Tullow Oil plc ($TLW)

Welcome, everyone, to Tullow's 2025 Full Year Results Presentation. I am Ian Perks, Tullow's CEO, and I'm joined by our CFO, Richard Miller. Since joining the company in September last year, I am often asked about my first impressions of Tullow. I'd like to start by saying how impressed I am with the people and processes through which we run our operating business and a rich opportunity set we have for continued investment to add value. So our presentation today will provide more detail on operating performance and these investment opportunities, building on what we presented in our credit presentation back in February. I will start by highlighting the tremendous progress we have made in creating a stable foundation and platform to improve performance and the momentum we have demonstrated so far in 2026, where results have been excellent during the first 4 months. Richard will then go through our financials, including our hedging strategy and exposure to high oil prices. I'll conclude by summarizing what this all means for our business outlook for the rest of 2026 and beyond. The last 12 to 15 months have seen an intense period of delivery, focused on setting a firm foundation for improved performance across the business, and we have delivered on that with resounding success, where we have seen disciplined execution against a set of clear actions. On the financial side of the business, these include accretive divestments, a continued focus on cost to improve economics and a comprehensive refinancing. Regarding the strategic foundations we have laid, we are already seeing a positive impact with the 4D and Ocean Bottom Node data supporting existing and possible future drilling campaigns. We have strengthened our relationship with the Government of Ghana as evidenced through the gas payment security mechanism and the petroleum agreement extension secured in early 2026. This growing track record over tangible delivery is strongly supported by a reset Board to oversee strong governance and sound decision-making. We've delivered a huge amount already in a short period of time, and we fully intend to continue this momentum. As we turn attention to improved performance, so far in '26, the signs look extremely positive. As you can see in the chart on the bottom left-hand side, production in Q1 2026 has been strong, with an average of 43,400 barrels of oil equivalent per day compared to 40,400 in 2025. If this performance continues, we would expect to be at the very high end of our production guidance of between 34,000 and 42,000 barrels of oil equivalent per day for the full year. This performance is driven by a successful start to our Jubilee drilling campaign with 3 wells brought on stream since the middle of last year, all of which are producing in line with our pre-drill expectations. We expect 3 further producers onstream before the end of July, and the program continues to be derisked as the log results from our next well, J76 indicate another positive outcome. The current drilling campaign will conclude with a water injection well in September. The success of the program so far speaks volumes to the benefit of the 4D data, which was processed in time to influence specific locations on several of the wells. The good start to the year has also been driven by exceptional operational performance, supported by an active and preemptive maintenance program. We have seen nearly 100% availability at Jubilee and TEN so far, and this is largely due to the specific actions we took during the shutdown last year on Jubilee to improve reliability of key equipment. In addition, better focus on voidage replacement through reliable and consistent water injection, as shown in the graph on the bottom right-hand side, is also supporting pressure management in the field, where we have seen enhanced recovery in addition to some flush production from key wells. Well stability and reliability has also improved significantly with the use of dual-riser operations and riser-based gas lift in Jubilee. All this means we are starting to see better performance than expected from our existing well stock and a slightly slower-than-anticipated production decline. I will now hand over to Richard to run through our financials.

Thank you, Ian. In 2025, we produced 40,400 barrels of oil equivalent a day. This includes a 17-day planned maintenance shutdown at Jubilee. This outturn was in line with guidance, although towards the lower end of our range, which was primarily due to operational challenges at Jubilee during the first half of the year. Production improved in the second half of the year, supported by the start of the drilling campaign and good performance from the first new well, which came on stream in July. As Ian has discussed, production performance has continued strongly in the first quarter of 2026 and is ahead of expectations, pointing to an outturn near the top end of our guidance range for the year. Our average realized oil prices in 2025 were $66 a barrel. In the first quarter of 2026, we have seen a material increase in realized prices. Our first 4 cargoes of the year have averaged $90 per barrel. We have also revised our oil price guidance range to between $70 and $100 a barrel to reflect both higher current prices as well as the uncertainty of where prices will be through the rest of the year. I will talk more about our significant oil price exposure in the coming slide. In 2025, our net cash G&A costs were $45 million, and we have already taken actions to reduce this by a further $20 million in 2026. CapEx for 2025 was $166 million, primarily associated with the drilling of 2 Jubilee wells. 2026 CapEx is also focused on the drilling campaign with nearly 90% allocated to Jubilee and 6 wells expected onstream this year. Decommissioning costs inclusive of the Ghana escrow payments remain relatively flat year-on-year following the completion of the Mauritania campaign in 2024. During 2025, free cash flow was $99 million and was lower than expected due to lower realized revenues towards the end of the year as Brent dipped below $65 in November and December. The receipt of the second tranche of the Kenya disposal proceeds was delayed until March 2026, and we also saw delays in the receipt of cash calls and gas payments from the government of Ghana. As a reminder, 2025 cash flow included $347 million of disposal proceeds. Therefore, we are guiding a material uplift in organic cash flow for 2026. As I've mentioned, our 2026 cash flow guidance is based on a range of oil prices from $70 to $100 a barrel. We expect to deliver $260 million to $365 million of prefinancing cash flow in that oil price range, which translates to free cash flow of $70 million to $175 million following the inclusion of approximately $130 million of financing costs and approximately $60 million of fees associated with the refinancing transaction. With the refinancing transaction completion, we have significantly reduced our cash interest run rate to approximately $125 million per year. Our cash flow guidance in '26 includes recovery of 2025 cash call receivables from the Government of Ghana and approximately $40 million of pretax gas revenues from 2026 gas production, but it does exclude roughly $110 million in historic gas receivables and approximately $50 million related to TEN development debt. We are working collaboratively with the Government of Ghana to reduce the receivables balance with significant progress already made. 2026 gas payments are up to date, and we have received settlement of certain 2025 cash calls. But importantly, we now have a payment security mechanism for gas approved by Parliament. Moving on to the next slide, where I'll highlight the work we've done both on refinancing and our cost base. The refinancing transaction, which we completed yesterday strengthen Tullow's financial position and provides a stable platform that will enable us to deliver value for our stakeholders. We have extended the maturity of our Senior Secured Notes to 2028, and the Glencore Notes have been extended to 2030. We have also agreed a new money cargo prepayment facility with Glencore for $100 million to provide the company with a robust liquidity position throughout the extension. Our liquidity profile is further strengthened by the lowering of cash interest costs by $50 million per year through the use of paid-in-kind and pay-if-you-can interest. This extension of our maturities, provision of a new money facility and reduction in cash interest provides Tullow with a stable platform to get after the value accretive investments and projects, which Ian will provide more details on shortly. With an enhanced value proposition and more time, Tullow is now able to explore longer-term refinancing options, strategic investment or a value-maximizing divestment process. The charts on the right of this slide show 4 metrics, where we have made significant progress in recent years to optimize and streamline our costs. Firstly, net cash G&A, which, as previously mentioned, is approximately 50% lower than 2 years ago. We are targeting a run rate of approximately $20 million per year. Our operating costs increased in 2025 as a result of the Jubilee maintenance shutdown and CSV campaign. A huge amount of work has been done to deliver the required maintenance and integrity activity in the most cost-effective manner. And this has delivered tangible results already this year with near 100% uptime on the Jubilee FPSO. We also expect further cost reductions following the purchase of the TEN FPSO. We were able to deliver 30% savings on operational and maintenance costs since taking over the Jubilee FPSO, and we are targeting similar results at TEN. We also see a clear opportunity for further savings as we tap into synergies that may be available as a result of operating both TEN and Jubilee. Now, I'll move on to cash flow delivery, leverage to oil price and our hedging program. Our hedging policy remains unchanged, targeting 60% downside protection whilst keeping at least 60% of our midpoint forecast fully exposed to higher oil prices. We use a mix of Puts, Collars and Three-ways to execute this policy and have not entered into any swaps. As you can see through the -- from the table, through our use of Three-ways, a portion of the upside giveaway is limited to a $10 a barrel range. Since the start of the war in the Middle East, we have seen a significant dislocation between the price of near-term crude deliveries and the oil futures market with the Dated Brent benchmark reaching an all-time high a couple of weeks ago. As luck would have it, we are pricing a Jubilee cargo during that week and realized a price of $130 a barrel, which is the highest realized price Tullow has ever achieved on a cargo. In addition to higher oil prices, West African crudes are now trading at a material premium to Brent, given the lower geopolitical risk associated with loading and delivering barrels from that region compared to the Middle East. It's worth noting our hedges are priced against Dated Brent. Therefore, we have 100% access to this premium. So to provide an idea of the sensitivities and the potential upside, the graph on the right shows our 2026 free cash flow potential between $65 and $150 a barrel. Incremental cash flow for every $10 price increase above our guided range is around $30 million. This chart also highlights the $130 a barrel level we achieved on the last cargo, which delivered over $116 million of revenue to Tullow. I will now hand back to Ian.

Thank you, Richard. I will now turn attention to the outlook for the business in 2026 and beyond and the rich opportunity set we have in front of us to add value. In February, we presented 3 business plan scenarios, a 2P reserves only case, a business plan base case and an upside case, all built on potential additions to reserves and improved recovery rates from Jubilee and TEN. As part of the business planning cycle in Tullow, we actively work to mature various projects and future drilling campaigns so we can provide greater certainty to the base case and upside values retained in our business plans and also unearth new growth opportunities for the future. Our approach to project selection is based on a rigorous capital allocation process, which ensures projects are only sanctioned and executed if they provide quick payback and high returns. In 2026, our particular focus is to transfer value from the 2C category into 2P. And this does not always require significant capital expenditure. The opportunity to mature resources into reserves often come simply from further technical and engineering studies leading to a growing confidence in the viability of these drilling campaigns and projects. So looking at Jubilee and the 3 business plan scenarios, we see a range of recovery rates starting with 35% and rising to 40%. This is against STOIP of 1.8 billion barrels. The audited 2P reserves includes the current Jubilee drilling campaign and a further campaign of at least 3 wells that we are looking to firm up for possible execution starting sometime in 2027. As I have said, all possible future drilling campaigns are being strongly supported by the new data from the 4D and the OBN surveys. Looking at future projects identified by the lighter shaded boxes on the chart, we see a realistic opportunity during 2026 to add some of these to the 2P case by the end of the year, as we conduct further studies. The extension of our petroleum agreements, the multi-phase pumps project, the teak gas development and possibly additional Jubilee wells, all have a good chance of being advanced enough to be added to the 2P category. The multi-phase pumps project is particularly important, as the pressure in the reservoir inevitably declines, the pumps will add energy and allow stable multi-phase flow to boost production, reduce decline and extend the field life. Furthermore, we will look to convert some of the upside scenarios into the base case business plan and then add additional longer-term opportunities to the upside case, as we continue to replenish the hopper of potential growth projects. Looking at TEN for the same business plan cases, we see recovery rates for Enyenra at 15% and for Ntomme ranging from 30% to 34%, where we see more potential. In the audited 2P scenario, there are near-term reserves associated with the water injector at Ntomme and the development of Enyenra South. The 2 major opportunities at TEN are to work up the gas play in our business plan case and also give greater certainty to the Ntomme infill campaign, currently shown in our upside case with the possibility of accelerating both of these into the 2P case by year-end 2026. If we look at value, here we show a wide range of net present values honing in on our base case and upside cases, as we feel growing confidence in our ability to deliver against these as described earlier. We are cognizant of a changing external environment, as explained by Richard and so are showing sensitivities at lower discount rates and higher oil prices. Overall, we see credible scenarios, which value Tullow at $2 billion and above. What is clear from this slide is there remains significant value that can be achieved organically combined with additional upside depending on oil price outlook and risk appetite. Finally, to conclude, we feel we have a credible and coherent story. We've delivered a huge amount in a short space of time. The foundations have been laid, and momentum is growing, as we see early success in the first 4 months of the year. We aim to maintain this momentum and continue to improve operational performance and cash flow management. The rich opportunity set ahead of us and the external geopolitical environment provides Tullow with a credible prospect of creating further value for our stakeholders. Having time to deliver this value was at the forefront of our minds during the refinancing process, which concluded yesterday. Thank you. We will now take any questions you may have.

[Operator Instructions] Our first question is from the line of Lydia Rainforth at Barclays.

Firstly, congratulations on getting the refinancing done. There's a couple of things I want to go into. Firstly, on the operational side, Ian, you talked about the FPSO working better post the work that you did last year. Can you just give us examples of that in terms of where it's working better? And then also a little bit linked that to what you'd expect to improve going forward when you get sort of the OBN seismic through? And then, secondly, Richard, you put it there earlier on the realization and some very high realization of $130 a barrel for your last cargo. But I think you said the first 4 cargoes of the year were $90 a barrel. And so that doesn't imply you'd be doing 1 cargo a month. So can you -- I'm just wondering why the pace that only leaves us, I think, with 5 or 6 to do for the rest of the year. I'm just wondering why the pace slows down a little bit and just if you're being conservative in terms of some of the guidance that you still have. And I'll leave it there.

Yes. Thanks, Lydia. Thank you for that. So just in terms of the reliability, obviously, we've had 100% -- near 100% availability so far this year, which has been a terrific performance. A lot of that is down to work we did during the shutdown with upgrades on the electrical systems, removing sort of spurious trips, sensors and things like that and just a preemptive maintenance campaign. So obviously, 100% is difficult to forecast that going forward, but certainly, it's not just been down to luck. There's been a proactive maintenance program that sort of led to that success. Richard, do you want to take the second question?

Yes, sure. Thanks, Lydia. So the 4 cargoes we've lifted have basically been to the end of April. We've lifted 3 Jubilee and 1 TEN cargoes. As we look at the balance of the year, we've got -- well, for the full year, we're now guiding 10 Jubilee and 2.5 TEN. If we are able to hit the top end of the range from a production perspective, there is potential that, that could increase to 11 Jubilee cargoes and 3 cargoes on TEN. So the option for an extra 1.5 cargoes from a high-end production outcome.

Great. And then just so I kind of follow up and just like trying to -- everything together. And clearly, we've got the first stage of the refinancing done, and when I look at the numbers that you're presenting on free cash flow and the upside potential there, it does feel like you've given yourself a lot more options and time as to how to ultimately where you want leverage to be. So can you just talk us through your thinking, especially as to where do we go on the financial structure from here?

Yes. So I'll hand over to Richard to provide detail. But as I said, I think we see the refinancing having bought us time before our next debt maturity. Our focus during that period is to very much continue to deliver good performance, good operational performance and tap into the rich set of opportunities we've got to add value. Looking to do that against a sort of geopolitical environment that we see could be moving in our favor. And then aggressively looking at all of the various opportunities that we may have to -- for refinancing ahead of the debt maturity. So Richard, do you want to provide further detail?

No. Ian, I think you've answered it really well. I mean, I think, exactly as you said, the time in the current environment and the cash flow we expect to deliver this year essentially gives us more opportunities in terms of what that refinancing solution could look like. And every day, the oil is above $100 a barrel. It fundamentally reduces the quantum that we would need to refinance, which obviously makes tasks significantly easier.

Our next question is from Mark Wilson at Jefferies.

Yes, a few points here. Some kind of admin. I just want to check on the free cash flow. That is before leases or after leases, just to understand?

It's after. So it's the bottom line free cash flow that will reduce net debt.

Excellent. Okay. Very clear. And then, on a go-forward basis, we should be thinking you'll be keeping the rig in Ghana for the foreseeable, certainly into '27, and we should be looking at another maybe 4 to 6 wells in '27. Is that the way we should think about the forward plan?

Yes. No. So just to be clear, so in terms of the rig contract that we've currently got with Noble that's for the current drilling campaign, and so that, as I mentioned, will conclude in September this year with a water injector. We are going through a process working with our partners on the rigs prospect inventory that we've got to firm up a drilling campaign that we expect to start sometime later in 2027, and that would be part of securing a new rig for that campaign.

Got it. Okay. And then, I guess, last point, in the guidance, there is, I imagine, summer shutdown for Jubilee, just to check that, please.

Yes. No, there is no shutdown plan in the -- for this year or next year for Jubilee. We did 1 last year.

All right. Excellent. Congratulations.

Our next question is from Chris Wheaton at Stifel.

A question on operations, actually, really good performance quarter-to-date or year-to-date rather. I'm interested in how much -- if you can talk about, how much that's actually the performance of the new wells being a bit better than you hoped, less interference with old wells. Clearly, one of the things bedeviling last year's performance was lack of water injection capacity, which means you had to shut in high water cut wells. It looks like you've started to get after some of those water injection problems. I'm just interested in the -- sort of, if you like, some of the color around that operational uptime. And the second one was a question on the medium term, the business plan -- one of the sort of central case, the business plan scenario that you just talked about, Ian. That seems to show a, as far as I can tell, quite a sort of pattern of production. You're drilling a lot of wells 1 year, then you've got decline the following year, then you drill more wells the year after. So you don't end up with a flat production profile. It's quite spiky. And I'm interested in what the operational constraints are that means you have to do it that way rather than have a more smoother drilling profile and smoother the production profile. Those are my 2 questions.

Yes. Thanks. Thanks, Chris. So just 2 elements to that question. So first of all, in terms of our production this year, as we've mentioned today, we're going to be -- expect to be at the very high end of guidance for that if performance continues. To add context to that, year-to-date performance has been driven by kind of 2 factors. So first of all, on production from existing wells, we've had near 100% availability, which has been truly exceptional performance from our team in Ghana. We've had dual-riser flow, which is essentially that reduces -- has reduced the back out from existing wells as we bring new wells on production. And we've had some flush production from a couple of wells that we weren't expecting. So that's been a good pressure management of the field. In terms of the new wells, they've pretty much been coming on as per pre-drill expectations. So with regards to our production, it's sort of 65% from existing wells, 35% for new wells. And the reason for the better-than-expected performance has been those 3 factors I mentioned, the 100% availability, the dual-riser flow and the flush production. In terms of sort of medium-term, I think you're absolutely right. I mean, exactly, it is a sort of a sort of -- obviously, there's a decline from the existing wells. We've seen that depending on how many new wells you bring in, around 25% to 35% decline year-on-year. We'd expect that to plateau out in the next 2 to 3 years, naturally anyway. And then we offset that production through drilling programs to -- and that brings the incremental production on. The reason why it's a sawtooth and why we just have constant drilling, I guess we've got new data coming in from production data, the seismic, et cetera. So it's just prudent to take new thinking time to assess new prospectivity before you go into future campaigns. Thanks, Chris.

Our last question for the call today is from James Hosie at Shore Capital.

Just a couple for me. Just maybe a clarification on the cash flow guidance. Is that based on the realized prices of $70 to $100 per barrel or the average Brent price? If it's on Brent, what sort of premium are you assuming for the remainder of the year?

Yes. Thanks, James. Yes, it's a really good question. So they're based on Brent prices, and we haven't adjusted our forecast diff to Brent. So diffs have been -- sort of have increased materially this year. I mean, West African differentials peaked at about $12 a barrel earlier this year, but there is a lot of volatility in them. So we're maintaining our sort of budget differential to Brent, which is broadly flat.

Okay. Thank you very much. That brings our presentation and Q&A session to a close today. Thank you for your time, everyone.

Thank you.