Listen: A North Sea tale: Diving into UK oil and the Dated Brent benchmark

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Joel Hanley: Hello and welcome to the Platts Oil Markets Podcast from S&P Global Commodity Insights. I'm Joel Hanley. On this episode of the podcast, we're taking a look at the North Sea, home of vital oil benchmarks, but how much oil is actually left?

As small bodies of water go, the North Sea punches well above its weight in terms of influence. While it has some way to challenge the likes of the Red Sea or the Suez Canal, this small sea tucked between Northwest Europe, the UK and Scandinavia has a long history as the base of several imperial fleets in the old days and more pertinently for this podcast, as the home of Brent crude oil. Now, growing in the 1970s and '80s to be a major supplier of crude oil around the world, it's fair to say that the North Sea is now probably more famous as a benchmark location than a contract name than it is as a powerhouse of crude oil supply. Production in hundreds of fields here is largely shared between the UK and Norway and while there could still be some big elephant fields out there somewhere, it has generally become a high-cost, low-return environment that has made several oil producers think twice about investing any more in it.

Now, this has been borne out by some recent figures and with me to discuss that and what it all means for the physical output and also the North Sea as a benchmark region are Nick Coleman from the Platts Upstream news team and Sam Angell, one of our price reporters who assesses that crucial dated Brent Benchmark and other North Sea crude oil markets. So Nick, welcome to the podcast, thank you for coming along. We saw UK oil production statistics for 2023 published at the back end of February this year, showing a real acceleration of decline with a drop of output of about 12% to barely 700,000 barrels a day. And that's pretty much a North Sea Cargo. That's an Aframax of oil loading out of the North Sea, at least on the UK side. Is this set to continue?

Nick Coleman: I think it is Joel. It is a different story for Norway and the UK. Norway, actually, the production is holding up really well, but for the UK, production is down actually 36% since 2019. And the industry, when you speak to executives, they are very pessimistic about investing more in UK oil and gas resources. Partly it's a question of tax and the politics. We've had this energy profits levy, which was introduced at the height of the pandemic in 2022. There was a lot of public outrage about high energy prices, and so the headline tax rate at the moment is 75% and the Labour party, should they win the coming election is threatening to actually increase that tax rate even higher.

Joel Hanley: Yeah, that is not an environment in which to do business for many people one would think. I appreciate that there is the Green Agenda and Labour and other parties, of course, are making great moves to say that the Green Agenda must be continued, but when it comes down to energy security, that's going to be quite hard to make those two things meet, right?

Nick Coleman: Yeah, I mean it's not all about tax. You have to acknowledge the geology. The reality is that this industry has been producing since the 1970s. We haven't really had any big projects, oil projects come on stream for quite a long time. There was a bit of an uptick in the last decade. You had BP investing west of Shetland in the Clair and Schiehallion fields, which gave a decent bump to production levels, but really it's been adding incremental bits and pieces here and there. So you have got some potential new projects coming on stream in the next few years. The big one that's been in the news is Rosebank, Ecuador. The Norwegian state oil company took an investment decision on Rosebank last year, and that is due on stream in 2026 or 2027. I think the peak production for Rosebank is supposed to be about 90,000 barrels a day, so that'll give a boost.

And then there are some other smaller projects. BP has got something called Murlach, which is going to feed into the Forties crude stream. So you might actually have a few things coming on in the next few years that might slow down that decline rate. But I have to say, the mood in the industry and the willingness to just eke out production to drill more wells is pretty diminished.

Joel Hanley: Well, it's good to know that I'm not the only thing that started up in the '70s that has been slowly declining since. I mean the Forties is a great example, right? So the enormous Buzzard field came on stream in the mid-noughties and was plugged into Forties as well. And that's all production of the Forties blend, which is a blend of several fields, about 50 different oil fields tied into that one saw it go up to over a cargo a day, that was the 34 cargoes of 600,000 barrels a day, and nowadays we're seeing something like eight to 12 cargoes a month. So that's been a very quickly-diminishing, quickly-depleting oil field, and that just gives just a snapshot of the picture we're up against.

And you mentioned Rosebank because there's a great big, I don't know, a great big hope is probably overdoing it. 70,000 barrels a day, 90,000 barrels a day, something like that. That's only a cargo every week or so. So it's not an enormous amount of oil when it comes down to it. And indeed, as you say, I think the Norwegian side with Johan Sverdrup and Johan Castberg coming on stream at some point, those are much bigger fields, right?

Nick Coleman: Yeah, so I mean actually Forties still loads relatively decent rates for the North Sea. You've got still some quite big fields contributing to that, including gas condensate fields like Elgin-Franklin, but in some ways Forties is still a bit more of a success than some of the others. If you look up in the Shetland Islands where you've still got some vestiges of Brent blend, crude oil loading, I think our data probably shows the loadings are down to some months recently averaged less than 50,000 barrels a day. And we've had announcements even in the last few weeks of further likely reductions in Brent's production companies like TAQA, which is a UAE company that operates the Cormorant field. It's just one of many fields that feed into Brent. They've said they're going to shut down production this year.

When you think about it, it's just not economical to produce even a modest amount of oil from an absolutely massive steel structure that was built in the 1970s and it requires a lot of maintenance. I'm generalizing here, and that's just a general observation rather than there's something about TAQA, but at some point these facilities become uneconomical.

Joel Hanley: Absolutely. And dirtier and dirtier in many people's eyes. And we saw this coming, right? The trading community indeed, Platts as a price reporting agency, saw this coming in the early noughties when we introduced Forties and Oseberg into our benchmark dated Brent assessment as alternative grades because there was a very real risk all those years ago, and in fact, indeed we saw it in the late '90s early 2000s. There are new stories out there of people taking very large plays on the paper side or on the forward side, essentially cornering the market potentially with so little Brent itself, we had to introduce other grades. So as time has gone on, we've acted to introduce even more grades. Sam, you're one of the lead guys assessing this stuff. It's more than just Brent itself, isn't it? I mean, the dated Brent as a complex has evolved hugely since 2002.

Sam Angell: Yeah, absolutely. And I think you can perhaps argue that the idea of Brent having to evolve as a benchmark as time has gone on isn't particularly new. I mean, the original Brent field was obviously blended with Ninian way back in the '90s in response to declining volumes as well, right? So there has been this, as you mentioned, this move as time has gone on to shore up the benchmark with new grades. That's obviously in 2002 with Forties and Oseberg, and most recently in May, 2023 with WTI Midland, which has been the largest single injection of liquidity into dated Brent ever. And we can talk a little bit about that. But yeah, I think it's certainly worth noting that Brent has evolved in response to this natural kind of decline in native North Sea fields and continues to do so. Certainly.

Joel Hanley: So in our assessment of dated Brent, we have, as you mentioned, Brent Forties, Oseberg, Ekofisk, Troll, and now WTI Midland, these alternative grades that could all, they sort of interplay to help define the price at any moment. Brent itself is quite rare. As Nick said, it's 50,000 barrels a day or something like that. We're only seeing a couple of cargos a month. It's a bit like Dubai in that respect, which is very, again, Dubai that benchmark grade, a major name, a major brand name when it comes to benchmarking, but very often it's the other grades that really define the price.

Sam Angell: Yeah, definitely. I mean, Brent is still playing a role even though we are seeing perhaps one or two cargos a month. It's still defining dated as the most competitive grade kind of every now and then, but it's really become a mixture of the six grades in the basket. Obviously WTI Midland has played a role since its introduction in May of 2023, but all of the grades really are trading quite liquidly in the market on closed process that we have and defining data as the most competitive grade in the basket. So it is, as you say, truly a basket of grades defining Brent now as the benchmark has grown and new grades have been added over time, it's become much more than just Brent blend itself.

Joel Hanley: No, indeed. And you mentioned Midland, and we've just come off International Energy Week at the back end of February, and much of the talk there was how, I don't mean to blow our own trumpets, but what a great success Midland coming into Brent has been. Essentially it's doubled the amount of volume in the benchmark at least. Are you seeing it having an outsized influence in a sort a small scale North Sea area? There's this US crude oil coming over from the Gulf and having an influence. Did the figures bear out some of the concern that it was going to flood the market in some way?

Sam Angell: Yeah, I don't think so. I mean, WTI Midland itself overall is clearly a very significant stream in Europe, about two million barrels per day. But of course the way the methodology was set up for Midland's inclusion is such that not all of that oil is going to be tradable in our process. It has to meet certain methodological parameters and it has to meet our global WTI Midland specs. So it is not a question of all of the Midland arriving in Europe is somehow kind of flooding our process and making the other grades in the dated Brent basket irrelevant. There are kind of limits on the volume of Midland that can be offered or traded in Brent. As for its impact so far, I mean the role of Midland in defining dated has ebbed and flowed depending on the cycle. In some cycles it's played a particularly large role. And in others, such as early this year, the January, February cycles, it's played quite a minor role. In January, it defined dated Brent between 25 to 30% of the time across all of the assessment days.

And that's really been just a mirror of the fundamentals really. Some months Midland has been very competitive and some months Midland hasn't. And that really just goes back to the reason why Midland as a grade was so attractive for inclusion in the first place in that it's an existing flow. Midland was already coming into Europe, it was already baked into the Northwest European crude fundamentals as that made it a natural fit and has helped it really just adjust quite seamlessly into the dated Brent basket in a way perhaps other crudes wouldn't have.

Joel Hanley: That's great, Sam. Thank you. And you've given me a really nice moment there to advertise something that I published on LinkedIn, not a site I really enjoy publishing on, but I did, and you can find this under my account of Joel Hanley, you can see the infographic that you and the team have put together, which we're now publishing every month for Platts subscribers, which digs a bit deeper into the numbers behind the benchmark and what's been defined as a benchmark, where the liquidity is, how many cash BFOE partials are published and all those kinds of things. Really interesting monthly infographic that we're going to update at the end of every month that really reveals even more transparency on dated Brent, so thanks for giving me the opportunity. Indeed, thanks for helping create that because the feedback I'm getting on that is phenomenal. So it's a really useful thing to have on such a major benchmark.

One thing that was mentioned to me a couple of times on IE week was we had this question publicly quite lot at our forums is what's the next grade coming in? When will another grade be needed? And to my mind, there won't be another grade needed for a while. We've only just installed this one. Let's just see how it goes. And I say we think it's going very well so far, but with the further dwindling in the North Sea, might other grades need to come in, might they even be North Sea grades themselves? So Nick, let's just come back to you on the physical properties of the North Sea, the geology there. Do you think that with all that's going on with the potential change of government and the fairly combative environment for investment in the North Sea, do you think that the North Sea, in terms of oil and gas, do you think its days are unnumbered?

Nick Coleman: I think you can get too hung up on the kind of tax row that is going on between the industry and the government. There is activity out there. You can get big tax reliefs if you happen to be ready now. You're not going to actually be paying that headline rate of tax. So there are companies out there. Think about companies that really did earn a lot of money from the gas price boom, like Equinor or Serica Energy is a small one, which basically was a massive gas producer and has done very well in the last few years, and it's now pivoting more into oil. It's promising to drill more in the UK. And then as you mentioned earlier, at the top of the podcast actually, in Norway you've got new grades coming up. There's this Johan Castberg field, which is a departure really due on stream at the end of this year in the Barents Sea.

But we should bear in mind that we can see a kind of diversification going on here. So Castberg is not going to be quite a typical light sweet crude. It's another one which is a bit more sort of a medium grade. The API number I just checked is 31, so it's not a very heavy oil, but it is not that kind of classic North Sea light sweet crude. And out there. If you look around, there are all sorts of schemes for different types of oil projects. Maybe operators promising to make their production as green as possible by adding wind turbines to power the facilities. There's lots of heavy oil projects kind of waiting in the wings that might get the go ahead. We'll just have to see. But things are not going to stay the same, that's for sure.

Joel Hanley: Oh, they really do in these markets, than indeed others. Nick, Sam, thank you so much for taking a bit of a dive into the North Sea. Really appreciate your time today. Now subscribers can find that monthly dated Brent update I mentioned in the infographics area of Platts Connect or indeed on my LinkedIn page as I mentioned. I should also mention that registration is still open for CERAWeek, which is taking place in Houston from March the 18th. This episode of the Oil Markets Podcast was produced by Felix Fernandez in London.