1.0

0.5 Existing Production Base 12% UK demand in 2020 0.0 2007 ‘08‘‘‘ ‘09 ‘10 ‘11‘‘‘‘‘‘ ‘12 ‘13 ‘14 ‘15 ‘16 ‘17‘‘‘ ‘18 ‘19 ‘20‘

Source: DECC / National Grid / Oil & Gas UK Ev 52 Energy & Climate Change Committee: Evidence

Natural gas is the cleanest of the hydrocarbons, producing 22% less CO2 than oil and 40% less than coal on combustion. As such, it will play an important role in acting as a bridge to a low or no carbon future. It has been acknowledged in the course of the climate change debate, that the substitution of natural gas for dirtier hydrocarbons in power generation can play an important part in the global bid to reduce carbon emissions. Given the unpredictable pace of development of renewables, the need to decommission a significant percentage of existing UK coal and nuclear fired generation in forthcoming years and the long lead time required for new nuclear power stations, large quantities of natural gas will be required to fill the gap. Given that the UK could be between 70%1 and 80%2 reliant on oil and gas to meet its primary energy needs3 in 2020, it is important to maximise indigenous production of hydrocarbons.

Security of Supply and LNG The UK Government should not underestimate the contribution to security of gas supply that LNG imports can make to the security of gas supply position in the UK. The next few months will see a major addition to the UK’s LNG import capacity with the opening for business of the Exxon/Qatargas South Hook terminal and the BG Group/Petronas Dragon LNG terminal. The Dragon terminal in Pembrokeshire will have the capacity to handle 2.2m tonnes of LNG a year. Between them, these three LNG terminals have the capacity equivalent to one-third of the UK’s annual gas demand at current levels. LNG developments will both add to the UK’s security of gas supply and reduce the percentage of gas storage capacity that the UK will need, compared to other EU countries with lower levels of indigenous gas production.

Fiscal Incentives In BG Group’s view, by introducing new players through revision of the licensing arrangements, the UK Government has taken an important step in opening up the basin; but, to win international capital, the investment environment must be competitive and attractive. The UK has much to oVer international investors: high quality skills, political stability and established oil and gas infrastructure. However, the fiscal regime must also be such that the risk-reward equation for new exploration and development is attractive compared to the international opportunities available to investors. Although oil and gas companies prospered during the period of high oil and gas-prices, now that prices have fallen back, the impact of the 20% Supplementary Corporation Tax and the additional 2% Corporation Tax—which apply only to oil and gas companies—is particularly significant, rendering a large number of discoveries uncommercial. During HM Treasury’s series of recent consultations on North Sea tax reform, BG Group’s initial preference for reform was a 25% uplift on capital allowances. Our view was that this would encourage activity and lead to more discoveries. This could be applied across the board for new exploration and/or developments or it could be targeted on certain kinds of fields with a view to bringing into play discoveries that were particularly challenging to develop—either technically or commercially. We understand HM Treasury’s principal reservation about such a proposal: namely, that it ran the risk of oVering this incentive without having any guarantee of additional hydrocarbon production. For that reason, BG Group was happy to work up a proposal around HMT’s preferred Value Allowance option. BG Group believes there are two types of fields in particular where real potential exists for a Value Allowance to deliver significant security of oil and gas supply benefits: high pressure, high temperature (HPHT) fields and small fields. HPHT fields are defined as those which have a reservoir temperature of in excess of 300) F and a wellhead pressure of in excess of 10,000 psi. These are extremely costly to drill but they can contain large volumes of oil and gas. For example, the initial reserves estimate for a recent BG Group HPHT discovery, Jasmine, are 130–240mmboe—a significant discovery. BG Group is one of the leading companies in HPHT operating in the North Sea at present. BG Group’s interest in small fields relates to prospects and discoveries that are near existing hubs of activity and which can often be linked to existing infrastructure and brought onstream. The fact that such fields can be developed using existing infrastructure rather than requiring their own new infrastructure can often make the diVerence between a discovery being commercially viable or non-viable.

1 Oil & Gas UK estimate 2 Dept of Energy estimate is “up to 80%” 3 Primary energy needs includes fuel for industrial usage, heating and transportation—not just fuel for power generation Energy & Climate Change Committee: Evidence Ev 53

We know from specific examples within our own portfolio that properly designed Value Allowances, oVering relief from SCT for certain kinds of field, would turn some marginal prospects and discoveries into commercial opportunities. This would generate additional oil and gas volumes that would not otherwise be produced. We submitted our proposal to HM Treasury ahead of the February 13 deadline and we are hoping that a Value Allowance scheme similar to that proposal will be announced in the Budget in April of this year. Another area of discussion between government and the industry in recent months has been Enhanced Oil Recovery (EOR). Ministers and oYcials acknowledged that thinking on EOR and research into relevant technologies are not suYciently advanced for this area of activity to be included in the current consultation on North Sea tax reform. BG Group would argue that enhanced natural gas recovery needs to be considered in parallel with EOR and that the goal should be techniques for enhanced hydrocarbon recovery rather than just EOR. It is highly likely that enhanced hydrocarbon recovery will require further adjustments to the tax-regime to make it viable. A debate around these issues should start now. Given the high oil-price environment that prevailed until the last few months, we understand why there was little appetite in HM Treasury and the Government for more radical reform of the North Sea tax-regime ahead of the 2009 Budget. However, HM Treasury may want to consider further measures in the medium and long-term, as the province’s challenges become greater and the technical and commercial challenges of finding and developing new hydrocarbons become more diYcult. One option HM Treasury may wish to consider over time is abolition of SCT, bringing the oil and gas industry in line with the rest of industry. This would mean CT being payable at 28%—a move that would be certain to release additional hydrocarbons from discoveries that are currently uncommercial because of the SCT regime. However, such a move would require certain safeguards in relation to capital expenditure relief. While it might be acceptable to oVer relief on capital expenditure at the reduced rate on new developments, it would not be acceptable in relation to past and existing developments, given the large amount of sunk costs and the eventual requirement to decommission them. The solution would be to lock in capital expenditure relief at the rate at which tax was paid on the income from those assets. This would mean a guarantee that decommissioning on PRT fields would be relieved at 75% and at 50% for CT/SCT fields only. While SCT abolition might appear at this stage in the cycle to be a radical option, it is essential in the medium and long term that measures are taken to maximise North Sea production, if we are to maintain and retain the existing infrastructure required to land as much oil and gas as is economically possible.

Partner Alignment and Department of Energy “Intervention” One of the principal challenges facing a company active in oil and gas exploration is gaining the backing of partner companies to proceed with exploration and development programmes. This challenge is heightened in a mature province like the UKCS because some partners may have priorities in other basins on which they would rather focus. The current global credit “crunch” and economic downturn is also having an impact, dulling many companies’ appetites for investment and risk. There is no simple solution to this problem but we have noted and we welcome the inclination of senior oYcials formerly in the DTI and BERR—now in the Department of Energy and Climate Change—to intervene and encourage companies to support activity or release their equity in relevant blocks. Although sometimes this is carried out formally through schemes such as the Fallow Initiative, on other occasions it has been pursued more informally. As an active player in the North Sea, this approach has tended to be helpful to BG Group. We do not believe that oYcials need further legislative or other regulatory powers to underpin this intervention but we welcome the trend and believe it has a positive impact on activity levels.

Asset Integrity, the Challenge of Ageing Infrastructure and Decommissioning The oil and gas industry in the UKCS has been particularly successful at maintaining and extending the life of its fields and assets. It is not unusual for oVshore infrastructure to continue to operate between 10 and 20 years longer than initially envisaged. Asset and field-life extension will continue to be a focus, as companies gain more and more expertise at extracting as much oil and gas as they can from their fields. This activity has to be carried out safely so, as assets age, more investment is needed to maintain the integrity of those assets and to ensure that all of those who work in the industry do so safely. With ageing assets, there is an increasing risk that infrastructure failure may suddenly jeopardise the economic viability of a suite of dependent installations. In the future life of the province, there are also limited numbers of developments that will be able to justify their own “greenfield” infrastructure to bring hydrocarbons to the beach. This means that there is likely to be ongoing and perhaps increasing pressure on existing infrastructure to handle and process new oil and gas finds. Ev 54 Energy & Climate Change Committee: Evidence

In BG Group’s case, our intention is to focus our activity around hubs. This means that we will seek eYciencies by using existing platforms and pipelines to land the product of new discoveries. However, in the event of a requirement to decommission part of our existing infrastructure, there will be a need for the remaining infrastructure to work harder. This will mean additional capital and operating costs to ensure that that infrastructure can continue to function eYciently and safely. There is a case in such instances for additional relief on this additional expenditure to be made available. BG Group would also urge the Department of Energy to introduce more clarity and certainty to the position relating to the decommissioning of assets. BG Group supports an active, transparent and eYcient asset-trading regime in the North Sea. One important area where, in our experience, the process of licence transfers has become slower, more expensive and more complex in recent times is with respect to legacy decommissioning liabilities.

We understand the obligation on DECC to ensure that all decommissioning liabilities are met by industry but we believe that this obligation should be coupled with a legal and regulatory framework, which is both clear and demonstrably fair to all licensees. Increased clarity will greatly facilitate the process of licence transfers in future.

We support the initiative taken by DECC in clarifying the existing law relating to infrastructure owners on multi-block licences in the Energy Bill and we are also in favour of further guidance with respect to the application of liabilities imposed under the Petroleum Act. We would welcome a statement by DECC as to when and how it would seek to apply the existing regulations in S.29 and S.34, requiring former licensees to undertake a decommissioning programme.

At this point in time, we do not fully understand how this fundamental principle in the decommissioning regime would be applied in practice. This uncertainty tends to restrict commercial activity, with some companies reluctant to take on assets, which they will then become liable to decommission. We believe further detail as to the application of this process will benefit the industry by: — Reducing the level of security required by transferors. — Simplifying commercial negotiations. — Speeding up the time required to execute transfers.

This in turn should help increase the number of participants in the UKCS by reducing costs and maximising ultimate recovery of hydrocarbons. March 2009

Memorandum submitted by BP

Introduction

1. Since the origins of oil and gas activities in the United Kingdom Continental Shelf (UKCS), BP has remained one of the largest and most committed investors in the Province—a position we wish to continue. At the end of 2008, we had an estimated resource base of some three billion barrels of oil equivalent (boe) still to be recovered from the North Sea as a whole, most of which is in the UKCS. We operate 31 producing fields in the UKCS and have two major decommissioning projects currently underway. BP’s total expenditure in the UKCS (capital and operating expenditure) was some £1.5 billion in 2008, and we expect to maintain investment at this level over the next few years.

2. While there is significant remaining potential within the UKCS—Oil and Gas UK estimates that there are up to 25 billion boe to be recovered, although only around 10 billion boe of this total has been identified in defined projects—there are massive challenges to be overcome if this potential is to be realised. Fundamentally, these challenges derive from the inescapable fact that the UKCS is now a very mature basin where the relentless pressure from declining field sizes, falling production and rising costs is undermining the economics of the remaining opportunities. It is only prudent to assume that maintaining production from existing fields oVers the best chance of extending the life of the UKCS, given their critical role in extending the life in the infrastructure legacy.

3. Even with the oil price at high levels, the UKCS must continuously battle to reduce costs in order to remain competitive with other global opportunities. At today’s oil price, this battle translates itself into a struggle for survival. With this as background, our comments on the issues raised by the Committee of special relevance to BP’s expertise and experience are as follows. Energy & Climate Change Committee: Evidence Ev 55

How can the UK’s remaining oVshore oil and gas reserves be exploited most eVectively? What barriers are there to exploiting such reserves?

How eVective is the current fiscal and regulatory regime in which the industry operates?

4. We address these two questions together, because in many ways the fiscal and regulatory regime constitutes one of the biggest “barriers” to exploiting UKCS reserves. This is not to imply that, in recent years, the UKCS Fiscal Regime has been draconian or uncompetitive in global terms. The diYculty is that it has not adapted suYciently to the needs of a mature basin. One of the characteristics of a mature basin is that geologically and commercially, every aspect of the operation becomes much more diYcult. Many of these aspects are beyond human influence; but this means that those which are capable of adjustment (i.e. regulatory and fiscal) become even more significant. 5. The key factors for maximising the potential of these remaining reserves are: — The safe and eYcient operation of existing producing fields to achieve the highest possible recovery of oil and gas from individual reservoirs. — Continuing significant capital investment at suYcient levels to extend the life of existing onshore and oVshore infrastructure and to find and develop new prospects. — A competitive and less complex fiscal regime which recognises the growing challenges facing the North Sea industry and the need to reduce the tax burden on a sustainable basis as the basin continues to mature. 6. The major barrier to exploiting the remaining reserves is the risk that declining production—combined with rising costs, low oil and gas prices and the legacy of a high tax burden—all together constitute a business environment which increasingly threatens the North Sea’s competitiveness. This would put at risk the investment required to sustain activity levels in exploration and appraisal, new field development and extracting more oil and gas from existing fields. 7. We now face this situation in the UKCS, as evidenced by the recently published Oil and Gas UK 2008 Activity Survey which forecasts a reduction in capital investment, exploration drilling and new field development in 2009 and 2010. Only a third of new developments currently under consideration “break even” with the current cost base and tax regime, should oil prices stay in the $40 to $50 per barrel range. 8. The area west of Shetland demonstrates the point dramatically. Here, BP operates the first, and currently only, fields in production—the deepwater Foinaven and Schiehallion fields and the Clair field. We are currently appraising the potential for further development of the Clair field and continued development of Foinaven and Schiehallion through infill drilling programmes and the identification of satellite development opportunities. 9. Many of the other discoveries which have been made West of Shetland are marginal and BP believes that a reduction in the fiscal burden is required if more of the potential west of Shetland is to be unlocked both from new discoveries, existing undeveloped discoveries and fields in production. The Government’s proposed Value Allowance mechanism only partially addresses the basin challenges as its scope is limited exclusively to certain narrowly defined categories of new fields. It is important that investment incentives are also made available to encourage investment in existing fields and should be applied as widely as possible, including west of Shetland. 10. Overall, the current fiscal regime provides a legacy of complexity and imposes a tax burden which is inappropriate to the increasing maturity of the basin. When oil prices were last at current levels (in 2004), production levels were higher, and both costs and taxes were lower. The Government’s recent proposals, including a Value Allowance to be set against SCT, are welcome but on their own will prove to be a wholly inadequate response, given that they were developed at a time when the oil price exceeded $100 a barrel. The proposal risks fragmenting the fiscal regime by the introduction of a wide range of fiscal burdens according to the nature of the potential development opportunity. Value Allowance by itself cannot make the material diVerence required in the current economic and oil price environment. It will also further complicate the already excessively complex fiscal regime, counter to BP and industry advocacy of simplification and the desired move towards a level playing field for investment decisions. A more appropriate fiscal reform would be a straight forward and significant reduction of the rate of SCT, which would achieve more eVectively and simply the objectives held out in the Value Allowance proposal. 11. If, however, current financial constraints rule out this option (remembering that there are ways its costs could be contained and postponed)—and if Value Allowance is all that can be oVered—then the Allowance should be made large enough to make a diVerence, and should be applied as broadly as possible with a focus on existing fields which are uncompetitive in a $40 oil world. More importantly, incentives must be made available to encourage incremental investment options in existing fields through the provision of capital uplift. 12. Thus, our fiscal preferences are: — A material reduction in the rate of SCT (back to the level when oil was last at $40). Ev 56 Energy & Climate Change Committee: Evidence

— A capital uplift to facilitate new investment in existing fields. — For new fields, a value allowance with qualifying criteria as broad as possible (including all new fields west of Shetland).

What can be done to minimize the environmental impact of exploiting the reserves? How should this be encouraged and/or financed? 13. It is a constant priority and principle of our continuing operations within the UKCS to minimize the detrimental environmental impact of our activities. This is part of our overall obligations which we have shouldered voluntarily, irrespective of what is or is not dictated by external legislation and regulation. 14. That said, policy makers need to be mindful of the extent to which the operation of the EU Emissions Trading System in Phase III is likely to have an increasingly negative impact on ultimate recovery levels throughout the UKCS. This would be the direct consequence of the higher field level operating costs associated with a progressive move towards increased auctioning of allowances. It should be noted, in this context, that these costs cannot be passed on to consumers due to the global nature of the oil market. Oil and Gas UK has recently estimated that if there were to be a requirement for the UK oil and gas industry to buy all of its allowances at auction under ETS Phase III (the ultimate EU ambition), it could result in the loss of up to one billion barrels of UK oil and gas production. 15. For some installations, the reality of 100% auctioning is imminent. As a consequence of the requirement that all emissions associated with electricity generation are to be denied any free allowances in phase III of the EU ETS, it is estimated that a number of BP’s installations will be obliged to purchase in excess of 90% of their required allowances from the very start of Phase III in 2013. 16. The unfortunate reality is that this significant loss to the UK economy (and in terms of Security of Supply) would provide no global environmental benefit as the shut in production would merely be replaced by other production from elsewhere in the world, quite possibly with a greater CO2 footprint.

Conclusions 17. We have concentrated on those questions raised by the Committee which we feel are of special importance to BP and where we have something distinctive to contribute. This is not to minimize the importance of the other areas; but in terms of current realities, we concentrate on those areas which have maximum importance and where we believe the Government has the greatest discretion to bring about improvements. March 2009

Supplementary memorandum submitted by BP

Introduction 1. In our original submission to the Committee dated 3 March 2009, we stated in respect of the United Kingdom Continental Shelf (UKCS) Fiscal Regime that a reduction in the fiscal burden was required if more of the potential from the UKCS—and from west of Shetland in particular—was to be unlocked from new exploration and discoveries, existing undeveloped discoveries and fields in production. 2. We said we expected the Government’s proposed Value Allowance mechanism only to address partially the basin challenges since its scope apparently was to be limited exclusively to certain narrowly defined categories of new fields. In contrast, we argued that it was important that investment incentives should also be made available which encouraged investment in existing fields and which should be applied as widely as possible, including west of Shetland. 3. In general, we argued that the current fiscal regime provides a legacy of complexity and imposes a tax burden which is inappropriate to the increasing maturity of the basin. We feared that the Value Allowance Proposal, while not having any significant eVect upon activity, would risk fragmenting the fiscal regime by the introduction of a wide range of fiscal burdens according to the nature of the potential development opportunity. Any further complication of an already excessively complex fiscal regime seemed to be moving in the wrong direction. 4. We summarised our fiscal preferences as follows: — A material reduction in the rate of SCT (back to the level when oil was last at $40) — A capital uplift to facilitate new investment in existing fields — For new fields, a value allowance with qualifying criteria as broad as possible (including all new fields west of Shetland). Energy & Climate Change Committee: Evidence Ev 57

The 2009 Budget 5. It should come, therefore, as no surprise when we conclude that the provisions in the Budget will fail to have any significant eVect upon BP’s planned activity levels in the UKCS. We do not oppose the Value Allowance, now defined as Field Allowance, as formulated in the Budget; but it does not go nearly far enough to assist our own activities or indeed, we would argue, the wider interest of the Industry and the nation. 6. In particular, the absence of any fiscal assistance for fields currently in production—and for the area west of Shetland—deprives both BP and, we believe, the industry as a whole of the fiscal incentive which might mark a significant improvement in today’s diYcult conditions. The sharp fall in UKCS platform drilling activity already witnessed during the first quarter of 2009 will soon translate into accelerated production declines in those fields where infill drilling has been reduced or ceased. 7. We also note with concern and disappointment the excessively high qualifying criteria for the Field Allowance, especially in respect of HPHT. If unaltered, we expect that this measure will have a negligible impact on UKCS investment. Indeed, it seems that only one HPHT undeveloped discovery in the North Sea satisfies the stipulated temperature and pressure criteria, both of which must be met in order to qualify. It certainly won’t aVect BP’s behaviour as none of our five HPHT discoveries meets this onerous criteria. The reality appears at odds with the Chancellor’s statement that the Field Allowance would encourage the development of up to a further two billion barrels of oil equivalent. If the Government had accepted Industry’s proposals in respect of the HPHT qualifying criteria, this measure could have made a significant medium term diVerence to industry investment. As it stands, this appears impossible.

Conclusion 8. There is still a material risk that UKCS investment will fall sharply over the next couple of years. While this is not related exclusively to the Fiscal Regime, it is clear from BP’s perspective that the Budget’s fiscal package will make no diVerence to our own investment plans. We expect the same applies to the industry as a whole. 9. We welcome the accompanying technical measures in other areas which have been the subject of extensive consultation ie the changes to the chargeable gains regime, to the regime governing the re-use of North Sea infrastructure for non ring-fenced purposes, the amendments to the PRT regime, and the clarification regarding cushion gas in gas storage facilities. These were necessary improvements for which we are grateful. Unfortunately, however, they are not material in terms of encouraging additional investment. May 2009

Memorandum submitted by the British Rig Owners’ Association

Executive Summary The British Rig Owners’ Association represents mobile oVshore units which include both drilling rigs and accommodation units. We believe that mobile oVshore units have an important role to play in the eVective and sustainable future exploitation of the UK’s hydrocarbon reserves, and that regulatory and fiscal mechanisms must be appropriate in order to enable this to occur.

1. Introduction 1.1 We, the British Rig Owners’ Association (BROA), are an industry association representing owners and operators of mobile oVshore platforms, of various types, in the North Sea. The fleet belonging to our membership includes drill ships and FPSO’s, maintenance platforms and accommodation units. Although analogous in many regards with fixed platforms, the needs and capabilities of mobile units are specific and unique in various areas. Below, we address each of the seven questions which you posed highlighting those issues which are particularly pertinent to the mobile units we represent.

2. Responses to Specific Questions

2.1. How can the UK’s remaining oVshore oil and gas reserves be exploited most eVectively? What barriers are there to exploiting such reserves? What steps need to be taken to unlock resources west of Shetland? 2.1.1 The primary determinant factor in the exploitation of further resources is the economic viability of doing so. When considering this, it must be borne in mind that the safety of personnel involved in the operation and levels of certainty regarding the future financial and fiscal climate are key controlling parameters. Where there is a necessity to develop new technologies for a specific task, a high capital cost is usually involved and, particularly in the current economic environment, this is associated with a high risk Ev 58 Energy & Climate Change Committee: Evidence

if any unnecessary uncertainty exists in the operating environment. While the UK’s mobile oVshore units are well suited to exploratory work, they are subject to a unique range of legislation, fiscal and regulatory concerns where certainty is needed in order to encourage further development. Low oil prices are a barrier to exploiting the UK’s remaining reserves and while a short period with prices at current levels will probably not have much eVect, if prices stay low for a prolonged time then smaller operators may be forced to abandon some of the more marginal fields without exploiting the last pockets of oil and gas. It should be noted, in the context of the points above that operations west of Shetland are in harsh environmental conditions and rigs and production facilities capable of operating safely in such conditions are more expensive both to build and to operate.

2.2. What can be done to minimise the environmental impact of exploiting the reserves? How should this be encouraged and/or financed?

2.2.1 It should be noted that the industry has a strong commitment to environmental management and the minimisation of unwanted impacts; this has been demonstrated in recent years by the employment of an increasing number of environmental specialists within the sector. In turn, this has led to a growing understanding of the subjects involved and an ability to maintain good currency amidst a field of developing knowledge. Technology plays a major role in controlling environmental impact, which is highly dependent upon the operations in question where mobile units are concerned. 2.2.2 Absolutely central, however, to ensuring a low impact on the environment is a clear understanding of the diVerent potential impacts, their severity and relation to each other. This is a broad oceanographic question and specific to the geographical area of operation. Among other considerations are the eVect of localised interventions on wider ecosystems, the behavioural response of organisms found in the area and the expected action of winds, tides and ocean currents in the area. In general, the environmental impact on the local area of extraction is believed to be low, however the provision of clear information as discussed above from the wider scientific community to the specialists within companies may assist in ensuring this. It should be noted that detailed environmental assessments already form part of the decision making process when choosing locations. Furthermore, the provisions contained within the impending Marine Bill are believed to provide a robust framework which will ensure the environmental appropriateness of exploitation. 2.2.3 Mobile units have already been steadily upgraded over the years to reduce environmental impact, particularly in terms of lessening the probability of hydrocarbon spills. In addition, it should be noted that mobile units are also classed as ships and so are subject to the full range of environmental legislation emanating from the International Management Organization (IMO) including the ISM Code which places upon vessel owners the responsibility for “continuous improvement”.

2.3. How eVective is the current fiscal and regulatory regime in which the industry operates?

2.3.1 It has been previously mentioned that mobile oVshore units are subject to a unique regulatory regime. When on station and operating, they fall under the authority of the Health and Safety Executive, as do fixed installations, but at other times they are within the remit of the Maritime and Coastguard Agency (MCA) and international regulations for ships. BROA maintains continuing and positive interaction with both the HSE and the MCA, and addresses issues directly with them. However, there are some areas where the certainty which is so required by operators appears to be lacking, or where decisions are made which appear to be disproportionate or unwarranted while resulting policies are implemented without statutory support. There is no doubt as to the technical competence of the HSE and the MCA to provide an eVective and positive regulatory regime, but both appear to be suVering from resourcing issues, in particular staV numbers, at the current time. Discussions and debate regularly focus upon the chargeable element of the HSE’s work, the proportionality of the charges and the subsequent use of the finances thereby acquired. It should also be realised that a number of BROA’s members are becoming increasingly involved in the oVshore renewable energy sector and it appears that there is a lack of regulatory equality in such work between those who do and those who do not also engage themselves in the oVshore oil and gas industry, where those who do must comply with a significantly more strenuous regulatory regime. 2.3.2 Where the fiscal regime is concerned, this is related to the answer given in question 1 (para 2.1.1). In order to commence an operation with a sound business plan, the industry needs a good degree of certainty with regard to financial impacts on that operation throughout its lifetime. There is a widespread perception that government is continually increasing the fiscal burden on operators and this obscures that much needed clarity. The regular proposals for tax increases and regular above-inflation increases in HSE’s charges do not encourage newcomers to enter the North Sea which is already seen as a high-cost region in which to do business. Energy & Climate Change Committee: Evidence Ev 59

2.4. What eVect is the recession and the credit crunch having on the industry? What is the impact on the financing of exploration and development?

2.4.1 The current financial troubles arrived at a time of high demand for the industry and a high oil price, the reversal of these trends has, therefore, been significant; drilling and exploration programmes have been cut back and there are currently an increasing number of Mobile OVshore Drilling Units being taken out of operation. Nonetheless, the industry remains positive, having previous experience of financial diYculties and variations of the oil price. To maintain activity among the oVshore industry’s mobile units, however, it is important to enable accurate financial forecasting through fiscal and regulatory regimes. Such measures have the potential to diminish the uncertainty implicit in undertaking the risks described in our response to question 1 when exploring and developing resources, and to address the concerns discussed in answer to question 3.

2.5. How are the skills needs of the sector being met? How transferable are those skills?

2.5.1 The skills required in the mobile oVshore sector are, in general, shared with those of the maritime and fixed oVshore sectors. As such, there are established training pathways for personnel suitable for employment by BROA’s members. Equally,skills gained while working on the units which BROA represents are often transferable to other arenas such as those mentioned. Some drilling companies operate training programmes, although mostly for drilling personnel. Despite that, staYng and attracting a talented workforce to this area of the industry remain high priorities with further progress needing to be made. Although the industry is considered to be one inside which training, development and progression can take place, there is a real need for a continuing supply of recruits with a high quality of traditional grounding in the technical and scientific disciplines involved, as well as knowledge and appreciation of the more modern technologies in use today. BROA has recently taken part in a short film for television which aims to promote awareness of the maritime and oVshore industries.

2.5.2 While in the past technical staV were largely recruited from the Merchant Navy or the forces, currently the demand is supplied from Eastern Europe and Russia. The recent boom in exploration led to skilled personnel being at a premium, particularly certificated engineers, electricians and electronics specialists.

2.6. What are the implications of an ageing existing infrastructure on the security of supplies from the North Sea?

2.6.1 The hypothesis that an aging infrastructure is a poor quality one is not necessarily correct in itself. OVshore platforms and units are high value resources which are subject to rigorous maintenance and upkeep programs. The maintenance and repair, as well as the initial design life of a mobile oVshore unit are more significant factors in, and indicators of, its operational state and capability than a simplistic judgment based upon its age. Furthermore, recent investment in new infrastructure has been taking place, and one of the unique advantages of mobile units is the ability to move them from their stations to coastal or port locations for refit, upgrading and maintenance. They are subject to regular docking, inspection, overhaul and modification, and are therefore not as susceptible as other infrastructure to age-related degradation. With regard to our members, therefore, the impact of this is not believed at this time to be significant.

2.7. Is the right policy framework in place to manage the decommissioning of that infrastructure as resources are depleted?

2.7.1 As has been previously mentioned, the industry has a high level of commitment to environmental matters; mobile units will also be subject to the International Maritime Organization’s imminent Draft International Convention For The Safe and Environmentally Sound Recycling Of Ships (to be agreed in May 2009). This will include requirements to achieve those objectives such as “green passports” which detail hazardous materials within their structures. These regulations will result in a more detailed regime for new mobile units and it is expected that, until such times as the new convention enters into force, owners will continue to abide by the industry good practice guide for ship-dismantling. Given the mobile nature of the units we represent it is unlikely that many will be sent for recycling to either UK or European yards. March 2009 Ev 60 Energy & Climate Change Committee: Evidence

Memorandum submitted by Carbon Capture and Storage Association 1. The Carbon Capture and Storage Association welcomes the opportunity to respond to the Energy and Climate Change Committee’s Inquiry into UK oVshore oil and gas and would like to submit the following evidence for your consideration:

Contribution of Enhanced Oil Recovery (EOR) to Maximising Oil Reserves 2. Exploiting Europe’s indigenous oil and gas reserves is fundamental to the security of European energy supply and is therefore central to European energy policy. In Europe’s maturing hydrocarbon provinces, Enhanced Oil Recovery techniques employing CO2 oVer potential additional recovery, to extend the longevity of oil & gas operations and to mitigate the steady decline in indigenous production, thereby minimising the rate at which Europe’s import dependency increases. Just as importantly, EOR using CO2 provides for the long-term, secure storage of significant volumes of CO2, commensurate with the incremental oil and water produced.

3. The technology to use CO2 for EOR has been technically (and commercially) proven in other parts of the world, specifically on land in the US. To date economics and the resultant lack of infrastructure carrying high volume concentrated CO2 have proven to be a key barrier to its adoption here in Europe. The eventual onset of carbon capture and the intention to permanently store large quantities of CO2 (CCS) beneath the North Sea should lead to the situation whereby EOR using CO2 becomes increasingly viable here. The combination of specific EOR opportunities with dedicated CCS schemes creates an economic synergy that should significantly reduce the cost burden faced by either as a stand alone development. There will also be additional ongoing benefits arising from the deployment of EOR: — First, and very much consistent with Government policy on climate change, where appropriately designed, CO2 storage operations may continue after EOR operations have ceased. Thus, investment in EOR has the potential to make incremental storage capacity available for later use that would likely otherwise not be developed. In this way, EOR projects could quite feasibly bring CCS deployment forward by many years. — Secondly, EOR can similarly contribute to the investment in pipeline infrastructure helping to enable other pure CCS storage operations. In this way we believe EOR has the potential to make a contribution to the cost of early CCS demonstration projects.

— Thirdly, EOR can provide an eVective route to long-term, secure CO2 storage. Lifecycle CO2 emissions from EOR operations are usually limited since operators have to pay for the CO2 they use and are therefore naturally incentivised to recover and recycle any produced volumes. Also it should not be overlooked that a significant fraction of CO2 used for EOR would be expected to have remained underground anyhow. Only the overall fraction of CO2 verified as permanently stored would benefit from a CO2 emissions allowance under the Emissions Trading Scheme. 4. In summary it is clear that our dependence on foreign oil imports is reduced by exploiting a significant additional source of home grown oil production. Whilst not applicable in all cases and not a substitute to dedicated CCS, the synergy created by CO2 EOR could with appropriate economic stimuli contribute to both security of energy supply and accelerate progress towards deploying low carbon power generation. The view expressed in this paper cannot be taken to represent the views of all members of the CCSA. However, they do reflect a general consensus within the Association. March 2009

Memorandum submitted by Centrica

Executive Summary — North Sea oil and gas industry is subject to particularly high rates of taxation on profits. EVective rate increases to 75% as it does for many of Centrica’s fields. This level is exceptionally high in global terms for a mature oil and gas province. By comparison rates in the US are 35% and 29% for Alberta in Canada. — The fiscal regime must change if the government is to meet its stated objectives to put in place the right incentives to maximise recovery of oil and gas reserves, whilst at the same time ensuring that the UK significantly increases its gas storage reserves to ensure security of supply in an environment of rapidly rising gas import dependence. — Government’s latest proposals are a missed opportunity for meaningful change. — Changes are required in five areas: 1. Buy-out or abolition of the Petroleum Revenue Tax (PRT) regime: Energy & Climate Change Committee: Evidence Ev 61

— likely that such a measure would be tax neutral. Government should take a longer term perspective to the tax take from oil and gas industry, which would support the abolition of PRT. 2. Introduction of investment incentives: — preferably in the form of capital uplift. 3. Change of use/incentives for development of gas storage: — development of the fiscal rules relating to change of use of North Sea infrastructure especially to facilitate the development of new gas storage facilities required for security of supply, for example, confirmation of relief for cushion gas; — Centrica committed to increasing storage in the UK and plans to invest £1.5 billion in new capacity but the economics are at best marginal; 4. The Crown Estate charging for new oVshore storage facilities: — Crown Estate, who act as the Government’s agency for oVshore leases, has a duty to extract the maximum rents from storage projects. All signals point to extraction of monopoly rents from storage developers. Crown Estate should adopt a more supportive approach to oVshore gas storage designed to encourage new entrants (as per the recent oVshore wind farm precedent). 5. Decommissioning trust funds: — Require exemption of decommissioning trust funds from income and inheritance tax, eVectively reducing long term industry capital costs and increasing investment flexibility with no immediate significant impact on the tax take.

1. How can the UK’s remaining oVshore oil and gas reserves be exploited most eVectively? What barriers are there to exploiting such reserves? 1.1 The North Sea oil and gas industry is subject to particularly high rates of taxation on profits. A corporation tax rate of 50% applies to all producing fields (including supplementary charge) and where Petroleum Revenue Tax (PRT) applies, as it does to many of Centrica’s fields, this eVective rate increases to 75%. This level is exceptionally high in global terms for a mature oil and gas province, particularly one where industry investors take all the risk. By comparison rates in the US are 35% and 29% for Alberta in Canada. 1.2 To put the existing challenge into perspective in gas, for example, the UK was until very recently self suYcient with the UKCS producing enough to meet the needs of UK industry and consumers. This self suYciency has turned around very rapidly. The UK imported approximately 40% of its gas needs last year, 50% imports are expected this year and around 75% by 2015. The eVect of this growing gas import dependence is that low and relatively stable wholesale gas prices have been replaced by high and volatile ones. The UK can not rely on gas supplies from Europe, because of the lack of eVective liberalisation on the continent, nor is the UK always able to attract LNG cargoes when it needs it the most. 1.3 Centrica believes that the fiscal regime must change if the UK is to maximise its recovery of oil and gas reserves, whilst at the same time ensuring that the UK significantly increases its gas storage reserves to cope with greater import dependence. The Department for Energy and Climate Change (DECC) estimates that between 17 and 20 billion boe remain to be recovered from the UK Continental Shelf (UKCS), but the current fiscal regime does not allow suYcient economic incentive for this. Centrica believes that change to the fiscal regime would promote the long term recovery of the UK’s remaining oil and gas reserves and in this context would ultimately like to see the UK Continental Shelf (UKCS) taxed on the same basis as other industries. 1.4 This need for change has been recognised by the Government, which initiated a consultative process in the 2005 Pre-Budget Report seeking to ensure that the North Sea fiscal regime is appropriate for the remaining life of the UKCS. Centrica is supportive of the Government’s willingness to consider change and has been closely involved with Oil & Gas UK in formulating the industry’s responses to this consultative process since its outset. Centrica was in agreement with the legislative changes enacted in the Finance Act 2008, in as far as they went, and welcomes the continued dialogue with the industry represented by the publication of the government’s latest consultative document. 1.5 However, Centrica believes that this latest document misses an opportunity for meaningful change, by focusing on marginal amendments to the regime that do not fundamentally address the needs of the industry. 1.6 Changes are required in five areas—the buy-out or abolition of the PRT regime, the introduction of investment incentives (preferably in the form of capital uplift), development of the fiscal rules relating to change of use of North Sea infrastructure (especially to facilitate the development of essential new gas storage facilities), The Crown Estate charging for new oVshore storage facilities and decommissioning trust funds. Ev 62 Energy & Climate Change Committee: Evidence

2. How eVective is the current fiscal and regulatory regime in which the industry operates? 2.1 Changes need to be made in five areas 2.1.1 Buy-out or abolition of PRT 2.1.1.1 The UK’s division of the industry into PRT and non-PRT paying fields is unique in a global context and eVectively imposes two special taxes on PRT paying fields (supplementary corporation tax and PRT). The 75% eVective tax rate suVered by such fields makes it very diYcult to justify large investments in enhanced oil recovery for low after tax returns. In recent years, Centrica has deferred investment in eYciency improvements on its platforms that would have had the eVect of lowering operating costs and extending field life, because those investments could not be economically justified on a post-PRT basis. In this context, there is a powerful argument that the abolition of the PRT regime would considerably enhance investment in the industry. 2.1.1.2 Furthermore, it is likely that such a measure would be tax neutral for HM Treasury over the medium term. Within the next decade, the Government expects its net take from PRT to turn negative as the tax relief available for the costs of decommissioning depleted PRT fields exceeds the remaining tax payable on revenues from the last producing PRT paying fields. This would clearly not be sustainable economically. 2.1.1.3 However, the Government’s focus on the five year Red Book timeframe means that it has not yet reached an appropriate conclusion to development of the PRT regime. Centrica strongly advocates that the Government should take a longer term perspective to the tax take from the oil and gas industry, which would support the abolition of PRT. 2.1.2 Capital uplift allowance or other investment incentives 2.1.2.1 The fiscal regime currently permits a 100% first year capital allowance for upstream investment, which enables capital investment expenditure to be oVset against profits in the year within which it is expended. We support industry calls for uplift to this capital allowance, for example to allow £125 of expenditure to be oVset against profits for every £100 invested. This would be a straightforward, equitable and most eVective way of boosting North Sea investment. 2.1.2.2 At the right level, we believe that a capital uplift allowance could be mutually beneficial both to the industry and to the UK taxpayer. We believe that such an allowance would act as an important incentive in attracting more investment to the UK in the face of increasingly stiV international competition for projects and for funding. 2.1.2.3 We further believe that the resulting additional taxable profits generated as a result of additional investment would more than mitigate the fiscal cost of the uplift, maintaining and increasing the total tax take over the medium term. 2.1.2.4 However, the current consultative document appears to back away from such a measure. Instead HM Treasury proposes only a selective value allowance, targeting mostly small, marginal projects and oVering a limited amount of revenue relief only on certain new fields unrelated to the actual cost of development. We believe HM Treasury has rejected the more comprehensive capital uplift allowance as a result of a focus on the five year Red Book timeframe, a focus that is inappropriate in an industry that is making investments to last a much longer period. 2.1.2.5 To the extent that HM Treasury continues to restrict its incentive proposals to a selective allowance, Centrica would support changes in three areas: (a) Incentives should maximise production from existing fields as well as new developments There is more to be gained from maximising recovery from existing fields than there is from developing new marginal sources of oil and gas. HM Treasury’s proposals for a value allowance appear to incentivise the development of new marginal fields over the exploitation of existing opportunities, ignoring the advantages of existing infrastructure. Centrica supports a broader capital uplift allowance, which would incentivise both new and existing fields on a comparable basis. (b) Any value allowance should be linked to development cost One of the key advantages of a capital uplift allowance is that it directly links the tax benefit to the actual development costs. Early indications are that HM Treasury will not take the size of targeted investments into account in determining the extent of value allowances. If the current value allowance proposals are adopted, we are proposing there should be a linkage between the development cost and the value allowance, which would bring some of the same economic incentives as capital uplift, albeit for restricted types of investment and with the tax cash flow benefit deferred. (c) There should be direct incentives for exploration There are no direct incentives for exploration envisaged in HM Treasury’s current proposals and it is unlikely that the value allowance will act as a meaningful incentive in this regard. Energy & Climate Change Committee: Evidence Ev 63

This would leave UK poorly positioned at a time when the recent fall in oil prices is expected to lead to a world wide diversion of rig capacity from production drilling to exploration activity. Centrica advocates that any incentive regime should also provide incentives for exploration. 2.1.3 Change of use / incentives for development of gas storage 2.1.3.1 After reservoir depletion, there are three main alternatives for the continued use of North Sea infrastructure: gas storage, carbon sequestration and wind farms. HM Treasury and HMRC have been helpful in removing the worst of the tax anomalies that hindered the reuse of upstream infrastructure. However in relation to gas storage, Centrica believes that the proposals do not go far enough. In most oVshore projects, storage requires large infrastructure investment. 2.1.3.2 New gas storage is required for security of supply in the UK now we have become a net importer of gas—a need that has been reiterated by the recent dispute between Russia and the Ukraine. The total storage capacity within the UK currently accounts for only 4% of annual demand, or around 16 days of average demand. Germany has 21% of annual demand or 77 days and France 24% or 88 days.

European Storage levels 120 100 UK 80 Avg 60 Netherlands days 40 Germany demand 20 0 Italy

UK Italy France France Germany Netherlands

2.1.3.3 It is estimated that the UK requires around £8–11bn of investment to gain around 56 days of storage—a level commensurate with the UK’s new found status as a nation dependent on gas imports. Centrica currently owns and operates Rough storage, Western Europe’s largest storage facility that is over 70% of the UK’s existing storage capacity. In the last 12 months we have announced plans for another 85bcf of storage capacity, approximately 70% the size of Rough. 2.1.3.4 Centrica is committed to increasing storage capacity in the UK and plans to invest £1.5 billion in new capacity, however, the economics are marginal at best particularly against the backdrop of increased financing costs caused by the credit crunch.

Rough Baird Bains Caythorpe

Size (bcf) 120 60 15–20 7.5 Injection (days 175 90 60 30 Withdrawal (days) 76 60 60 30 Number of cycles 1.4 2.4 3.0 6.0

2.1.3.5 Whilst there are a number of projects in the pipeline, only a small amount of new storage capacity has come on-line in the last few years against a background of a number of storage projects recently reporting delays. 2.1.3.6 There is a great deal of uncertainty about the availability of tax relief for certain capital costs, not least cushion gas (the base level of gas required to remain in the reservoir to maintain pressure and permit eYcient evacuation of gas). Cushion gas, which represents a substantial part of the capital cost of a new storage facility, has no economic value other than as a result of the pressure it provides. 2.1.3.7 Many storage projects based their economics on the precedent recently set by the Humbly Grove storage facility that qualified for capital allowances, though storage projects will only receive 10% writing down allowances for tax at best. Unfortunately HM Revenue and Custom (HMRC) has yet to confirm whether or not storage facilities qualify for such relief. Industry legal evidence was provided to HMRC in 2009 (letter from Gas Storage Operators’ Group) to confirm eligibility status to no avail. Ev 64 Energy & Climate Change Committee: Evidence

2.1.3.8 Given the Government’s stated ambition to develop significant indigenous gas storage in the interests of lower, more stable prices to the UK consumer, Centrica would strongly advocate the development of fairer tax relief for the capital costs of storage development and particularly the cost of cushion gas. 2.1.3.9 The current softening of demand may provide UK consumers with a respite from recently high and volatile markets. However, forward prices for wholesale gas next winter are still 53 pence per therm, which is 20 pence or 60% higher than it is today, indicating that any respite will only be temporary. 2.1.3.10 Centrica recently announced that its Baird storage project could be on-line in 2013. The length of time to develop storage projects means that action needs to be taken now if we are to have suYcient storage capacity in place when, for example, the UK is expected to be importing 75% of its supplies around 2015. 2.1.4 The Crown Estate charging arrangements 2.1.4.1 The Crown Estate, who act as the Government’s agency for oVshore leases for storage facilities, have a duty to extract the maximum rents from storage projects. All signals point to the extraction of monopoly rents by The Crown Estate from storage developers. This approach is in direct conflict with the government’s broader energy policy and its desire for increased security of supply. 2.1.4.2 The Crown Estate should adopt a more supportive approach to oVshore gas storage designed to encourage new entrants (as per the recent oVshore wind farm precedent). 2.1.5 Decommissioning trust funds 2.1.5.1 Along with the majority of the industry, Centrica relies on letters of credit to satisfy its guarantees of future decommissioning costs associated with current producing fields. These represent a real cost to the business, which becomes more expensive as decommissioning approaches. 2.1.5.2 Earlier this year, a new standardised model was developed with PILOT, a joint programme involving the Government and the UK oil & gas industry, for calculating the level of decommissioning security required by each North Sea participant. This model (the decommissioning cost provision deed or DCPD) is progressively being introduced to joint operating agreements, with requirements to be backed by letters of credit. 2.1.5.3 However, the DCPD is actually based on the amount that would be required if deposited in a trust fund. Income within trust funds is taxed at 40% and trust funds are also subject to inheritance tax. The amount that needs to be set aside in letters of credit is higher than commercially necessary as a result, tying up capital that could otherwise be used for investment. Centrica advocates the introduction of clearly defined rules that would exempt DCPD trust funds from income and inheritance tax, eVectively reducing long term industry capital costs and increasing investment flexibility with no immediate significant impact on the tax take. 2.1.5.4 In the absence of the necessary reform it is likely that industry will revert to the previous practice of bespoke agreements. This would miss the prospect oVered by a standardised agreement, namely that of facilitating the eYcient transfer of assets between industry participants. The transfer of assets helps ensure that new operators are able to take up the opportunity to maximise reserves where otherwise the fields would be abandoned by their existing owners. March 2009

Supplementary memorandum submitted by Centrica In the recent budget, the Government put forward a number of welcome measures that should provide a boost to UK energy supply security. Centrica particularly welcomes the introduction of new arrangements for change of use of facilities that could be of benefit to the development of new storage facilities, as well as HM Revenue & Customs’ earlier clarification of additional support for the development of new gas storage in the UK, through the application of capital allowances for purchase of the “cushion gas”. Centrica believes that there remain a number of challenges to ensure the delivery of suYcient and timely new storage capacity, including clarifying the role of The Crown Estate, which acts as the Government’s agency for oVshore leases. Centrica looks forward to working with the Government on these challenges. Centrica also supports the introduction of incentives to encourage investment in the North Sea’s smaller gas fields. The high tax rates on the North Sea, where the eVective tax rate is as high as 75% on Petroleum Revenue Tax paying fields such as Centrica’s South Morecambe, act as a continuing deterrent to investment in a global economy, particularly in a mature oil and gas province where industry investors take all the risk. Measures such as these which mitigate the deterrent impact of these high tax rates are welcome. Energy & Climate Change Committee: Evidence Ev 65

However since our previous written submission to the Committee, the North Sea has continued to decline—a recent report by Deloitte suggests that UK oVshore exploration activity is down 78% over the past 12 months. So whilst we strongly welcome the important progress that has been made, we believe that further reform is needed to the fiscal regime to ensure that the UK’s security of supply is maximised through appropriate levels of investment, particularly in the current, challenging, environment.

Change of Use/Incentives for Developing Gas Storage A favourable ruling was received just before the budget from HM Revenue & Customs on the availability of plant and machinery capital allowances for cushion gas, the single largest cost of a storage facility, this is positive. The budget also introduced new arrangements for change of use. This should benefit oVshore storage developments, where we expect the majority of new long duration storage capacity, of the type to boost security of supply during a severe winter or major supply failure, to be developed. However we believe a number of barriers and uncertainties to storage developments do remain. — The Crown Estate (TCE), that acts as the Government’s agency for oVshore leases, has a duty to enhance the value of the estate and the return obtained from it. Initial indications point to the extraction of monopoly rents from storage developers. TCE should be enabled to adopt a more supportive approach to oVshore gas storage, recognising the vital contribution storage makes to security of supply. Centrica believes that greater upfront transparency on pricing would be beneficial in the form of a published schedule of charges based on capacity measures akin to the regime for pipelines. — Centrica is restricted to a maximum reservation of 15% of the Rough storage facility owned and operated by Centrica, so Continental European suppliers can book up to 85% of Rough’s capacity to support their European businesses. Unfortunately, UK suppliers like Centrica don’t have the same levels of reciprocal access to European storage facilities when supplies are tight in the UK. To help address this deficiency, Ofgem and the OYce of Fair Trading should allow Centrica to compete on a non-discriminatory basis for access to Rough and all future storage development capacity. — The recently introduced Energy Act set the scene for the introduction of a new oVshore storage regulatory framework, which is welcome. Continued and timely progress in this area will be essential.

Investment Incentives a Welcome Start The SCT Field Allowance for small fields announced in the budget is welcome as it may lead to additional developments of new small fields. The lump sum allowance will be significant for a 30bcf prospect, though it will be marginal for a 100bcf prospect. Similar field allowances announced for High Pressure High Temperature and Heavy Oil are tightly defined so that they will benefit only a very small number of North Sea prospects. These new allowances apply, however, only to new fields, thereby providing no support to further development of marginal resources in existing fields, potentially a much larger pool than available in new fields. To address this gap, Centrica believes that the Government should extend allowances to existing fields, preferably via a 25% capital uplift on the current 100% first year capital allowance for upstream investment. Centrica also supports industry representations for the extension of PRT supplement beyond payback. PRT supplement is a 35% uplift on development expenditure available for fields pre-payback. Against the backdrop of a base production profile, an extension of uplift beyond payback for new investment is easily justified. A 35% uplift for capital expenditure for fields already paying 75% tax will encourage new investment in incremental projects, and eYciency improvements that will have the eVect of lowering operating costs, extending field life and increasing economically recoverable reserves.

Buy-out or Abolition of PRT Whilst allowances can provide helpful targeted incentives to further investment in specific areas, a regime of allowances is neither the simplest nor the most eVective way to attract a significant level of additional investment into the UKCS. The key barrier to increased investment in new or existing fields remains the high eVective rates of tax of 50% for non-PRT fields and up to 75% for fields paying PRT. As a starting point for radical reform, Centrica believes that the Government should reform the PRT regime if it is to meet its stated objectives of maximising recovery of oil and gas reserves. Centrica believes that such a measure could be tax neutral for HM Treasury over the medium term, with tax revenues close to the tipping point at which the tax relief for costs associated with decommissioning PRT fields will ultimately oVset the short term revenues received by HM Treasury associated with the residual production from those fields. Centrica continues to support buy-out or abolition of PRT. Ev 66 Energy & Climate Change Committee: Evidence

Decommissioning Trust Funds Centrica’s concerns about taxation in this area remain, though HM Revenue & Customs and industry bodies are expected to discuss these issues shortly. May 2009

Memorandum submitted by the Department of Energy and Climate Change 1. The Department welcomes this opportunity to provide evidence to the Committee’s initial inquiry,into UK oVshore oil and gas. 2. The UK’s endowment of oil and gas resources is a major asset to the country. The Government’s overall objective for the management of these resources is to maximise their economic recovery over time, and to maximise the consequent benefits to the UK economy and to UK employment. The underlying geology and the evolution of future oil and gas prices, together with the development of the necessary technology, will be the dominant drivers of investment and, hence, ultimate recovery levels. However, Government does have a crucial role to play in ensuring that the regulatory and fiscal regimes help deliver the best possible future for the UK Continental Shelf (UKCS). 3. This memorandum first oVers some background information on the broad ambit of the Committee’s inquiry—the extent of the UK’s oil and gas reserves and the contribution these can make to the UK’s future energy needs—and then some comments on the seven questions specifically identified in the Committee’s call for evidence.

The extent of the UK’s oil and gas reserves and the contribution these can make to the UK’s future energy needs 4. The Department publishes estimates of the UK’s oil and gas reserves each year.4 They are compiled from the oil and gas companies’ estimates of their individual fields’ reserves. In accordance with standard industry and geological practice, the discovered volumes of oil and gas remaining to be produced are categorised into “proven”, “probable” and “possible” reserves depending on the likelihood of the oil and gas being technically and commercially producible. “Proven” corresponds to at least 90% probability of production, “proven plus probable” combined corresponds to a 50% probability of production while “possible” has a 10% probability of being produced in full. As time passes and technology improves, reserves tend to be reclassified, moving from possible and probable into proven. Typically “proven plus probable” is taken as the central estimate of reserves. 5. The central estimate of oil reserves remaining at the end of 2007 was 780 million tonnes, and the central estimate of gas reserves remaining at the end of 2007 was 647 billion cubic metres (bcm). 6. Chart 1 in the Annex 1 to this memorandum shows the pattern of UK oil reserves, and cumulative production, over time; Chart 2 presents the same information for gas reserves. It is clear that, provided exploration work continues, additions to the reserves base will continue to be made, and will continue to support significant oil and gas production for many years to come.

Additional and undiscovered resources 7. The Department also publishes estimates of “Potential Additional Resources” (discovered volumes not currently considered producible for technical or commercial reasons) and “Undiscovered Resources” (potentially recoverable resources in mapped leads that have not yet been tested by drilling). Potential Additional Resources (PARS) are also reviewed every year, and where appropriate can also be re-classified as reserves if new technical information becomes available or the economics of production improved. Estimates of Undiscovered Resources are also updated each year, taking into account any new geological information from exploration and appraisal drilling, seismic survey etc.

Summary Table giving ranges of UK Discovered Hydrocarbon Resources 8. (Reserves plus Potential Additional Resources, as at end 2007: billion barrels of oil equivalent)

Oil and Gas Lower Central Upper Fields in production or under development 5.5 8.2 11.4 Other significant discoveries not fully appraised 0 1.6 3.2 Reserves 5.5 9.8 14.6 Potential Additional Resources 0.9 2.3 4.7

4 See: https://www.og.berr.gov.uk/information/bb updates/chapters/reserves index.htm Energy & Climate Change Committee: Evidence Ev 67

Oil and Gas Lower Central Upper Total Discovered Reserves and Resources 6.4 12.1 19.2 Cumulative production to date 37.5

Total remaining hydrocarbon potential 9. An indication of the total remaining recoverable resources on the UKCS can be obtained by adding the central estimates for discovered reserves and PARS to a range representing the possible range for undiscovered resources that might become producible in due course. Figures for resources not yet discovered are naturally subject to a higher degree of uncertainty than those for discovered resources. But with the increasing maturity of the UKCS, there is understandable interest in the question of how much further production is likely. To facilitate more meaningful answers to such questions, the Department’s estimates for undiscovered resources now include two mid-range estimates of undiscovered resources—the lower of 5.2 billion barrels of oil equivalent (boe) corresponding to a reasonable estimate of what might be found based on current knowledge, the higher of 8.7 billion boe corresponding to a reasonable estimate of what might be found with better understanding of the basins or better technology. 10. Taking account of this range of possibilities for undiscovered reserves, our current best estimate of remaining recoverable hydrocarbon resources from the UKCS is a figure of around 20 billion boe.But it is of course entirely possible that the development of better understanding and technological change will in the event enable higher figures to be reached.

UKCS Oil and Gas Production Projections 11. The chart below shows actual and currently projected UKCS oil and gas production, and actual and currently projected UK demand for oil and gas.5 As shown, the UK is expected to become increasingly reliant on imported oil and gas. Nevertheless, UKCS oil and gas production can be expected to amount to a large proportion of our oil and gas needs, and overall energy needs, for many years to come. This prospect is of great significance for UK energy security, and well as for its economic benefits. DECC Projections of UK Oil and Gas Production and Demand 150 140 130 120 110 100 90 80

mtoe 70 60 50 40 30 20 10 0 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Oil Production Oil Demand Net Gas Production Net Gas Demand

12. While central projections of oil and gas production are shown in the chart, there is in reality a wide range of possible outcomes because the rate of production is dependent on a number of diVerent factors including the level of investment and the success of further exploration. Operators continue to find it diYcult to predict production accurately as older fields mature and their reliability reduces. A significant share of future oil and gas production is expected to come from new fields, compounding the diYculty of making accurate forecasts given the risks of project slippage and uncertain start-up profiles. The central projections are therefore our best estimates rather than a definitive prediction of future production of oil and gas from the North Sea. There is similar uncertainty surrounding projections of future UK oil and, especially, gas demand.

5 The production projections for 2008–13 are as published at https://www.og.berr.gov.uk/information/bb updates/chapters/Section4 17.htm. After 2013, oil production is assumed to decline at 4.5% per annum and gas production to decline at 5.2% per annum. The demand projections are consistent with the Updated Energy and Carbon Emissions Projections published at http://www.berr.gov.uk/whatwedo/energy/environment/projections/index.html) in November 2008. Ev 68 Energy & Climate Change Committee: Evidence

Oil Production and Reserves 13. After a dramatic build-up following the start of oVshore oil production from the North Sea in 1975, and against a background of rapidly falling dollar oil prices, UK oil production peaked in the mid 1980s ahead of the Piper Alpha disaster in 1988 which resulted in a sudden and dramatic decline in production, due partly to the loss of the Piper field itself, and partly to the eVects of extensive work programmes to implement new safety measures. With recovery of production from existing fields and increasing numbers of new fields coming on stream (following a period of significantly higher development expenditure in the early and mid 1990s), oil production reached a second (and higher) peak in 1999.Until 1997, exploration activity had maintained the level of discovered oil reserves remaining.The subsequent lower level of exploration activity has not added suYcient to “ultimate recovery” (i.e. the total of cumulative production to date and estimated remaining discovered reserves) to prevent an overall decrease in remaining reserves. Unless future exploration activity6 results in a significant increase in ultimate recovery, the level of discovered reserves remaining (currently representing less than a third of ultimate recovery) will set a natural limit on the level of oil production which, over time, can be expected to continue to decline as remaining reserves are depleted. 14. In the absence of significant new fields starting production or major incremental projects in existing fields, UK oil production tends to decline at 10–15% or more per annum.However, if (large) enough new fields start production (as happened in 2002, with Elgin/Franklin and Shearwater coming into full production), or there are enough significant incremental projects in existing fields, the decline can be arrested or even temporarily reversed.

Gas Production and Reserves 15. Prior to the late 1990s the rate of natural gas production from the North Sea was, eVectively, constrained by the level of domestic demand for gas (with gas from most fields being sold under long-term field depletion buyer’s nomination contracts), though throughout the 1980s some demand was met by direct imports from the Norwegian Frigg Field. The “dash for gas” in the 1990s saw a large increase in demand for gas for power generation and, from 1998 with the opening of the Bacton–Zeebrugge Interconnector, significant exports were possible, allowing UK production to increase faster than UK demand. An increasing proportion was “associated gas” i.e. produced in association with oil (for example from the oil fields in the central and northern North Sea) rather than from the “dry” gas fields in the southern basin of the North Sea. Gas production peaked in 2000 and has been declining sharply since 2003 as new fields starting production have been too few and too small to compensate for the decline in production from existing fields. As with oil reserves, estimated ultimate recovery of gas increased through to 1997 as additions from exploration more or less kept pace with the increasing rate of production. Technical and commercial reassessments have, subsequently, reduced ultimate recovery at the proven plus probable plus possible level. Remaining gas reserves represent less than a third of the total discovered to date. 16. The rate of decline of UK gas production has until recently been less dramatic than the rate of decline of UK oil production. Compared with oil production, which exhibits some seasonality (as maintenance tends to be scheduled for the summer months), gas production fluctuates much more over the course of the year, reflecting the strong seasonality of gas demand.

How can the UK’s remaining oVshore oil and gas reserves be exploited most eVectively? What barriers are there to exploiting such reserves? What steps need to be taken to unlock resources west of Shetland? 17. As discussed in the previous section, the UKCS still has substantial oil and gas resources. At the beginning of 2008 our central expectation was that 12 billion boe of discovered hydrocarbons had yet to be produced, with additions from fields yet to be discovered estimated to be between 5 to 9 billion boe, giving a best estimate of remaining recoverable resources of around 20 billion boe. 18. Over the course of 2008 the UK’s combined oil and gas production was some 1 billion boe (2.6 million barrels per day); this represents around 60% of the UK’s total energy consumption and 80% of its oil and gas demand. After more than 40 years of continuous activity, production has however peaked and, without continuing capital investment, would naturally decline at around 10–15% per year in line with other mature basins. Over the past several years, capital investment of some £5 billion per annum in new and existing fields (see Chart 3 in Annex 1) has reduced this decline to 5–7.5%. 19. To exploit the remaining resources, both discovered and undiscovered, and to continue to slow the decline, it is essential both to attract substantial further investment—against fierce competition from oil and gas regions throughout the world—and to maintain a population of oil companies, particularly those with operational skills to identify and then exploit the opportunities in the basin.

6 Higher oil prices and technological developments could also increase the extent to which existing discoveries are commercial; improved geological knowledge can also aVect the estimates of the commerciality of existing discoveries. To date, recent increases in oil and gas prices have not resulted in a significant reclassification of the status of existing uncommercial discoveries to probably or possibly commercial; some reclassification has occurred but the extent has been masked by downgrading of reserves for technical reasons. Energy & Climate Change Committee: Evidence Ev 69

20. Clearly, geology and the levels of future oil and gas prices will be key determinants of future investment; and little can be done to influence these. In a mature basin such as the UKCS, other factors can be equally important to attract investment: the costs of activity must be low; regulation and commercial practices must be appropriate and follow the grain of activity; skills of individuals, of the companies that make up the supply chain, and of licensees, must match the opportunities; technology must be developed to reduce the costs and risks of finding and developing new fields and fully exploiting those already in production; and infrastructure, both facilities and pipelines, must be maintained and accessible. The policies pursued over the past few years have been designed to achieve these objectives. 21. Licensing policy is aimed at providing regular opportunities for the whole spectrum of companies to access acreage suited to their skills. The Department has been actively seeking and encouraging new licensees, particularly operators, to come into the basin, and have adapted the types of licences available to meet the needs of the industry. The Promote and Frontier types of licence have been added to the Traditional licence, all with a structure to encourage activity. (The Promote licence is a short-life, low-cost licence to encourage exploration and prospect promotion activity; the Frontier licence oVers larger areas and longer exclusivity to encourage exploration of challenging territory in the Atlantic approaches.) Similarly the “Fallow” initiative has been introduced to drive new exploration and development activity on older licences in parallel with the “Stewardship” process which puts pressure on the bottom quartile of fields in production to improve performance.With the support of the whole range of licensees, these approaches have demonstrably increased the opportunities and levels of activity in exploration, appraisal and development in the basin. 22. We are also working with the industry to reduce commercial and administrative ineYciencies and costs. Through PILOT (an industry, Government, trade union forum which is chaired by the Secretary of State) industry has produced Codes of Practice for commercial activity between licensees and within the supply chain. DECC has recently agreed to play a more active role in helping to monitor and enforce these Codes. To reduce the costs to industry of our administration of the licensing regime we have e-enabled much of the transactional process and have further improvements underway.We have also worked with industry to enable them to reduce the burden of their necessary obligations to hold geological data. 23. The maturity of the UKCS means that the majority of new finds and developments will be small, and unlikely to be able to support the cost of substantial, dedicated, production and export infrastructure. It follows that access to existing infrastructure (both pipelines and facilities) on fair and reasonable commercial terms is critical to the full exploitation of the basin. Through PILOT, industry has developed an Infrastructure Code of Practice aimed at ensuring transparent and timely negotiations for that access.The Department has agreed to assist in the enforcement of that Code, in particular to help provide an expected timeline for negotiation. Beyond that function however, the Secretary of State has powers on application to set tariVs and terms for access to infrastructure, and has published guidance on disputes over third party access, to aid industry in understanding our approach to resolving such disputes.The nature of access to infrastructure is changing as the basin matures, and the Department, in discussion with industry,is currently revising the Guidance to accommodate these changes. 24. We see technology development as primarily a task for industry but, where it is appropriate and there is a particular need, we support individual technology development or more fundamental research, particularly where this will encourage the pooling of industry resources. Projects in the oil and gas field have been supported by the Technology Strategy Board, and DECC has contributed to development and university research projects supported by the industry’s club financing (the Industry Technology Facilitator). The Department also funds geological and geophysical analysis of parts of the UKCS with the aim of attracting bids for specific areas in licensing rounds.

West of Shetland 25. The area to the west of the Shetland Islands and the Hebrides is the largest remaining area of significant prospectivity on the UKCS, holding some 10 to 20% of UK’s remaining oil and gas. The area represents a potential 3–4 billion barrels of oil equivalent—around 17% of the UK’s remaining oil and gas reserves and includes some 10 to 15% of remaining UK gas reserves. It is remote, being nearly 400 km from the nearest gas terminal, and most of the gas discoveries are too small to support the necessary gas infrastructure on their own. The existing gas pipelines (WOSPS, EOP and FLAGS) do not have capacity in the short and medium term to support major development. 26. Exploration and development has been hindered by the lack of gas transportation capacity and no one company or single field has been suYcient to drive the building of this infrastructure. As a result of the Energy Review in 2006, a Government/industry taskforce was established to get the right infrastructure in place to the west of Shetland so that, with minimal impact on the environment, development and exploration in the area could be speeded up. The taskforce includes representatives from leading oil and gas companies with gas projects that have the potential to start within five years:

Total operator of the Laggan and Tormore fields Chevron operator of Rosebank and Lochnagar BP operator of the Clair field Ev 70 Energy & Climate Change Committee: Evidence

ExxonMobil operator of Tobermory DONG Energy participant in Laggan, Rosebank and Tobermory 27. The taskforce started work in November 2006, to examine the potential for a multi-field development with gas export to mainland Scotland. A range of alternative options including power generation and the production of liquefied or compressed natural gas close to the point of production, were also considered and rejected on at an early stage on cost grounds. The taskforce identified four types of gas gathering hub, three of which were located oVshore with a direct pipeline connection to St Fergus and the fourth, onshore at the existing Sullom Voe terminal in the Shetland Islands. All were assessed to be technically feasible. 28. In September 2007 a well was drilled by Total into the Tormore prospect close to the Laggan field which identified additional gas. At the same time Chevron commenced an extended appraisal programme of their Rosebank/Lochnagar discovery in the growing confidence that they had a viable development further to the west. 29. These developments oVered better prospects for development, and the Laggan/Tormore and Rosebank/Lochnagar partners co-sponsored an independently managed process in the autumn of 2008 to test the appetite for third party investment in a basic engineering study and ultimately, in the collective project. This revealed a potential requirement for about 18 million cubic metres per year (cm/y) of gas transportation capacity (equivalent to about 5% of UK annual demand), involving 10 licensees in three separate licence groups. 30. Total have now commissioned the basic engineering study for Laggan/Tormore and the work is proceeding primarily on the basis of an onshore gas gathering hub located at the existing Sullom Voe Terminal in the Shetland Islands. 31. For the gas export pipeline, there are two options (see Chart 4): — a direct pipeline from Sullom Voe to St Fergus on the Scottish mainland, or — an indirect route using a new shorter pipeline to connect Sullom Voe to the existing, 100% Total- owned Frigg UK gas pipeline and then via Frigg to St Fergus. In either case, the pipeline is expected to have capacity for the 18 million cm/y of gas identified in the third party investment process.We understand that the partners consider that there is a commercially viable development option for Laggan/Tormore, with development sanction in September 2009 and first production in late 2013. The parties interested in developments west of Shetland are now moving towards a decision on development later this year which will be followed by a submission of a development plan to the Department for consideration. The Department considers that this collaborative process has a real prospect of providing infrastructure to deliver gas to the market in 2013–14. It will be a collective solution that reflects the requirements of players in the West of Shetland area prepared to commit to development.

What can be done to minimise the environmental impact of exploiting oil and gas reserves? How should this be encouraged or financed? 32. A comprehensive framework of environmental protection measures has been developed to minimise the impact of oil and gas activities. This is embodied in the relevant legislation, consistent with and in large part derived from the legislative framework of the European Community (EC). In addition, the UK is a signatory to the Oslo and Paris Convention for the Protection of the Marine Environment of the North East Atlantic (the OSPAR Convention). It is Government policy to implement and apply all of the OSPAR Commission’s decisions and recommendations. 33. This robust oVshore environmental protection regime, which covers oil and gas development throughout its life cycle, from the initial licence application to the final decommissioning of facilities, as detailed in the remainder of this submission. All activities that could potentially impact on the environment are subject to rigorous assessment, and significant activities are controlled through the issue of permits, consents or authorisations. There is also an inspection and enforcement regime in place to confirm compliance with the conditions included in the environmental approvals. 34. The robust regime is reflected by the industry’s performance, and the UK has a good environmental record with no significant impact on the marine environment resulting from oVshore oil and gas activity.

Environmental aspects of licensing 35. To meet the requirements of EC Directive 2001/42, transposed into UK legislation by the Environmental Assessment of Plans and Programmes Regulations 2004, a Strategic Environmental Assessment (SEA) is carried out before oil and gas licensing is undertaken. The SEA is subject to public consultation and evaluates both the individual and cumulative impacts of oVshore oil and gas activity at a strategic level. Licence areas can be withheld if mitigation of potentially adverse eVects is not considered to be feasible, or if there is insuYcient information available to determine the potential impact of the licensing activity. For example, the 2008–09 OVshore Energy SEA recommends that an area to the west of the Hebrides and the deepest parts of the southwest approaches should continue to be withheld from oil and gas licensing due to significant gaps in our knowledge of these areas. Energy & Climate Change Committee: Evidence Ev 71

36. Following the completion of a SEA, operators are invited to apply for licences in selected areas, usually as part of a licence round. The licence application process includes an Environmental Competency Assessment. Applicants must have, or commit to develop, an Environmental Management System (EMS) that satisfies the requirements of OSPAR Recommendation 2003/5; must have adequate oil spill liability provision; and must prepare a high-level Environmental Impact Assessment (EIA) to identify the environmental sensitivities in the area that is the subject of the application. 37. An EMS is designed to achieve the prevention and elimination of pollution from oVshore sources; the protection and conservation of the maritime area against other adverse eVects of oVshore activities; and continual improvement in environmental performance. All of the 81 licensed operators on the UKCS have an independently verified EMS.

Project specific regulation 38. The granting of a licence does not automatically confer any rights or permissions for activities within the licensed area, and all proposed projects are subject to an environmental assessment. 39. The OVshore Petroleum Production and Pipelines (Assessment of Environmental EVects) Regulations 1999 implement the EC EIA Directive, and require the operator to undertake an environmental assessment for a wide range of projects. For all new developments, significant increases in production and large pipelines, the assessment must take the form of an Environmental Statement that is subject to Public Notice. 40. The OVshore Petroleum Activities (Conservation of Habitats) Regulations 2001 implement the EC Habitats and Wild Birds Directives, and apply to all projects and activities. Where a project or activity could aVect the integrity of a protected habitat or species, an Appropriate Assessment (AA) is required to demonstrate that any eVect would be insignificant.

Activity Specific Legislation 41. In addition to the project level legislation being applied to activities such as the drilling and testing of wells, all minor pipelines and pipeline works and minor production increases; all activities that could adversely aVect the environment are strictly regulated (further information can be found at Annex 2). Assessments are required for: — seismic and other survey activity; — the use and discharge of chemicals; — the discharge of oil; — atmospheric emissions; — oil spill response. 42. Most of these activities are controlled by the issue of activity specific permits, consents or authorisations containing legally binding terms and conditions. In addition, every oVshore installation must be the subject of an approved Oil Pollution Emergency Plan. The oVshore sector is also included in the EU Emissions Trading Scheme. 43. Whilst the majority of the project and activity level legislation referred to above has been developed specifically to control oVshore oil and gas operations, the industry is also subject to non-sectoral environmental legislation that is applied to all marine activities. For example, all deposits in the sea that are not covered by oil and gas industry legislation will be controlled under the Food and Environment Protection Act (FEPA) 1985, Part II Deposits in the Sea. The industry is also subject to regulations relating to merchant shipping. The environmental controls are therefore similar to those imposed on other marine activities and to those imposed on terrestrial activities. 44. In addition, DECC continues to work closely with industry to improve environmental performance, by encouraging initiatives such as the increased use of reinjection for produced water (a by-product of the production process that is contaminated with reservoir hydrocarbons); the preferential use of chemicals with little or no environmental impact; and energy audits to determine the most eYcient way to meet power requirements and reduce atmospheric emissions.

Environmental aspects of decommissioning 45. The EIA for a proposed development will include consideration of the long-term impacts, including those arising from decommissioning. However, there is usually a lengthy period between project sanction and decommissioning, and UK Government policy could change during that period. There is therefore an additional requirement for a detailed assessment at the time of decommissioning, which is submitted as part of the decommissioning programme. Ev 72 Energy & Climate Change Committee: Evidence

Enforcement 46. DECC actively ensures that industry is complying with the conditions included in environmental approvals, following a four step process of audit and review, inspection, investigation and enforcement. A risk-based inspection strategy is used to prioritise the installations that will be inspected. Inspections provide evidence and assurance that operators have been, or are complying with the requirements, restrictions or prohibitions imposed upon them by the relevant statutory provisions and that pollution prevention procedures are being implemented. 47. OVshore environmental incidents involving oil and chemical spills to sea and notifications of non- compliance with permitted activities are reported to DECC. All reported environmental incidents are reviewed and where applicable action is taken to ensure that response procedures are implemented to minimise the potential impact of any pollution. Where any spill results in, or there is a threat of, significant pollution, the Secretary of State’s Representative (SOSREP) has the power to take control of the situation. Although the SOSREP has never been required to take significant action in relation to oVshore oil and gas activities, there is close liaison between DECC, the SOSREP, and the industry. Legislation requires operators to carry out Oil Spill Response exercises to test and further strengthen pollution response. 48. DECC also collaborates with the Maritime and Coastguard Agency (MCA) to ensure that an eVective pollution identification aerial surveillance capability is maintained for UK oVshore oil and gas activities within the UK Pollution Control Zone. At the international level the UK supports the activities of the Bonn Agreement (Maritime Pollution and Prevention). 49. Where oil and chemical spills to sea occur, or breaches of regulatory requirements are identified, the circumstances will be investigated. If it is considered necessary, enforcement action may be taken to ensure that: preventative or remedial measures are taken to prevent pollution, measures are put in place to achieve regulatory compliance and operators are held to account when failures to comply occur. DECC has the power to revoke permits, enforce actions, prohibit activities and to prosecute oVenders. There have been 11 reports to the Procurator Fiscal and 9 prosecutions since 1998.

Finance 50. The vast majority of the costs associated with the environmental regime, including the assessment of applications, the issue of environmental permits, consents and authorisations and the associated enforcement activity is met by the oVshore oil and gas industry. In addition to their project costs, including any waste treatment and disposal expenditure, an application or maintenance fee is levied for most permits. In order to streamline the handling of the large numbers of permits required and to reduce the administrative costs where possible, there are a number of e-commerce developments underway to simplify application and reporting processes.

Case Study—Moray Firth 51. In 2006, a licence application was received for an area in the Moray Firth that overlapped with a Special Area of Conservation (SAC) for bottlenose dolphins. A draft Appropriate Assessment (AA) was prepared to inform the licensing decision, which concluded that the licensing could proceed, subject to appropriate mitigation measures being employed for specific activities. 52. The AA was subject to public consultation and several detailed responses were received, a number of which expressed concerns about the interpretation of data that had been included in the draft AA. Following a meeting with many of the relevant stakeholders in January 2009, DECC proposed a substantial research programme, to be funded by DECC and others, that will seek to provide firm data on the significance of the proposed licence area for bottlenose dolphins (and other marine mammals) during the summer months. 53. The stakeholders welcomed this proposal and it is hoped that the research programme will commence in May 2009. No decision will be made on whether to issue a licence for this area until the findings have been collated and fed into the AA process.

Consultation 54. StaV within DECC’s OVshore Environment Unit in Aberdeen have a wide-ranging specialist knowledge of environmental issues. Nevertheless, the value of consulting with other government departments and bodies who may have an interest in the proposals is recognised, and DECC routinely seeks the views of the Centre for Environment, Fisheries and Aquaculture Science (an agency of Defra), the Fisheries Research Services (an agency of the Scottish Executive Marine Directorate), the Environment Agency, the Scottish Environment Protection Agency, the Joint Nature Conservation Committee, Natural England, Scottish Natural Heritage, the Countryside Council for Wales and many others. DECC also has a good relationship with industry, and regularly meets both Oil and Gas UK (the industry representative body) and operators to provide advice and discuss the legislative requirements, in addition to making presentations at workshops, seminars and conferences. Energy & Climate Change Committee: Evidence Ev 73

Summary 55. Whilst the continued development of the UKCS oVshore oil and gas sector is considered to be crucial to the security of the UK’s energy supply, the Government is committed to ensuring that the impact of oil and gas activity on the environment continues to be minimised. Legislation adopted over the last 10 years has resulted in the development of a comprehensive, robust and eVective environmental regime, which is consistently applied, understood by industry and fully satisfies the UK’s international obligations.

How eVective is the current fiscal and regulatory regime in which the industry operates? 56. The regulatory regimes as regards licensing and environmental protection have been addressed in earlier sections of this memorandum, and decommissioning is discussed later. This section focuses on the fiscal regime. 57. The North Sea fiscal regime is one of the main mechanisms for capturing for the nation the economic benefit from the UK’s oil and gas resources. In support of its overall objective of maximising the economic recovery of the UK’s oil and gas reserves, the Government aims through the North Sea fiscal regime to encourage investment in and production from the UKCS while ensuring a fair return for the UK taxpayer from the UK’s national resources.The regime has been developed and adjusted over time in response to developments in the industry and the economic climate in which it operates, with the introduction, amendment to and abolition of a number of diVerent fiscal measures. 58. Responsibility for the North Sea fiscal regime is split between HM Treasury (HMT) and HM Revenue & Customs (HMRC). HMT has overall policy lead and leads on policy formulation while HMRC supports HMT and leads on policy maintenance. Both work closely with DECC in developing policy and DECC plays a central role in interaction between the fiscal departments and industry stakeholders.The following comments have been agreed with HMT and HMRC. 59. The fiscal regime which currently applies to oil and gas exploration and extraction from the UK and the UKCS consists of three elements: — Ring Fence Corporation Tax With some important modifications (e.g. relating to capital allowances and losses), this is calculated in the same way as the standard corporation tax applicable to all companies, with the addition of a “ring fence” and 100% first year allowances for virtually all capital expenditure. The ring fence prevents taxable profits from oil and gas extraction in the UK and UKCS being reduced by losses from other activities or by excessive interest payments by treating ring fenced activities as a separate trade. The current rate for non-ring fence profits is 28% and 30% for ring fence profits. HMRC has recently simplified the general capital allowances regime but this does not impact on the 100% first year allowance rules within the ring fence. — Supplementary Charge This is an additional charge of 20% (10% prior to 1 January 2006) on a company’s ring fence profits excluding finance costs. The supplementary charge was introduced from 17 April 2002. — Petroleum Revenue Tax (PRT) This is a special tax on oil and gas production from the UK and UKCS. It is a field based tax charged on profits arising from individual oil fields. The current rate of PRT is 50%. PRT was abolished for all fields given development consent on or after 16 March 1993. PRT is deductible as an expense against corporation tax and the supplementary charge. The marginal tax rate on new fields is thus 50%, while the marginal tax rate on the older fields paying PRT is 75%. 60. A Ring Fence Expenditure Supplement (RFES) assists companies that do not yet have any taxable income for corporation tax or the supplementary charge against which to set their exploration, appraisal and development costs and capital allowances. The RFES increases the value of unused expenditure carried forward from one period to the next by a compound 6% a year for a maximum of six years. It applies to all unrelieved expenditure from 1 January 2006. This is intended to help support new entrants into the basin. 61. The current North Sea fiscal regime gives Government a system that: incentivises investment; creates a fair return to the UK; is simple to operate; has accelerated payments (compared to other sectors); and sets relief against profits/tax paid. It gives industry: competitive tax rates; immediate tax relief for almost all revenue and capital expenditure; full tax relief for decommissioning expenditure; and Government eVectively sharing in risk and reward. The regime is kept under review. Since the start of 2006, the Government has been engaged in discussions with industry about “structural concerns” over aspects of the North Sea fiscal regime. These discussions were driven by concerns, both within Government and industry, that elements of the existing fiscal regime were having a negative impact on investment decisions—and therefore running contrary to Government’s wider objectives. Following almost two years of discussions, Government published a consultation document in December 2007 setting out a range of proposed reforms Ev 74 Energy & Climate Change Committee: Evidence

to the regime to remove anomalies and change elements that Government felt were potentially restricting investment—most of these were taken forward in Budget 2008. None of these proposals involved changes to tax rates. 62. A further package of reforms to the North Sea fiscal regime was set out at Pre-Budget Report 2008 which should help encourage investment in the UKCS. Building on the changes to the North Sea fiscal regime made at Budget 2008, and productive discussions with industry over the past year—involving BERR/DECC as well as HMT and HMRC—HMT and HMRC published a consultation document on the North Sea fiscal regime alongside Pre-Budget Report 2008. Supporting investment7 set out a further package of reforms which should help encourage investment in the UKCS. In particular, the consultation document raises the concept of a “value allowance” that could be built into the fiscal regime to help bring forward challenging developments. A number of other proposed changes which responded positively to representations by industry have been widely welcomed by industry. 63. Discussions with industry over the past year have been wide-ranging and the proposals set out at PBR 2008 covered a disparate array of issues. In addition to the idea of targeted incentives (where Government wished to discuss the potential of a value allowance), they addressed: the North Sea fiscal regime and chargeable gains taxation; a number of fiscal issues arising from “change of use” from oil and gas production to other energy-related activities such as carbon capture and gas storage; and several other features of the PRT regime, including issues concerning licence expiry and simplification of some features of the PRT regime. 64. A consultation period which ended on 13 February 2009 was intended to give stakeholders the chance to comment on the Government’s proposals for changes to the North Sea fiscal regime and to engage further on the question of potential fiscal incentives, in particular to discuss the concept of a value allowance incentive in more detail. It is intended that, if confirmed in light of the present consultation, the package of changes will be finalised at Budget 2009 and legislated in Finance Bill 2009. Where possible, draft legislation for the proposed measures has been published on the HMRC website to allow interested stakeholders a chance to comment.

What eVect is the recession and the credit crunch having on the industry? What is the impact on the financing of exploration and development? 65. The impact of the current economic climate on oil and gas companies is significantly diVerent from that on industry more generally. The key development of the past 12 months for this sector has been the substantial fall in oil prices. From a peak of almost $150 a barrel in July 2008, prices have fallen to the region of $40–50 more recently. Though almost all current developments would have been financed and committed in an oil price environment well below the recent peaks—oil prices varied between $50 and $70 a barrel over 2005 and 2006, for example—the sudden fall in prices and the uncertainty about future prices dominate the business outlook for this sector. Companies have reacted by substantially curtailing exploration expenditure, and by reviewing and in many cases deferring discretionary investment which is not likely to lead to early production. 66. The credit crunch, by contrast, has been a less salient concern for many players. The major oil companies, with substantial revenues from production, have relatively little dependence on external finance. The largest companies have indicated their intention to maintain capital investment levels at global level (ExxonMobil, Shell, Total, BP), although within that broad intention, it appears that some projects may be deferred while the participants seek lower material and supply costs to improve the project economics. Some medium-sized companies with significant production are similarly placed. Other medium-sized companies, along with smaller companies, are more dependent on external finance. Those without production, or facing heavy development expenditure, can face serious financial pressures. A number of companies have been bought by stronger competitors, and one prominent exploration company has gone into administration. It is worth noting that historically the banks most involved in lending for North Sea developments are RBS and HBOS.The current diYculties of these banks are a complicating factor in the outlook for UKCS investment. 67. An aspect of the current financial freeze with a particular impact on the oil and gas sector is the unavailability of new equity. This is of particular concern to smaller exploration companies, since banks have never, even in more favourable times, been willing to finance exploration activity. If these companies cannot raise equity, they will be unable to secure bank loans or project finance for new developments, even if the developments are in themselves viable and project finance otherwise available. Since most developments involve a group of participants, the inability of even a junior partner to raise finance may hold up or even stall development. 68. Companies in the supply chain, as opposed to those engaged in exploration and production, are broadly speaking exposed to a similar combination of circumstances to those faced by industry at large— a substantial reduction in demand for their products and services, and a very diYcult financing climate. There are many reports of diYculties in obtaining short-term credit or working capital. Significant numbers of redundancies have been announced.

7 Available from http://www.hm-treasury.gov.uk/prebud pbr08 northsea.htm. Energy & Climate Change Committee: Evidence Ev 75

69. The combined impact on investment must inescapably be a significant fall. As noted earlier, the maturity of the UKCS as an oil province implies that production will fall by some 10–15% a year if there is no new investment in production. The benefit of the sustained investment by the industry over recent years— running at an annual rate of about £5 billion—has appeared in a markedly slower rate of decline of around 5–7% a year. A recent survey of activity intentions by Oil and Gas UK however estimated that capital expenditure in development and drilling may fall by between £1 billion and £2 billion in 2009. Industry’s view of the geological attractiveness of the basin has not changed markedly—the decline in investment is a reflection of a combination of lower oil prices making some investments economically unattractive or higher risk, an expectation that costs will fall in the near term, and a reduction in the availability of funding whether internal, equity or bank borrowing. The impact will be felt particularly sharply in exploration spending, though development work will also be aVected over time. A falling-oV of development investment can be expected to result in a progressive increase in the rate of decline, as existing fields decline more rapidly and new fields are delayed or cancelled. For employment, the industry has estimated that each £1 billion drop in investment will result in the loss of 20,000 jobs.

How are the skills needs of the sector being met? How transferable are these skills?

Employment numbers and age profile 70. The number of people employed directly within the industry is 350,000 with a further 100,000 employed in export activities by supply chain companies, bringing the total to 450,000. Within the 350,000 figure 34,000 are employed directly with oil and gas companies and major contractors, 230,000 in the wider supply chain and the remaining 89,000 are jobs supported by the economic activity of the industry. This is an increase in employment of about 30% since 2004. The number of females employed by the industry has increased gradually over recent years with around 1,800 females travelling oVshore, the majority of whom are employed in the catering sector. The age profile of females is younger with the average age being 34.1 years. 71. There are distinct clusters of high employment within the industry around the UK, with the Aberdeenshire area accounting for 39% of the total employment. The other regions with sizeable employment levels are east of England 5%, north west England 6%, and London and the south east 21%. 72. The supply chain mixture of businesses includes the following:

Engineering Construction 16% Structural metal products 10% Technical consultancy 9% Legal services 5% Business and professional services 5% Public administration 4% Renting of machinery 3% 73. The average age for the whole workforce is currently 41 years, which is the expected average age of a workforce in the range 20 to 60 years.

Training 74. The industry has its own skills academy—OPITO, based in Portlethen near Aberdeen. The academy embodies the concept, which Government supports, of employers taking ownership of the skills and workforce development agenda in their sector. It is therefore able to respond quickly to the specific needs, or emerging needs within, the sector. OPITO exceeds DFES guidelines for industry led and funded skills academies. Their goal is to actively coordinate and consolidate the activities, eVorts and resources, needed to address employers’ demand for skilled people. They also have the objective of addressing STEM (science, technology, engineering and mathematics) subjects within schools, as most jobs in the industry require a strong engineering and technical background. 75. OPITO is working with colleges and universities in particular through the Technician Training programme, which is an exemplar training provision. It was launched in 2002 and trains around 100 technicians each year with the course lasting around 3° years and there are currently 390 young people in training. Each year’s intake is determined through a demand forecasting exercise to ensure employment for all those who finish their training. This is followed by two years practical training and there is a 96% completion rate after 3° years. 76. Salient points on OPITO: — It has over 50 industry specific competence standards, created by employers to deliver against the needs of the workplace. — In 2007, 96,000 people were trained to the OPITO industry standards. Ev 76 Energy & Climate Change Committee: Evidence

— Industry employers directly invested approximately £49 million in training to OPITO standards in 2007. The industry has directly invested £52 million over six years in its flagship Modern Apprentice scheme. — OPITO exports UK training into 24 countries. — It works with foreign Governments and national oil companies to help develop overseas workforces to the UK standards. — It has a direct annual workforce investment of £10.1 million for 2008 (schools, education provision, teacher training materials, career and lifestyle road shows, apprentice schemes, workforce development programs etc). — New subsea technician qualification introduced recently to meet emerging needs within the sector. — Runs a bespoke training programme for ex-military personnel with relevant skills (a valuable source of recruitment for the sector). 77. There are a high level number of training providers within the industry, delivering OPITO standard training—a link on OPITO’s website (http://www.opito.com) lists these providers and the variety of training they provide. 78. Falke Nutec who provides oVshore survival training to the industry reports high levels of oVshore training with 15,000 trainees going through the oVshore survival course in the last year. 79. Industry, in conjunction with Step Change in Safety, and OPITO has also developed an introductory training programme that introduces the key safety elements required by all employees oVshore. The course is being delivered by an OPITO approved training establishment. Training will also be given to current employees within the industry with refresher training being given annually. 80. The challenge for the industry and OPITO now is to sustain training and recruitment programmes through the current downturn, and ensure there is a strong skills base maintained to enable the industry to maintain its capability and be ready to take full advantage of the expected recovery in oil prices and economic activity.

What are the implications of an ageing existing infrastructure on the security of supplies from the North Sea? 81. The main focus for security of supplies in the upstream industry is on gas, because it is less easily transported from other areas of the world and less easily stored compared to oil. As a result, gas shortages could be felt by consumers much more rapidly than shortages of fuels derived from oil. The following points are therefore directed at gas. 82. There are 36 pipelines supplying gas into the UK; 32 from UKCS fields and five from other countries. These pipelines land at 16 reception terminals in seven separate locations around the coastline. The pipelines typically vary from 16+ to 44+ to diameter, and can be in excess of 200 miles long. Once onshore, the gas is fed into the pipelines forming the National Transmission System (NTS), and then through local distribution systems to industrial and domestic consumers. 83. For UKCS fields, there are a large number of platforms and facilities that produce gas. These vary from wellhead valves on the seabed, up to large production platforms accommodating 200 people and containing large amounts of equipment. A network of smaller pipelines is used oVshore to connect more remote fields into main production or collection platforms (termed “hubs”), from which pipelines run to shore. 84. Gas production first started in the UKCS in 1967 from BP’s West Sole field, where the platforms and pipelines are still in operation. The development of platforms and pipelines has continued steadily from the late 1960s to the present day, moving from early infrastructure in the southern North Sea into deeper water areas further north and eventually to the west of the Shetland Islands. New developments are still taking place in all areas of the UKCS. The graph below shows the number of fields starting production over time: Energy & Climate Change Committee: Evidence Ev 77

25

20

15

10 Number of new fields

5

0 1967 1970 1973 1976 1979 1982 1985 1988 1991 1994 1997 2000 2003 2006

85. Many platforms and pipelines were originally designed for a life of 20 to 30 years. Hence a lot of these facilities are now at or beyond their design life. The design life was originally linked to the expected length of production, but this has been extended for many facilities due to better than expected reservoir performance or new nearby fields being connected to the platform. For example, three new fields have previously been connected into the West Sole facilities, and a further two new fields will soon be connected, leading to a further 10 years or more of production from the combined fields. 86. Calculation of a design life has not always been carried out rigorously, typically being based on an assumed rate of corrosion in main equipment items and sometimes crude assessments of the accumulation of fatigue damage in main structures. The actual rate of deterioration depends on many factors, including material and manufacturing specifications, the reservoir fluid composition and condition, the operating environment and the maintenance philosophy. The successful operation of older facilities demonstrates that careful management of all the factors aVecting deterioration is the key to extending the design life. 87. It is generally accepted that the low oil and gas prices during the 1990s led to reduced eVort being spent on maintenance. This has led to increased “downtime” of oVshore facilities, and was one of the main drivers for DECC to start the Stewardship initiative for producing fields in 2004. At around the same time, the Health and Safety Executive (HSE) started a Key Programme on Asset Integrity (KP3) on the basis of similar concerns. 88. The HSE report on KP3 was publicly released in 2007 and described a number of diYculties with maintenance management systems and overall condition of infrastructure. However, it also concluded that some of the main components of platforms (main hydrocarbon boundary, jacket and primary structural integrity) were reasonably well controlled. Industry has responded positively to the challenges laid down in the KP3 report, and the indications are that maintenance activity has increased in recent years as a result of this programme and the DECC Stewardship initiative. 89. The table below summarises the contributions of various pipelines to UK gas supply, grouped by terminal. The percentage contributions are averaged for the 2008–09 winter to date.

Percentage contribution Pipeline Source of gas to UK winter supply Date of construction 1 Foreign 17 2005 2, 3 UKCS, Foreign 17 1977 to 1978 4, 5, 6 UKCS 9 1992 to 2004 7 UKCS 7 1993 8 UKCS 7 1999 9 Foreign 7 2006 10 UKCS storage 6 1984 11, 12, 13 UKCS 6 1982 to 2003 14, 15, 16 UKCS 6 1968 to 1990 17, 18, 19, 20 UKCS 5 1971 to 1993 21, 22 UKCS 4 1984 to 1994 Others (14) Mostly UKCS 6 1967 to 1995 Ev 78 Energy & Climate Change Committee: Evidence

Summary

90. It is possible for oVshore infrastructure to be operated successfully beyond the notional design life, provided that this is properly resourced and managed by the operators. DECC and other regulators are seeking to ensure that this takes place. There is significant diversity and robustness in the arrangements for gas supply from the UKCS and abroad. DECC is continuing to work with industry to better understand and improve where possible the resilience of gas supply arrangements.

Is the right policy framework in place to manage the decommissioning of that infrastructure as resources are depleted?

91. The Government has a responsibility to ensure that all oVshore installations and pipelines are decommissioned with regard to safety, environmental, social and economic impacts. DECC manages a decommissioning regime that addresses these factors and conforms to international commitments and public expectations, whilst minimising the risk that the taxpayer might have to step in if companies default. Legislation has been updated to take account of changes in industry practices and the growth of smaller players in the sector. DECC balances the national interest in maximising oil and gas activity and use of the oVshore infrastructure against the responsibility for ensuring eVective decommissioning.

Legislative background

92. Oil and gas decommissioning is regulated by Part IV of the Petroleum Act 1998, as amended by the Energy Act 2008. Notices setting a decommissioning obligation on all the companies responsible for an installation or pipeline are served at the start of field life. If interests change hands, the new company is given an obligation notice and we release the selling party from their liability, if the risk is acceptable. Towards the end of field life the companies are asked for a decommissioning programme which must be approved by the Secretary of State. The parties are then responsible for carrying out the work specified in the programme. 93. Obligations to carry out an approved programme are joint and several. If one party defaults the other companies must pay the defaulting party’s share. This is an important concept and helps mitigate the risk and protect the taxpayer in a potential default situation.

Decommissioning scope and programmes

94. The industry has begun to decommission the 500 installations and 35,000 kilometres of pipelines on the UKCS but with UK oil and gas continuing to supply around 70% of our prime energy demand, decommissioning work will be spread over the next 40 or more years. The cost of this work is currently estimated at £23 billion with individual installations costing from £5 million to £300 million. 95. It is important that this ongoing decommissioning work is carried out in a sound manner consistent with our international obligations. The OSPAR Convention came into force in 1998. Ministers adopted a binding Decision, OSPAR Decision 98/3, to ban the disposal of oVshore installations at sea. The Decision recognised there would be diYculty in removing the “footings” of large steel jackets weighing more than 10,000 tonnes and in removing concrete gravity base installations. As a result derogations may be granted in these cases. But there is a presumption that all installations will be removed entirely and exceptions will only be granted if an assessment and consultation process shows that there are significant reasons why leaving it in place is preferable to re-use, recycling and final disposal on land. 96. The OSPAR Decision is the principal international ruling regarding decommissioning and in the majority of cases installations will be brought on land for recycling and waste disposal. However, DECC is keen to encourage the re-use of facilities e.g. for other oil and gas developments, gas storage, renewables or carbon sequestration and companies have to consider these options in their plans. The Energy Act 2008 extends the oil and gas decommissioning regime to oVshore gas storage and carbon sequestration projects. 97. Decommissioning programmes need to consider the safety, environmental, social and economic impacts of a project. All programmes must include an environmental impact assessment which addresses the impact on climate change by detailing potential emissions and consumption of natural resources and energy. 98. Transparency and openness is an important aspect of the regime and DECC consults other departments and agencies and requires companies to consult the public; the outcome of the consultation must be reported in the programme before approval by the Secretary of State. 99. DECC publishes comprehensive guidance notes explaining its policies, the programme approval process and the factors that companies should consider. The notes were revised in January to take account of comments from industry and clarify how the new Energy Act provisions will be implemented. Energy & Climate Change Committee: Evidence Ev 79

Changing industry practices and update of legislation 100. The Petroleum Act 1998, which consolidated earlier legislation, was drafted over 20 years ago when most fields were in the hands of the oil majors. Since then the majors have sold many assets to independents and smaller companies, which have also developed new fields. These companies have fewer financial resources than the majors and bring an increased risk that they might not be able to meet their decommissioning liabilities. New business models and commercial arrangements have also meant it has not always been possible to share liabilities equitably between all the companies responsible for an installation or pipeline because of the wording of the legislation. 101. The Energy Act 2008 addresses these issues by closing a number of gaps in legislation and giving the Secretary of State power to require financial guarantees whenever he believes that the risk to the taxpayer is unacceptable. Prior to the Energy Act the Secretary of State could only require guarantees to be provided once a decommissioning programme had been approved and programmes are only developed towards the end of field life when there is a clear understanding of technical abilities and legislative requirements. The Energy Act enables new projects to go ahead with the assurance that the taxpayer will be properly protected. 102. There was full and open consultation with industry and other interested parties on the new legislation and where possible, industry concerns were accommodated. In particular, the Act clearly specifies which licensees can be given a decommissioning obligation, addressing an issue created by the way that licence partners divide their interests under commercial agreements. DECC continues to work closely with industry to ensure we understand their concerns and our requirements remain fit for purpose.

Risk assessment 103. DECC uses a transparent risk assessment process to determine the risk of companies defaulting on their decommissioning obligations. This assessment process supports decisions whether to require financial guarantees for new projects when licence interests change hands or when company circumstances change. 104. The costs of decommissioning the installations for which a company is responsible are compared to the net worth on its balance sheet. We look at all the company’s UKCS interests and the strength of any corporate group to which they belong. Given the current financing climate, we also look at cash flow and debt repayment data. If the costs of the project, or the company’s UKCS liabilities, are more than 50% of the net worth, DECC will discuss the situation with the company to confirm its assessment. 105. If the assessment indicates a medium or high risk we will check if the company has a parent or other associate which has suYcient assets to cover the decommissioning costs. Decommissioning obligations can be placed on the associated company to spread the risk. If the risk cannot be mitigated, DECC will require a financial guarantee after first giving the company an opportunity to make representations, and consulting the Treasury on any implications for tax. 106. Security can be cash or bank guarantee such as a letter of credit. Guarantees need to be from a suitably rated financial institution and the current downgrading of banks and reluctance to lend money restricts industry options. DECC recognises this and invites alternative forms of security whilst ensuring our requirements remain proportionate. Despite the increase in smaller companies operating in the UKCS, financial guarantees have only been necessary in a minority of developments and security costs are not a significant element in project budgets.

Summary 107. DECC operates an eYcient regime ensuring sound decommissioning is carried out in a manner consistent with the UK’s international obligations and public expectations. A flexible approach enables decommissioning policy to take account of industry concerns and the open and transparent process ensures stakeholder access. The risks of company defaults are monitored and assessed throughout field life and mitigation measures instigated if the risk to the taxpayer is unacceptable. 108. DECC recognises the impact of liabilities on trading of licence interests and future developments and works with the industry to minimise any restriction on future oil and gas activity. DECC recognises the opportunities for re-use of structures for other energy or climate benefits. The Energy Act 2008 has updated the decommissioning regime to meet the requirements for future oil and gas activity. Clear guidance and a transparent risk assessment process help companies understand their position. This is particularly important as Government and industry cope with the impact of the banking crisis and the current low oil price. March 2009 Ev 80 Energy & Climate Change Committee: Evidence

Annex 1:

CHARTS

Chart 1

Chart 2 Energy & Climate Change Committee: Evidence Ev 81

Chart 3 Ev 82 Energy & Climate Change Committee: Evidence

Chart 4

GAS PIPELINE ALTERNATIVE ROUTES FOR WEST OF SHETLAND DEVELOPMENTS Energy & Climate Change Committee: Evidence Ev 83

Annex 2

KEY ACTIVITY-LEVEL ENVIRONMENTAL LEGISLATION — The OVshore Chemicals Regulations 2002 (as amended)—control the use and discharge of all operational chemicals, and implement OSPAR Decision 2000/2 on a harmonised mandatory control system for the use and reduction of the discharge of oVshore chemicals. — The OVshore Petroleum Activities (Oil Pollution, Prevention and Control) Regulations 2005— control all deliberate oil discharges. Major discharges are waste streams contaminated with reservoir hydrocarbons, e.g. produced water. — The OVshore Combustion Installations (Prevention and Control of Pollution) Regulations 2001 (as amended)—control the quantities of noxious pollutants emitted from combustion equipment on qualifying installations, and implement the Integrated Pollution Prevention and Control Directive for oVshore oil and gas installations. The regulations ensure that “best available techniques” are employed to reduce emissions. — The Greenhouse Gas Emissions Trading Scheme Regulations 2005 (as amended)—authorise the emission of greenhouse gases (currently only CO2), and implement the EU Emissions Trading Scheme. — The OVshore Installations (Emergency Pollution Control) Regulations 2002—ensure that operators have appropriate measures in place to prevent oil spills and to ensure that if they occur they are handled eVectively. — The Merchant Shipping (Oil Pollution Preparedness, Response and Co-operation Convention) Regulations 1998—require operators to prepare and submit an Oil Pollution Emergency Plan (OPEP), covering all activities where there is a risk of hydrocarbon spill and detailing the action to be taken should a spill occur.

Supplementary memorandum submitted by the Department of Energy and Climate Change

Note for the Energy and Climate Change Committee on the Changes to the North Sea Fiscal Regime included in Budget 2009 The following material has been agreed with HMT and HMRC.

North Sea Fiscal Regime 1. The Government remains fully committed to maximising the economic recovery of the UK’s oil and gas resources and recognises the vital role that the oil and gas industry plays in contributing to the UK’s energy security of supply. It is also fully aware of its wider contributions to the UK economy through employment, impact on the balance of trade and the skills, expertise and cutting edge research and development it engenders. 2. Following a consultation “Supporting Investment” launched at the 2008 Pre-Budget Report, Budget 2009 announced a further package of reforms to the North Sea fiscal regime, building on those announced in Budget 2008, to support the investment necessary to realise the potential of the UK Continental Shelf (UKCS). The measures, which are designed to encourage the economic recovery of the UK’s oil and gas reserves, will be legislated in Finance Bill 2009. 3. Central to this package is the introduction of a new “Field Allowance” (described in the consultation document as a “value allowance”). This will give incentives to encourage investment in small or technically challenging fields, which could assist in unlocking around 2 billion barrels of the UK’s remaining oil and gas reserves. It will be targeted at new small fields, with an allowance set at £75 million, and at challenging new High Pressure High Temperature or Heavy Oil fields, with the allowance set at £800 million. The introduction of the Field Allowance marks a significant change to the approach of the North Sea Fiscal Regime. The Government believes it has the potential to make an important contribution to the competitiveness and attractiveness of investments in the UKCS. Industry also made a case for the Field Allowance to extend to some other types of development. Whilst the Government was not convinced of their arguments on this occasion, it of course remains willing to discuss such matters further in the future if a compelling case can be made. 4. The package also includes measures to assist asset trades and give companies the certainty and stability they need to underpin investment. In brief, in addition to the new Field Allowance, the package of reforms announced at Budget comprises: (a) Changes to the chargeable gains regime within the North Sea ring-fence to remove chargeable gains entirely from licence swaps and making gains exempt where disposal proceeds from ring fence assets are reinvested within the UKCS. Ev 84 Energy & Climate Change Committee: Evidence

(b) Changes to the North Sea fiscal regime to remove potential barriers to projects that re-use North Sea infrastructure for non-ring-fenced purposes including gas storage, carbon capture and storage and wind energy. (c) Amending the petroleum revenue tax (PRT) regime to ensure that companies whose production licences have expired are still able to access PRT decommissioning relief where appropriate. (d) Changes to the PRT regime to reduce the administrative burden it imposes, simplify compliance and repeal obsolete legislation. Further details of these changes are set out in the attached Budget Notes. Legislation to enact these measures will be published as part of Finance Bill 2009. 5. Discussions with Industry on the North Sea regime have been ongoing since 2005. The Government thanks all those in Industry for the eVorts they have made in engaging fully and constructively with Government on these issues over this extended period. There is no stated “next step” for the discussions but that should certainly not be taken as a sign that the Government considers that the process of engagement is at an end. The Government will continue to engage with stakeholders wherever necessary to ensure that the North Sea fiscal regime continues to help deliver the best possible future for the UKCS. In particular, oYcials from both DECC and HMT/HMRC have been asked to look further into the question of post tax decommissioning security and to discuss this complex area with Industry in the coming months.

Preventing Accelerated Decommissioning Relief 6. Budget 2009 also announced that, in order to close down a tax avoidance scheme, the Government was amending with immediate eVect the rules providing tax relief for the decommissioning costs of North Sea installations and infrastructure. The changes to the North Sea fiscal regime will ensure companies cannot access tax relief for decommissioning oil and gas infrastructure years in advance of the decommissioning activity actually being carried out. As originally intended, companies will in future be able to claim tax relief for decommissioning costs only for the accounting period in which the work is actually carried out. Draft legislation and Explanatory Notes in relation to the changes were published alongside the Budget.

Tax Relief for Cost of Cushion Gas 7. Following calls for clarification of the tax treatment of cushion gas in gas storage facilities, the Budget also confirmed that, after a full and detailed consideration of the established case law, and after taking advice from leading Counsel, HMRC accept that purchased cushion gas does comprise plant for the purposes of plant and machinery capital allowances and hence expenditure on cushion gas will be eligible for capital allowances. HMRC have written separately to individual operators, and to the Gas Storage Operators Group, to confirm this treatment. This announcement will give the industry the clarity and certainty they need to bring forward gas storage projects to meet the UK’s gas storage requirements which will increase security of supply and help smooth energy price fluctuations. April 2009

Further supplementary memorandum submitted by the Department of Energy and Climate Change

Performance against the PILOT Targets 1. PILOT is a joint programme involving the Government and the UK oil & gas Industry—including operators, contractors, suppliers and trade unions—aiming to secure the long-term future of the Industry in the UK. It is the successor to the Oil & Gas Industry Task Force (OGITF) which was established in late 1998 in recognition of the dramatic fall in oil prices, the maturing of the UKCS and the urgent need to reduce the cost base of activity in the basin. The results and recommendations of the OGITF were detailed in its report Template for Change8 launched in September 1999. 2. OGITF’s overall objective was to create a climate for the UKCS to retain its position as a pre-eminent active centre of oil & gas exploration, development and production and to keep the UK contracting and supplies industry at the leading edge in terms of overall competitiveness. This objective was quantified into a “Vision for 2010”. OGITF ran through to 1999, instituting several new industry bodies to enable improvements in the industry’s competitiveness and capabilities. PILOT was established on 1 January 2000 and monitors the progress being made towards achieving the Vision and identifies new areas of activity to assist this progress. It also provides a forum to discuss the condition of the Industry and to build alignment about the appropriate direction it should take. 3. The Vision for 2010 was:

8 Available from http://www.pilottaskforce.co.uk/docs/aboutpilot/atemplateforchange.pdf. Energy & Climate Change Committee: Evidence Ev 85

The UK oil and gas industry and Government working in partnership to deliver quicker, smarter and sustainable energy solutions for the new century. A vital UK Continental Shelf is maintained as the UK is universally recognised as a world centre for the global business. 4. To make this vision a practical reality, specific aspirational targets were set for the year 2010: — investment sustained at £3 billion per annum from UKCS activity — production at three million barrels of oil equivalent per day — prolonged self-suYciency in oil and gas — a 50% increase in exports in oil and gas supplies products [by 2005] — £1 billion additional value from new businesses — supporting up to 100,000 jobs more than there otherwise would have been 5. The following additional target was added in 2002: — In 2010, the UK is the safest place to work in the worldwide oil and gas industry 6. Progress to date against these targets is assessed below.

Investment sustained at £3 billion per annum from UKCS activity As shown in the chart below, UKCS capital expenditure since 2000 has comfortably exceeded £3 billion per annum:

UKCS CAPITAL EXPENDITURE 1970–2007 (2007 PRICES)

UKCS Capital Expenditure 1970–2007 (2007 prices) 13 Exploration & Appraisal Expenditure (£52 billion) 12 Development Capital Expenditure (£208 billion) 11 10 9 8 7 6 £ billion 5 4 3 2 1 0 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

Source: https://www.og.berr.gov.uk/information/bb updates/appendices/Appendix7.htm. A survey of operators’ intentions to invest in UKCS oil and gas production was conducted in autumn 2008.9 The survey indicated total development capital expenditure (ie excluding expenditure on exploration, appraisal and decommissioning) relating to existing fields and significant discoveries of around £5.0 billion in 2008, slightly lower than the outturn total of £5.3 billion for development capital expenditure in 2007. As illustrated in the chart below, the reported survey data suggest that (in 2008 prices) expenditure might rise to around £6 billion in both 2009 and 2010 but great uncertainty applies to these figures which seem unlikely to be seen in practice.

9 See “UKCS capital expenditure survey 2008” (Energy Trends, March 2009; http://www.berr.gov.uk/files/file50677.pdf). Ev 86 Energy & Climate Change Committee: Evidence

TOTAL UKCS DEVELOPMENT CAPITAL EXPENDITURE 8.5 8.0 7.5 7.0 6.5 6.0 5.5 5.0 4.5 4.0 3.5 3.0 £ billion (2008 prices) 2.5 Possible New Fields 2.0 Possible Incremental Projects 1.5 Probable New Fields 1.0 Probable Incremental Projects 0.5 Sanctioned Fields 0.0 2008 2009 2010 2011 2012 2013

The survey was conducted during a period when oil prices were falling from a recent historically level which had been responsible for significant input cost inflation. Continued lower product prices combined with only a slow fall in input cost levels and funding diYculties caused by lower cash flow and the “credit crunch” lie behind recent reductions in many companies’ investment plans which are not reflected in the reported data. It seems certain that development capital expenditure in 2009 will fall well short of £5 billion and might actually fall below £4 billion in 2010. However, it seems likely that the PILOT target will be comfortably exceeded.

Production at three million barrels of oil equivalent per day (boepd) The chart compares this target, and the interim target set in 2001 for the year 2005, with actual production through to 2007 and the Department’s latest production forecasts for the period 2008–13. It now seems certain that total oil and gas production will not be maintained to reach the 2010 PILOT “Vision” production target of 3 million boepd. The current projections imply total production in 2010 of 2.4 mboepd (compared with 2.8 mboepd in 2007). Nevertheless, these aspirational targets were useful in providing a focus for many of the initiatives which have borne fruit in the last decade. The aspirational nature of the vision target for production in 2010 is emphasised by the fact that the supporting analysis against which it was set indicated production declining to a maximum of 2.2 million boepd. Energy & Climate Change Committee: Evidence Ev 87

PROJECTED UKCS OIL AND GAS PRODUCTION AND PILOT TARGETS

4.5

4.0

3.5

3.0

2.5

2.0

1.5 DECC Projection (Sept 2008) 1.0

million barrels of oil equivalent/day PILOT Production Targets 0.5

0.0 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 DECC Projection (Sept 2008) 4.3 4.6 4.5 4.2 4.2 4.0 3.6 3.3 3.0 2.8 2.7 2.5 2.4 2.3 2.2 2.1 PILOT Production Targets 4.0 3.0

Source: https://www.og.berr.gov.uk/information/bb updates/chapters/Section4 17.htm. Ev 88 Energy & Climate Change Committee: Evidence

Prolonged self-suYciency in oil and gas The chart below shows actual and currently projected UKCS oil and gas production and actual and projected UK demand for oil and gas. It shows that the UK is expected to become increasingly reliant on imported oil and gas. The dotted green line measures achievement against the PILOT “Vision” target of prolonged self-suYciency in oil and gas. This was maintained until 2004 against a target of 2010.

ACTUAL/PRODUCTION UK OIL AND GAS PRODUCTION AND DEMAND (MILLION TONNES OF OIL EQUIVALENT)

150 150 140 140 130 130 120 120 110 110 100 100 90 90 80 80 70 70 60 60 50 50 40 40 30 30 20 20 10 10 0 0 -10 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 -10 -20 -20 -30 -30 -40 -40 -50 Oil Production Oil Demand -50 -60 Gas Production Gas Demand -60 -70 Net Oil and Gas Exports/(Imports) -70 Source: https://www.og.berr.gov.uk/information/bb updates/chapters/Section4 17.htm.

A 50% increase in exports in oil and gas supplies products [by 2005] This was the first target to expire and was exceeded by a considerable margin. The UK is now recognised as a global hub for oil and gas expertise (especially in the sub-sea sector) with the global market set to grow at pace into the future. A recent report issued by UKTI projected potential growth from a current figure of around £8 billion to £30 billion by 2030.

£1 billion additional value from new businesses The renewables, and particularly oVshore wind, market will predominantly be serviced by the oil and gas supply chain and generate a substantial diversification opportunity.The restricting factor being capacity and the export market grows for core oil and gas services.

Supporting up to 100,000 jobs more than there otherwise would have been Against a background of sustained higher expenditure, notably capital expenditure but also expenditure on exploration & appraisal, operations and decommissioning, employment in and supported by the UK upstream oil industry has risen in recent years. Even if expenditure falls this year and next, employment is likely to be significantly higher than it would have been without the results of the sustained co-operation between Government and industry through PILOT over the past decade. Energy & Climate Change Committee: Evidence Ev 89

UK OIL AND GAS INDUSTRY EMPLOYMENT 1998–2008 (EXCLUDING EXPORT ACTIVITY)

400,000 Induced Supply chain 350,000 Oil and Gas companies 300,000

250,000

Jobs 200,000

150,000

100,000

50,000

0 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 Source: Experian / National Statistics / BERR / Oil & Gas UK

In 2010, the UK is the safest place to work in the worldwide oil and gas industry While significant improvements have been made over the past nine years with lost time incidents more than halved there is still more to do as we have now reached a plateau in the UKCS and are still behind Australia and Asia on safety. The industry has a dedicated safety initiative in “Step Change” which continually monitors progress and sets even higher standards in its quest to become the best in the world. The charts below come from Oil & Gas UK’s 2007 Sustainability Report (at http://www.oilandgas.org.uk/ issues/sustainability/2007/main/social/social-5.cfm):

LOST TIME INJURY FREQUENCY—UK TO BE THE SAFEST PLACE TO WORK IN THE WORLD-WIDE OIL AND GAS INDUSTRY BY 2010 4

3.5 UK LTIF (includes fatlities) Best Region in the World 3.0

2.5

2.0 manhours 1.5

1.0

Lost time incident frequency per million 0.5

0 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Source: OGP Ev 90 Energy & Climate Change Committee: Evidence

LOST TIME INJURY FREQUENCY (LTIF)—2006 EUROPEAN COMPARISION (INCLUDES FATALITIES) 3

LTIF 2006 2.5 European Average 2006 (LTIF 1.65)

2.0

1.5

1.0

0.5 Lost Time Injury frequency (per million manhours) Lost Time

0 Denmark Italy Norway UK Netherlands Romania Germany Ireland Source: OGP

FATAL ACCIDENT RATE (FAR)—2006 REGIONAL COMPARISON 0.06

0.05

0.04

0.03

0.02

0.01 Fatal Accident Rate (per million manhours)

0.00 Africa FSU S.America Australasia Middle East N.America Europe (inc UK) UK Source: OGP

Lost Time Injury Frequency – UK to be the Safest Place to Work in the World-wide Oil and Gas Industry by 2010 Lost Time Injury Frequency (LTIF)—2006 European Comparison (includes fatalities) Fatal Accident Rate (FAR)—2006 Regional Comparison DECC, 26 March 2009 May 2009 Energy & Climate Change Committee: Evidence Ev 91

Memorandum submitted by the Joint Nature Conservation Committee, Countryside Council for Wales, Natural England and Scottish Natural Heritage

Summary of Key Points

1. From a nature conservation perspective, we consider that the current framework of regulatory control is generally good with most advice provided by the statutory nature conservation agencies being heeded. 2. We consider that DECC should review the current system by which operators can commit to undertake certain environmental protection activities, but then alter these commitments after a licence has been granted. Greater consistency in these commitments between operators should also be sought. 3. To ensure that environmental advice is underpinned by a sound evidence base we consider that better information is required on: (i) oVshore seabird distribution; (ii) impacts of developments on benthic communities; and (iii) impacts of noise from developments. 4. We consider that the future strategy for undertaking Strategic Environmental Assessment (SEA) of oil and gas should include a review of the process and a mechanism for updating existing SEAs in the light of new information.

1. Introduction

1.1 The Joint Nature Conservation Committee (JNCC) is the statutory advisor to Government on UK and international nature conservation, on behalf of the Council for Nature Conservation and the Countryside, the Countryside Council for Wales, Natural England and Scottish Natural Heritage. 1.2 The Countryside Council for Wales (CCW) champions the environment and landscapes of Wales and its coastal waters as sources of natural and cultural riches, as a foundation for economic and social activity, and as a place for leisure and learning opportunities. CCW aims to make the environment a valued part of everyone’s life in Wales. 1.3 Natural England (NE) conserves and enhances England’s natural environment, for its intrinsic value, the wellbeing and enjoyment of people and the economic prosperity that it brings. 1.4 Scottish Natural Heritage (SNH) is a statutory advisor to Scottish Government. SNH’s role is to look after Scotland’s natural heritage, help people to enjoy and value it, and to encourage people to use it sustainably. 1.5 This memorandum is a co-ordinated response from JNCC, CCW, NE and SNH.

2. Background to the Agencies’ work in relation to the oil and gas industry

2.1 JNCC, CCW, NE and SNH (the “Agencies”) are statutory consultees for oil and gas activities under several pieces of legislation and are consulted for advice by DECC, the regulatory authority, concerning activities within their advisory ambit. CCW, NE and SNH provide advice within their respective territorial waters (out to 12 nautical miles). JNCC provides advice in oVshore waters beyond 12 nautical miles, extending to the limit of the United Kingdom Continental Shelf. 2.2 JNCC is responsible for the majority of oil and gas advice and it also co-ordinates advice from the country agencies where appropriate. The Agencies have had an advisory role within the steering group for the Strategic Environmental Assessment (SEA) process for oil and gas licensing rounds. 2.3 There are some general principles that the Agencies use when advising on oil and gas issues. These are: (i) advice should be consistent with the need to protect important habitats and species listed by European Directives, such as the Habitats (92/43/EEC) and Birds Directives (79/409/EEC); (ii) advice should be based on the best available scientific information; (iii) advice should provide best environmental practice that is proportionate and appropriate, consistent with a risk-based approach to the management of environmental issues; and (iv) advice to the regulatory authorities and oil and gas operators should be consistent. Ev 92 Energy & Climate Change Committee: Evidence

3. How eVective is the current fiscal and regulatory regime in which the industry operates?

EVectiveness of current regulatory regime 3.1 The Department of Energy and Climate Change (DECC) has an in-house Environmental Management Team that is the main contact point for the Agencies’ advice. There is a regulatory requirement for the Agencies to be consulted on all applications that require consent, such as: drilling of wells, Food and Environment Protection Act (FEPA) licences, laying of pipelines, oil spill response, oil spill contingency planning and carrying out of geological surveys. We consider that the Agencies currently have a good relationship with both the industry and the regulator that generally enables eVective collaboration in order to address key environmental issues. 3.2 From a nature conservation perspective, we consider that the current framework of regulatory control, with advice provided by the Agencies, eVectively meets the UK’s obligations under the terms of the Habitats and Birds Directives as well as providing the potential to deliver best practice measures.

4. What can be done to minimise the environmental impact of exploiting the reserves? How should this be encouraged and/or financed?

Regulatory compliance with project-specific conditions 4.1 The Agencies believe that compliance with the Environmental Impact Assessment (EIA) process that is undertaken for oil and gas activities by the operators has scope for improvement. 4.2 It has been our experience that operators and their associated environmental consultants present Environmental Statements for projects that indicate that best practice mitigation measures will be adopted throughout implementation. However, in some cases, once the project has been granted approval, operators have subsequently amended the project and not delivered on initial commitments made in the Environmental Statement, examples being: (i) failure to deliver the best available techniques (BAT) as specified in the Environmental Statement; (ii) changes in methods of discharging drilling and chemical wastes; (iii) unanticipated use of rock to stabilise pipelines; and (iv) unanticipated flaring of hydrocarbons. The impression given can be that the information provided within the Environmental Statement is solely for the purposes of gaining consent and does not reflect the reality of what will be implemented. In our view, cost-eVectiveness is not a suitable justification for changing commitments made within an EIA. 4.3 At the moment, Environmental Statements and Petroleum Operations Notices often contain far too much generic data extracted from previous statements. Commitments by operators can be lost within excessive text. The quality of the EIA process would be improved if regulators were able to ensure oil and gas operators make it clear within their applications what measures will be implemented to minimise adverse impacts upon the environment. Ideally, these commitments should be presented as a set of statements within their submissions; amendments to these statements subsequent to gaining consent should be an extreme exception, and subject to a renewed EIA. The OVshore Inspectorate within DECC should be able to check these commitments during inspections and ensure that there is regulatory compliance. Currently, we do not think that the OVshore Inspectorate is provided with enough project-specific information to be able to eVectively check compliance with approval consents. 4.4 DECC are currently amending the EIA guidance notes for operators, which should lead to improvements. We recommend that DECC should review the current system of ensuring EIA compliance.

Importance of up-to-date environmental data 4.5 The provision of reliable environmental advice to the oil and gas industry and regulatory authorities is reliant on the information underpinning the advice being up-to-date and accurate. The Agencies promote and share good practice by hosting and contributing to a wide range of initiatives that seek to improve survey techniques and monitoring programmes. The following issues need further investment to ensure that information is fully reliable: (i) knowledge of oVshore seabird distribution; (ii) impact of developments on benthic communities; and (iii) impacts of noise from developments. 4.6 Information on oVshore seabird distribution can be used for a number of purposes, including assessing potential impacts of oil spills and oil spill contingency planning; more importantly, it provides an easy guide for the oil and gas industry to plan their activities by highlighting areas and times of the year when any oil spills could have a significant environmental impact. The majority of information in use derives from the Energy & Climate Change Committee: Evidence Ev 93

1980s and 1990s, when data collection was funded very eVectively by a consortium of relevant Government and industry partners. We recommend that a similar programme be established to update information relevant to oil and gas developments. 4.7 There is considerable variability between oil and gas operators in relation to monitoring the impacts of their activities on benthic (seabed) communities. Some operators undertake extensive and comprehensive surveys around their installations, whereas others do not carry out any surveys. Impacts may be chronic in their eVect and monitoring is needed in these cases. We recommend that benthic monitoring be carried out by industry to standards set by Government. 4.8 A number of oil and gas activities, principally seismic surveys, hammer piling of infrastructure and explosive use in decommissioning activities can generate sounds that can disturb, and in extreme cases injure, marine mammals. Oil and gas operators use best practice guidelines, developed and updated by JNCC, to mitigate the impacts of these sounds. The development and refinement of the best practice guidelines is an adaptive process, reliant upon the latest scientific research and development of mitigation techniques. The oil and gas industry has an extensive research programme in place to examine these eVects and to further develop mitigation techniques. Our greatest priority for research or mitigation of the impacts of noise from developments is to improve techniques to monitor marine mammals during night time or periods of poor visibility.

EYcacy of the SEA process for future oil and gas licensing rounds 4.9 The eighth Strategic Environmental Assessment (SEA) has recently been undertaken for oil and gas licensing and was incorporated within the “Energy SEA”. There is a long future for the oil and gas industry in the UK, and we would welcome a commitment for there to be future SEAs specific to oil and gas licensing. In order to be confident that any future licensing rounds are based on suitable and up-to-date environmental information, we recommend that the Government commit to undertaking a review of the oil and gas SEA programme after the Energy SEA has been completed. 4.10 Future SEAs should be directed at ensuring that the recommendations of the current oVshore SEA are still valid, and that suYcient resources have been directed towards addressing any uncertainties, or recommendations made within previous SEAs. A clear explanation of how this fits into the wider context of SEA for other oVshore industries (eg oVshore wind) and Marine Spatial Planning would be helpful. SEAs are also suitable for addressing the cumulative eVects of industries and ensuring that these do not have an adverse eVect on the marine environment. 4.11 We consider that the future strategy for undertaking SEA of oil and gas should include a review of the process and a mechanism for updating existing SEAs in the light of new information, and we recommend that the future strategy for undertaking SEA of oil and gas is clearly articulated to all stakeholders by the regulator. March 2009

Memorandum submitted by Professor Alexander Kemp, University of Aberdeen

Executive Summary The UKCS is now a maturing province with declining remaining proven, probable, and possible reserves and production. New field sizes average around 20 million barrels of oil equivalent with the most likely being less than that. Nevertheless the remaining aggregate potential exceeds 20 billion barrels of oil equivalent. The recent collapse in oil/ gas prices has greatly reduced cash flows and the prospective returns on many new investments are below commercial thresholds. Continuous investment is required to maximise economic recovery. To mitigate the inevitable fall in investment a significant value allowance for the Supplementary Charge is desirable. Tax incentives are also desirable for incremental projects and exploration. Non-tax initiatives, principally those relating to fallow acreage, stewardship of mature fields and the infrastructure Code of Practice should be vigorously pursued over the longer term. The current provisions for financial security for decommissioning should be modified to encourage asset transactions. 1. The UK Continental Shelf may be defined as a maturing petroleum province. It is personified by a combination of falling production of both oil and gas, declining remaining discovered reserves, and declining average field sizes. All these combine to put upward pressures on both the investment and operating costs per barrel of oil equivalent (boe). This problem has been greatly exacerbated over the past four years or so by the dramatic worldwide cost escalation which has followed the large oil price increases. In turn this reflected a tightness in the markets for a range of equipment and materials. The spectacular increase in drilling rig hiring rates was the most dramatic and well-publicised example of this phenomenon. Ev 94 Energy & Climate Change Committee: Evidence

2. The maturing of the province has also brought some benefits and advantages. Firstly, there now exists a large oil and gas cluster incorporating well-developed expertise in all aspects of oVshore exploration and production. Secondly, there is now a large infrastructure of pipelines, terminals and large processing platforms. These can be used to facilitate the development of new fields which would otherwise be uneconomic. The majority of new developments are subsea ones tied back to existing infrastructure. Third party tariYng arrangements are very common. 3. The current perspective with respect to future prospects may be summed up as follows: (a) The remaining potential in aggregate is large. The central estimate of the aggregate remaining potential according to DECC estimates is around 21 billion barrels of oil equivalent (bn boe). This may be related to total depletion to date of around 38 bn boe. Remaining discovered reserves (proven ! probable ! possible) according to the DECC are just under 10 mm boe while undiscovered resources could be 8.7 bn boe. There is, of course, a wide range of possibilities and the current DECC estimates for the remaining potential involve a low of 11 bn boe and a high of over 37 bn boe. (b) The remaining reserves are generally located in relatively small fields. The average size of a new field development is now around 20 mm boe, and, because the size distribution is lognormal, the most likely sizes are less than 20 mm boe. This figure can be compared to an average size of new field development in the 500–600 mm boe range during the period from the later 1960s to the mid- 1970s. Because of the substantial economies of scale in the hydrocarbon development/ production activity the smaller field size puts upward pressure on costs per unit (boe). In turn this reduces the competitiveness of the UKCS as an investment centre compared to other petroleum provinces where the fields are larger and unit costs lower. (c) The above features relate to the criteria generally employed by oil companies in assessing investment opportunities. Typically they compare their opportunities on a world-wide basis. This statement applies not only to large companies but to medium-sized and smaller ones as well. In making comparisons companies typically rank the prospective returns and put emphasis on the materiality of these and the relative productivity of the capital invested.10 The current major problems in the financial markets have reduced the availability of external capital to the small/ medium-sized companies, and this capital rationing means that the investment hurdles have to be raised. This can have adverse eVects for the UKCS where the small, high cost fields translate into relatively modest values in the capital productivity index. (d) A feature of the maturing UKCS is the (inevitable) increasing reliance on production from fields of more recent vintages. This follows because depletion proceeded to such an extent that production from them is quite low. But the newer fields are not only on average smaller than older ones but their decline rates are much faster. Generally peak output is achieved greatly in field life but then production declines at a brisk pace, and certainly faster than has been the case in the older fields. This is seen in graphical form for the oil fields in Chart 1 below.

10 In the language of economics there is emphasis on the size of the net present value (NPV) on wealth expected to be generated, taking into account the cost of capital, and the capital productivity index or the ratio NPV/ I where I is the investment cost, again taking the cost of capital into account. Energy & Climate Change Committee: Evidence Ev 95

Chart 1

There is a major implication of this trend for the future of the UKCS. The production decline rate will be quite brisk unless substantial numbers of new fields and incremental projects can be brought on stream year by year to counter this inherent trend. Given the likely sizes of the new fields as many as 20 new fields coming on stream per year plus a substantial number of incremental projects would be insuYcient to halt the production decline. Given the financial and physical constraints on the industry it is most likely that the average number of new field new developments will be less than 20 per year over the longer term, and considerably less at current oil prices. The recent collapse in the oil price plus the substantial fall in the wholesale gas price has greatly reduced the industry’s cash flows which, coupled with the increased diYculty in obtaining external finance, mean that financing constraints will be significant at least in the short term, with no current indications when they are likely to be lessened or removed. These financial constraints also have marked eVects on the volume of exploration and appraisal activity for which no bank finance is in any case generally available. (e) The key to the mitigation of the decline rate is clearly continuous investment in new fields and incremental projects which in turn are made more possible when backed up with a healthy volume of exploration and associated new discoveries. It should be noted that any decline in field investment (new and old) has further knock-on eVects. The infrastructure of pipelines, processing platforms, and terminals will be less fully utilised. It is clearly important that the life of this infrastructure be prolonged to facilitate the development of future projects. But the remaining economic lives of a significant number of platforms are currently not very long due to the imminent approach of maximum economic recovery from the host fields. Worthwhile tariV incomes from new fields could prolong the lives of the platforms. Similar considerations apply to pipelines where substantial third party use could justify the expenditure of funds to maintain the integrity of the facilities. A rundown in field investment in the near term could lead to the earlier decommissioning of host platforms and pipelines. Deferral of investment in the North Sea is not in the national interest. 4. The present author has recently undertaken substantial economic modelling of the future of the UKCS under the present tax system and at diVerent oil and gas price scenarios namely (1) $80 per barrel and 70 pence per therm (in constant real terms), (2) $60 and 50 pence, and (3) $40 and 30 pence.11 The weighted average cost of capital was taken to be 10% in real terms. The results for total hydrocarbon production over the long period to 2035 are shown in Charts 2–4. It is seen that under the $40,30 pence12 scenario total hydrocarbon production falls oV very rapidly indeed, and ultimate recovery from the UKCS is very much less than the potential as seen by DECC. In fact in the period 2008–35 only 10 bn boe are recovered. Under

11 For full details see A.G. Kemp and L. Stephen, The Prospects for Activity in the UKCS to 2035: the 2008 Perspective, North Sea Study Occasional Paper No. 109, University of Aberdeen Department of Economics, October 2008. 12 On 3 March 2009 the Brent blend oil price was $42.50 and the wholesale gas price 34 pence. Ev 96 Energy & Climate Change Committee: Evidence

the $60,50 pence case the decline rate is much less pronounced and in the period 2008–35 15.5 bn boe are recovered. Under the $80,70 pence case production falls slowly and in the period 2008–35 19.6 bn boe are recovered.

Chart 2

Chart 3 Energy & Climate Change Committee: Evidence Ev 97

Chart 4

5. The behaviour of field investment under the corresponding three price scenarios is shown in Chart 5–7. It is seen that there is a dramatic fall in investment under the $40,30 pence case: many new projects are not viable. Under the $60,50 pence case investment falls moderately over the next few years and more noticeably in the longer term. Under the $80,70 pence case investment holds up well for a very considerable number of years.

Chart 5 Ev 98 Energy & Climate Change Committee: Evidence

Chart 6

Chart 7

6. The clear conclusion is that under present cost conditions and tax system and oil and gas prices close to current levels investment in the UKCS will fall substantially from recent levels, with the ensuing dangers from the faster production decline rate and the secondary adverse consequences noted above. Even if these relatively low prices do not last for a long period the adverse consequences could be substantial. A steeper short-term production decline rate could have significant knock-on eVects.

7. Following from the above analysis it is clearly important that steps are taken to mitigate the adverse eVects. The steps which could be taken come under three headings, namely (1) self-help by the industry, (2) tax relief, and (3) modifications to the licensing and regulatory arrangements. To maximise economic recovery from the UKCS measures which impact on the short-term and long-term situations are both pertinent. Energy & Climate Change Committee: Evidence Ev 99

8. Self-help measures by the industry can cover a range of actions all designed to reduce costs and/ or enhance the productivity of operations and development activities. In turn this can involve changes to contract terms to incorporate provisions which share the risks and rewards between the operating companies and their contractors in ways consistent with productivity enhancement and unit cost reduction. Contracts which relate rewards directly to oil/ gas prices can help to make projects acceptable which otherwise might be non-viable. It is understood that cost-reducing initiatives of various types have already commenced. 9. At the time of the pre-budget report the Treasury published a consultation document entitled Supporting investment: a consultation on the North Sea fiscal regime. This opens up the possibility of introducing a value allowance for new fields. Supplementary Charge is levied at 20% in addition to Corporation Tax at 30%. The value allowance would be set against gross income for Supplementary Charge on eligible fields. Corporation tax at 30% would remain as at present. The consultation document identified small fields, heavy oil fields, high pressure, high temperature fields, and fields located West of Shetland as being candidates for the allowance. The details of the allowance formed the basis of the consultation. The present author has conducted a detailed analysis of the eVects of diVerent sizes of value allowance in incentivising new field developments. Specifically, the economic modelling identified those fields which passed the investment hurdle (NPV/ I ≥ 0.3) under the present tax system and those which failed it. It then identified those fields which passed the hurdle after the introduction of the allowance for Supplementary Charge but which had failed it in the absence of the allowance. The allowance is introduced on a field basis with yearly and cumulative limits. All fields continue to pay corporation tax at 30%. The resulting number of fields triggered by the allowance when applied to all new fields and the related extra economic production in the period to 2035 are shown in Table 1.

Table 1

TOTAL NUMBER OF NEW FIELDS TRIGGERED BY VALUE ALLOWANCE AND RELATED EXTRA ECONOMIC PRODUCTION IN PERIOD TO 2035

Price Allowance Numbers Mm boe

$40,30p £2.5m x 5 years 16 134 £10m x 5 years 45 544 £20m x 5 years 58 825 $60,50p £2.5m x 5 years 32 225 £10m x 5 years 56 529 £20m x 5 years 61 652 $80,70p £2.5m x 5 years 7 48 £10m x 5 years 19 258 £20m x 5 years 20 352

The extra economic production varies considerably according to the price. At $40,30 pence prices many new fields remain uncommercial even after the allowance. At the $60,50 pence case the allowance is much more eVective in triggering new developments. At the $80,70 pence case many projects are viable without the allowance. It is also seen that the volume of extra economic production varies very considerably with the size of the allowance. There is clearly a case for an allowance at the higher levels of these shown in Table 1. 10. The exercise was also conducted for small fields only. These were defined as these with recoverable reserves ≤ 20 mm boe at the $60,50 pence prices. The resulting number of new field developments triggered and their economic production are shown in Table 2.

Table 2

TOTAL NUMBER OF NEW SMALL FIELDS TRIGGERED BY VALUE ALLOWANCE AND RELATED EXTRA ECONOMIC PRODUCTION IN PERIOD TO 2035

Price Allowance Numbers Mm boe

$40,30p £2.5m x 5 years 15 108 £10m x 5 years 35 313 £20m x 5 years 38 355 $60,50p £2.5m x 5 years 31 195 £10m x 5 years 51 359 £20m x 5 years 54 387 $80,70p £2.5m x 5 years 7 48 £10m x 5 years 16 157 £20m x 5 years 16 157 Ev 100 Energy & Climate Change Committee: Evidence

The pattern of the results is similar to that for the aggregate of new fields. It is clear that substantial extra economic production can be generated by the allowance, with the volume varying directly with its size. 11. The study also considered fields in West of Shetlands. The operating environment is particularly diYcult and expensive there. Field development costs alone could be $20/boe. But there are some undeveloped discoveries in the region, particularly gas. Taking the region as whole these gas fields can most economically be exploited in the form of a cluster development with a common hub for initial processing, followed by a communal pipeline to markets (probably at St Fergus). In current oil/ gas price circumstances there is a clear need for incentives to trigger developments. Given the particularly high unit costs in the region a larger volume allowance is appropriate. An example would be £50 million x 5 % £250 million per field. 12. The pursuit of the maximisation of economic recovery involves investment in incremental projects. This has also been the subject of consultation in recent years. In older fields these projects can subject to Petroleum Revenue Tax (PRT) at 50% as well as Corporation Tax at 30%, and SC at 20% (total 75%). There now exists a scheme of total relief from PRT for certain projects which the licensees can demonstrate to be uneconomic with PRT but economic in its absence. But the scheme is restricted to projects which are clearly physically separated from the main field (such as a satellite developed as a tie-back to the main field). The present author has conducted an analysis of incremental projects on PRT-paying fields and found that in current market conditions some incremental projects of all types may be rendered uncommercial by the existence of PRT.13 It is thus desirable that eligibility for the scheme be extended to all incremental projects in PRT-paying fields. The current scheme is also discretionary in the sense that the investor has to demonstrate that a project is uneconomic when PRT is payable. This creates much investment uncertainty. To remove this, a formula indicating the circumstances under which PRT relief will be given should be made available to investors. 13. As part of an earlier consultation the Government indicated that there were merits in the total abolition of PRT, with a suggestion that a PRT buy-out scheme could be agreed with investors. This would have incorporated decommissioning relief. Unfortunately agreement was not reached on the buy-out scheme despite its manifest advantages in encouraging new incremental projects (which would have been exempt from PRT). There is a strong case for the reconsideration of this scheme. PRT is becoming increasingly anomalous. 14. It is very likely that exploration and appraisal activities will fall sharply in 2009 and 2010. The outlook beyond that period depends on the behaviour of oil and gas prices. The current tax treatment of exploration costs for investors in a tax-paying position permits their deduction against other income from the UKCS with 100% first year allowances being available. For investors not in a tax-paying position the allowance can be carried forward at 6% interest for up to six years to be set against income if and when it arises. There is not a level playing field between existing taxpayers and new players who have no income from the UKCS. There is a case for making this playing field a level one. This could be achieved by adopting the Norwegian scheme whereby, for investors not in a tax-paying position, the Government in eVect shares the costs of approved exploration work to the extent of the marginal tax rate of the investor. In current circumstances when cash flows are greatly depressed this allowance could have a worthwhile eVect. To limit the cost to Government it could be introduced only for a specified time period. 15. Over the past few years various non-tax measures have been introduced by the DECC (and its predecessor bodies) often through PILOT (the joint Government-industry consultative body) to enhance activity levels and maximise economic recovery from the UKCS. These initiatives are generally very praiseworthy, and, if implemented vigorously have the potential to make a significant contribution to both enhancing the discovered reserve base and maximising economic recovery from it. Key measures are now discussed in turn. 16. Licensing rounds are now generally conducted annually.They incorporate conventional, frontier, and promote licences. Annual licensing permits a large amount of acreage to be put on oVer at frequent intervals. Given the maturity of the UKCS and the need to attract exploration this is generally desirable. The relinquishment conditions are now 4 ! 4 ! 18 years meaning that after four years 50% of the acreage has to be surrendered. After a further four years the remaining acreage is surrendered but, if a development is in prospect, the relevant area can be retained for a further 18 years. This scheme ensures that exploration takes place in an expeditious manner and that acreage is not kept fallow. This has been a problem in the past when acreage could be kept by a licensee after the first term had ended with no further work obligations and the payment of only modest rental charges. This problem particularly applied to acreage awarded in Rounds 1–4. To deal with this problem DECC has a fallow initiative applied to acreage which, after the first period of the licence, has not been worked for three years or more. The licensee has to bring forward an acceptable work plan to the DECC within a specified time period, or, if this cannot be done, the acreage has to be traded or relinquished. This scheme appears to be working reasonably and should be vigorously implemented. The availability of promote licences (involving 90% discount on licence fees for the first two years of the licence)

13 See A.G. Kemp and L. Stephen, The Economics of PRT Redetermination For Incremental Projects in the UKCS, North Sea Study Occasional Paper No. 110, University of Aberdeen Department of Economics, November 2008. Energy & Climate Change Committee: Evidence Ev 101

have attracted many small companies, although the acreage in question is generally high risk. The evidence to date is that in a significant number of cases the result has been to proceed to more substantial work programmes in stage 2 of the licence. There is clearly merit in the scheme. 17. In mature fields DECC has introduced a stewardship scheme which can require an operator to demonstrate that he is doing as much as can reasonably be expected to maximise economic recovery from the field in question. If DECC has doubts on this the operator has to listen to suggestions made and is given a specified period of time to implement schemes. In the event that the operator fails to do this he can be required to trade or relinquish the asset. This scheme does not yet have a substantial history to judge its eVectiveness, but in principle it has merit and should be implemented vigorously. 18. Third party use of infrastructure is now very common in the UKCS. The tariVs for transportation and other services (such as processing) are determined by negotiation between the asset-owner and prospective user. Historically these negotiations have often been very protracted. In the 1990’s attempts were made to streamline the process but with mixed results. In 2004 a revised Code of Practice was agreed between the industry and the Government. A key element stated that, if after 6 months of negotiation in good faith, the parties could not reach agreement on the terms, the Government, on request, could determine what the tariV should be. In doing so it would take into account the cost and risks incurred by the asset-owner and then determine the tariV as if it were taking place in a competitive market. This was a big step forward. It is not very clear, however, how successful the scheme has been. It is clearly important that, in the interest of speeding up the pace of development and so maximising economic recovery, negotiations on tariV terms are accelerated. The alternative would be to adopt the Norwegian system whereby third party tariVsare regulated by the Government. The situation is rather diVerent in Norway, however, with the great bulk of the pipeline network being operated by Statoil Hydro. In the UKCS ownership is much more diversified. 19. To procure maximum economic recovery asset transfers which oVer the prospect of bringing additional output should not be hindered by Government policies. There are now many instances of the sale of mature fields where the buyer feels that he can add more value from the asset than the seller. The problem regarding financial liability for decommissioning can greatly complicate such transactions. The DECC is (understandably) concerned about the risks of default on decommissioning obligations and has had in place since 1987 a scheme of joint and several liability. Further, if there is a concern that the buyer of an asset may not be able to meet his obligation the DECC can stipulate that the original licensee be liable in the event of a default by the new one. This clearly causes problems when asset transactions are contemplated. To procure security for itself the DECC can also require bank guarantee (letter of credit) from a licensee in relation to the decommissioning work. These are expensive and in some cases the banks may be unwilling to extend their guarantees. One solution to the problem is to introduce Decommissioning Trust Funds whereby licensees make contributions into an alienated Fund during the life of the field. This provides security to all co-venturers and the Government. Unfortunately this laudable idea has not been generally implemented because the contributions are currently not tax deductible. A gross Fund is possible but very expensive. In several other oil producing countries Decommissioning Funds with alienated contributions now exist with safeguards for the Government with respect to the costs involved. There remains a case for such a scheme in the UK/ UKCS. It need not apply to all cases where other forms of acceptable security are available but should be available as one option. March 2009

Memorandum submitted by the Oil and Gas Independents’ Association (OGIA)

OGIA The Oil and Gas Independents’ Association is a self-help group of 34 oil companies active in the UKCS. Our membership includes a wide spectrum of companies from UK divisions of large well-established multinational organisations through to small start-ups and from companies with an active exploration drilling capability to purely financial investors. We do not admit major production operators. Our focus is principally on exploration and appraisal issues although many of our members are non operated producers.

Introduction and Executive Summary As a group generally representing smaller UK companies and UK based subsidiaries of multinational oil and gas investment companies in the UKCS we have taken the liberty to respond more fully on those issues which are more directly relevant to the bulk of our members’ experience: — Exploration and appraisal (E&A) drilling for the discovery of new hydrocarbon accumulations, mainly in the “mature” areas of the UKCS. — Access to existing infrastructure issues. — The fiscal/investment environment. Ev 102 Energy & Climate Change Committee: Evidence

We feel that Oil and Gas UK will adequately and perhaps more eVectively cover issues relating to West of Shetland, Skills and Infrastructure and decommissioning.

In summary, OGIA feel that the UK is now at a critical crossroads in determining how the future of the UK hydrocarbon resources will be developed and exploited. The mature nature of the basin means that there needs to be significant consideration given now on how we encourage the finding and development of the remaining resources (much of it yet to be discovered). What may have been appropriate 20 or 30 years ago when large discoveries were still regularly being made and when the ability for the UK to attract significant investment inflows was still high, are no longer appropriate for the future of our basin. Both the nature and desires of the players involved and the nature of access to the required investment capital has changed significantly. From a security of supply perspective as well as the knock on employment and skills issues, we need to ensure that we maximise the production of our own indigenous hydrocarbons as well as ensuring that the investors and the public purse get a fair return for the risks and resources they both invest. Above all we need to ensure we encourage an eYcient industry where we maximise the use of existing infrastructure to economically produce the smaller fields we are discovering. After all, much of the large infrastructure assets have eVectively been paid for by the public purse, and as such the public should have an expectation that they should be used for the public good of extracting the maximum resources for the UK, not provide a low risk revenue streams for companies who wish to reinvest much of that in other parts of the world.

Every barrel of oil and cubic foot of gas that remains undeveloped and undiscovered in the UK, pays no taxes, provides no jobs, and requires that we have to import its replacement from a place where we have no control over its production, its environmental impact or its use as a foreign policy tool.

How can the UK’s remaining oVshore oil and gas reserves be exploited most eVectively? What barriers are there to exploiting such reserves? What steps need to be taken to unlock resources west of Shetland?

1.1 Significant oil and gas remains to be recovered from the UKCS. Other than from those fields already in production or under development, it is impossible to accurately quantify the volume of hydrocarbons not yet discovered. The broadly accepted number is that possibly up to 9 billion barrels of oil equivalent still remain to be found. This undiscovered volume is by far the largest single portion of the UKCS’s remaining potential. It will certainly be more diYcult to find and commercially exploit than the geologically simpler and more obvious structural discoveries of the 70’s and 80’s. With basin maturity the probability of commercially successful exploration drilling becomes less and less, which, combined with the significantly smaller average discovery size ('15mm bbls) for the wells which are successful has meant that those companies whose skills and capital were required to initially exploit the UKCS no longer find it attractive to seek new hydrocarbon discoveries in the UKCS (West of Shetland excepted). Materiality and increased risks mean that their shareholders capital is better directed to sedimentary basins where more material discoveries are likely to be made, even though fiscal terms in these areas may be seen as more onerous than the UK. At the risk of making an overly broad generalisation, these companies now see the UK as a source of relatively predictable cash flow to finance exploration/exploitation in other areas, increasingly enhanced by low risk tariV income for use of “their” infrastructure.

1.2 This situation was recognised by the Government in 2001–03, and reforms were put in place to attract new entrant and smaller companies whose appetite for risk was somewhat higher, and where smaller discoveries still remained material. Much, and probably a majority, of the exploration and appraisal work of recent years has been undertaken by these newer entrants and smaller companies. A number of significant discoveries have been made that would not otherwise have happened. Credit crunch aside, to encourage the full exploitation of the UK’s remaining hydrocarbon resources will require development of an environment that encourages risk taking companies prepared to explore for, and ultimately develop, new accumulations.

To maximise the remaining potential we need to: 1.3.1 Encourage sustained, but sensible levels of exploration/appraisal drilling to establish new fields for future production, and encourage the development of existing discoveries that are not economic investments in the current fiscal environment. 1.3.2 Simplify the process for producing these new (mostly smaller) fields via existing infrastructure, ensure that the owners of the infrastructure do not extract a disproportionate share of the value by creating delay or oVering inappropriate tariVs and liabilities in relation to the risks they take. The current voluntary Infrastructure Code of Practice (ICOP) is NOT making any significant diVerences and many bad behaviours and practices still remain. This actively discourages exploration and appraisal for new fields as the risk reward balance is significantly skewed in favour of the infrastructure owner rather than the risk taker. Legislation for guaranteed access terms or “common carrier” status should be seriously considered. Energy & Climate Change Committee: Evidence Ev 103

What can be done to minimise the environmental impact of exploiting the reserves? How should this be encouraged and/or financed? 2.1 The UK already has one of the most highly environmentally regulated hydrocarbon provinces in the world. Whilst we should continue to mandate adherence to high environmental standards and practices, we should also bear in mind that we cannot unduly burden the industry to achieve standards significantly in excess of other areas. Adherence comes at a cost, both financial and also in terms of leaving undeveloped and unrecovered hydrocarbons in the ground. Every barrel of oil or cubic foot of gas that cannot be extracted from the UK will have to be imported from an area where such environmental standards will likely not apply.We should take care not to simply shift the problem elsewhere whilst at the same time reducing our security of supply. If necessary, fiscally neutral changes will need to be considered to ensure that we achieve acceptably low levels of environmental impact for our production whilst not promoting the production of less environmentally acceptable oil or gas from elsewhere. 2.2 Carbon storage in Hydrocarbon reservoirs or in saline aquifers identified by hydrocarbon exploration is a significant way in which both the skills and technology of the oil and gas business can be redeployed and also used to mitigate the environmental impact of exploiting the reserves. The regulatory and fiscal framework for this major potential business is not yet clear and needs acceleration and clarification.

How eVective is the current fiscal and regulatory regime in which the industry operates? 3. The UK fiscal regime is extremely complex and a result of 40 years of constant tinkering. It was developed when fields containing hundreds if not billions of barrels were being found. It is now recognised as a fiscal environment with significant risk of (adverse) change. For investors to invest they will always make assumptions about the stability of the tax system prior to investing. The UK does not fare well in this regard, particularly as it requires very significant upfront investments over a number of years prior to cash flow. One actual example would be an exploration investment made on the basis of a 30% tax regime in 2001, which then changed to a 40% regime whilst the discovery was being evaluated for development, and finally became 50% when the bulk of the development capital (totalling $3 billion) had already been committed. Is this an environment that encourages sustainable and long term investment? The industry understands that the UK needs a fair return on the development of its resources, however we need to consider a tax regime that is above all predictable, encourages new investment in maximising the development of remaining hydrocarbons from the basin, perhaps it should now be linked more directly to the product price. Above all the government needs to consider whether we have a fiscal regime that will attract the investment risk capital for the discovery and then exploitation of the oil and gas we have yet to find.

What eVect are the recession and the credit crunch having on the industry? What is the impact on the financing of exploration and development? 4.1 The move to an environment where much of the exploration and appraisal (E&A) drilling is being undertaken by smaller companies than those that have traditionally worked in the North Sea has meant that the recent “credit crunch” and turmoil in the equity markets has had a disproportionate eVect on E&A activity in the UK. Companies can no longer access equity or new debt funding for activity in the UKCS. Indeed some existing debt facilities are being withdrawn, with a recent notable example. As much of the UK’s E&A activity is now undertaken by such companies, activity levels are more directly driven by the availability of relatively high cost equity capital and by the availability and cost of debt and quasi debt financing. The credit crunch has driven investors to reduce price and reduce exposure to risk. The Oil and Gas business is by its nature a high risk/high reward business and it has been disproportionately aVected by this change. Indeed RBS, one of only two significant lenders for the North Sea, recently announced that they would be withdrawing from project finance. 4.2 The Government has already recognised that companies principally undertaking exploration and appraisal activity were at a significant fiscal disadvantage to those companies with significant production cash flows, as they could not write of these sunk costs against income in the same year. Such costs simply accumulated until suYcient cash flow was achieved. In part recognition of this problem, HMG allowed these cost pools to escalate at 6% per annum. The lack of further equity and debt now means that these costs are likely to be trapped for significantly longer or in some cases simply remain unused. The advancement of these existing tax pools followed by annual repayment for those unable to use them (as is the case in Norway) would have a two fold eVect. 4.3 Firstly it would provide a source of much needed near term capital for companies to immediately reinvest in further UKCS E&A activity and thus help mitigate the upcoming slump. In addition it would help sustain many of these companies, the supply chain and of course their employees through the current downturn until the equity and debt markets become available again. 4.4 Secondly, the equity markets would recognise that such a move would make their investment in smaller companies exploring and developing in the UKCS much more attractive as their investment capital would be significantly more eYcient, as much of it wouldn’t be eVectively sterilised until they became Ev 104 Energy & Climate Change Committee: Evidence

significantly cash flow positive. Such a move would be a strong and positive signal to the equity providers and may help promote additional equity investment in such companies sooner that would otherwise be the case and in addition mark out the UK as a more attractive place to explore for and develop hydrocarbons. 4.5 A large part of the North Sea’s critical resources now come from the service business—both consultancies and technology companies. This interplay provides R&D ideas, data and outsourced subsurface teams to generate new exploration plays and optimise the development of smaller fields through innovative technology. The credit crunch has had a number of high profile casualties which have produced major problems for unsecured creditors. Knock on eVects are likely to be increased requirement of pre- payment and escrow facilities before work can commence, lack of earnings for those businesses aVected, even higher cost of capital for all concerned and reduced the availability of investment funds for R&D for new technologies that may increase the recovery rate from existing fields.

How are the skills needs of the sector being met? How transferable are those skills? 5.1 In general the oil and gas industry relies on a steady supply of science and engineering graduates, there is an increasing shortage of both of these skills both generally in the UK when combined with our unfashionable status and perception as a legacy industry over the past 15 years has caused and will increasingly create critical skill shortages. In particular the upstream skills needs of the sector are from a small and shrinking pool—UK based specialist MSc’s and to some extent PhD courses in Geology, Geophysics and Petroleum engineering. This is exacerbated by competition for geoscientists and engineers from the increase in environmental science based courses. 5.2 Overall oil sector demographics also give continued cause for great concern. The UK workforce has been working on average almost for as long as the North Sea infrastructure, and this will give rise to major capability reductions in the next 5–10 years. Such skills can of course be imported; however the cost of these skills would add significantly to the industries cost base, as such management and decision making for UK assets from remote locations may become increasingly the norm.

What are the implications of an ageing existing infrastructure on the security of supplies from the North Sea? 6. The infrastructure is already significantly older than it was expected to become when commissioned. Maintenance/Integrity is clearly an issue that the industry is currently addressing. The discovery of new fields which can be produced via this infrastructure is the simplest way to extend its economic life, as well as having the added benefit of recovering additional volumes from the original field that would otherwise not have been economically recoverable. As mentioned earlier access terms must be simplified, streamlined or mandated.

Is the right policy framework in place to manage the decommissioning of that infrastructure as resources are depleted? 7. The industry is currently in a period of great uncertainty in understanding what the policy is attempting to achieve. First, the industry will be able to oVset the costs against tax. However we are expected to post pre- tax guarantees, this is costly and does not reflect the company’s actual financial exposure. Secondly many of the Letters of Credit are issued by RBS, these are no longer acceptable under government regulations as the bank no longer meets the required credit ratings!!… March 2009

Supplementary memorandum submitted by the Oil and Gas Independents Association (OGIA) We would like to thank you for the opportunity to present oral evidence to the Energy and Climate Change Committee on the 11 March 2009. In addition to the oral evidence we would be like reiterate four key points.

Fiscal Change We need to recognise that the era of easy to produce hydrocarbons is drawing to a close in the UKCS. The fiscal terms should reflect this and be designed to encourage the development of the more challenging resources. Through the consultation process between HM Treasury and the Oil and Gas Industry we have identified changes that can achieve this. Through the proposed targeted Value Allowance (details attached) there is a way to encourage the development of Small Fields, Heavy Oil and High Pressure High Temperature Fields. This proposal encourages developments in a low commodity price environment and gives HMT access to a greater fiscal share if the commodity price increases without any further legislation change. Energy & Climate Change Committee: Evidence Ev 105

Security of Supply and Jobs

There is a substantial quantity of discovered heavy oil (0.7–0.9 billion barrels recoverable) and HPHT (1.5 billion BOE recoverable) in the UKCS. The development of Heavy Oil could contribute over 200,000 bopd of incremental production together with a further 150,000 boepd from HPHT by 2015. This equates to 25% of the UK oil production today.Assuming $50/BOE this would improve the UK annual balance of payments by $6.4 billion and reduce our dependence on imported energy, as well as generating material tax revenue and jobs.

Access to Infrastructure

Extract from transcript 11 March 2009: Q5 Sir Robert Smith: “I must first declare my interest: as a shareholder in Shell, which is in the Register of Members’ Interests; and Vice Chair of the All-Party Group for the OVshore Oil and Gas Industry. In that role, we went on an oVshore northern seas visit, and accommodation was sponsored by various oil companies. On access to infrastructure, is there a crucial message that if we are going to see the rosy picture, then whatever happens that infrastructure has to be seen to be worth maintaining so that it is still there; because you could not from scratch—the finds you are now finding would not be much use without that infrastructure? Mr Booth It is vitally important that infrastructure is there. Increasingly, we are finding smaller accumulations in the North Sea, and they cannot support their own dedicated infrastructure, so we have to be able to tie them back to existing infrastructure, which has to be there. Ultimately, it drives exploration. If you are expecting to find relatively modest pools, you have to know there is an eYcient way of getting it to the shore. It is vitally important that it stays there. I guess you have touched upon the issue of the infrastructure code of practice, which came out in 2003 or 2004. As we put in our submission, we are not convinced that is working eVectively. We would like to see changes in that regard. Q6 Sir Robert Smith: More intervention by the Government? Mr Booth: The Government does have the ability to intervene on tariV arrangements; however, it needs to be invited to do so, and certainly the infrastructure code, which was introduced a few years ago, requires all companies to issue an invitation to the Government to participate. I can tell you from first-hand experience that that is perhaps not happening as often as it should do, or at the time it should do. Q7 Sir Robert Smith: So what should change? Mr Booth:ItisdiYcult. It is still a voluntary arrangement, and until the industry decides it wants to apply those voluntary arrangements, it is really not going to happen. I have always had a bee in my bonnet about this issue, and it is still there. My own company is in the middle of trying to get access to infrastructure, and without naming names— Q8 Paddy Tipping:Goon! Mr Booth: We only have one development under consideration, so it is very easy to find out! The issue is that the companies concerned did not want to issue the automatic referral notice, which is the invitation to Government, because our operator told us, “we didn’t want to upset the other side and we want to agree the terms before we put it in”. That is not really why it was put in place, but that is the nature of—a direct example of what is happening right now. Q9 Chairman: If there were going to be some changes to this code, what would be your priority? Mr Booth: I think you have to understand before you start exploring for hydrocarbons and wanting to develop and appraise hydrocarbon accumulations, what the terms and conditions will be to go across that infrastructure. What you do not want to do is find your hydrocarbons and then you find someone who owns the infrastructure wants to take what they might regard as a fair share, and what I might regard for my shareholders as a disproportionate share of the risk I have taken. My view is that that happens quite a lot. Q10 Paddy Tipping: We have a Government that is becoming increasingly interventionist; is this an area in which it ought to be more involved? Mr Booth: I think they should seriously consider that. I am not a great fan of intervention myself, but we have an extensive infrastructure in the North Sea and we do need to make sure that it is made available for those who wish to produce hydrocarbons that still need to be found and still need to be produced, and there is a role there for Government. Ev 106 Energy & Climate Change Committee: Evidence

Q11 Mr Weir: Perhaps I should mention my interest as another vice chair of the Oil and Gas Group, but you say in your submissions that there should be a common carrier status for infrastructure. Can you explain to us what you mean by that? Mr Booth: It means that there is eVectively guaranteed access to major infrastructure. It is something that is quite common in the Gulf of Mexico. The US is not known particularly for interventionist policies, but it is the way you ensure you get access to that infrastructure, and you pretty much understand the terms under which you do. Q12 Mr Weir: But who imposes the common carrier status? Is it a— Mr Booth: I believe it has to be a regulatory event. It is quite clear from the North Sea that there is one pipeline system that eVectively has a monopoly over large parts of the North Sea.

Refund of Exploration Allowances Q28 Anne Main: What can be done to help? What are you asking for in terms of financial support or intervention or alteration? Mr Booth: I do not think we are asking for support. In our submission we have the example of my own company. We have £25 million of tax pools, which are costs we have sunk into the North Sea. If we were a producer we could claim those back straight away, oVset against our income; however, I cannot get into a cash-flow producing situation because I cannot either borrow money or get more equity to develop the fields I have found. Q29 Chairman: We are going to look at the fiscal regime. Mr Booth: It is a fiscal regime issue. I guess I am just asking for those funds to be brought back to me so that I can reinvest them in the North Sea. Q30 Anne Main: If there was some sort of conversion, like a planning conversion, for change of use for the field that you found to go to carbon capture storage, something like that would be— Mr Booth: That is certainly one issue, yes. Q31 Anne Main: Change of use for the licence. Mr Booth: Yes. The other one that I mentioned is that I have money tied up eVectively with the Government, which if I were a producer would come straight back to me, as an oVset against my tax bill. I cannot achieve those funds because I cannot get into a position to produce cash, because the banks do not want to lend me money to develop the fields I have found. So my equity investors can see that investing in smaller companies like this is not eYcient, because half the money—we are on a 50% tax regime—gets stuck until I can get the cash flow, but I cannot get the cash flow because the banks will not lend me money to develop the field that we found. That is exactly where I am right now.” As we frequently say undeveloped oil in the ground does not generate taxes, create jobs or secure energy supply.

Value Allowance (Who gets What and How) For this proposal to lead to new activity Value Allowance must be material. With a material targeted approach the possibility of moving stalled projects forward is improved. If the benefit is spread too thinly the initiative is likely to fail. The Value Allowance will be deducted from the 20% Supplementary Corporation Tax. Targeted projects and levels of allowance are as follows: — Heavy Oil (less than 18) API gravity and or greater than 10 ctp viscosity at reservoir temperature.) The Value Allowance would be £10 per BOE of reserves at the point of Field Development Approval capped at a reserve figure of 200 million BOE. — High Pressure High Temperature (HPHT) (Temp. greater than 300)F [149)C] and or a pore pressure of at least 0.8 psi/ft (x15.3 lbm/gal) or requiring a BOP with a rating in excess of 10,000 psi [68.95 MPa] ). The Value Allowance (same as Heavy Oil) would be £10 per BOE of reserves at the point of Field Development Approval capped at a reserve figure of 200 million BOE. — Small Fields (below 25 million barrels of oil equivalent (BOE which are neither Heavy Oil nor HPHT)), A flat allowance of £100 million for fields under 20 million BOE tapering to zero between 20–25 million BOE. The net eVect to the project of a Value Allowance of £100 million would be £20 million with a discounted Net Present Value of approximately £15 million. The key issue in all developments is the return on capital when compared with the risks undertaken. The Heavy Oil and High Pressure High Temperature (HPHT) projects will incur larger capital expenditure and hence a greater Value Allowance will be needed. Energy & Climate Change Committee: Evidence Ev 107

We hope this is helpful and if there is any further information you need please contact me. April 2009

Further supplementary memorandum from Oil and Gas Independents’ Association (OGIA) With respect to your request for further written evidence on the provisions in the 2009 Budget relating to the North Sea fiscal regime following the Chancellor’s statement on 22 April 2009, we would like to thank you for this further opportunity and would like to make the following submission. As a general comment our membership were encouraged by the fiscal changes. They indicate that there has been an eVective exchange of ideas between Government and Industry. The UKCS is at a mature stage in its development and there is recognition of this in the fiscal changes. Full utilisation of existing infrastructure has been encouraged, there is an understanding that the more challenging resources need improved fiscal terms and there is assistance for Companies that are specifically focussed on investment in the UKCS, which are all positive steps.

Field Allowance This was the major change to result from the budget statement. It was the culmination of a long and detailed consultative process. We see this as an encouraging first step and is a recognition by Government that the challenging resources require a less onerous fiscal treatment. The allowances as announced in the budget were in general lower than those proposed by ourselves and the mechanism we suggested more closely tracked the size of the asset. The result of the mechanism outlined in the budget is less size sensitive and is therefore more advantageous to smaller resources in the three targeted areas of small fields, ultra heavy oil and ultra HPHT. The high impact, large resource assets have not benefited as much as hoped. We are concerned about the definition of Ultra HPHT and feel there should be consideration of a wider criteria. As currently defined the resources captured by this definition are limited to one risked project which will be insuYcient to contribute the two billion incremental barrels the Chancellor targeted in his Budget Statement. Having created the Field Allowance we would encourage Government to look at additional qualifying targeted areas. The two areas that we would focus on would be assets West of Shetland and Non Conventional Gas. Assets in the area West Of Shetland face considerable challenges with respect to weather and infrastructure additional fiscal assistance is required to accelerate activity. Under the heading of Non Conventional Gas we would include gas from tight reservoirs and gas that requires specialist treatment to improve its quality. We are ready to engage in further discussions on these two areas. We believe that to achieve the goal of an additional two billion barrels of developed oil the qualification definition for assets eligible for the Field Allowance needs to be relaxed as discussed. Other items addressed in the Finance Bill: (a) “Changes to the chargeable gains regime within the North Sea ring-fence to remove chargeable gains entirely from licence swaps and making gains exempt where disposal proceeds from ring fence assets are reinvested within the UKCS.” This has been well received by our membership and is a logical improvement to the fiscal regime. It is of specific assistance to companies who are not yet in production and who are focussed on investment activity on the UKCS. (b) “Changes to the North Sea fiscal regime to remove potential barriers to projects that re-use North Sea infrastructure for non-ring-fenced purposes including gas storage, carbon capture and storage and wind energy.” We feel this is a positive step and will encourage the prolonged use of existing infrastructure. Extending the life of these assets will allow smaller deposits to be developed as well as create incremental benefits from the change of use. (c) “Amending the petroleum revenue tax (PRT) regime to ensure that companies whose production licences have expired are still able to access PRT decommissioning relief where appropriate.” (d) “Changes to the PRT regime to reduce the administrative burden it imposes, simplify compliance and repeal obsolete legislation.” We feel that points (c) and (d) are a fair and logical amendment to the fiscal regime.

Tax Relief for Cost of Cushion Gas in Gas Storage Cushion gas is now considered as plant for the purposes of plant and machinery capital allowances, expenditure on cushion gas will now be eligible for capital allowances. We believe that this treatment will improve the economics of gas storage projects and lead to the further development of what will become and important area in the UK’s energy infrastructure as we become more dependent on imported natural gas. Ev 108 Energy & Climate Change Committee: Evidence

I addition to the comments specific to the 2009 Finance Bill we would like to reiterate two points we have made in earlier correspondence. Access to Infrastructure—Existing and anticipated future discoveries on the UKCS cannot support their own dedicated infrastructure. Hence the availability of existing infrastructure will have a major impact on exploration and investment plans. Modest hydrocarbon pools require a competitive and eYcient route to market. The current regulations and guidelines are not being enacted by the industry or enforced by industry/government. One of the biggest problems is trying to conclude negotiations in a timely manner, unless of course the Infrastructure Host Owner/Operator has a stake in the potential development. In such cases the problems appear to disappear and negotiations proceed to a very rapid timetable. This seems to us to be a clear breach of the Commercial Code of Practice which Industry and Government have signed up to but Government appears unwilling to intervene to enforce participants to honour their commitments. Refund of Exploration Allowances—Small companies, of which there are currently many active on the UKCS, partly as a result of the Government’s praise-worthy encouragement, now find equity markets (for exploration funds) and debt markets (for development funds) closed. Furthermore the current fiscal regime disadvantages such investment. To resolve this we support modifications to the Ring Fence Expenditure Supplement (RFES) to allow a cash payment of the tax relief. In addition we propose that the tax relief due on the drilling of Exploration and Appraisal wells should be paid at the time of drilling, in line with the practice in Norway. For technical reasons this would actually be of some benefit to the Government given that the Government’s cost of capital is below the 6% interest rate that such sums currently accrue. Finally, we have a great deal of respect for the staV of DECC, they do a very good job under diYcult circumstances. We understand that they are very stretched and would encourage Government to utilise some of the UKCS licence fee to fund an expansion of their resources. We would like to thank the staV of HMT and DECC for their assistance during this consultation process and look forward to working with them in future to address the further improvements outlined above. May 2009

Memorandum submitted by the United Kingdom OVshore Oil and Gas Industry Association (Oil & Gas UK)

1. Oil &Gas UK 1.1 Oil & Gas UK is the leading representative body for the UK oVshore oil and gas industry. Our 80 plus members comprise the major multi-national oil and gas companies, smaller specialist producers and explorers as well as large contractors and SME suppliers active across the UK Continental Shelf (UKCS).

2. Introduction and Executive Summary

2.1 UK oil and gas is a resource of strategic economic importance Britain’s oVshore oil and gas industry is a central pillar of the UK economy:

2.1.1 Security of energy supply (a) The industry is the single most significant contributor to this country’s security of energy supply, today providing 70% of our primary energy needs. (b) In 2008, the UKCS produced 2.63 million barrels of oil equivalent (boe) per day. The UKCS is a mature province but 40% of its reserves remain to be recovered. Output is declining at around 5% per annum but, nevertheless, the UK is still the 13th largest oil and gas producer in the world, ahead of countries such as Qatar, Kuwait and Indonesia. (c) Oil and gas will continue to be the dominant source of the UK’s primary energy for some decades to come. Even upon the achievement of the Government’s targets for renewable energy supply (ie 15% of primary energy to come from renewable sources in 2020) 70% of our primary energy in 2020 will still need to be provided by oil and gas. The oil and gas that the UK does not produce itself will have to be imported. (d) With up to 25 billion barrels of oil and gas still to recover, in 2020 the UK could still be producing oil and gas in suYcient volumes to supply 65% of our oil needs and a quarter of UK gas demand— enough gas to cover all that we need for our homes, for example—provided capital investment can be sustained at £5 billion per annum and the production decline rate held at 5% per annum. (e) Maximising the recovery of the country’s own reserves is therefore essential for future UK security of energy supply. Energy & Climate Change Committee: Evidence Ev 109

2.1.2 A key industrial sector (a) The industry is the single largest industrial investor in the UK economy with annual expenditure of around £12 billion. Over £400 billion has been spent in exploration, development and production over the last four decades. (b) As an extractive industry supported by a strong technology-driven manufacturing base, it is the highest value adding sector in British industry. As such, it oVers potential to help pull this country through recession, providing vital primary energy resources, jobs, tax revenues and export earnings.

2.1.3 Employment, exports and technology transfer (a) In 2008, the UK oVshore oil and gas industry supported almost half a million jobs across the UK, many in high value, highly skilled positions within a world leading supply chain, which not only services the UKCS but also exports oilfield goods and services across the world worth £5 billion per annum. (b) The skills and expertise found within the supply chain provide the UK with an opportunity to position itself competitively, through technology transfer, in the global low carbon economy.

2.1.4 A major contributor to the public purse (a) The industry is a major contributor to the public purse, saving the UK’s balance of payments on oil and gas imports to the tune of £40 billion per annum. In the current fiscal year, oil companies will pay £13 billion to the Exchequer, which is the equivalent of around 30% of UK corporation tax receipts. (b) Activity in the supply chain contributes a further £5–6 billion from payroll taxes, national insurance contributions and corporation tax. (c) Revenues from UK production in the forthcoming tax year are expected to yield some £8 billion.

2.2 The recession and the fall in the oil and gas prices have exposed the UKCS’s declining competitiveness

2.2.1 The UKCS competes for investment with other less costly, more attractive oil and gas regions around the world. (a) New field developments are now smaller (typically less than 15 million boe) and are struggling to attract development capital. The breakeven oil price for new field investment in the UKCS is now above $40. (b) Unit operating costs are typically 10—15% higher than a year ago. (c) Despite recent high oil prices, capital investment fell 6% in 2008 and is forecast to fall further over the next two years, possibly to as low as £2.5–£4.5 billion by 2010. (d) Capital eYciency is declining: with production falling at 5% per annum, the industry is spending more to produce less. (e) When the oil price was last in the $40–45 per barrel range, new developments were subject to a tax rate of 40% but these are now liable for 50%.

2.3 The banking crisis is placing severe additional strain on oil and gas companies and their supply chain

2.3.1 The freezing of capital markets is severely restraining investment in exploration and development while the withdrawal of normal banking facilities is creating cash flow problems for solvent supply chain companies. 2.3.2 Exploration and appraisal (E&A) activity appears to be stalling (see section 3.5.2 below); the fall in capital investment (see section 3.2.5 below) will have an impact on employment. Every £1 billion invested in the UKCS supports around 20,000 jobs; the eVect of the fall in investment over the next two years could hit up to 50,000 jobs. 2.3.3 The industry took five to six years to recover from the last serious downturn in activity in 1998–2000. Ev 110 Energy & Climate Change Committee: Evidence

2.4 Urgent measures are needed to mitigate the worst of the impact of the current business climate and ensure that critical investment, productive capacity and valuable skills are not lost from the UKCS irretrievably

3. Evidence Addressing Questions Posed In the following section we have sought to reinforce the points made above by answering the specific questions posed by the Committee:

3.1 How can the UK’s remaining oVshore oil and gas reserves be exploited most eVectively? Maximising the recovery of the UK’s oVshore oil and gas reserves will require:

3.1.1 Significant capital investment (a) In February 2009, Oil & Gas UK published its 2008 Activity Survey (http:// www.oilandgasuk.co.uk/issues/economic/activitysurvey08.pdf), an annual review of the investment plans of over 70 exploration and production companies active in the UKCS. The report shows that the UK has the potential to produce significant volumes of oil and gas well into the future, with up to 25 billion barrels of reserves estimated still to be recovered. (b) Current business plans suggest that up to 9.6 billion barrels of these remaining reserves (roughly 40%) will be produced. This includes 6.1 billion barrels to be produced from existing fields and from new developments with sanctioned (i.e. secured) investment. The remaining 3.5 billion barrels are in new field and brownfield developments which have not yet secured capital funding. (c) Therefore, there are potentially a further 15 billion barrels of reserves which, at present, are not being targeted in company plans. Assuming a future oil price of $100 a barrel, these “neglected” reserves could represent $1.5 trillion of economic activity for the UK. (d) The Oil & Gas UK survey shows the UKCS has the potential to add 600 million barrels of oil and gas per year to the production base going forward, but this depends on substantial investment continuing to flow into the basin. Approximately £1 billion is required to develop and bring on- stream each 100 million barrels of production. (e) If investment can be sustained at around £5 billion a year over the next five years the production decline rate could be held at an average of 4–5% per annum. This would mean that the UKCS could produce around 1.5 million barrels per day in 2020, the equivalent of 40% of our combined oil and gas needs. If the basin fails to attract the necessary investment, exploration, new field development and incremental projects on existing fields will be cut back and the production decline rate will accelerate. The low case scenario would see the UKCS producing less than 0.5 million boe per day in 2020, or just 13% of our oil and gas needs. (f) The UKCS can and does respond to investment. An increase in expenditure in 2005–06 resulted in the rate of production decline in the period 2002–07 fall from 7.5% per annum to 5% in 2008.

3.1.2 A diverse portfolio of companies The UKCS needs to attract and retain a diverse portfolio of companies which see opportunity in the range of prospects now available in the mature UKCS, from the large multi-national majors targeting high risk, high cost developments such as those west of Shetland or in high pressure, high temperature (HPHT) reservoirs to the niche players seeking out the smaller accumulations and using low-cost, innovative techniques to recover their reserves. The province also needs to maintain a healthy number of specialist exploration companies, to enhance the feedstock of reserves for future development.

3.1.3 A strong UK-based supply chain The industry’s story is not just about production. It is also about a world leading supply chain whose expertise and cutting edge technologies not only service the UKCS, but also earn £5 billion per annum through exports. It supports high quality, well-paid employment for nearly half a million people throughout the UK (44% of them in Scotland). It is essential that these jobs remain anchored in the UK not just so they can continue to support UKCS activity, but also so that this valuable export business can be grown. The International Energy Authority estimates that oil and gas development and infrastructure will require investment of $9.6 trillion from now until 2030, representing a major opportunity for home-grown technology,engineering and project management, together with supporting functions such as legal, financial and insurance services. Energy & Climate Change Committee: Evidence Ev 111

3.1.4 Fit-for-purpose fiscal and regulatory regimes As maturity advances in the UKCS, having the right fiscal and regulatory regime in place is essential: one that stimulates and does not hamper investment in new developments, that allows existing platforms and pipelines to be preserved and encourages the development of high risk, high cost areas such as West of Shetland.

3.2 What barriers are there to exploiting such reserves? The current economic climate has sharply exposed the fundamental challenge to the goal of maximising recovery of the UK’s oil and gas reserves; namely this province’s declining competitiveness which undermines its attractiveness relative to other oil provinces with which it competes for capital. This declining competitiveness is caused by a combination of factors:

3.2.1 UKCS maturity The UK is a mature oil and gas province where new field discoveries are typically much smaller and technically more challenging to develop than in the past. Oil & Gas UK’s survey shows that of the 50 new field developments reported in 2008, half have less than 15 million boe of recoverable reserves, compared with the hundreds of millions or even the billion barrel finds of the 1970s and 1980s.

3.2.2 Sharply rising costs The industry’s costs have risen sharply, in line with oil prices and driven by high worldwide demand for oilfield equipment, goods and services. Last year the cost of developing and producing a barrel of oil or gas rose by 12% compared with 2007 and was around three times higher than in 2002. Unit operating costs are typically 10–15% higher than a year ago. Although recessionary pressures are expected to reduce costs over time, past experience shows that it could take 12–18 months before the eVects are fully felt and that this is more likely to help sustain investment at a reduced rate than lead to any increase in investment.

3.2.3 Declining capital eYciency (a) Meanwhile, capital eYciency is declining. Although capital investment was up by half in 2008 compared with 2002, it will only produce about a third of the volume of oil and gas. (b) Of the 50 new developments now under consideration, Oil & Gas UK’s studies indicate that only a third of these break-even at reported costs, a $50 oil price and the current tax regime. (c) The continuing downward trend for capital investment from its 2006 peak of £5.6 billion to £4.8–£5 billion in 2008 clearly demonstrates that even when oil prices were reaching record highs of over $140, some projects in the UK were still struggling to attract development funding.

3.2.4 Fiscal and regulatory barriers The barriers presented by the current fiscal and regulatory regimes are addressed in Section 3.3 and Section 3.4 below.

3.2.5 Current economic climate The recession and falling oil price was expected to give rise to a slowdown in activity.This has been further compounded by the freezing of the capital markets which is severely restraining new investment in the basin. It is anticipated that investment will fall to somewhere in the range of £3.5–£4.5 billion in 2009 and could decline to £2.5–£4 billion in 2010. (For more about the eVects of the current recession and credit crunch, see Section 3.5 below.)

3.3 How eVective is the current fiscal regime in which the industry operates? In our view the current fiscal regime is no longer fit for purpose. It appears to be designed to maximise short-term revenues for the Treasury at the risk of long-term recovery of reserves and security of energy supply. 3.3.1 Oil & Gas UK has long argued that the overall tax burden on the mature UKCS must be reduced. Now, the diYculties in attracting and maintaining investment in the UKCS for projects of all kinds have been suddenly and materially increased. Ev 112 Energy & Climate Change Committee: Evidence

3.3.2 When the oil price was last in the $40–$45 per barrel range, new developments were subject to a tax rate of 40%, but are today liable to 50%. Certain mature fields are subject to a marginal tax rate of 75%. The mismatch of tax rate and current business environment is detracting from the value of investment and is contributing to the dampening of that investment. 3.3.3 Government help is urgently needed for both established companies and the new smaller businesses that have been explicitly encouraged into the basin by Government policy. Material improvements in the current tax regime are now required to stimulate additional capital investment both through the current downturn and in the longer term. 3.3.4 The Government’s recent proposal to give a “value allowance” to be set against the supplementary charge on corporation tax is a clear acknowledgement that there is a problem. It is a welcome step in the right direction but, if it is to have any eVect, it must be material in scale for both new and incremental investment. Moreover, this proposal was conceived in May 2008 when the oil price was approaching a record high of over $140 and will not on its own prevent the industry from experiencing a slump in activity and investment this year and next. 3.3.5 To help maximise reserve recovery, current economic imperatives now require additional and bolder measures that would incentivise exploration as well as new field and brownfield development, and help to extend the life of the oVshore infrastructure. Such measures should include, for example, reducing or removing the 20% supplementary corporation tax on all new projects and accelerating the payment of accrued, but so far unrelieved, tax allowances to smaller companies. The latter measure would release much needed capital to small companies for investment in the basin at minimal cost to the Government. The Government has pursued a laudable policy to attract these smaller companies into the basin. It should throw this inexpensive lifeline to them now and not simply abandon them.

3.4 How eVective is the current regulatory regime in which the industry operates? 3.4.1 Oil & Gas UK welcomed the creation of the new Department of Energy and Climate Change, having argued for many years that energy policy needed to be better aligned and represented within Government and that a dedicated department led by a Secretary of State for Energy would allow for a more eYcient and coherent approach. 3.4.2 However, we are concerned that the Energy Unit is not adequately resourced. We see job vacancies unfilled and existing staV somewhat stretched. We also question how much of the £60 million taken in UKCS licence fees each year finds its way back to fund the Unit’s activities. This is not a plea for more regulation, but we believe that one of the lessons of the banking crisis is the need for well resourced and highly competent regulators who are capable of fully understanding and comprehending the needs and activities of the industry they seek to regulate. 3.4.3 For example, one of the symptoms of this long period of under-resourcing we have experienced is the lack of a public and reliable registry of UK oVshore production licence holdings. The existence of such a registry would greatly speed up commercial transactions and reduce the costly legal process of “proving title” back to original grant which has to be undertaken on each licence transfer today. If the development of such a scheme for existing licenses is too costly and burdensome, it should surely be considered for all new ones. 3.4.4 The oVshore industry is one of the UK’s most heavily regulated sectors but the regime must be fit for purpose. Regulatory risk can arise where the implementation of multiple regulations results in an administrative process which requires resources—and expenditure—disproportionate to the benefits gained. For the regulator and advisory agencies, the need to assess large amounts of information submitted by the operators, some of which is unnecessarily duplicated, can also lead to ineYciencies. 3.4.5 This last point becomes all the more pertinent in the context of the constantly changing UK and European regulatory environment. For example, the 2008 Energy Act brought in many changes and the Marine and Coastal Access Bill, currently making its way through the Parliamentary process, is bringing additional challenges for the industry. Devolved parliaments, too, risk adding to the already complex regulatory environment by adding their own layers of legislation. 3.4.6 While Oil & Gas UK supports the principles of the Marine Bill, it remains concerned about the impact that the designation of marine conservation zones (MCZs) could have on future oil and gas licensing. It is also concerned that socio-economic factors are considered when decisions on marine planning are taken by the new Marine Management Organisation (MMO). Here too is an example of the risk of regulatory duplication, arising from the Scottish Marine Bill. 3.4.7 While some recent regulatory developments have been innovative and welcome (such as the Promote and Frontier licences), others, including those coming from the EU, have not been well directed and risk constraining investment and the production of UKCS reserves. 3.4.8 One area of particular current concern is our research which shows that, if there is a requirement for our industry to buy most of its allowances at auction under Phase III of the European Emissions Trading Scheme, this could result in the permanent loss of up to one billion barrels of oil and gas production. There Energy & Climate Change Committee: Evidence Ev 113

would be no environmental benefit as the foregone UK production would merely be replaced by production from elsewhere in the world, probably not subject to the same environmental constraints or likely to take part in any new international agreement in Copenhagen in December 2009.

3.5 What eVect are the recession and the credit crunch having on the industry? What is the impact on the financing of exploration and development? 3.5.1 The rapid decline in oil (and latterly the gas) price combined with the collapse in the capital and equity markets is placing a severe strain on the industry, causing the sector as a whole to reassess its investment decisions, with major ramifications for the supply chain. 3.5.2 Such evidence is corroborated by our survey which demonstrates how the withdrawal of finance capital combined with high well costs will severely constrain exploration and appraisal (E&A) activity both this year and next. Although we have reports that 77 E&A wells will be drilled this year, only 35 have firm rig commitments, compared with 109 wells drilled last year. In 2010, we anticipate only 10 firm E&A wells. 3.5.3 Similarly, small oil companies needing debt capital to finance development activities are unable to secure it. Large oil companies are taking a conservative approach and many are reviewing budgets in light of the uncertainties caused by the recession and the banking crisis. 3.5.4 A comparison may be made with the period of 1998–2000 when the fall in the oil price placed the industry under extreme pressure. Investment fell by half over two years between 1998 and 2000 and took six years before it recovered. E&A spend took the greatest hit and fell by two thirds over three years and again took five to six years to recover. Across the supply chain there was a major reduction in capacity; it took seven or eight years to recover from that setback and that loss of capacity has remained a fundamental constraint to the development of the UKCS in recent times. 3.5.5 Supply chain companies advise us that banking facilities are being withdrawn or charged at new prohibitive rates, potentially placing solvent businesses under threat of liquidation. 3.5.6 There is also evidence to suggest that the banking crisis is preventing the industry from obtaining the decommissioning securities they require from the banks (see Section 3.10). 3.5.7 Any downturn in activity will have an impact on jobs. We estimate that each £1 billion expenditure on the UKCS provides around 20,000 jobs. With capital expenditure forecast to fall by up to £2.5 billion over the next two years, this could mean a loss of up to 50,000 jobs.

3.6 What steps need to be taken to unlock resources west of Shetland? 3.6.1 The area to the west of Shetland is the UKCS’ next frontier and could potentially yield up to a fifth of the country’s remaining oil and gas reserves. 3.6.2 However, despite exploration over many years and a number of promising discoveries made, development has been restrained by the deep, hostile marine environment, extreme weather and the shortage of infrastructure to transport oil and gas to market. 3.6.3 This makes projects in the region high risk, technically challenging and therefore extremely costly. The Government believes that costs to develop known projects could well be over £4 billion. 3.6.4 The attraction of the area for investment has been further reduced by the recent falls in oil and gas prices. A reduction in overall costs would have a direct impact on investment economics and would improve the attractiveness of prospects in the area. 3.6.5 Fiscal measures such as a reduction or the abolition of the supplementary corporation tax rate or tax incentives for exploration as outlined in Section 3.3.5 could provide the necessary stimulus for new exploration and development west of Shetland.

3.7 What can be done to minimise the environmental impact of exploiting the reserves? How should this be encouraged and / or financed? 3.7.1 Oil and gas exploration and production on the UKCS is one of the most tightly regulated sectors, subject to over 100 pieces of environmental legislation spanning a broad range of issues. 3.7.2 The industry monitors its environmental impact via the Environmental Emissions Monitoring System (EEMS) to which Oil & Gas UK members submit, each year, measured and calculated data on solid, liquid and gaseous emissions from oVshore installations and associated onshore terminals. Since 1997, EEMS has been the single source of data used by both the industry and government. 3.7.3 Oil & Gas UK also monitors and assesses the marine environment through annual seabed surveys, designed to assess and monitor trends in contamination in both seabed sediments and biota. 3.7.4 Environmental impact assessments have to be undertaken before any activity commences, from licensing through to decommissioning, and are open to public consultation and scrutiny by the regulator. Ev 114 Energy & Climate Change Committee: Evidence

3.7.5 An example of the steps taken by the industry to minimise the environmental impact of its activities is its work on produced water. The industry has invested £450 million in recent years in new separation technologies and re-injection projects which have dramatically reduced the volumes and concentrations of oil in produced water discharged to sea, outstripping targets set in 2001 by the Oslo-Paris Convention (OSPAR). The volume of discharged oil in produced water fell by 24% over the period 2000–06 (compared with the OSPAR target of a 15% reduction) and this trend continues downward. The average oil in water concentration per UK installation has also fallen to under 20 parts per million, far better than OSPAR’s recommendation of 30 parts per million.

3.7.6 It should also be noted that the reason for UK’s success in meeting its Kyoto targets on CO2 emissions can be largely attributed to the switch from coal to gas fired power generation in the 1990s. 3.7.7 The industry has in recent years embraced subsea technology which accesses and produces reserves in a more environmentally friendly fashion. The UK leads the world in this lower energy intensity technology which, by placing processing facilities on the sea bed and tying them back to existing platforms, obviates the need for large above surface structures.

3.8 How are the skills needs of the sector being met? How transferable are those skills? 3.8.1 The industry has a fine track record in addressing its skills needs, and a large number of companies across the sector have had their own skills, learning and workforce development programmes in place for many years. 3.8.2 However, global demand in recent years for skilled oil and gas personnel has led to shortages across the sector, raising the necessity for the UK industry to work collaboratively to address its needs for a skilled, eVective and safe workforce. 3.8.3 The industry and the unions together regarded this matter as of such importance that they took steps to re-acquire OPITO, the oVshore industry’s training organisation, from the sector skills council COGENT to form OPITO, the Oil & Gas Academy in 2007. 3.8.4 The Academy is fully funded by the industry to provide support for the investment that oil and gas employers throughout the country are making in workforce development to ensure that the UKCS remains at the forefront of oVshore expertise and technology. Its role is to work in collaboration with industry employers, learning and training providers, education and academia, and partnership organisations to develop industry training standards and facilitate their implementation across the sector. 3.8.5 An example of the essential service the Academy provides is the development and implementation of the Minimum Industry Safety Training (MIST) programme which introduces the key safety elements required by all oVshore employees and ensures that all personnel have the necessary safety awareness and basic skills training to recognise and avoid risk. 3.8.6 The Academy has also been instrumental in the success of the industry’s modern apprenticeship scheme set up in 2001 to develop a competent, stable and flexible technician workforce. The industry has invested some £65 million in this scheme, which has helped to recruit almost 1,000 young technicians into the industry. 3.8.7 The modern, cutting-edge technologies, skills and expertise found in the UK oVshore industry today are all transferrable to related activities, both on and oVshore, including the renewables sector. Several of our members are already actively engaged in servicing these emerging sectors, supporting for example the development of oVshore wind turbine and wave energy technology, as well as carbon capture and storage.

3.9 What are the implications of an ageing existing infrastructure on the security of supplies from the North Sea? 3.9.1 Extending the use of North Sea infrastructure beyond its original, anticipated life plays a crucial role in allowing more reserves to be recovered both from existing fields and from those more remote discoveries which are too small to justify the major capital outlay required for dedicated facilities. 3.9.2 The pace of exploration and development therefore needs to be maintained to keep production flowing though the system in suYcient volumes so that the infrastructure remains economic and can be kept in place. Once it is removed, it will never be replaced and any remaining reserves in the vicinity will become unrecoverable. 3.9.3 However, the safety of an ageing installation remains of paramount importance and the decision to extend its life can only be taken after a rigorous examination of the integrity of its safety critical parts, in particular the primary and secondary structure, the processing plant, temporary refuge, emergency response equipment, etc. This is an on-going monitoring process, subject to independent scrutiny by a certifying authority, such as Lloyd’s Register, as part of a legally required formal verification scheme. It is also subject to inspection and approval by the Health & Safety Executive (HSE). 3.9.4 The industry has re-intensified its eVorts on asset and process integrity, spending more than £1 billion a year for the last three years to replace or refurbish safety critical equipment, improve management systems and train personnel. Similar expenditure is planned for the next three years. As a result of industry Energy & Climate Change Committee: Evidence Ev 115

eVorts, the number of dangerous occurrences, in particular hydrocarbon releases, has decreased to the lowest in the last 10 years and we expect to see further improvement in the 2008 safety statistics when they are published by the HSE in April 2009. The industry is committed to maintaining that improvement and investment in safety through the current economic downturn.

3.10 Is the right policy framework in place to manage the decommissioning of that infrastructure as resources are depleted? 3.10.1 Oil & Gas UK believes not. Decommissioning of oVshore installations and pipelines is regulated by the Petroleum Act 1998, with the current owners being jointly and severally liable. Whilst companies make full and proper provision for the costs in their accounts (estimated to reach a total of £23 billion over the next three decades), such provisions are not allowable against taxation, even when put into a special trust fund, and the current regulatory construct is fast becoming a barrier to investment. 3.10.2 Oil & Gas UK has been instrumental in setting up the Decommissioning Security Agreement which identifies the liabilities of parties concerned and how these should be secured against default. However, the Government’s position on the types of security, whose use it has encouraged, is not satisfactory. 3.10.3 The Government has relied upon the corporate covenants of investment grade companies and bankers’ letters of credit. The urgent need for a wider range of securities has been particularly exposed by the current banking crisis, with reports of banks disputing annual renewals of securities and limiting the size of security they are willing to post, or even denying it altogether. 3.10.4 The problem is compounded by the requirement to post the letters of credit on a pre-tax basis. This means that the companies have to provide securities up front for a sum which includes the amount which the Government pledges it will ultimately provide by way of tax relief. This in turn unnecessarily reduces the funds a company has available to invest. 3.10.5 Oil & Gas UK believes this situation can best be resolved by the Government allowing companies a range of options to provide for decommissioning security such as: (a) corporate covenants, for the larger investment grade companies; (b) letters of credit, on a post-tax basis; and (c) accepting that payments made into dedicated trust funds to be used solely to meet the cost of decommissioning are a valid and tax deductible business expense, which, regrettably and unfairly, they currently are not. This is in marked contrast to the new regime for future decommissioning liabilities in the nuclear power industry. March 2009

Supplementary memorandum submitted by Oil & Gas UK

1. Oil &Gas UK 1.1 Oil & Gas UK is the leading representative body for the UK oVshore oil and gas industry. Our 80 plus members comprise the major multi-national oil and gas companies, smaller specialist producers and explorers as well as large contractors and SME suppliers active across the UK Continental Shelf (UKCS).

2. Evidence on the Provisions in the Budget Relating to the North Sea Fiscal Regime

2.1 Introduction and Summary 2.1.1 Oil & Gas UK sees the measures in the 2009 Budget for the UK oVshore oil and gas industry as a modest step in the right direction, and notes that the new field allowance in particular could mark a watershed in that the government appears to have recognised that it needs to reduce the tax burden to stimulate investment in the mature UK Continental Shelf (UKCS). 2.1.2 We welcome the Government’s statement that it recognises the vital role that the oil and gas industry plays in contributing to the UK’s energy security of supply and its acknowledgement of the wider contributions the sector makes to the UK economy through employment, impact on the balance of trade and the skills, expertise and cutting edge research and development it creates. 2.1.3 However, Oil & Gas UK remains concerned that the provisions only address some of the issues we raised with the Prime Minister and the Chancellor of the Exchequer when we met in May 2008 and fail to respond to the radical change in economic circumstances, most notably the collapse in the oil and gas prices, the drying up of the debt and equity markets and the consequent rapid decline in capital and exploration expenditure within the sector. Ev 116 Energy & Climate Change Committee: Evidence

2.1.4 Quite simply, the fiscal package did not go far enough. While the Budget introduced a new field allowance and a number of positive technical measures (see Section 3), no provisions were given to encourage investment in existing fields; nor was action taken in the Budget to address the industry’s strong concerns regarding decommissioning securitisation or on amendments to the Ring Fenced Expenditure Supplement (RFES) which could have both stimulated exploration activity and helped small oil companies finance their operations. 2.1.5 The new field allowance is a modest step forward and will oVer some limited incentives for the development of marginal fields. However our members tell us that it will do very little to improve the UK’s competitiveness or attractiveness for investment when competing for capital on a global scale. Given the limited scope and extent of the allowance, it is only likely to accelerate the development of one or two marginal small fields over the next couple of years. We certainly do not see it reversing the decline in capital investment. 2.1.6 The allowance does not apply to existing fields and will therefore do nothing to address the collapse in investment in brownfields, nor will it reactivate drilling campaigns which have currently halted. Its impact on exploration activity will be negligible and it will not boost West of Shetland or tight gas development. 2.1.7 The government is yet to address our request that they accept decommissioning security on a post tax basis but has written oVering to consult further on this, which we welcome and will pursue. 2.1.8 The government also failed to act on our proposals to provide cash relief of unexpensed “Ring Fence Expenditure” which would have helped small companies and given a much needed boost to exploration. 2.1.9 We have now seen drilling activity drop 78% in the first three months this year, compared with the same period last year (Deloitte: North West Europe Review, April 2009)—and little prospect of it picking up in the remainder of this year or next. The measure to bring forward tax relief on exploration costs could be implemented at little or no cost and indeed at some potential financial benefit to the government. This is because it would be cheaper for the government to provide the tax refund now rather than allowing the monies to accrue interest at 6% pa until the time when it is paid out. 2.1.10 Oil & Gas UK notes from the Budget statement that the European Investment Bank is making £4 billion available to the UK for energy projects. We hope that some of this money could be made available to the UK oil and gas industry and Oil & Gas UK intends to follow up this up with DECC.

3. Specific Comments on the Fiscal Changes

3.1 New Field Allowance 3.1.1 The budget announced the introduction of a new field allowance to seek to encourage investment in small fields, ultra high-pressure, high temperature (HPHT) and ultra heavy oil fields. Oil & Gas UK members anticipate that in the current climate, the impact on UKCS economics will be very limited. 3.1.2 New small fields less than 20 million boe will gain a field allowance of £75 million field before tax, diminishing to zero for fields of 25 million boe or more. This allowance can only be oVset against the 20% supplementary charge on income from the field, eVectively reducing the marginal tax rate below 50%. These allowances will typically boost the economic value of new small field developments by around £8 million on a discounted post tax basis based on current prices. To set this in context, the benefit of the small field allowance should be compared with the scale of the investment, typically £100–200 million, that it is trying to encourage. 3.1.3 The respected petroleum economist, Professor Alex Kemp, estimates that the measure for small fields could add around 400 million barrels of oil equivalent (boe) over the life of the UKCS. 3.1.4 Ultra HPHT and ultra heavy oil fields receive a value allowance of £800 million eVectively worth around £80–100 million on a discounted post tax basis. The threshold for qualifying ultra HPHT fields has been set at 15000psi and 350F and for ultra heavy oil fields at less than 18)API and greater than 50 cp viscosity. In both heavy oil and even more so for HPHT, these are tighter technical limits than were proposed by Oil & Gas UK and many of our members have expressed strong reservations about the allowance’s eYcacy in light of their opinion that it is only likely to have very limited impact. 3.1.5 HM Treasury declined to include tight gas or West of Shetland in the list of targeted fields. The fact that the Treasury admits that the legislation would allow them to extend the target field types, provided a suYcient case is made by industry, leaves us to wonder why these field types weren’t included in the list in the first place. 3.1.6 Furthermore, we would strongly suggest that the qualification for the HPHT allowance is extended to include the thresholds proposed by the industry so that more prospects can potentially qualify. The original thresholds proposed were pressures of 10,000 PSI and 300F. 3.1.7 The decline in investment in existing fields is as much of a concern to industry. Here, high marginal tax rates of up to 75% on fields paying Petroleum Revenue Tax (PRT) are a major deterrence on new investment and do little to advance the need to enhance recovery. Energy & Climate Change Committee: Evidence Ev 117

3.2 Changes to Chargeable Gains Regime 3.2.1 The Budget confirms previous proposals that that no chargeable gains will arise where the proceeds from the disposal of North Sea assets are reinvested in the UKCS and similarly where assets of the same value are swapped. This should help encourage asset trading which has slowed down significantly in recent years.

3.3 Access to Petroleum Revenue Tax (PRT) relief on decommissioning 3.3.1 The Budget confirms access to PRT relief post licence expiry and also included some measures to simplify PRT compliance. These should provide additional assurance to late life assets.

3.4 Capitalisation of Cushion Gas Storage 3.4.1 After extended discussions, it has been agreed that for gas storage projects expenditure on cushion gas will be eligible for capital allowances. This tax change has long been sought by investors and may accelerate the development of new gas storage sites.

3.5 Encouraging Change of Use of Assets 3.5.1 A range of fiscal barriers deterring the re-use of platforms and infrastructure for applications such as gas or carbon storage or wind power generation have been addressed. These include removing any income from change of use activities from the scope of Petroleum Revenue Tax and retaining relief against tax for decommissioning costs for change of use assets.

4. Conclusion:Urgent Decisive Action Needed on Fiscal Change 4.1 Oil & Gas UK members have voiced their deep concern to us at what has been left undone by the 2009 Budget. In the current climate, the package of measures will have limited impact on the UKCS’ economics, will have little eVect on the UK’s competitiveness and attractiveness to investment and will not lead to any significant increase in activity. 4.2 The consequences of the failure to act decisively could be severe. Current economic circumstances are already placing industry work programmes under extreme pressure. The fiscal measures announced in April may help a small number of projects but will not reverse the significant decline in capital investment forecast by Oil & Gas UK—to around £3 billion by 2010. 4.3 Under-investment at this stage in the mature UKCS life risks fatally undermining the government’s stated goal of maximising the recovery of the UK’s remaining oil and gas reserves. Without new injection of oil and gas from the development of outlying satellite fields, key oVshore infrastructure hubs risk will see their decommissioning being brought forward. 4.4 Once these strategic platforms and their pipelines are removed, it is unlikely that they will ever be replaced and the means to recover the estimated remaining oil and gas reserves of up to 20–25 billion barrels, much of which is yet to be explored for and developed, will be lost. Even at today’s prices, these “neglected” reserves represent circa $1 trillion of potential economic benefit to the UK. 4.5 The decline in investment and activity will result in job losses across the supply chain, many of these in Scotland and the North East and with these, the disappearance of UK skills and competencies which will be diYcult to replace. 4.6 The government failed in the recent Budget statement to take the necessary strategic action that will encourage the maximum recovery of its indigenous oil and gas reserves and ensure that these precious resources can play a full role in helping to meet the UK’s future energy needs. Time is running out and corrective action now needs to be taken. 4.7 Oil & Gas UK therefore urges government to secure further changes to the North Sea fiscal regime and in particular repeats its call that all new projects, whether in or around existing fields, in the West of Shetland and elsewhere in the UKCS, should be relieved of Supplementary Corporation Tax. 4.8 Furthermore, and in any event, the Government should: 4.8.1 Extend the new field allowance to include: (i) opportunities West of Shetland which will help open up a new frontier in the life of the UKCS; (ii) opportunities for tight gas which will increase gas recovery, aiding security of supply over the next decade; (iii) either reverting to Oil & Gas UK’s original proposal for HPHT allowances or, at the very least, widening the threshold for Ultra HPHT opportunities by setting the requirement at 15000psi or 350F to render this a more practical incentive. 4.8.2 Introduce means to incentivise investment in existing fields, especially for PRT fields where the tax burden is excessive and is currently preventing the development of substantial oil and gas reserves. Ev 118 Energy & Climate Change Committee: Evidence

4.8.3 Provide means to fund and securitise decommissioning on a net of tax basis which will reduce company gearing, increase investment and encourage cash provisioning of decommissioning fund. 4.8.4 Take action now to boost exploration and support small oil companies by releasing the amount accrued under the FRES to those companies, solely to be spent on UKCS operations. May 2009

Memorandum submitted by the Royal Society for the Protection of Birds

Executive Summary

The challenge of climate change demands nothing short of a revolution in the way we use and generate energy. It is clear that we will need to end our dependency on fossil fuels, massively reduce the amount of energy we use and deliver environmentally sustainable renewable energy. We want this revolution to take place in harmony with the natural environment. The RSPB has argued that the natural environment is not sacrificed in pursuit of wider public policy objectives. This is the context for debates about future exploration of oVshore oil and gas. The main concerns associated with oil and gas developments with respect to seabirds, and other wildlife are disturbance, displacement from habitat or food resources, risks from oil spill, both major and minor from both the exploitation infrastructure and the associated shipping, and especially the cumulative eVects of these, either separately or in combination. Damage to wildlife can be minimised by: — Investing in sustained environmental surveys of marine wildlife, including seabirds. Impacts on seabirds, and the marine environment more generally, can be minimised by financing the surveys required to fill the gaps that have been identified in previous oVshore Strategic Environmental Assessments and studies. The data collected can help to guide development to those areas of least risk and inform selection of a network of marine protected areas. — Designating a comprehensive marine protected areas network. The absence of a network of Marine Protected Areas (MPAs) is not only bad news for wildlife, but also risks undermining investor confidence in energy infrastructure projects. Energy developers want clarity about the most sensitive locations. This is why it is in everyone’s interest to deliver a network of MPAs as soon as possible. Certainty regarding the location of important sites for marine wildlife will aid decision-making process on marine projects for oVshore energy, such as oil and gas and marine renewables. — Using environmental assessment tools more eVectively. OVshore energy Strategic Environmental Assessment (SEA) and Environmental Impact Assessment (EIA) processes oVer an opportunity to collect more data. However, despite data collation and collection through previous SEAs 1–8, there are still significant information gaps, especially for seabirds at sea. Although SEA and EIA of oVshore oil and gas developments and plans is improving, these assessment tools are still falling short of their potential. Future strategic assessments of oVshore oil and gas licensing plans could be improved by i) considering an appropriate and wide range of reasonable alternatives, ii) focusing on evaluating cumulative eVects, and iii) applying the precautionary principle. Strategic assessments should also, where possible, consider spatial alternatives. — Careful consideration of whether to unlock resources west of Shetland. Unlocking these resources could have potentially adverse eVects on Scotland’s marine environment. We recommend that certain sensitive areas are excluded for future rounds of oil and gas licensing, including the area around St Kilda and the Hebrides. We would also recommend a buVer zone around these areas to ensure that feeding seabirds are adequately protected. The area west of Shetland has significant data gaps, and available data on seabirds is old and limited in geographic and seasonal scope.

The future role of oil and gas in the UK’s energy policy

1. The RSPB believes that climate change is the greatest threat we face and that unless action is taken to reduce greenhouse gas emissions, one third of all land based species may be committed towards extinction by 2050. We have welcomed the UK Government’s plans to cut emissions by 80% by 2050 and we support the Government’s pledge to deliver the UK’s share of the EU renewable energy target for 2020. 2. The Government’s Renewable Energy Strategy has proposed that, to contribute its fair share to the target, it will seek to generate 15% of its energy (and up to 40% of electricity) from renewable sources. This will require a revolution in the way that we generate and use energy. To meet these targets, research we have Energy & Climate Change Committee: Evidence Ev 119

undertaken with others (The 80% Challenge—Delivering a low-carbon UK by IPPR, WWF and RSPB) suggests that much more eVort needs to be invested in reducing the amount of energy we use, in stabilising aviation emissions and decarbonising the electricity sector. 3. The contribution that the UK’s remaining oil and gas reserves should make to the UK’s future energy needs must be considered in this context.

What can be done to minimise the environmental impact of exploiting the reserves 4. Inappropriately designed and/or sited energy projects, including oil and gas developments, can seriously damage biodiversity. Such damage is not inevitable, and we believe policies should be designed, and safeguards put in place, so that damage to wildlife can be minimised. Our experience of working successfully with renewable energy developers, such as the London Array Ltd in the Thames Estuary, demonstrates that energy developments which avoid unnecessary conflicts are achievable.

Address Environmental Data Gaps and Designate a Comprehensive Marine Protected Areas Network 5. Any environmental database used to assess the likely eVects of oVshore oil and gas developments should be adequate to ensure that these developments are sited in the least sensitive locations. The RSPB is concerned that there are currently significant gaps in our knowledge of the marine environment. We need to understand the risks of oVshore oil and gas developments to particular species and areas and identify the key knowledge gaps. 6. OVshore energy Strategic Environmental Assessment (SEA) and Environmental Impact Assessment (EIA) processes oVer an opportunity to collect more data. However, despite data collation and collection through previous SEAs 1–8, there are still significant information gaps, especially for seabirds at sea. Now that these data gaps have been verified, the next step is to fill them—this will necessitate new data collection. 7. These information gaps may limit a comprehensive assessment of the potential eVects of further oil and gas licensing on sensitive marine species and habitats in UK waters. The RSPB believes that the knowledge gaps are so significant, that assessments of oil and gas licensing, e.g. most recently in the UK OVshore Energy Plan SEA, may fall short of predicting the magnitude and cumulative nature of these potential eVects. Investment in data collation and collection is therefore essential. 8. The absence of a network of Marine Protected Areas is a further level of uncertainty regarding the impacts of oil and gas exploitation on marine species and habitats. Uncertainty due to lack of knowledge is one of the elements that leads to delay in licensing not only oil and gas but other energy projects at sea. This requires a step-change in the approach taken towards resourcing the survey,identification and designation of these sites. 9. Furthermore, we also need comprehensive legislation to provide an eVective framework for the designation and management of Marine Protected Areas (MPAs), including Natura 2000 sites. The RSPB is advocating strong legislative provisions for the designation of marine conservation zones (MCZs) in the Marine & Coastal Access Bill (and equivalent Scottish Marine Bill). Certainty regarding the location of important sites for marine wildlife will aid decision-making process on marine projects for oVshore energy, such as oil and gas and marine renewables.

Minimise Impacts on Seabirds by Financing the Surveys Required to Fill Data Gaps 10. The UK is of outstanding international importance for its breeding seabirds, notably Manx shearwater, northern gannet, great skua and lesser black-backed gull. Yet, oil and gas developments may cause problems for colonial breeding seabirds, non-breeding seabirds and waterbirds at sea. The main concerns associated with oil and gas developments are disturbance displacement from habitat or food resources, risks from oil spill, both major and minor from both the exploitation infrastructure and the associated shipping, and especially the cumulative eVects of these, either separately or in combination. 11. Impacts on seabirds, and the marine environment more generally, can be minimised by financing the surveys required to fill the gaps that have been identified in previous oVshore SEAs and studies. The data collected will have the added value of supporting the faster delivery of a network of MPAs, and be useful for wind leasing assessments. It is possible, and fitting, for the Department of Energy and Climate Change to work with Defra to invest in developing the knowledge base and so accelerate the designation process through financial support and prioritisation of systematic environmental surveys at sea. We believe that it would be appropriate to also detail how any such data gathering would be integrated with other databases to progress the designation of MPAs and facilitate the role out of oVshore wind electricity generation. 12. In particular, we need: (i) comprehensive baseline seabird data collection in potential development zones, using a combination of aerial and ship-based surveys using recommended methods. A minimum of two years preconstruction data collection is required for potential development zones. Ev 120 Energy & Climate Change Committee: Evidence

(ii) a systematic survey programme to plug gaps in spatial and temporal coverage and provide updated contextual information for UK Continental Shelf waters. This should include sample re-surveys of areas covered by European Seabirds at Sea (ESAS), to determine whether broad patterns of distribution and abundance remain unchanged or whether there have been changes that cast doubt on the value of older data for identifying marine Special Protection Areas (SPAs) under the Birds Directive or areas of potential greater sensitivity for oil and gas developments. (iii) further research into foraging ranges and areas used by priority species relevant to each development zone, making use of developing technology such as data loggers and habitat suitability modelling (also relevant to SPA identification). (iv) Note: baseline data for other marine species and habitats is also required. 13. A Geographic Information System atlas of bird distribution and abundance, pulling together all available information, would be an extremely useful component of a constraints assessment for oVshore energy, whilst also enabling information gaps to be identified (thereby updating the (then) DTI’s seabird gaps analysis by Pollock & Barton 200614). Inclusion of down-weighted ESAS data where older than say 10 years would be advisable. 14. The RSPB has reviewed the likely impacts of wind farms on seabirds and waterbirds in UK waters. We have also identified those bird species which are most likely to be priorities for data collation and collection as part of the Round 3 SEA and subsequent individual project Environmental Impact Assessments, particularly in the areas mapped by the Crown Estate as potential development zones. Some of this review may also be applicable to oVshore oil and gas developments. 15. We note that where oVshore seabird data collection has been more intensively conducted, this has yielded some significant results, such as the discovery of the extent of the Liverpool Bay common scoter population.

Use Environmental Assessment Tools more Effectively to Minimise Environmental Impacts

16. Environmental assessment tools, such as SEA and EIA, are key to minimising the environmental impacts of oil and gas developments. In the absence of an MPA network including marine Natura 2000 sites, these assessment tools are also the main processes through which marine environmental data is collected. 17. Strategic Environmental Assessment (SEA) in particular is a key tool for integrating environmental considerations into the planning and decision-making process, thereby enabling the impacts of development on wildlife to be avoided, or at least minimised. It evaluates the significant environmental eVects of development proposals and reasonable alternatives to them, so that the most environmentally damaging proposals can be eliminated early on before significant resources have been invested in working them up through the design stages. Where preferred alternatives are likely to have negative eVects, SEA can identify how these can be reduced and positive outcomes enhanced to benefit biodiversity. 18. Because SEA is strategic, it provides decision-makers with the information they need to license the least environmental sensitive areas for oil and gas developments. This is something that project-level EIA cannot do because it begins when developers are already seeking consent for specific areas. Any plan to exploit remaining oil and gas reserves should be subject to SEA, and if it is likely to aVect a Natura 2000 site, appropriate assessment (AA). 19. Although SEA and EIA of oVshore oil and gas developments and plans is improving, these assessment tools are still falling short of their potential. Future strategic assessments of oVshore oil and gas licensing plans could be improved by i) considering an appropriate and wide range of reasonable alternatives, ii) focusing on evaluating cumulative eVects, and iii) applying the precautionary principle. Strategic assessments should also, where possible, consider spatial alternatives. Environmental Impact Assessments further down the line should take on board the conclusions of strategic assessments, as well as any recommended mitigation and monitoring measures. 20. There could be potential conflicts between the oil and gas licensing applications and our as yet incomplete MPA network, including both marine Natura 2000 sites (European Marine Sites) and the forthcoming MCZs network (required to fulfil Government’s obligations under OSPAR). Applying appropriate assessment at plan and project levels is central to avoiding conflicts between the oil and the future oVshore Natura 2000 network. Prior to licensing areas that include proposed and existing European Marine Sites, an appropriate assessment must be carried out. Licensing should proceed only if the appropriate assessment concludes that there will be no adverse aVect on these sites. We also recommend an energy licensing policy that avoids damage to areas that include features meeting protected status criteria, particularly where no sites have been designated for a particular feature yet and/ or the network is not complete.

14 Pollock, C. & Barton, C. 2006. An analysis of ESAS seabird surveys in UK waters to highlight gaps in coverage. Report to the DTI by Cork Ecology Energy & Climate Change Committee: Evidence Ev 121

What steps need to be taken to unlock resources west of Shetland 21. Unlocking resources west of Shetland could have potentially adverse eVects on Scotland’s marine environment. In particular, the cumulative eVects of oil and gas activities with non-oil and gas activities could be significant. We recommend that certain sensitive areas are excluded for future rounds of oil and gas licensing, including the area around St Kilda and the Hebrides. We would also recommend a buVer zone around these areas to ensure that feeding seabirds are adequately protected. In addition, important seamounts that have been mapped within 14 degrees west should also be excluded, e.g. Anton Dorn and Hebrides Terrace Seamounts. 22. The area west of Shetland has significant data gaps. The data on seabirds is old and limited in geographic and seasonal scope. The seabirds at sea data was collected opportunistically onboard petroleum industry vessels, and therefore focuses on locations of interest for the industry,rather than systematic seabird surveys. Furthermore, seasonal weather conditions also restrict the coverage of the European Seabirds at Sea database. 23. The risk assessments carried out west of Shetland will need to be rigorous and must fully consider the much more extreme nature of this environment, compared with the bulk of industry experience in the North Sea. These risk assessments should include the modelling and assessment of the eVects of oil spills on seabirds and their associated colonies. 24. The supply chain from petroleum resources west of Shetland to the nearest coastal depot will be a long one. Therefore, focusing on the most environmentally and carbon friendly methods of exploiting the reserves and maintaining the infrastructure will be important. March 2009

Memorandum submitted by Scottish Council for Development and Industry (SCDI) 1. SCDI welcomes the opportunity to comment on the inquiry by the Energy and Climate Change Committee into UK OVshore Oil and Gas and the contribution that it can make to the UK’s future energy needs. SCDI looks forward to the meeting between the Committee and SCDI members in Aberdeen on 19 March. 2. SCDI is an independent membership network that strengthens Scotland’s competitiveness by influencing Government policies to encourage sustainable economic prosperity. Its membership includes business, trade unions, local authorities, educational institutions, the voluntary sector and faith groups. 3. SCDI and Scottish Enterprise produce the only annual report into Scotland’s International Activity in the Oil and Gas Sector. SCDI has regularly commented on the North Sea Fiscal Regime in submissions to the UK Government, most recently on the consultation from HM Treasury and HM Revenue and Customs on Supporting investment: a consultation on the North Sea fiscal regime. It has also hosted a meeting for the Scottish AVairs Committee and SCDI members in Aberdeen to discuss its inquiry into EVects of tax increases on the oil industry.

Summary of Domestic and International Benefits of Investment in UKCS

Security of Supply 4. Even with ambitious eYciency eVorts, global energy demand is expected to increase significantly between now and 2030. While the UK Government is establishing ambitious targets for the growth of renewable energy by 2020, decarbonising heat and, especially, transport will take longer than electricity, and oil and gas will still account for a growing portion of the UK’s energy supply. Attracting significant investment into conventional energy sources will therefore also be needed. Current business plans will see the UKCS only providing about 12% of the nation’s oil and gas demand in 2020. However, with sustained investment, this could increase to 40%. Thus, maximsing UKCS output is critical to generate more investment for exploration, production and help sustain assets in a mature, high cost province competing for mobile international investment.

Economic Benefit 5. UK unemployment is expected to increase sharply this year, and there is widespread agreement that the current recession demonstrates the need for the UK to rebalance its economy more towards production, manufacturing and exporting. The UK oil and gas industry provides employment for 450,000 people. Oil and gas producers invested £5.7 billion of capital in 2006, 37% of the total by production and manufacturing industries. Recent work reported in the Oil & Gas UK Economic Report 2008 demonstrated that each £1 billion of investment provides employment for around 20,000 across the supply chain. Any fall oV in investment will have a consequential impact on employment by the industry. Ev 122 Energy & Climate Change Committee: Evidence

6. The latest Survey of International Activity in the Oil and Gas Sector shows that total sales by Scotland’s oil and gas supply and service specialists increased by 9.9% to reach £14.2 billion in 2007–08, more than double the value in 2000. International sales were 19.5% higher, while, in comparison, domestic sales were only 4.3% higher. International activity accounted for 40% of the Scottish supply chain sales total. This compares to 27% in 2000 and 32.2% as recently as 2005. This latest research recorded sales activity in 103 diVerent markets across the world, the highest number of diVerent destinations recorded in the history of the research. This is powerful recognition of the increasing international capability of the oil and gas supply chain which has been built over the last 30–40 years. 7. Sustaining activity in the UKCS is critical because it still provides the majority of sales by the supply chain and also to anchor this economically important industry in the UK as international activity becomes a greater proportion of its total sales. The Annual Survey identified that the value of total international sales recorded into Norway in 2007 was £351 million, an increase of £75 million since 2006 and a figure which represents a record for revenues generated from this market. There is increasing cross border collaboration on major projects that straddle or are close to the North Sea boundary line between Scotland and Norway which is enabling Scottish companies to capture a greater range of opportunities in the Norwegian market than they have in the past. Sustaining UKCS activity will support the supply chain in accessing opportunities around the European Continental Shelf.

Tax Revenue/ Balance of Trade 8. Tax payments to the Treasury for 2008–09 should be around £13.3 billion, more than double those of 2004–05, despite the declining trend in production and higher capital and operating costs. The UK’s balance of trade in goods and services would have been £"78bn last year had it not been for the production of North Sea oil and gas. The industry has shown that eVective tax incentives will lead to larger returns for the Exchequer. It is especially important to sustain activity in the UK oil and gas industry as the financial services industry retrenches and public finances are rebuilt over the next five years. It is also important that HM Treasury considers the multiplier eVect from supply chain companies. Taxation on the burgeoning profits which they are generating is an important source of revenue. Oil & Gas UK has estimated that the Exchequer benefits by around £5–6 billion a year in corporation tax, payroll taxes and national insurance contributions from the supply chain, in addition to the tax revenues generated by exploration and production companies in the UKCS. Sustaining activity in the UKCS and anchoring the supply chain in the UK will sustain the benefits to the Exchequer.

AVordability of Supply 9. The view of a number of people in the industry is that the next spike in the oil price when global economic activity eventually picks up again—especially in Asia—may be even higher than in July 2008, which would lead to higher electricity, gas and fuel prices, and more people suVering from fuel poverty. Maximising UKCS output would add 600 million barrels of oil and gas per year to the production base and make a contribution to ensuring that global supply can meet growing global demand, and that fossil fuel price inflation is controlled as far as possible.

How can the UK’s remaining oVshore oil and gas reserves be exploited most eVectively? What barriers are there to exploiting such reserves? What steps need to be taken to unlock resources west of Shetland?

EVectively Exploiting the UK’s Remaining OVshore Oil and Gas Reserves 10. It is generally recognised that the UK still has a possible 25 billion barrels of oil equivalent (boe) left to produce. The top priority for the UK has to be maximising economic recovery. This requires investment in new field developments, incremental projects and exploration to turn remaining potential into discoveries. 11. There is still a broad range of commercial opportunities which could attract investment in the right circumstances. Despite being a mature basin there is little doubt that the UKCS remains an attractive region to do business. It is characterised by political stability and does not have the security issues prevalent in many other emerging oil and gas provinces. The results of the latest Survey of International Activity in the Oil and Gas Sector, which cover 2007–08, demonstrate a period of further steady growth in sales into the UKCS market. Sales rose from £8,146.6 million in 2006 to £8,497.2 million in 2007, an increase of 4.3% over the period. The international growth in the same period was 19.5%, but it must be remembered that the actual level of domestic sales remains higher than international, £8.5 billion compared with £5.7 billion. Companies continue to show willingness of companies to invest in the region. 2007 saw the highest number (111) of oVshore exploration and appraisal wells drilled since 1996 (112). The ongoing interest and potential of the UKCS was further reflected in the summer announcement by the Department for Business Enterprise and Regulatory Reform that 193 applications had been made by a total of 131 companies for licenses in the 25th OVshore Licensing Round. This represents the highest number of applications ever made and a 31% increase on the number of applications made in comparison with the 24th Licensing Round. In mid November 2008 Energy & Climate Change Committee: Evidence Ev 123

the Department of Energy and Climate Change (DECC) announced a very positive set of results for the 25th licensing round, with 171 new licenses oVered to 100 companies covering 257 blocks of the North Sea. This included successful bids from eight companies new to the North Sea. 12. Oil & Gas UK has said that if investment were to be sustained at around £5 billion a year over the next five years the production decline rate would average 4.5% per annum, compared to the natural decline rate of the basin of 15% per annum. If all the investment projects which have been identified could be delivered, 16 new fields could be brought on-steam in 2011, rising to 20 in 2012. In its 2008 Activity Survey, Oil & Gas UK has also found that new projects which start-up in 2015 and beyond ultimately boost production in the later half of the next decade by 250,000 boe pd compared with last year’s survey. However, it noted that half the projected production in 2014–15 comes from investments which are yet to be sanctioned. This underlines the need for current investment to be sustained and for the UKCS to be an attractive location for a broad range of companies. 13. An extra one billion barrels of reserves could be recovered from existing and new UKCS fields though the use oVshore of new forms of technology, such as “tight” gas production. This technology and other technologies are at present used onshore, but are still regarded as uneconomic for oVshore application. The UK has a supply chain which is at the cutting edge of technological development and, as the latest Survey of International Activity in the Oil and Gas Sector demonstrates, is exporting around the world. It needs to be anchored in the UK.

Barriers to Exploiting the UK’s Reserves 14. The UK oil and gas industry has been investing at high levels to recover the 16 to 25 billion barrels which is estimated to remain in the UKCS. Oil and Gas UK figures show that, in 2007, expenditure by the upstream industry was £12.4 billion, including more than £1 billion per year to extend the life of existing oVshore assets and onshore plants. The Well Services Contractors Association noted in its most recent annual report that new capital investment in 2007 was over 300% higher and new technology spend was estimated to be over 470% higher than in 2000. But massive additional investment is needed if recovery from the UKCS is to be maximised. The natural decline rate of the basin is 15% per annum. UKCS production was 2.63 million boe pd (1 billion boe) in 2008, 5% lower than in 2007. Production is estimated at 2.5 million boe pd per day in 2009, 5% lower again than in 2008. Oil production alone was down 5.2%, whilst gas production fell by 4.8%. The overall production decline rate has slowed to 5% from the 7.5% seen over the period 2002–07, in part responding to increased capital investment. 15. This is a global challenge. A recent presentation by the Chairman of Simmons & Company International, an independent investment bank specialising in the energy industry, suggests that the fundamentals of the oil and gas industry have fundamentally changed since 1997. He highlights that exploration and production spending grew from less than $100 billion to $400 billion in the decade to 2007, there were major technological advances which allowed deepwater/ ultra deepwater exploration and greater amounts of trapped oil to be drained and, by 2008, every quality drilling rig (and other oil service assets) were being used. Despite this, while demand for oil and gas grew by 12.7 MMB/D, production grew by only 7.3 MMB/D and OECD total petroleum stocks fell from 56 days use to 52 days use. He warns that almost all the super-giant oil fields are “mature” and past-peak, and that: “The era of band aids is over, the era to rebuild the entire infrastructure has to begin ASAP.” He says that the total cost could exceed $100 trillion and manpower needs may top 500,000 to 1 million engineers and construction workers. 16. Even with the exceptionally high oil prices of the first half of last year, there were question marks over whether the required level of investment in the North Sea could be sustained under the current fiscal regime. Rising costs were putting intense pressure on the economics of the mature oil and gas provinces. It now costs nearer five times as much to develop each barrel of oil or gas as it did in 2001, while operating costs per barrel have more than doubled. The average technical cost for projects coming on-stream between 2008 and 2010 rises to $29 per barrel. The break-even point for new field developments in the North Sea is now averaging above $40/bbl. It will take time for operating expenditure to react to the falling price of oil. The cost inflation associated with rising oil prices up to July 2008 and the subsequent shuddering correction has therefore exposed the UKCS’s declining competitiveness compared with lower cost regions. 17. At current prices, most of the new categories of hydrocarbon resources are not economic to develop and the most significant declines in demand are expected in mature oVshore basins (along with North American drilling and Russian oil production enhancement). The recently published 10th Aberdeen and Grampian Chamber of Commerce Oil and Gas Survey found that 75% of operators expect a reduced trend in total activity in 2009 (25% of operators expect a level trend with none expecting an increase). All reported being less confident as to the business situation than a year ago and the majority expect to reduce employment levels in 2009. Oil and Gas UK’s 2008 Activity Survey anticipates that capital investment will fall from £4.8 billion to £5 billion in 2008 to £3.5 billion to £4.5 billion in 2009 and £2.5 billion to £4 billion in 2010. While it was predicted a year ago that 113 wells would be drilled in 2009, 77 wells are now planned and only 34 have a drilling rig committed. For 2010, planned wells have fallen from 30 to 10. 18. These projections are consistent with experience in the late 1990s. Investment fell by half in 1998–2000, with exploration spend cut by two thirds, and employment was reduced across the industry. Recovery in investment took six years and another one or two years in the supply chain, but the loss of Ev 124 Energy & Climate Change Committee: Evidence

capacity has remained a constraint on the UKCS. Moreover, it must be remembered that the big diVerence is that production peaked in the late 1990s where as it is now declining at 5% per annum which pushes up operating costs. If investment drops oV, production will be aVected and the decline rate will again accelerate post 2010 and unless infrastructure is kept active, decommissioning will be brought forward which will prevent the recovery of future reserves from within their area. Some 45% of the infrastructure in the UKCS could be decommissioned by 2020.

West of Shetland 19. Around 16% of the UK’s proven and probable oil and gas reserves are located to the west of the Shetlands. Limiting the decline rate in UK oVshore oil and gas production depends on commencing from West of Shetland by 2013–14. However, this assumes that infrastructure is put in place within this timeframe. This is by no means guaranteed, especially at the current oil and gas prices. It has been estimated by the UK Government that the cost may be over £4 billion. 20. In Incentivising Investment in the UKCS, Professor Alexander G. Kemp and Linda Stephen demonstrate that a large value allowance is required to have a worthwhile eVect on investment west of Shetland. At prices of $60/bbl, 50p/ therm, a value allowance of £250 million is shown to incentivise three extra projects. But the reduction or the removal of the Supplementary Corporation Tax on the oil and gas industry would be the most eVective step to unlock these resources.

What can be done to minimise the environmental impact of exploiting the reserves? How should this be encouraged and/ or financed? 21. Minimising the environmental impact of exploration and production has been a high priority for the oil and gas industry for a number of years. The UKCS is at the forefront of the development, utilisation and export of subsea technology, which has enabled the more environmentally sustainable exploitation of reserves. 22. The Race to Capture the Carbon Pound: The UK’s place in the global market for low carbon innovation published by Shell Springboard highlights that improvements can only be achieved through technological innovation and by creating the right conditions for innovative companies to bring their ideas to fruition. Government intervention is critical, but there is still significant uncertainty about the policy framework for reducing carbon emissions in the medium-to-long term and international co-operation in policy, technology and ideas, rather than national or even regional action, is important. Access to finance is essential and governments must help to create the market. The total annual cost of reducing CO2 emissions in 2030 is estimated at between £420 million and £2,100 billion per year. 23. Access to finance is an increasing problem for low carbon SMEs. Overall investment from venture capital and private equity in these companies was $854 million in 2007, over twice the $342 million invested in 2006. But, following the onset of the credit crunch in the first quarter of 2008, investment dropped to $108 million. 24. SCDI believes that it is critically important that tax relief should be available for the reuse of existing oil and gas infrastructure for Carbon Capture and Storage (CCS) and, indeed, other forms of oVshore energy production. This will support the eVective exploitation of the UK’s remaining oVshore oil and gas reserves in a more environmentally sustainable manner. The early deployment of CCS is important if the essential contribution of fossil fuels to the security of UK energy supply is not to result in higher emissions. In the North Sea, it has one of the world’s best locations for CO2 storage and SCDI anticipates that a study for the Scottish Government to be published imminently will demonstrate its potential. However, the challenge cannot be underestimated and there is increasing uncertainty about its development. Existing technologies have to be scaled up by 50–100 times, there are rising engineering and construction costs and significant investment is needed in pipelines within the UK and oVshore in the North Sea. CCS cannot currently be regarded as economic without further financial support. 25. SCDI was disappointed that delays in support from the UK Government prevented the realisation of the BP Miller Field CCS Project. This was a missed opportunity for the UK. It is concerned that delays in the UK Government’s CCS competition are further harming the UK’s competitive position in this emerging industry and would welcome a decision to support more than one demonstrator project and technology. It believes that appropriate financial arrangements need to be put in place to enable the re-use of the infrastructure and maximise the opportunity. Tax relief for well drilling costs associated with CCS are absolutely necessary for industry and, in respect of gas storage, industry needs to secure an acceptable tax treatment for cushion gas. SCDI is generally content with the UK Government’s proposals to remove fiscal barriers to change of use. It has also suggested that the UK Government considers if the proposed incentives for the oil and gas industry should be extended to utility companies involved in CCS. 26. Environmental regulations for the UKCS should not simply displace oil and gas activity to other competing provinces at the expense of the UK security of supply and economic and employment benefit, and with no overall global carbon emission reduction. In particular, the inclusion of the North Sea industry within phase three of the European Emissions Trading Scheme for electricity generation on oVshore platforms would substantially increase its costs and make it less competitive for mobile international Energy & Climate Change Committee: Evidence Ev 125

investment. The industry believes that this could result in the failure to develop up to one billion barrels of oil from the UKCS. This shortfall would be made up from production in provinces outside the EU which, with transportation, would actually increase global carbon emissions.

How eVective is the current fiscal and regulatory regime in which the industry operates?

Fiscal Regime 27. North West Europe is one of the most expensive oil and gas regions in the world. The UKCS is also one of the most highly taxed provinces, with the oil and gas industry paying 20% more in corporation tax than any other UK industrial sector. 28. SCDI believes that it is right that the UK should fairly benefit from the profits generated by oil and gas production in the UKCS. However, the top priority for the UK has to be maximising economic recovery and the overall UKCS fiscal regime is increasingly inappropriately balanced. Oil prices are now back in the same range as in 2004 when the supplementary corporation tax was half what it is today. Last year saw unprecedented price volatility and there is evidence that this is a general trend. International investors regard the fiscal regime as increasingly unsustainable for a mature, costly and challenging province, and there is a danger of “resource flight”, including skills, to other areas. This is within a global context where the fundamentals of the industry may have fundamentally changed, with a new order of investment needed in exploration and production, technological advances and the rebuilding of an entire global infrastructure. 29. This challenge can only be addressed in the UKCS by progressively reducing the overall tax burden on the industry. This would be simple, eVective and predictable, send a message that the UK is committed to a commercially viable UKCS and greatly increase its competitiveness in attracting mobile international investment. But time is of the essence if recovery of the resources available is to be maximised before decommissioning of the infrastructure begins in earnest. 30. SCDI has welcomed the Treasury’s plans to introduce incentives for the industry, but it believes that these should be made available to existing and new fields. — Existing Fields—Declining investment in exploration and R&D, ageing infrastructure, and problems in raising development capital all increase the importance of investment for production from existing fields. The UK Government may need to revisit the assumption that smaller new entrants will pick up and maximise the assets of the oil and gas majors. Bigger players, which often have more specialised expertise, will need incentives too. The latest survey by Aberdeen and Grampian Chambers of Commerce found that, based on operators’ plans in 2007, 54% of future investment will be targeting extensions to existing fields, up from 33% of investment in 2006. But SCDI understands that the current “low oil price world” requires a stimulus to keep the ageing infrastructure competitive and combat depletion. The UK needs to do this now before the existing North Sea infrastructure becomes too costly to maintain. — New Fields—Exploration is the seedcorn for extending the productive life of the UKCS. Half of all potential new field developments are less than 15m barrels in size, which were challenging to develop even in the higher oil price business climate. Innovation and ability of the sector to compete globally in small field development and subsea technology are essential to the long-term prospects of the UKCS. These activities depend on confidence among operators and contractors in the future and access to investment funding. But, as Aberdeen and Grampian Chambers of Commerce found, the recent collapse in the oil price, continued uncertainty and limited access to working capital and long term loans means that spending on R&D is expected to decline over the next two years. 31. SCDI has argued in its submission to the Treasury on Supporting investment: a consultation on the North Sea fiscal regime that the proposal from the oil and gas industry, similar to the proposal which has since been announced by the Netherlands, for a 25% uplift on capital investment would be eVective through: — Promotion of the recovery of the UK’s oil and gas reserves. — Sustaining the competitiveness of the UKCS. — Upfront acceleration for investment while infrastructure is still available. — Simple and consistent application e.g. across new and brownfield development. 32. HM Treasury has, however, said that it prefers a value allowance proposal. Detailed modelling in Incentivising Investment in the UKCS by Professor Alexander G. Kemp and Linda Stephen has shown that, particularly in the current market conditions, the introduction of the value allowance can make a positive contribution to enhancing field developments and that the greater the value allowance, the greater the activity increase. The oil price is also an influence. The modelling found that a value allowance in the £50 million–£100 million range could have very substantial eVects under the $60/bbl, 50p/ therm price scenario. 33. SCDI would therefore support the introduction of a value allowance, provided it is easy to implement, the benefits are easy to assess at the point when decisions on investment are being made and that it is significant enough to be attractive and provide a material stimulus in the short-term. SCDI would support Ev 126 Energy & Climate Change Committee: Evidence

the proposal that there should be larger value allowances for bigger fields. It would accept that there should be a ceiling on value allowance, but believes that the tax system should support the commercial viability of many projects as possible. 34. SCDI considers that, at the very minimum, the scope of HM Treasury’s proposals on Value Allowance needs to be extended to cover all new fields West of Shetland. The modelling by Kemp and Stephen indicated that substantial allowances were required to make a worthwhile impact on the number of viable new developments given the relatively high costs per boe of undeveloped fields. 35. SCDI agrees that the types of field which should receive an incentive include: — Small developments of less than 25m barrels. — High Pressure High Temperature projects. — Heavy oil. — Challenged gas. 36. In addition, if workable proposals are made, it should be extended to: — Incremental projects in existing fields. — All future UKCS exploration. — West of Shetland projects. 37. SCDI welcomes the launch of a joint government and industry working group on Enhanced Oil Recovery (EOR). It believes that the group should examine proposals for incentives which encourage investment in new EOR projects, while avoiding retrospective tax changes which could increase the perception of uncertainty in investing in the UKCS and disadvantage existing EOR schemes. 38. SCDI has previously expressed the view that fields which are “never payers” should be removed from the Petroleum Revenue Tax (PRT) regime, and that access to PRT relief should be maintained and improved for decommissioning costs. It understands that exempting investments in unprofitable parts of older fields from PRT would significantly enhance the attractions of investment in incremental projects, particularly at this time, and could liberate at least an additional 20,000 barrels of oil per day over time. However, SCDI appreciates that the industry itself has not reached a collective view on a buy-out proposal.

Regulatory Regime 39. SCDI has long called for a single Department of Energy, headed by a Secretary of State for Energy, to be re-created. It warmly welcomed the announcement by the UK Government of a Secretary of State for Energy and Climate Change. 40. The UK and Scottish Parliaments are both considering Marine Bills which would create separate Marine Maritime Organisations. There is a risk of duplication or a lack of co-ordination between the new regimes, a joined-up approach will have to be taken, especially in relation to key strategic industries like North Sea oil and gas. Westminster is responsible for licensing, exploration and regulating development of the industry. It will be important that this is co-ordinated eVectively with Holyrood’s maritime planning and nature conservation powers. 41. SCDI supports the three main regulatory initiatives which are being pursued to promote the exploitation of the UK’s remaining oVshore oil and gas reserves—Fallow Field, Infrastructure Code of Practice and Stewardship. These should be pursued vigorously. It understands that the voluntary Infrastructure Code of Practice between companies is still not working fully eYciently and it is important that this is rectified as in a mature province with smaller discoveries and an ageing infrastructure more fields need to be brought on stream and more quickly. SCDI would hope that the Stewardship initiative can demonstrate that it is improving the average recovery rate from fields by another 10 to 15% by encouraging the greater use of enhanced recovery technologies oVshore.

What eVect is the recession and the credit crunch having on the industry? What is the impact on the financing of exploration and development? 42. The latest forecast from Energy, Metals and Mining industries consultancy and research services company Wood Mackenzie estimate that global GDP will contract by 0.6% in 2009, leading to significantly lower global oil demand of 84.3m barrels per day (b/d) for 2009, a decline of 1.5 million b/d compared to 85.3 millions b/d in 2008. This would be the first drop in demand since 1982 and Wood Mackenzie also says that the outlook is the weakest for decades. The changes to 2010 are bigger still with modest growth of 0.7%, or 0.6 million b/d, and world demand now expected to be only 84.9 million b/d, but this is a “significant” 2.1 million b/d lower than expected as recently as October 2008. 43. The biggest revisions are in Asia-Pacific. In Europe, demand is expected to be 15.3 million b/d in 2009, a fall of 3.9%, while demand in 2010 is forecast at 15.0 million b/d, a further drop of 2.2%. Aside from GDP declining, the factors impacting on European demand include: falling car sales and a changing structure of car sales with less fuel eYcient 4x4 vehicles being particularly hit, and air travel shrinking significantly, leading to drop in jet kerosene demand. Energy & Climate Change Committee: Evidence Ev 127

44. In response, OPEC has been reducing production. In late December 2008 OPEC agreed a cut of 2.2 million barrels per day from Jan 1 2009 in the volume entering the market and further cuts may follow if revenues continue to decline. But these production cuts have had little eVect and there are doubts about whether it can eVectively police and maintain them among its membership. 45. The problems are exacerbated by the credit squeeze which has developed in the second half of 2008. This has already impacted on the ability of some of the smaller independent oil companies which moved into the UKCS to raise the capital required to proceed with drilling and field development programmes. Much of the exploration in the UKCS is undertaken by these medium and small companies and their exploration budgets are currently very likely to be reduced. The well-known problems in the financial markets have reduced the availability of both debt and equity capital for companies requiring external capital. In the latest Aberdeen and Grampian Chamber of Commerce survey 50% of operators and 54% of contractors rated access to capital and loans as very important. All operators and 87% of contractors shared the view that the current credit issues would lead to more mergers and consolidation in the UKCS and all believe it will have an adverse eVect on working capital and activity, leading to the deferment and cancellation of capital expenditure. The prevailing view is that this much tighter lending environment is likely to persevere for some time. Globally, the credit squeeze and global economic downturn have resulted in key projects being postponed and cancelled, in drilling rigs being laid down and in new rigs facing credit problems with shipyards. Rating agency Moody’s has changed its outlook for the global oilfield service sector to “negative” because it expects a substantial and potentially prolonged downturn in demand for drilling and oilfield services. It predicts that a rebound in demand would lag behind an improvement in commodity prices until producers—particularly independents—are confident that price increases are sustainable with suYcient visibility in demand trends. 46. In addition, the pound has weakened considerably against the US dollar in 2008. The combined impact of this is likely to aVect profit margins in the industry and with the late 2008/early 2009 oil price considerably reduced from recent peaks it is likely that sustaining recent investment levels will be highly challenging. 47. Exploration activity is the pipeline for future development. The eVect of the recession and the credit crunch makes clear the need for fiscal incentives. Where companies which were successful in the 25th licensing round are no longer in a position to develop the blocks at this time, the UK Government and the industry should discuss proposals to extend licenses or transfer them to other companies. 48. Over the last three years decommissioning dates have moved out as a result of the rise in oil prices. However, there is a risk that lower oil and gas prices will now bring decommissioning dates forward. Banks have also supported companies with decommissioning liabilities, but in the current credit squeeze, it seems possible that they may charge them more and, eventually, stop. This would also have the result of making earlier decommissioning more likely.

How are the skills needs of the sector being met? How transferable are those skills?

Skills 49. The oVshore industry has expanded by 30% in the last couple of years. It is therefore unsurprising that shortages of key skills have been a constraint and have impacted on the industry’s ability to fully capitalise on projects and investment opportunities which have been facilitated by the buoyant oil price. 50. The latest survey by Aberdeen and Grampian Chambers of Commerce showed that among operators the strong demand for staV continued through 2008 with 50% of operators reporting total hours worked being above planned levels and 29% reporting rising, and 57% a level trend, in total employment over the last six months. Among contractors, 51% report increasing, and 43% a level trend, in permanent staVs and slightly more than 37% of contractors reported hours worked being above, and 47% at, planned levels in 2008. Some easing in demand is generally anticipated by operators in 2009 with only 16% expected to increase and the majority expect to reduce total employment levels in 2009. The rising trend in permanent employees is expected to level oV in 2009 and the current level trends in the employment of temporary and contract staVs are expected to turn downwards in 2009. Nevertheless 40% of operators still expect total hours worked to be above planned levels. The strong demand for staV from contractors is expected to continue at only slightly reduced rates. In contrast the current modest rising trends in the use of contract and temporary staVs is expected to end as 32% expect to reduce the use of temporary, and 31% the use of contract staVs in 2009. The trend of actual hours worked being above planned levels is expected to continue by 23% compared to 61% at planned levels. 51. Overall, the major diVerence in industry barriers to previous surveys by the Chamber of Commerce is the declining importance attached to skill shortages. This undoubtedly reflects the slowdown in activity. However, in SCDI’s view, the industry must not lose sight of the need to continue to invest in people and skills. Reactionary cost cutting would be extremely detrimental to the industry’s long term reputation and health. The skills challenge will not go away and the considerable eVorts that have been brought to bear on this issue over the last couple of years by the industry need to be maintained to nurture the talent for the Ev 128 Energy & Climate Change Committee: Evidence

future. While the average age for the whole oVshore workforce has been found to be 41 years, the expected average of a workforce generally in the range from 20 to 60 years old, there remains concern about the pipeline of skills into the industry and the ability of the UKCS to access highly-mobile international talent. 52. The recently-published survey Trends in International Mathematics and Science Study, which compared primary and secondary school standards in more than 60 countries and regions found that Scotland’s performance in maths and science subjects is deteriorating alarmingly and is now nearly bottom of the OECD class. The study also highlighted that only 51% of P5 pupils and 68% of S2 pupils in Scotland were taught science by a teacher who felt “very well” prepared. 53. The industry has collectively invested around £6 million to set up OPITO- The Oil and Gas Skills Academy, an organisation which is industry owned and run and is working on identifying and tackling key skills gaps, as well as providing cross-industry training programmes and working with UK schools and universities to ensure a constant feed of new entrants to the industry. Opito and a number of oil and gas companies are among the principal supporters of SCDI’s expanding network of Young Engineers and Science Clubs in schools around Scotland. But the Scottish Government and the education system, with strong support from business, clearly need to address this problem as a matter of real urgency. 54. The industry spends millions every year training and developing employees. For example, since 2001 it has invested £60 million in its modern apprenticeship scheme. In addition, due to the ongoing skills shortages within the industry, “fast-track” promotion systems are now common within certain occupations, as companies intensively train less experienced employees in order to fill the senior level vacancies across the industry. Employment conditions within these companies are extremely attractive, with salaries well above the UK average. The annual Hewitt salary survey shows that annual salary increases within the oil and gas sector have continued to show growth well above inflation each year. 55. Despite these eVorts, companies have reported that a range of vacancies were very diYcult to fill, primarily in Engineering and Science/Technology fields. This has increased recruitment costs and staV overtime. In some cases, the shortage of skills for these key positions had led to the abandonment of projects. 56. The oil and gas industry is one which can require very specialist skills in some areas, which are often not easily transferable from other sectors. It is vital therefore that the UK encourages continued investment by promoting an environment in which industry can access the skilled labour it needs from around the world. The UK is already one of the most expensive oil and gas provinces. Pressures on the supply of skilled workers will risk reducing the attractiveness of the province to larger multinationals, make it harder to recover from the downturn and ultimately harm the industry’s long term sustainability. The latest Survey of International Activity in the Oil and Gas Sector identifies activity by the supply chain in 103 diVerent country markets and the success of this UK industry depends in part on the international mobility of the workforce. The Migration Advisory Committee is scheduled to undertake a review of the Engineering sector for its revision of the Shortage Occupation List later this year. It should consider how the industry can access the skills its needs to sustain activity. 57. In the competition for highly-mobile international talent, it is important that the UK remains an attractive and well-connected location. Aberdeen is the hub of the UKCS and the supply chain based in the city needs access to global markets. The expansion of Heathrow Airport is necessary to ensure that flights from Aberdeen retain their slots and businesses can interline via the UK’s hub airport.

Transferability 58. The skills and expertise of individuals and businesses in the oil and gas industry are, along with its world-leading technology, a major competitive advantage for the UK in building an international class renewables industry, especially oVshore. 59. The Annual Report of Scotland’s International Activity in the Oil and Gas Sector 2007–08 identified a substantial level of activity undertaken within non oil and gas sectors with a total of £797.4 million recorded during the latest survey, compared with £678.7 million in the 2006 survey. The major key sector for this activity by far was Non Oil & Gas Energy, which accounted for 46.7% of the total by value. This sector relates principally to power generation. Respondents specifically identifying the Renewable Energy market as a source of diversified income equated £10.8 million by value. It might have been anticipated that this figure would have been higher given the ongoing focus for the supply chain to diversify into renewables, and it should be expected that more companies will become involved in the future.

What are the implications of an ageing existing infrastructure on the security of supplies from the North Sea? 60. In the North Sea there are almost 600 platforms and 54% of these are more than 15 years old. The average age of platforms decommissioned in the North Sea is 17 years old—though this average increases to 20 years if platforms that have a life of less than 10 years are excluded from the analysis. There remains a general reliance on existing, ageing infrastructure throughout the UKCS, as commercial discoveries are too small to support their own. Oil & Gas UK state that capital and operational expenditure in asset and process integrity has exceeded £1 billion a year in each of the last three years, and will reach an estimated £1.2 billion to £1.5 billion in each of the next three years in a variety of ways including replacement or Energy & Climate Change Committee: Evidence Ev 129

refurbishment of safety critical equipment and improvements to management systems. Significant investment has also been made in safety training for all staV on the importance of asset integrity. In consequence, over the last decade there has been a steady fall in the frequency of major and significant leaks from oil and gas processing plant and pipelines. 61. With an ageing, interconnected infrastructure there is the danger that the shutdown of one major pipeline could impact on numerous fields. Conversely, this established network improves the commercial viability of developing smaller prospects. This can only be achieved if investment is sustained in asset integrity and an increasingly collaborative approach is taken to the operation of fields.

Is the right policy framework in place to manage the decommissioning of that infrastructure as resources are depleted? 62. Higher oil prices and ways of extending the production lives of fields have delayed decommissioning in recent years. But the enormous challenge that the process poses to the entire supply chain—including technological constraints, availability of large heavy lift vessels and the need for suitable onshore facilities— has also been a factor. The latest report for Scottish Enterprise on the Decommissioning Market by the energy business analysts Douglas-Westwood Limited which was published last year highlights that for many platforms installed in the North Sea, particularly the larger platforms in water depths beyond 100m, there is currently little or no decommissioning experience to aide operators with their task. There are almost 70 platforms with a total substructure and topside weight of over 20,000 tons currently installed in the North Sea—all of which will inevitably present unique challenges when they are finally decommissioned. Innovation will continue to enhance the industry’s ability to extend the production lives of fields. But there is a risk that lower oil prices will reduce the incentive and bring forward the timescale in which these challenges need to be addressed. 63. In the North Sea the decommissioning process typically takes 4 to 6 years from the decision to initiate a study to decommission a platform to gaining all the necessary approvals and actually removing the facilities and carrying out final surveys. Within the UKCS legal requirements are determined by the OSPAR Convention, national regulatory frameworks and licensing agreements which, following the OSPAR Decision 98/3, collectively exceed global standards through a requirement for the total removal of oVshore structures in all but a few cases. 64. Decommissioning liabilities are a barrier to the transfer of fields between the majors and smaller and medium sized companies. One potential solution is a Decommissioning Trust Fund into which regular payments are made while the field is producing, but the Treasury has refused to make them tax deductible. The Government has also encouraged the use of corporate covenants of investment grade companies and bankers’ letter of credit to identify and secure liabilities against default. However, as previously mentioned, the credit crunch is leading to banks increasing their charges, and limiting or refusing to provide security. The UK Government should change the tax system to ensure that companies have suYcient funds to invest and that payments into trust funds are tax deductible. 65. Substantial decommissioning is currently scheduled to begin around 2013 and the total spending on decommissioning of the UKCS through to 2040 is now forecast to reach £23 billion, 15% higher than was expected a year ago. This is clearly a significant market opportunity for UK companies. However, at present Norwegian shipyards appear to be better placed to take advantage of the work. The planning system should enable the development of competitive UK facilities. March 2009

Memorandum submitted by Shell UK Shell U.K. Limited is a leading operator in the UK sector of the North Sea, operating on behalf of Shell, Esso and other co-venturers. In Scotland we provide direct and indirect employment for around 6,500 people oVshore and onshore and in the UK around 8,500. We produce some 20% of Britain’s oil and 20% of its gas, enough to supply over one third of UK domestic gas customers. Shell operates 35 platforms/platform clusters, three Floating Production Storage and OVtake vessels (FPSOs) and 31 subsea installations on 54 operated fields, three onshore gas plants (St Fergus, Mossmorran, Bacton), and one Marine Terminal (Braefoot Bay).

Executive Summary 1. The oVshore oil and gas industry is a core part of the UK economy—paying more than 30% of total UK corporation tax, in addition to being a world leading supply chain which provides goods and services globally and also high quality, well paid employment, with over 400,000 direct and indirect jobs in the UK. 2. However, in the current economic climate—with the recession, a low oil price, and high costs— investment in the North Sea is a challenge for Shell and industry. Whilst 2008 saw oil prices rise rapidly to peak at over US$145, they subsequently fell back to below US$40/bbl by the end of December 2008 and in Ev 130 Energy & Climate Change Committee: Evidence

January 2009 were around $40–45/bbl. These most recent prices ranges are at levels we have not seen since 2004–05, however the cost environment has changed somewhat, with costs and supplementary corporation tax (SCT) double to when we last had oil prices at $40–45bbl. 3. Shell believes that maintaining investment levels is critical to realising the full production potential of the UKCS, thus protecting 100,000s of jobs, continuing the flow of tax receipts to the UK Exchequer, and preventing early erosion of security of supply. All these objectives are increasingly important—and increasingly challenged—in a time of recession; and the industry looks to government to provide fiscal and regulatory stability to underpin investor confidence. 4. Shell has input into the recent HMT Fiscal Consultation and sees some merit in the HMT proposals for a Value Allowance (VA). However, we think Government is missing major opportunities in not targeting both new developments AND incremental investment in existing fields. Bringing on incremental production is a huge challenge in the current environment and we believe that Capital Uplift15 is a more eVective measure to bring incremental projects on-line. We believe the VA proposal benefits only a small portion of the UKCS portfolio, in addition to being complicated and prohibitively expensive for Government to make a real diVerence. Moreover, it does not address brownfield expenditure, where the largest opportunity sits. 5. Ultimately, any mechanism introduced needs to be simple in application and companies should obtain certainty in application up-front. We believe the most eVective mechanism would be to either reduce or abolish the rate of SCT or in absence of this introduce some change to the capital allowance. 6. Shell is undertaking a full range of activities to continue to improve hydrocarbon recovery from the UKCS, both from existing fields and through development of satellite fields using existing infrastructure. All these investments are eVectively leading to improved oil (and gas) recovery from mature areas of the UKCS, where there are no longer any new stand-alone green-field opportunities. 7. Surveys have revealed little or no significant long-term negative impact of our oil and gas operations on the indigenous flora and fauna, therefore we feel that existing regulatory requirements including Environmental Impact Assessment of new projects and discharge limits have worked well to minimise the environmental impact of the oil and gas industry. 8. We fully support the working group that PILOT, the joint programme involving the Government and the UK oil and gas industry, has recently set up to focus on this issue and welcome the outcome of its work.

Question 1: How can the UK’s remaining oVshore oil and gas reserves be exploited most eVectively? What barriers are there to exploiting such reserves? What steps need to be taken to unlock resources West of Shetland?

Question 3: How eVective is the current fiscal and regulatory regime in which the industry operates?

Question 6: What are the implications of an ageing existing infrastructure on the security of supplies from the North Sea? 1. The oVshore oil and gas industry is a core part of the UK economy—paying more than 30% of total UK corporation tax, in addition to being a world leading supply chain which provides goods and services globally and also high quality, well paid employment, with over 400,000 direct and indirect jobs in the UK. 2. Whilst stressing the importance of the industry to the UK economy, the cross-border nature of the industry must also be recognized. Our business operates and invests across the North Sea and as a result of these investments we have prolonged the life of our onshore plants and also secured access to Norwegian gas. The need to continue good relations across these borders is of significant importance not just to us as a business, but for the UK security of energy supplies. 3. However, in the current economic climate—with the recession, a low oil price, and high costs— investment in the North Sea is a challenge for Shell and industry.

The Cost Environment 4. In what is already one of the most expensive oil and gas provinces in the world, costs continue to provide a challenge year on year, as the figures contained in the Oil and Gas UK 2008 Activity Survey illustrate: — Total operating expenditure concerned with recovery from existing fields rising by 11% to £6.8 billion in 2008. — Unit operating costs rose by 10–15% in 2008 as a result of declining production and the increase in operating costs. — Costs of new field developments were typically 10–15% higher than a year ago.

15 Capital Uplift is an incentive oVered by government to encourage the contractor to maximize investment. It is an additional amount of cost recovery on capital expenditures over and above amounts spent eg if a company spends $1,000,000 in recoverable capital expenditures and there is a 10% capital uplift in the contract, the company will be allowed to recover 110% of actual spending or $1,100,000. Energy & Climate Change Committee: Evidence Ev 131

— The costs per barrel of brown-field development rose more steeply between 15–20% in comparison to a year ago. 5. Whilst 2008 saw oil prices rise rapidly to peak at over US$145, they subsequently fell back to below US$40/bbl by the end of December 2008 and in January 2009 were around $40–45/bbl. These most recent price ranges are at levels we have not seen since 2004–05, however the cost environment has changed significantly, with costs and supplementary corporation tax (SCT) double the levels when oil prices were last at $40–45bbl. 6. Moreover, the UKCS is a mature oil and gas province; new discoveries have halved in size and the number of fields in production has doubled over the last ten years. Substantial parts of the UK’s oVshore infrastructure are over 25 years old and operating costs continue to rise, in part reflecting the need to maintain the infrastructure’s long-term integrity. With capital eYciency within the UKCS continually dropping, the cost of developing a barrel of oil or gas is now around three times higher than in 2002. 7. These figures collectively show the high cost, high inflation environment within which we are operating—and unless investment levels are increased to bring on more production, a potentially uncompetitive position will arise in the UKCS.

Maintaining Investment Levels 8. Shell believes that maintaining investment levels is critical to realising the full production potential of the UKCS, thus protecting 100,000s of jobs, continuing the flow of tax receipts to the UK Exchequer, and preventing early erosion of security of supply. All these objectives are increasingly important—and increasingly challenged—in a time of recession; and the industry looks to government to provide fiscal and regulatory stability to underpin investor confidence. 9. This means an open market for energy set within a transparent fiscal framework which encourages maximum possible incremental production. This framework should seek to: — Promote full economic recovery of oil and gas resources. — Be consistently applied and provide certainty across all phases of field life. — Sustain competitiveness of the province. — Recognise the long-term nature of investments and refrain from increasing tax rates in response to short-term increases in commodity prices. 10. When making investment choices, the energy industry considers a wide range of factors. Product prices, costs, materiality of the investment choices, availability of alternative investment opportunities, strategic fit and investment risk all sit alongside tax as determinants of investment behaviour. However, tax rate is the primary measure government can use to increase the investment the energy industry makes in a particular jurisdiction. Lower tax rates provide a greater incentive to invest, and hence maximize recovery and supply. Marginal or risky opportunities are more likely to be ventured by multi-national oil companies, if tax rates are lower, given that their capital allocations are determined globally and placed in jurisdictions with highest potential after tax returns. 11. The importance of maintaining investment levels is also essential for preserving the oil and gas supply chain in the North Sea of Scotland, not only for the benefit of the UK’s indigenous oil and gas industry but also for the support it gives to the global oil and gas industry. The recent Scottish Council for Development and Industry (SCDI) figures16 have revealed that Scottish-based service/supply companies generated a record £14.2 bilion in domestic and international sales, compared to £12.9 billion in 2006 and international activity accounted for over 40% of the Scottish supply chain sales total for the first time. In 2000, the international share was 27%.

The Fiscal Regime 12. It follows that the most eVective means the Government has to maximise production and the long- term potential of the North Sea, is an attractive and stable tax regime. An overall cut in tax rate will incentivise investment, and hence maximise the long-term viability of the North Sea. But there is a need for additional measures over and above this to target specific incremental production. 13. Shell has input into the recent HMT Fiscal Consultation and sees some merit in the HMT proposals for a Value Allowance (VA). But we believe the VA proposal benefits only a small portion of the UKCS portfolio, as it does not address brown-field expenditure, where the largest opportunity sits for increased recovery. Brown-fields are two-thirds of the remaining potential of the UKCS. 14. We think Government is missing major opportunities in not targeting both new developments AND incremental investment in existing fields. The oil price is at a level not seen since 2004, since when supply chain costs have hugely inflated and SCT has doubled. Bringing on incremental production is a huge

16 Survey of International Activity in the Oil and Gas Sector 2007–08 Ev 132 Energy & Climate Change Committee: Evidence

challenge in such an environment and we believe that Capital Uplift17 is a more eVective measure to bring incremental projects on-line. We believe the VA proposal benefits only a small portion of the UKCS portfolio, in addition to being complicated and, prohibitively expensive for Government to make a real diVerence. Moreover, it does not address brownfield expenditure, where the largest opportunity sits. To encourage investment in projects such as HPHT (high pressure, high temperature), projects that are specifically mentioned by HMT for potential targeting, the VA would need to be very significant. 15. Ultimately, any mechanism introduced needs to be simple in application and companies should obtain certainty in application up-front. We believe the most eVective mechanism would be to either reduce or abolish the rate of SCT, or in absence of this, introduce some change to the capital allowance.

Accelerating Recovery 16. Allied to the need for an eVective fiscal regime is the need to fully optimise the use of the existing infrastructure of platforms, pipelines and terminals, before they are decommissioned. After that, the opportunity for development of today’s small fields will be much reduced. In that context, industry greatly appreciated the meeting with the Prime Minister Gordon Brown and the Chancellor Alistair Darling in May 2008 and also subsequent correspondence with Mike O’Brien MP,Energy Minister. During these discussions specific areas where Government assistance could lead to an acceleration of investment and increased recovery were discussed. We believe, as an industry, there could be 25 billion barrels or more of oil and gas yet to be recovered from the UKCS and want to do all we can, working with Government, to unlock this potential. 17. Shell is undertaking a full range of activities to continue to improve hydrocarbon recovery from the UKCS, both from existing fields and through development of satellite fields using existing infrastructure. We are managing a multi billion-dollar investment programme over the next five years (2009–13) on our operated UKCS assets. 18. In addition, we are studying a significant number of additional opportunities which are currently immature or commercially unattractive and considerable eVort will be required to bring these to final investment decision in future years. 80% of this total investment programme is targeting additional recovery from existing fields. Most of the remaining spend is to develop satellites to existing fields or to pursue near field exploration. These opportunities are becoming increasingly more complex and targeting ever smaller volumes per well. Consequently they require innovative technology and continued cost reductions, especially in the current volatile economic environment. 19. In addition an increased focus on well and reservoir management is maximising recovery from existing wells. All these investments are eVectively leading to improved oil (and gas) recovery from mature areas of the UKCS, where there are no longer any new stand-alone green-field opportunities. Taken together the activities we are considering have the potential to significantly increase recovery and we do not wish to restrict any discussion to the traditional narrow definition of EOR (enhanced oil recovery).

Question 2: What can be done to minimise the environmental impact of exploiting the reserves? How should this be encouraged and/or financed? 20. Shell is spending between £1 million and £1.5 million per annum on environmental surveys in the vicinity of its producing installations to ensure that suYcient data is available to assess the environmental quality of the seabed in the areas most likely to be aVected by the extraction of oil and gas reserves. 21. Surveys have revealed little or no significant long-term negative impact of our oil and gas operations on the indigenous flora and fauna. We believe that existing regulatory requirements, including Environmental Impact Assessment of new projects and discharge limits, have worked well to minimise the environmental impact of the oil and gas industry.

Question 4: What eVect is the recession and the credit crunch having on the industry? What is the impact on the financing of exploration and development? 22. We fully support the working group that PILOT, the joint programme involving the Government and the UK oil and gas industry, has recently set up to focus on this issue and welcome the outcome of its work. March 2009

17 Capital Uplift is an incentive oVered by government to encourage the contractor to maximize investment. It is an additional amount of cost recovery on capital expenditures over and above amounts spent eg if a company spends $1,000,000 in recoverable capital expenditures and there is a 10% capital uplift in the contract, the company will be allowed to recover 110% of actual spending or $1,100,000. Energy & Climate Change Committee: Evidence Ev 133

Supplementary memorandum submitted by Shell Shell U.K. Limited is a leading operator in the UK sector of the North Sea, operating on behalf of Shell, Esso and other co-venturers. In Scotland we provide direct and indirect employment for around 6,500 people oVshore and onshore and in the UK around 8,500. We produce some 20% of Britain’s oil and 20% of its gas, enough to supply over one third of UK domestic gas customers. Shell operates 35 platforms/platform clusters, three Floating Production Storage and OVtake vessels (FPSOs) and 31 subsea installations on 54 operated fields, three onshore gas plants (St Fergus, Mossmorran, Bacton), and one Marine Terminal (Braefoot Bay).

Introduction 1. This submission is in response to an invitation to submit further written evidence to the Energy and Climate Change Committee’s Inquiry into the UK OVshore Oil and Gas industry, with a specific focus on the contents of the 2009 Budget.

Commentary 2. We welcome the fact that the recent Budget contained elements of fiscal reform for the oVshore oil and gas industry—an indication of Governments recognition of the challenging times the oil and gas industry is experiencing. There is a shared recognition between Government and industry that there is a substantial portfolio of projects which are marginal and struggling to attract investment in the current environment and that fiscal incentives are needed to promote investment. 3. However, whilst there were helpful fiscal reform measures in the 2009 Budget, we were disappointed that the scope and qualification criteria for the new Field Allowances are far more stringent and the allowances are set at a lower level than industry was seeking. We are concerned that the proposed scope, criteria and levels for the incentives set out in the 2009 Budget are not enough to reverse the projected decline in capital investment in the UK Continental Shelf (UKCS) and will not have adequate impact on the UK’s competitiveness and attractiveness to win global investment. We believe the measures will result in only a relatively limited increase in activity in the UKCS. 4. To illustrate this, we have undertaken an analysis on how the new Field Allowances would impact upon our UK portfolio and our conclusion is that the impact is limited. Whilst we are unable to share the detailed information in such a submission due to confidentiality, the analysis showed that out of our entire UKCS portfolio: — Only one development prospect would potentially qualify for the Field Allowance relating to small fields. However due to the fact that the prospect currently has marginal economics, the allowance is too small for the eVect to be a deciding factor in capital allocation. — Similarly, the ultra Heavy Oil fields (UHO) allowance will only potentially be applied to one field. Again the impact on the economics of the project is so small that it makes no change to taking the project out of the marginal category. — The ultra High Pressure High Temperature (UHPHT) allowance will have a significant eVect on one of our blocks, however due to the stringent criteria applied to the HPHT allowance, no other prospects in our portfolio currently qualify for this allowance. 5. Overall we believe the qualification criteria for the new Field Allowance is too stringent and the allowances too low to make a noticeable impact on stimulating investment and bringing forward production. Specifically: — UHPHT pressure and temperature criteria are higher than expected and the maximum allowance is 40% of the level requested by Industry in discussions with government. — Small Field Allowance cut-oV is slightly smaller than requested and allowance is 75% of requested level. — UHO viscosity cut-oV is more stringent and allowance is 40% of requested level. — A GB£2 billion total allowance (GB£10/boe) that was requested for Tight gas, oVspec gas and West of Shetlands developments are not evident in any form in the Budget. 6. Whilst there is merit in the proposal for an allowance based on new development prospects, due to the stringent criteria currently proposed, this allowance will only potentially incentivise a very small portion of our portfolio and we believe it is unlikely that these measures will generate the additional two billion barrels of incremental oil predicted by the Chancellor in the Budget. 7. More fundamentally, the proposed field allowance does not address brown-field prospects. As brown- fields are two-thirds of the remaining potential of the UKCS, and 85% of Shell’s future prospects, we believe that major opportunities are being missed to incentivise extra production in the North Sea. In the present economic climate bringing on incremental production on producing fields is hugely challenging. EVorts to extend field life and increase recovery of existing fields are more marginal than in past years due to lower oil price, smaller targets and high reservoir complexity. Ev 134 Energy & Climate Change Committee: Evidence

8. We therefore believe that a critical priority for government must be aligning an incentive relating to brown-field developments alongside the presently proposed Field Allowance. It is only then that a significant step will be taken to meet Government’s and Industry’s joint aspirations of maximising recovery from the UKCS. 9. Of the other elements in the Budget, we welcome the encouraging announcement with respect to North Sea asset transfers. All of the measures contained within the Budget to assist asset trades ie changes to the chargeable gains regime, amending PRT etc are, as the Government quite rightly points out, provide very helpful certainty and stability. It was also encouraging that the Change of Use issues identified in the November 2008 PBR were included in the Budget papers with the additional good news that HMRC are now willing to accept that the cost of Cushion Gas in Change of Use projects will, as requested by Industry, be treated as plant for the purposes of Plant and Machinery Capital Allowances. Finally we were also encouraged that the PRT decommissioning concern from Industry (post licence expiry decommissioning cost) was also addressed in the Budget.

Concluding Remarks 10. Overall Shell U.K. Limited welcomes the measures in the April 2009 Budget as a step in the right direction. However we believe it is not enough to reverse the projected decline in capital investment in the UKCS, will have little impact on the UK’s competitiveness and attractiveness to attract global investment and ultimately result in a relatively limited increase in activity in the UKCS. 11. We have welcomed the ongoing dialogue between industry and the Government since May 2008 in Banchory and the initial steps that the 2009 Budget makes to ensuring the UK North Sea fiscal regime is not a barrier to additional investment. However we are firmly of the belief that the proposed measures are not enough. The need to incentivise additional development has become even more pressing since discussions started, with the additional dimensions of an economic recession and associated challenges re access to capital and the collapse in the oil and gas prices. The eVects of this are being seen by the rapid decline in the capital and exploration expenditure within the sector. We do not believe that the changes contained within the 2009 Budget are adequate to attract investment and stimulate activity at a suYcient level. 12. Under-investment now will result in long terms problems for the UKCS, as developments and infrastructure are brought forward for premature decommissioning. Once removed such facilities are unlikely to be replaced and the ability to recover remaining oil and gas reserves will be greatly diminished. Not only will this result in a loss of economic benefits to the UK, through jobs and receipts to the Exchequer, but will ultimately undermine the Government’s stated goal of maximising the recovery of the UK’s remaining oil and gas reserves. 13. As such, we will seek to continue our engagement with HMT, and progress discussions, primarily for the inclusion of brown-field projects to be part of the current fiscal incentive package, but also for a revision of the new field criteria and allowances. Fundamentally, taking the package of reforms as it currently stands, the intended consequences of attracting investment and increasing production will and in fact cannot be met, however a relaxation and widening of the package would we believe secure further investment. May 2009

Memorandum submitted by Total E&P UK Limited Commenting on the questions posed in DECC Committee announcement 3, Total E&P would like to make the following observations and comments:

How can the UK’s remaining oVshore oil and gas reserves be exploited most eVectively? What barriers are there to exploit such reserves? What steps need to be taken to unlock resources west of Shetland? 1. The oil and gas industry has the skills and capacity to eVectively exploit the UKCS but faces increasing pressures due to very high technical and operating costs coupled with low oil and gas prices. The UK is in competition for investment funds from other areas of the world and so must have a fiscal and regulatory environment to encourage the investment necessary to retain existing infrastructure, develop new discoveries and continue with appropriate levels of exploration and appraisal drilling. The costs in the UKCS, today, are not competitive with many other areas of the world. In time, technical costs should reduce as the current economic situation filters through the system and long term contracts either come to an end or are renegotiated. It is a must for such costs to come down to appropriate levels in line with the prices of oil and gas. There is also a major concern that the lack of access to capital in the current climate will in general mean delays to projects as companies and suppliers contract. Total E&P UK is trying where possible to reduce costs without impacting on our work programme and any delays will undoubtedly have a knock-on eVect in terms of production in the future. To stop now would make it all the more harder to restart in the future Energy & Climate Change Committee: Evidence Ev 135

with the inevitable impact of reduced work for the supply chain, thereby adding to the pressures on the supply chain in general. In particular it is to be mentioned that all the vital contractors have to be protected as their input is essential. The West of Shetland project is a vital step forward for the UKCS in developing the first gas infrastructure from this remote and hostile environment. Without this infrastructure many prospects and smaller discoveries will remain undeveloped, thus increasing our reliance on imported gas whilst UK resources remain untapped. It is important to ensure essential services and supplies that will enable the project to be completed at a reasonable cost and on time are not sacrificed to the current banking pressures. Giving the green light to the Laggan Tormore gas project in the present economical climate would be a very positive signal for the industry.

What can be done to minimise the environmental impact of exploiting the reserves? How should this be encouraged and/or financed? 2. Total E&P takes its impact on the environment very seriously and invests substantially in improving its performance both oVshore and onshore. Over £23 million has been spent on produced water reinjection, energy consumption has been reduced by up to 20% at some sites and there is a successful recycling and waste reduction programme in place. In a Sunday Times survey in 2007, Total was voted the 11th Greenest Company in Britain. The improvement of energy eYciency is a permanent concern. The company acknowledges the importance of and observes regulatory obligations but would like to see greater substantiation and proof of benefit for some legislation prior to expensive implementation. This is a point raised with former government departments through Oil and Gas UK. One other major concern is the predicted cost impact of ETS Phase III on our facilities, where a 100% auction process would heavily increase operating costs. We understand that emissions have to be reduced. However, we are supporting Oil and Gas UK in better assessing the risk of premature field decommissioning that could result from the very substantial cost increase. In this case it could be argued that carbon leakage will occur since the loss of indigenous energy supplies would undoubtedly result in increased imported energy. We very much hope that this very serious issue can be discussed with some urgency since long term investment decisions by the industry may be adversely aVected by the uncertainty.

How eVective is the current fiscal and regulatory regime in which the industry operates? 3. Current taxation of the oil and gas industry is high. When SCT was last increased, in January 2006 oil was at $56/bbl; today it is approximately $45/bbl and the gas price is these days between 35 and 40 p/th (x30$/boe). There is a strong argument for the reduction of SCT rather than a complex Value Allowance determination which is proposed by HM Treasury. A simple reduction in SCT would be unambiguous, simple and give a direct signal to industry that Government is committed to helping sustain the UKCS. This is for us the major point. Taking into account the lack of visibility of future prices, decisions to proceed with new projects are diYcult to take and such a signal from government would have a real impact. TEP UK has responded to the fiscal consultation on Value Allowance and if the current consideration of a Value Allowance is pursued, it must ensure the level of allowance oVers a real benefit. For small fields with recoverable reserves of up to say 20 million barrels of oil equivalent (boe), we would propose £100 million and a reduced rate for those fields in the range of 20–30 million barrels. For High Pressure High Temperature (HPHT) accumulations, the very high cost of wells is a critical metric. We therefore propose that any allowance should relate to recoverable reserves. For the West of Shetland, we believe the critical metric in determining economic viability will be development cost per boe and so any Value Allowance should again be related to the recoverable reserves, with a cap on the amount of Value Allowance to ensure larger fields do not achieve an allowance greater than necessary. There are many considerations and outstanding issues in the Value Allowance proposals, including: — the treatment of the use of several companies within the same corporate group; — the avoidance of “cliV edge” criteria in determining the allowance; — the diYculties associated with economic cut-oV tests, which may not encourage cost eYciencies; and — the potential need to make adjustments after final capital expenditure is known, undermining the key principle of certainty. As already stated, and in view of these observations, Total E&P prefers the simpler approach of a reduced SCT for new developments so as to tax the returns from investments made today at a lower rate than the current 50%. This would be a real and highly visible move to encourage the green light for new projects. Ev 136 Energy & Climate Change Committee: Evidence

What eVect is the recession and the credit crunch having on the industry? What is the impact on the financing of exploration and development? 4. TOTAL E&P is not immune from the eVects of the current economic circumstances and is making every eVort to reduce its operating budget. Where possible, we are making every eVort to reduce costs whilst maintaining, as far as possible, our planned work programme. Funding a significant exploration programme together with our ongoing operations and projects, together with the large asset maintenance programme, is a challenge. Total E&P believes the government should take every opportunity to look at how to work with the financial sector to ensure the supply chain and particularly all vital contractors have access to appropriate finance. Potentially sound, some of those vital companies are facing an unsure future, which could have significant consequential damage to our own ability to invest in the UK.

How are the skills needs of the sector being met? How transferable are those skills? 5. Over the last few years the industry has made substantial eVorts to promote the industry, to train new recruits and up-skill existing workforces. After diYcult periods in 2006–07, the number of “green hats” has drastically been reduced on our facilities. Total E&P has also clearly the intention of continuing to hire graduates through this diYcult period since the company relies upon maintaining a highly competent technical workforce. Our overall workforce numbers will increase during 2009. However, we are concerned that many supply chain companies facing the current economic pressures might lose experienced staV thus impacting the quality of service required on current projects and also limiting the ability of the industry to respond swiftly to the economic upturn when it will occur within the next years. It is not clear what government can do to alleviate this situation but we hope that the industry will be able, with the support of the authorities, to continue the engagement demonstrated in the last year to improve skills through eYcient training programmes.

What are the implications of an ageing existing infrastructure on the security of supplies from the North Sea? 6. Total E&P will have invested £500 million over the last years to ensure asset integrity and the ability of our facilities to operate for at least another 20 years in safe conditions. New accommodation units are also being installed at a cost of between £0.5 and £1.0 million per new bed oVshore, which is very expensive. The result of some of our recent discoveries in the mature Alwyn Area, such as the Jura or Islay fields, demonstrates the long term role of production hubs for both our own production and that of third parties using our operated infrastructure. Total E&P is committed to the long term maintenance of our two existing hubs, Alwyn in the Northern North Sea and the HPHT Elgin/Franklin complex in the Central North Sea. Hopefully, the development of the equally vital third hub around the West of Shetland Laggan-Tormore gas fields will also play a role for capturing production of future discoveries or produced by third parties. Every eVort should be made by companies and authorities to ensure the infrastructure remains operational and companies are not forced into unnecessary closure by financial institutions at a time when failure to carry out essential work could have serious medium and long term consequences for maximising recovery from the UKCS.

Is the right policy framework in place to manage the decommissioning of that infrastructure as resources are depleted? 7. Total E&P UK has gained the experience of decommissioning through the work carried out on the Frigg Field in Norway and in the UK. This whole project of decommissioning of a major field with large fixed structures has proven very complex, diYcult and expensive. Total EP UK’s share of this one project will be finally around £1.4 billion. It has forced operator and contractor companies to seriously reassess how such work could and should be done in the future. One observation is that policy frameworks in the UK require significant emphasis be placed on safety and environmental considerations. Total E&P fully endorses this approach and acknowledges the lessons learned from the Frigg decommissioning project. New entrants, as they are commonly called, and many more established but smaller operator and or non- operating companies, are facing a serious problem of ensuring they are able to discharge future decommissioning liabilities. Operators are conscious of the liabilities they face with regard to decommissioning and naturally seek legal comfort that joint venture partners will be equally able to fulfil their obligations in the future. Government also requires comfort in the form of financial instruments to protect the tax payer. These two requirements, under current economic circumstances are in fact adding unreasonable pressure on already stretched financial circumstances and may actually bring about the failure of a company that the instruments are intended to protect against. Energy & Climate Change Committee: Evidence Ev 137

Total E&P urges government to work swiftly with industry and the financial institutions to find a solution to this problem that will reduce rather than increase the risk of companies failing to achieve the level of cover required. In that respect several proposals have been made by Oil and Gas UK which are clearly supported by Total E&P UK. March 2009

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