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2026.10.08 | TB | Energy | Serica Energy: North Sea Activity

原标题：Serica Energy – North Sea Activity & Organisational Capabilities

#energy

Third Bridge · 2026-10-08

Analyst-led • 29 Sep 2026

Companies: SQZ GB, BP. GB

Mark Richardson (MR) Project Lead at Highview

Olly Anibaba (OA) — Third Bridge Sector Analyst

Agenda

Key Insights

Introduction

OA [00:00:03]: Welcome to Third Bridge's Interview entitled Serica Energy – North Sea Activity & Organisational Capabilities. I am Olly Anibaba, and I'll be moderating today's Interview with Mark Richardson, former VP, Projects at Neptune Energy Group Ltd.

Before we start today's Interview, please state I agree or I disagree to the following statement: You understand the definition of material non-public information and agree not to disclose any such information, or any other information which is confidential, during this Interview.

MR [00:00:39]: I agree.

OA [00:00:42]: Could you start with an introduction to your background and experience as it relates to our Interview today?

MR [00:00:49]: Serica Energy is an interesting young independent going through the early growth stages. I've followed a very similar path with both Apache North Sea and Neptune in the same operating environment. It's interesting to see the playbook they're using that I have seen throughout my career. I joined the oil and gas business after leaving the military, started working with various companies, mainly diving in the subsea companies and ended up in BP. I was lucky enough to join the Apache acquisition, taking over the Forties field, later the Beryl fields, where I was managing and running projects, a fairly large and extensive range of projects as part of the international Apache organisation. Then was involved in the start-up of Neptune Energy, which again took on a series of North Sea assets, including Cygnus, which is part of potentially a new portfolio of Serica as of the 1 October of this year. Undertaking those various projects, I've been lucky enough to meet many of the… Work with or meet or be engaged with a lot of the Serica Energy executives who are following that same playbook. It's good to see that the things that we've done in the past or the things I've been engaged with are being repeated and successfully repeated in the present environment.

Questions

00:02:17] Regarding Serica Energy's portfolio, could you detail the primary producing assets located on the UKCS [United Kingdom Continental Shelf] and the company's role as an operator or non-operator?

MR [00:02:36]: Certainly, I think the key element is the Bruce Hub because they're the operator there and a 98% operator, which is absolutely key in terms of free and fast-moving development and asset management. That directly replicates to where Apache was in the Forties field. What made Apache successful in the Forties and was also making Serica successful in the Bruce Hub is that 98% ownership, which means they don't have the partner drag that you suffer in a lot of assets. Therefore, they can move fast and they can make decisions without having to go back for budgetary changes or approvals from other operators. That hub of Bruce, Keith and Rhum, that is a good, strong producing asset, which provides a significant amount of gas for the UKCS. I think that control of production, maintenance, capital allocation, all those things really play into a real cornerstone of a gas-producing asset and maintain that balance of oil and gas across their portfolio. Interesting enough and as a sidebar really, I actually helped install the Keith subsea tieback quite a few years ago, but that was a long time ago, but Bruce is a strong asset, and there's plenty of upside opportunity around it. That's their key asset.

Now they've also got the Triton area, which is non-operated, Dana Petroleum area. That's the Triton FPSO, which has its issues. It's almost 20 or so years old, but it's a large number of fields, quite a diverse set of fields around it and a fairly strong production when the Triton is operating on plan and has got good uptime. That has potential, again, fairly evenly weighted oil and gas for heavy gas condensate coming out of that area. We've got Columbus and Orlando. Columbus gas condensate, fairly small tieback into existing infrastructure. Then you have Orlando, which was operated by Serica, is now moving into decommissioning. Now they've also very successfully got a new hub and actually diversifying away from just having that pure Bruce Hub is a great thing to do and also a different geographical area by the Nu Class assets of the West of Shetland. This used to be TotalEnergies plant and assets. That's meaningful production growth, but also from a separate area, that diversification of geography and asset means that there's less volatility in their production if they have single point failures. That's their main present asset base. However, as of the 1 October, if the deal goes through, which I'm sure it will, they're expanding with the acquisition of Spirit Energy.

The jewel in the crown is Cygnus. I was the operator of Cygnus under Neptune Energy. It's a great asset, great opportunities, low OPEX. I think that's that and the other southern North Sea assets, again, heavily weighted towards gas and produced into the UK gas market, the likes of Clipper South and the Greater Markham area where they'll be operated, really gives a stronger balance across their portfolio and actually beds them in and will give less volatility as their production increases. The assets, Bruce operated, Triton non-operated, Cygnus non-operated and then a few smaller operated assets in the southern sector, which is great because it actually spreads their internal operating costs across a larger number of assets with probably not too many additional headcount in order to support those additional assets. That really covers their portfolio in the UKCS, but one important but is they started to expand internationally. I think that's their first foray into the international market. I wouldn't be surprised if you saw further acquisitions. My guess would be the likes of Egypt and Indonesia would be the places they're most likely to go. Having known some of the people in the positions in the M&A and the acquisitions market, that's where they've looked before, and that's where they'll probably look again.

00:07:24] How would you evaluate the underlying decline rate YoY of Serica's operated assets? What does it mean for additional operating cost spikes facing the company in the coming quarters?

MR [00:07:35]: The operating costs across the fields vary quite significantly depending on where you are. West of Shetland would be USD 15-25, that sort of level. Cygnus is down around USD 11 or USD 12 right now, but would be USD 10-20. Every single asset has its own operating costs. Every single asset, depending on what it's looking to undertake over that year, will change. It's difficult, but on average across their portfolio, USD 20 a barrel would not be unexpected, and that's what they're forecasting and that's what they've been producing over the last six or so months. The way I see it, that's going to continue, but what's most important for Serica is the fact that they're growing production, and therefore, their operating costs should remain stable even if they've got a slight decline in production because they will have until '27 where they start to really ramp up their drilling campaigns and start to really reinject into the decline rates around the Bruce area. USD 20 a barrel is pretty stable for them unless they have any major upsets, then I think that is probably the way forward, but they're spread over more barrels, I think that's perfectly achievable over the next year or two.

00:09:07] Where do you see opportunities for Serica to reduce direct field OPEX or transportation costs relating to key producing assets in its portfolio? How significant could the cost savings be?

MR [00:09:19]: It's actually because they're late-life field assets, it's actually really, really difficult to reduce operating costs. A lot of the big saving opportunities have probably been removed and already undertaken by previous owners. However, what we did in Forties and both Forties and Neptune with late-life development assets is try and keep that base production stable and where possible, use infill drilling to not only maintain that stability, but increase production and that, therefore, reducing OPEX cost per barrel, but there are some things that they could do, I should think, around the Bruce Hub. The Bruce Hub, perhaps digital conditioning monitoring, that has become quite a major event across the North Sea and it becomes more and more to the fore as AI and robotics and the level of electrification, digitisation of data becomes more widely available. The biggest thing that always hits your OPEX is unplanned shutdowns. Ensuring that their maintenance integrity activity is absolutely on plan and any planned work shutdowns or turnarounds are kept to the absolute date and only the optimised requirement of upgrades and maintenance work is undertaken.

They could do some workforce optimisation work as they expand their portfolio. Perhaps reducing the headcount per barrel is a way to do it. These are small savings, maybe USD 1-2 a barrel across the piece. Triton is much more difficult. They're a non-operated partner. I'm sure they're working closely with Dana to try and improve the FPSO reliability. Hopefully, the big turnaround they did with two-month outage that they've managed to improve that. The latest figures show that the uptime has significantly improved, but the big thing about any offshore asset, the number… The two big hits are always compressor reliability and power generation. If they can get those up and running and reliable, then you could see a potential saving through the additional production through that reliability. Reducing OPEX by the additional production through go through Triton. There's perhaps areas of renegotiation on tariffs as they're not major pipeline infrastructure holders.

That's probably worth a look and trying to reduce that OPEX per barrel, but overall, it's about uptime of the production assets and increasing through infill drilling or subsea tiebacks, the level of production being throughput whilst maintaining the minimum core headcount inside your organisation to ensure that you don't incrementally add OPEX per barrel by your headcount. I think maintaining that, reducing it is hard unless you massively increase production.

00:12:15] Given Serica's size as an independent player, is there an ideal threshold in terms of headcount per barrel that the company should be aiming for?

MR [00:12:25]: You have to look at the individual assets to understand what sort of organisational structure that you have because likes of Bruce where it's HPHT, you do need some specific high-quality intelligent capable individuals that fully understand both the reservoir production, but also drilling operations. That headcount will vary, but across the other assets, the late-life gas assets in support of Triton, the new areas where they've become operators and the likes of taking over some operatorships and non-operated in those other gas assets. You can maintain that same mindset of having the core disciplines within the organisation with a few specialists and then outsourcing as much as possible outside the organisation. Probably the throughput or the requirement to maintain anything but those core disciplines within the organisation. The important facets are always going to be the reservoir and subsurface evaluation and engineering, the detailed asset management, production optimisation and integrity management. You get those right, unless you're doing projects like subsea tiebacks, then everything else and then you add a projects group to that organisation.

Otherwise, the likes of marine operations, construction, intervention services, utilisation of these big players out there, Halliburtons, etc, of the world, that is the most optimum organisation. We did exactly the same in Forties. When we took over Forties as Apache, we left the mothership of BP behind. Then we honed down on a core set of individuals and then outsourced or pulled in the competent resources as and when required. I think that model preserves the flexibility that they require with the in-house expertise, so you're an informed buyer for these services. The HPHT, the DaaS HPHT where I did the Seagull, it's a very different mindset. It's a very different approach. It requires some very specialist skills. Maintaining that around their Bruce Hub is absolutely important because of the safety and integrity of those wells, but everything else is pretty much common asset management. The rest of the stuff you can really farm out to some of these big specialist contractors where you can alliance with them or partner with them, give them your portfolio to manage so that they can optimise their integration with you as an organisation.

00:15:12] For Serica's Triton FPSO [floating production storage and offloading vessel], what operational oversight measures can be implemented on floating production facilities to ensure high uptime and avoid unscheduled downtime?

MR [00:15:24]: Asset oversight and being a good partner is always incredibly difficult because as a partner, you have access to not all of the data, but some of it… It depends on the working relationship they have with Dana. The closer they are, the more that they support them and they realise this is a support and not investigation. They're two smaller independents, they could probably work well together, but that asset oversight, production planning, reliability engineering, keeping that in-house and having some expertise in the Serica organisation that can assist, support and challenge Dana is really important, but Dana, like Serica, will be heavily contractor dependent in terms of support in the organisation for the marine operations and vessel management crew, all that sort of stuff. There's a lot of things that they won't be doing in-house. An optimal model of oversight is more about how do we build that partnership relationship rather than some of the relationships I've been in with partners where There's more conflict than there is cooperation and collaboration. Working on that relationship will actually see much bigger benefits than a different model where you're challenging a one-to-one marketing the people in Triton.

00:16:48] What trajectory do you anticipate for Serica's unit OPEX regarding uptime and operational maintenance for the Bruce platforms and the Triton FPSO over the coming 12 months?

MR [00:16:57]: It should remain reasonably stable. Hopefully, that two-month outage for Triton should help enormously. The next 12 month… The Bruce, it's not going to start until Q3. You won't get the OPEX savings then, but in Q3 of '27, you will start to see a small drop in OPEX around the Bruce field because they'll have an HPHT rig out there, and they'll be able to share vessel savings, share helicopters and the like as part of the organisation, but in the next 12 months, it should remain reasonably flat as long as there are no major upsets, both at the Triton or Bruce. I don't see a huge change in that cost to the organisation because the stability of performance and preparing for the rig hopefully arriving in Q3 of '27, should mean that they are ready and clear and clean to allow the drillers to come on board and then share assets. You'll actually see a drop-off in OPEX from the rig being on station, and I think they're looking at a 400-day contract. It's going to be around for some time around their assets. Then ultimately, it gives you an OPEX saving because you share the operating costs of logistics, but then as the production comes through, you'll see an OPEX cost per barrel in the Bruce go down because you've actually got more throughput.

00:18:25] Serica had a net cash position of USD 26m as of 30 June 2026. What is your assessment of the company's ability to translate production into strong operating cash flows over the coming 12 months? How could this impact free cash flow generation?

MR [00:18:41]: There's always two elements to your ultimate cash flow. One is commodity price, of course, which isn't your control, but it's going very much in the favour of Serica, both the oil price with Brent crude hovering between USD 90-100 a barrel. A lot of their estimates, a lot of their forward-looking statements will be based on USD 78 a barrel as an optimistic upside. They've instantly got 30% over… A significant percentage over that because of the high Brent crude prices at the moment. Gas prices, the same. We see nothing but spikes in gas prices coming over the next 6-12 months, maybe longer into the future. Again, their forward-looking forecast will not bake that in by any means. Therefore, I see that the cash flow will significantly increase. The other part of the equation, of course, is the optimisation and uptime of their production. Minimising the unplanned outages, minimising the turnarounds or shutdowns undertaken across the organisation, maintaining integrity and maintenance. All of those. Protecting the base production and then wherever possible, bringing in small additional enhancements, well interventions are like that you can bring on as early as possible.

Although they may be planning a drilling campaign, they'll also be planning small well interventions, just workovers, just to maximise the production right now while the gas price and oil price are high. These are classic things to do in an operating environment where you got the oil prices are high. If you can, in any way, tweak up production, you're going to make hay while the sun shines and get after these things. In terms of cash flow, I can only see it increasing as long as there's no major upset in one of their hubs, be that West of Shetland, Triton or in the Bruce Hub.

00:20:37] Which producing assets in Serica's portfolio would you expect to be the most profitable from a cash break-even point over the next 12-18 months?

MR [00:20:46]: I would say Cygnus is probably the best. It's probably got the lowest OPEX, the highest uptime and it's heavily gas weighted. I would see that as being the best asset. I appreciate it's not in their portfolio just yet, but when it comes into the portfolio, I think that will become their jewel in the crown in terms of production costs, overall cash flow generation from that particular asset. Some of those smaller assets as well. The great thing about gas, generally, once it's up and running and flowing as long as you don't have a shutdown, tends to be very high productivity rates, very high uptimes. The Bruce is the next most reliable in terms of cash coming through the door. Then Triton had a good production run over the recent past at 95% uptime. If that remains online, that could actually bring in a huge amount of cash. There's a lot of upside and opportunity with the high commodity prices and if they maintain their… What has been quite a difficult period in terms of maintenance and uptime and productivity, but if it all goes in their favour, I think there could be significant cash flow out turns, which will, of course, return to dividends or additional M&A opportunities, probably international ones.

That's where they've come. They've gone from cash negative to cash positive in the past few months. I think that trajectory can only continue. I don't see commodity prices coming down from there, floating around the USD 90-100 a barrel until there's some resolution to the oil side to the Iran crisis. Then on the gas side, that's just going to continue as long as Ukraine is… The Russian gas assets are out. That's putting LNG up as well. There's upside on both sides. The downside of that, of course, is trying to do any M&A deals, trying to get any asset purchases in the UKCS or overseas, there's going to be a price hike on all those assets. They were lucky. They got in at the right time and then rose on the tide of higher prices. Their timing has been impeccable in terms of commodity price, but I think the next 12-18 months, I see nothing but strong cash flows and therefore, strong dividend payments.

00:23:16] In a strong, sustained higher-price commodity environment, should Serica look to dividend payments, preserve cash or explore M&A acquisition opportunities?

MR [00:23:32]: They've always been a dividend-based company. They'll maintain their dividends to their shareholders. It's interesting, if you're looking to move from the AIM onto the FTSE. That step to have that cash availability to show the profitability they've had over the last 18 months will make them a great contender to move into the FTSE and assuming that they're accepted in, that will bring a groundswell of new shareholders into their markets once they move into the FTSE. It's very, very good timing, high commodity price, high cash flow, a good profitability out in front of them. They're going to be moving from 40,000-50,000 barrels per day to 65,000 with the Cygnus acquisition. Acquisitions in the UKCS, there's… The regulatory burden is always there. The upside opportunities are diminished because you can't really do new fields, new development, new licences right now. There's not the opportunity set for growth, but I think you'll see them with that cash paying their dividends, but also looking to acquire overseas. My best guess would be Egypt and Indonesia would be the two places.

Now they started as an exploration company, then turns into an M&A company, and they've been immensely successful in the UKCS on that basis. They're going to go overseas, do M&A, but with exploration opportunities within the M&A. Cash-producing assets that have a footprint of exploration opportunities, but firstly, they'll be paying their dividend. That will be their primary concern is to keep the shareholders that have supported them throughout on board. The opportunities in the UKCS, fairly limited. They've got a big enough of a footprint and portfolio in the UKCS, they're going to go overseas. Buying cash-producing assets always gets good support from the banks, but with a large exploration upside in the portfolio of any asset they buy.

00:25:37] After the Spirit Energy transaction completes on 1 October 2026, Serica is expected to produce 65,000 barrels per day by year-end 2026. Where would that rank the company compared to other oil and gas producers in the UKCS?

MR [00:25:55]: It certainly puts much further up the overall list. They'll probably be just behind… They're probably in the top 5-10 producers in the UKCS. They'll be just behind Harbour Energy, among the largest UK-listed independent certainly and comparable to virtually any other private equity-backed North Sea operator. Top 5-10 producers in the UKCS. It's a great place to be. You're nimble enough, fast-moving enough, small enough to get after the big opportunities without the massive issues of being a major with all the competing priorities, but they've got enough capacity, wherewithal and depth now and breadth in terms of their asset base, in terms of their cash flow opportunities to bring in the support of bondholders and further private equity. The move to the FTSE would just open up a whole new lot of investors. I can see their ranking moving up through the UKCS, but also their credibility as an investment vehicle will move up. If people want to get into oil and gas, a great thing to move into would be Serica.

00:27:17] What is your view on the balance between natural gas and crude oil in Serica Energy’s production mix? Do you expect output over the next 12-24 months to remain evenly weighted, or will it tilt more heavily towards one specific commodity?

MR [00:27:31]: Historically, they've always been a more gas-centred asset portfolio, but with the acquisitions, I think you're still going to maintain that 50/50 balance, 40/60 balance. That weighted portfolio is something we always try to achieve in Neptune across our whole portfolio. It gives you, again, more diversification. Gas and oil price used to follow each other. That's no longer the case. They are totally different markets. By having the ups and downs of two separate markets, it just levels out, gives you stability in terms of your cash flow, in terms of your production, your ability to look like a stable company is so important to the market. Yes, probably a slight tilt towards oil over the next few months with Triton, but some of the acquired assets are quite gas… Sorry, quite liquid-rich gas. Slightly more on the liquids side, not pure oil, but liquid side, but over time, I think it's just going to maintain around that 50/50 balance. It's not going to move too far away from that, and it's something you want to maintain in terms of a balanced portfolio of liquids to gas.

00:28:47] Which producing assets in Serica's portfolio might be prioritised for infill drilling campaigns over the coming years? What is your reasoning?

MR [00:29:04]: Undoubtedly, the Bruce, I harp back to this fact that you haven't got partner drag. 98% ownership and operatorship of the Bruce means that they can go where they want to go. Very often, you'll pull together a drilling campaign based on subsurface work and data… It doesn't just stop. As you start to drill through that campaign, you update and improve your models, your understanding of the reservoir. There's all sorts of things that happen. Very often, you would want to chop and change between prioritisation of certain wells, where and how you drill those wells and just operational decisions as you're drilling through the reservoirs, you might discover things that weren't expected. Now if you have partners on board, everything else has stopped, you have to go back to partners. If you want to make a major change to your programmes, you have to go back and get them on board and prove to them and they challenge it hard because it's their pennies. No disrespect to people who are non-op partners, but the people they send to non-op are not normally good enough to work in the operating business. That's a bit of a generalisation, but because of that, they like to spend their time just challenging things and being difficult.

If they're in Bruce and they want to undertake a major drilling campaign in Q3 of '27, they will be able to move quickly, make, select the right wells, have a portfolio and actually move on the hoof. It's great. They can operate it. They've got their existing infrastructure. It's a low development cost. There's lots of untapped near-field reservoirs around Bruce. As always with BP and the other majors, they haven't explored. It hasn't had the prioritisation. It hasn't had the A team, and they've got highly focused individuals who are looking for the best opportunities, knowing that they've got the capital, and they're number one in their company. It's a totally different mindset inside the organisation to the way BP and others would have run the asset previously. That infill drilling and because it's infill drilling, you don't have all the regulatory burdens of a new asset. The second place is probably the Triton area, maybe the Bittern. There's good tieback opportunities, but the regulation around that is… There's a massive risk around doing anything on new licences, new drilling, new opportunities.

The supply chain market is probably not as strong as it was 5-10 years ago when you knew that there were other operating assets, people out there laying pipelines or getting umbilicals built or drilling operations where you could slip a couple of wells programme into another drill rig to seize an opportunity. The wells out there, Bruce will be my number one place to aim for.

OA [00:31:55]: How many new wells would need to be drilled per annum at the Bruce Hub, the Triton area including the Bittern asset to maintain healthy production levels? What would you consider to be healthy production levels?

MR [00:32:06]: The decline rates will vary enormously between reservoirs, and they can fall off a cliff or they can just decline slowly and decline rate generally eases over time, but a decline rate of around 5-10% around the Bruce field, I think 1-2 wells will maintain that base, anything more than that, and you'll look at production increase. It's probably about the same for the Triton area is 1-2 wells per year. It's not a huge campaign. HPHT wells take longer, cost more, technically complex, but one or two wells in the Bruce Hub, which will take a fair amount of time with their new wells and not just sidetracks or workovers would be sufficient to maintain the Bruce Hub area. Triton, again, 1-2 wells. Again, it depends how successful are what they have in their portfolio, the detail of the reservoir engineering, are they doing anything different to what's previously been looked at and sustained. Then the rest of the portfolio, 2-4 wells. If you look at that because HPHT wells probably take twice as long as your standard well, their 400-day campaign, I think, would start in Bruce, probably do two wells and depending on the six, maybe one-third. Triton, 1-2 wells.

Then the other portfolio, if there is a specifically good opportunity, they'll go after those as well, but it will be a very high-end rig and may not be suited to the southern sector. You'd want a jack-up in the southern sector and you probably want a floater up to do these Bruce area wells, but there are some HPHT jack-ups, but that would be a waste in terms of day rate to go all the way down south because of the mobile cost and the day rates to go and do that further south. It's probably the Bruce Hub followed by the Triton area and depending on success out of those wells as to how many they actually drill.

00:34:01] How would you assess rig availability over the next 12 months in the North Sea? What impact could it have on day rate charges?

MR [00:34:06]: One of the big problems about the North Sea is, there's plenty of activity in Norway, but a Norway-qualified rig is going to be very expensive. The actual employment rates of rigs in the UKCS has been woeful. In fact, they will drill less wells than probably the first few years of production in the whole of the UKCS. There's not the availability or opportunity. The rates you'll be charged will be Norway rates because you're going to try and drag away a rig from the Norwegian market to bring it across. It's going to be expensive, certainly for an HPHT because that's at the upper end of the market in terms of capability. It's not going to be a cheap drilling campaign by any means, and that's why the economics have to be really stellar for some of these wells, and therefore, high production rates, which helps enormously if you can get that additional production through the organisation. As to the actual rate, it's so rig-specific and sector-specific that it's difficult to know where those rig rates are going to go, but they're openly published, they're openly available. You can see the utilisation. As utilisation gets into the high 80s, early 90s, then you'll get the top rig rates will be being charged. I will not look to what those most recent rig rates are, but they will be high. You can't pick up a cheap rig any more.

OA [00:35:30]: Is it a case of rig contractors stacking rigs or prioritising other regions over the UK North Sea?

MR [00:35:39]: It's prioritised in other regions than the UKCS. When you've got a ban on new operational drilling, you've got decommissioning, but that market is taken up by the companies like Well-Safe and others. It's a good fill-in, but it's not meat for the main drilling contractors. Most of them are moving overseas. Norway has been a big drag on rigs because during the COVID years when they removed the… When they upgraded the tax regime to make it really efficient to go after new tiebacks and new opportunities. All of those opportunities are now at the point where they're starting to drill them up and do the projects. It's pulling a lot of rigs normally be in the UKCS into that market. In the Middle East, they've been pulling in lots of rigs, some of the jack-ups and the like have been going down to the Middle East, where there's still significantly high activity. There's a lack of rigs, bringing rigs out of mothball or that are stacked is a massively expensive thing to undertake. Unless the economics are stellar, in most cases, rig operators will probably just lay them to rest rather than actually bring them out, but there has to be stellar rates and a long-term contract. Of course, they always stack the rigs, which are least efficient, given the least day rate and least technologically advanced.

00:37:09] Could you highlight subsea tieback opportunities available to Serica across the UKCS? How do these tieback projects optimise subsea infrastructure and O&G [oil and gas] recovery?

MR [00:37:20]: Once again, I'll go for the Bruce, not just because they're 98% operator, but you've actually got quite a few… A big opportunity set and the BP never really exploited. There's quite a few satellite accumulations around Bruce. I remember when I was installing Keith, and this must have been 25-30 years ago. There were always lots of tieback opportunities around there and just never got the prioritisation among BP because they wouldn't put their best people on it. They wouldn't use drill rig time on it. They would prioritise the big opportunities, but these small accumulations are the accumulation that can not only maintain base production and defy the decline rate, but it can actually bring upside to a company like Serica. The satellite accumulations around Bruce, I think, will be the primary one I'd go for. The Kittiwake redevelopment, some additional Triton area discoveries, but the trouble with discoveries is new licences, the regulatory issues.

The Glendronach development, again, because it's a new development, the regulatory issues are the ones they might be easier to just do infill drilling campaigns until such time as there is almost a sea change in the mindset of new licences, regulatory approvals, environmental statements and all the other issues you have to undertake with NSTA. That's where I'd go first. Bruce satellite accumulations and infill drilling around Bruce, but tiebacks right now, the economics might look good, but actually, the deferment and time and CAPEX and the lack of supply chain and the issues around it, I just don't see that stacking up perhaps against an international M&A opportunity that could bring in the cash flow a lot faster in a regulatory environment that is probably more pro-oil and gas than the UKCS.

00:39:28] What do you think are the key assurances required to gain approval from the NSTA [North Sea Transition Authority] in terms of tieback projects? How long could the approval process last?

MR [00:39:42]: The approval has grown in length over the years. It used to be a simple process. Now you've got reservoir recovery plans and you've got to cover well integrity, how you're going to utilise the local infrastructure. You've got decommission obligations, looking at emissions impact, the whole environmental statement, and you've seen that from Jackdaw and Rosebank, the issues around there. You've got approved financial capability. All this environmental compliance and financial compliance and the sheer level of regulatory compliance before you even look like you're going to start working on the project. If you want to maintain the schedule of the project, you are working through pre-FEED, reservoir engineering, you're working through the FEED before you get to sanction, and you're not going to go to sanction until you've got all those other things in place. You have to do them in parallel. You're spending a lot of capital, a lot of resource, a lot of time, a lot of management effort on something that may not get approved because of the regulator. The timelines for the NSTA can be at least two years. Then you get sanctioned and then you go off and build a project.

What used to take six months or maybe even faster than that is now… Could be two years, and there's not a definitive yes at the end of it. Then you've got the actual delivery and execution of the project. I used to get a subsea tieback in producing in 12, worst case, 18 months. Now you don't really start building the thing for 24 months, and then it's another probably 12 months on top of that, depending on the time of year you get sanctioned before you see any production out of it. The economics may be good, but the uncertainty is so great. Why would you go after this? There's a lot of cost pressures on tiebacks now. There's lots of constrained offshore vessels because there's lack of utilisation, and therefore, they're not around. The long lead items are getting even longer lead like subsea trees and controls because Norway sucked up a lot of that opportunity. Flow lines, all these other things, umbilicals, short supply and expensive. You can mitigate some of those things with standard design and framework agreements and early production, but you actually need a conveyor belt of these things to make that stuff work, a multi-project campaign. All those things disappear.

All those synergies, all those opportunities for enhancement of delivery of projects have all just gone along with this longer timeframe and uncertainty. I'm sorry, my job with subsea tiebacks in projects in the North Sea. Even I wouldn't recommend going to do those things right now. It's almost too hard.

OA [00:42:41]: By contrast, how does the approval timeline compare on the Norwegian Continental Shelf?

MR [00:42:48]: The great thing about Norwegian Shelf is you've got this mindset within the regulator, they're encouraging people to go and do things, not discourage it and challenging and finding reasons why not. They want full compliance. They want full transparency, but in terms of actually getting something through the regulator, they are very clear, well organised, well set out guidelines on what needs to be achieved when and to what standard it needs to be achieved. If you pass those hills, if you can prove to yourself that you're going to get over this, you're pretty certain it's going to get approved. It is not down to political will because the political will is we want to increase production. We want to continue exploration. We want to continue this cash flow. The timeline is probably 12 months. It's about 12 months for full compliance. They're with you throughout the journey. It doesn't stop at sanction with the regulator across there, but it's because you know that they are of the mindset they want you to be successful and not the other way around in the UKCS where they're looking to challenge you so you can't move forward.

It's about the background political will to make things move forward. If you did come across a hurdle in the Norwegian continental shelf, you always knew you could turn to politicians, you could turn to other powerful groups to get support for your requirement. Although the timeline isn't massively different, the certainty of you actually achieving it if you tick all the boxes and fulfil the cry is much higher.

00:44:28] Do you think the political willingness to increase production and continue exploration projects could change under the UK's new PM, Andy Burnham? Could you see a softening of the NSTA compliance threshold?

MR [00:44:39]: No, unfortunately. It doesn't bear the scrutiny of reality, unfortunately. Yes, they're going to keep killing the North Sea. They're not going to change the drilling licences. I look at the delay on Jackdaw and Rosebank. It's obvious. Jackdaw should have been approved. It's a gas development. We're short of gas. Gas prices are through the roof. We're importing gas. You use one-third of the environmental emissions getting UKCS gas into your pipes and into your houses, which we earned. We're going to need it for at least 30-40 years at a minimum. It's like every common sense thing tells you you need to keep doing… What do they do? They still haven't approved it. Now Rosebank is a different story. It's an oil development. Therefore, there is an argument you could say, "It's an oil development, and that's probably not the same way. It can't affect the economics. It doesn't increase security of supply."

There's lots of arguments you can make. Still doesn't make sense long term, but they should actually approve both. I don't see that changing at all. If anything, the stance is probably going to harden.

00:46:35] In terms of labour outsourcing, how can Serica retain and scale the broad range of disciplines required across subsea engineering, marine management and HPHT [high pressure, high temperature] operations without excessively inflating overhead costs?

MR [00:46:51]: The great thing is it's a buyer's market right now. Serica is one of the few growth companies in the UKCS and in Aberdeen. They're actually going out and looking to undertake, everybody would like to work for Serica Energy right now. I've got quite a few friends that work in there, ex-Neptune colleagues, ex-Apache colleagues, Head of M&A, Chris Baur, between us, we're one of the seven that started up Neptune. He's one of the first seven employees. They're in there and they're doing things. They're exciting. They're fast-moving. People want to go there. It's not like there's a seller's market and people have got lots of choice. Actually, they can constrain the rates. They don't need to do anything exceptional to bring in the right staff and people, people would like to work for them. Now that's on an individual level in recruiting the right people. The competence is definitely there. There's not a gross inflation on the rates people's expectations or salary expectations. Some people are just glad to have a job in Aberdeen, but they do need to keep in-house that reservoir subsurface competence and asset management knowledge in-house.

Their outsourcing strategy, they can push out a lot of those other things. Plenty of companies out there want to be all things to all man and will take on these opportunities if it broadens their base because nobody wants to be a one-hit wonder in terms of what they can do for any operator. Outsourcing marine operations, the campaigns, the construction, specialist intervention and partnering with larger organisations is absolutely the way to go for them, but they don't need to grow. It's amazing how small an organisation you need to run it if you are competent, sensible and you focus on your three priorities, which is safety, production, cost, focus on those three things and everything else can fall by the wayside.

00:48:50] How do the specific technical demands of HPHT well interventions affect Serica's long-term CAPEX forecast and contingency planning?

MR [00:49:02]: HPHT is just a subdiscipline within a drilling organisation and with an operator's organisation. High pressure, high temperature. If it's understood and there's competence, experience and capability or the right contractor's background, if you went into a complete novice, that's fine, but they have enough competency experience from the Bruce organisation. There's enough capability experience across the UKCS to actually… It doesn't give me any particular great concern about managing HPHT. It wasn't common 30 years ago, and now it's common across the globe to do HPHT. There's plenty of technical competency out there, and they've already got some existing expertise in and around the Bruce-run operations and developments. I don't see any particular issue affecting the long-term capital expenditure forecast. Yes, it's much, much more expensive to go and drill an HPHT well. It can be up to 100% more expensive. If it goes wrong, it can go horribly wrong and be very, very expensive and therefore, need very large contingencies, but the upside is once you've got it on stream and you got it working and running, it does massively increase your production.

Because of that, the downside on the cost because the rig rates are so much more expensive. If you get a delay of any sort, that chews into your budget like you wouldn't believe. We had that on Seagull when we had a few wells we had some issues with. We 100% overspend on our budgets for the drilling side of things. That's massive when you're looking at some of the day rates for HPHT rigs. They'll probably have to ascribe a significant amount of contingency in case the drill rig campaign goes wrong, but they probably have the right people to deal with it. It doesn't give me a huge issue. It's an expensive operation. It has to go well. If it doesn't go well, then people will have to look closely at what they're spending their money on because it's amazing how it sucks up your capital is an HPHT well intervention. It goes wrong, it goes south.

00:51:19] What contractual frameworks or multi-year service agreements can be implemented by Serica to secure priority access to scarce drilling rigs and specialised subsea equipment?

MR [00:51:31]: It's something we did both at Apache and Neptune on the project side and on the drilling side, where we built strong partnership alliances. There's a couple of things that keep companies in business. One is cash flow, so make sure you pay them on time and they've got plenty of work. They can see the forecast, the future work. If you get a partnership alliance and you remove all the tendering packages, you remove all of that uncertainty around, you remove all the cost gouging and the fight in fight to get somebody to actually deliver some service or some goods, then that partnership alliance model with a long-term 3-5 year framework where you work very closely, every single contractor I ever worked with loves those things. You have a preferred supplier, you have integrated service contracts. They provide all of the key pieces. It's very much a campaign-based pricing structure. If they're going for a long rig contract, then they have the opportunity to build all these things. On top of that, they could actually do a shared rig consortium where if they need gaps in the programme, somebody else can take the rig at a specific day rate.

Now there's massive long-term value in those sorts of contracts. Strategically, I would say for them, and we did in Neptune strategic alliances, multiyear call-off agreements, so people know that they're always… You're not going to have to re-tender everything, where you can share procurement and you have performance incentives to encourage the best possible delivery. The great thing about Bruce, again, because you're 98% partnership, you can make those decisions. You haven't got partners on board to agree to these contractual terms because they are difficult to get across the line with some supply chains, but that's the way forward, partnering, alliancing, rather than having lump sums or tendered contracts, you go for a shared pricing structure where you go for a target cost, you work together, you share teams.

It's amazing what you can do under those agreements and arrangements as a small operator because everyone assumes everybody wants to work for the majors, the oil, the BPs, the Shells, the Totals, of those are here in the North Sea any more, but actually, their preferred state is they used to get charged more on rig contracts and vessel day rates because they were so difficult to do business with because there were so many experts inside their organisations just getting in the way. Small lean teams of the likes of Serica, who are competent, capable and want to move fast and get things done, the contractors love it because they actually say, "We're going to go and do this, let's go do it." Off they go. Bruce is perfect with a 98% ownership.

00:54:30] To what extent will future M&A or asset partnership structures be driven by acquiring missing organisational capabilities rather than just adding production volume?

MR [00:54:42]: Whenever you take on a unique asset or a new asset, then, of course, you're going to take on new nuances in that particular asset or project or opportunity, but I don't think there's a massive requirement to significantly increase the size of Serica. 200-300 people. A lot of those are working offshore, but in terms of the organisation, if you're subcontracting and if you're working with strategic alliances and partners, you don't need to massively increase your headcount. Actually increasing headcount, it almost becomes a snowball effect where you end up administering yourself because you become so large. Actually maintaining the headcount discipline is absolutely key. I remember Raymond Plank, who was the original… He set up Apache. He said he used to like small offices because they had small car parks. He said, the thing about having a small car park is only so many people can come to work in the office. As soon as you get a big fancy office with a big car park, you will fill it.

This discipline of maintaining a small tight headcount who are competent and can subcontract any specialist disciplines that require is absolutely key to maintain the OPEX, but also maintain the fast-moving decision-making that you get from that small lean organisation. It's like the special forces of oil and gas is small independent operators because they can move fast, think quickly on their feet and get after stuff, especially in that environment like Bruce, where you have full operatorship, full ownership.

00:56:20] What proportion of marine and floating asset management capabilities do you think can be brought in-house by Serica vs remaining outsourced to FPSO operators?

MR [00:56:31]: Floating production and storage operation. Yes, there's a marine aspect to it. Yes, there's a production operations aspect to it, but it's… We looked at multiple times to put on FPSOs in both Neptune and Apache, both for projects and potential purchase opportunities. It is not as complex and as technically difficult. Yes, there's some nuances. There's some specialities around it, but most of that can be outsourced to specialty contractors or you can bring in the competence. It's not particularly onerous or difficult. Like all of these things, whether it's HPHT or FPSOs, there are specialist individuals who are capable. If you pick the right people, you can keep your team small. You pick the right contractors and alliances, you can keep those operating costs out of your organisation and put through the CAPEX requirements if you're undertaking some major event like a drilling operation or a major purchase, but you don't need to grow the organisation to be experts in all areas and fields. It's just not a requirement.

00:57:34] Is there anything else you'd like to discuss about Serica or the wider UKCS?

MR [00:57:42]: One big missing from the question you had about decommissioning liability. The big thing about small independents coming in is how do you manage the decommissioning? Is it retained by the previous major operator? If they're small, have they got the wherewithal, financial backing, the debt to actually take on the decommissioning liability. These are all sorts of things. Actually, although they're very focused and everyone's focused on Serica and its production growth, some of their assets are starting to go into decommissioning. This is where you need to look at the timing of abandonment expenditures, how are you going to do life extensions, what's the tax recovery on decommissioning, whether operators converting those mature assets into cash flow-generating hub before abandonment, they're in this great position right now with the high commodity price, but there comes a point where that efficient management of decommissioning liabilities will ultimately prove whether over the long term, that drilling success, the management success actually is a long-term shareholder return success.

Because if that element goes wrong, and I don't see much about the decommissioning, anything that I've read or that could actually completely outweigh all of the growth that they've got right now because it's coming. It's coming. When it comes, it can destroy all the value created through this growth. There should be a strong focus, even though going through a growth stage of how are you managing your decommissioning? What's the plan for that? That would be my biggest concern. Apart from the fact that Serica, I think it's a brilliant company. What they're doing is great. They've got some really high-quality people like Chris Cox in there, doing the work, doing what independents should do, M&A deals, exploration growth, mergers and acquisitions, that's maximising production, maximising safety, minimising cost. This is what small independent oil and gas companies are all about. Then moving on to the FTSE is a great move for them. High cash flow returns.

Everything is going in the right direction for them right now, and it will do for the next 12-18 months as far as I can see. It's five years' time and 10 years' time when the decommissioning liabilities will start to hit. Will it all go completely pear-shaped at that point? Maybe that's too far out for investors, and it doesn't really matter. They'll be in and out before then, but that would be my concern.

OA [01:00:15]: Thank you for taking the time to speak with me today, and I hope you enjoy the rest of your day.

MR [01:00:25]: Thank you very much. It's a pleasure.

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