TUWLF (TUWLF) Q2 2026 Earnings Report, Transcript and Summary

Welcome everyone to Tullow's 2026 Half Year Results Presentation. I am Ian Perks, Tullow's CEO, and I have now been in the role for 12 months. I am joined today by our CFO, Richard Miller. This morning, Richard and I will take you through various operational, financial, and strategic updates across all areas of the business since the start of the year. Back in April, I highlighted the progress we had made in building a stable foundation for improved performance. Today, I am pleased to show how this foundation is continuing to deliver positive results. Richard will then go through our financials, including the refinancing transaction completed in April, and free cash flow generation against a backdrop of high oil prices. I will then talk about the depth and scale of the opportunity set we have in Ghana and what this means for our business outlook. Starting with operations, production performance has been outstanding in the first half of the year, and we are now confident of being at the high end of our guidance range by year end. We have added material 2P reserves, delivering reserve replacement of around 380%. We have also continued to de-risk the business plan as we firm up future drilling campaigns and projects. The strong operational performance flows through to our financials, where we have significantly upgraded free cash flow guidance from between $70 million and $175 million to between $170 million and $250 million. in April this year, we completed a comprehensive refinancing transaction, and we continue to optimize our cost base, including the important purchase of the TEN FPSO set for early next year, which will remove the annual lease cost. Data from the recent 4D seismic will be further supported by the OBN survey data and is helping us shape future drilling campaigns and unlock significant growth potential in and around the Jubilee and TEN fields. Our alignment with the government of Ghana remains strong, underlined by the extension of the Petroleum Agreements and the agreed gas payment security mechanism. We also continue to work closely with the government of Ghana to resolve the outstanding tax arbitrations. We will now take you through this in a bit more detail, and I will start with our production performance before handing over to Richard to take you through the financial update. This slide explains the Jubilee and TEN oil production story for the first half of 2026, excluding gas and Espoir. The single largest contributor is the performance of the new wells, all of which have come on stream in line with or ahead of expectations in terms of schedule and initial production rates. Optimization of existing wells through careful reservoir management has led to lower well downtime and reduced natural decline rates. Dual riser operation is reducing back-out of existing wells where new wells are brought on stream, which has had a further positive production impact. Finally, the performance of our FPSOs remains very high with combined uptime of over 99% across Jubilee and TEN in the first half of the year. Not only does this strong performance give us confidence for the remainder of 2026, we believe it is to be largely sustainable over the longer term. The seismic data is informing our decision-making. The facilities are running reliably due to specific actions we have taken. And optimization work continues to have a positive impact as our understanding of the reservoir improves. Now let me take you through this in more detail on the next slide. This slide shows how we have achieved the high production performance through a project delivery mindset, which has brought a culture of accountability, high energy, and focus on our operations. The 2025/26 drilling campaign, which delivered seven wells on time and on budget, is now complete, with the final well, a water injector, on stream this month. As stated earlier, all new wells are in line with or exceeding expectations, both in terms of schedule and initial production rates. The success of the drilling campaign speaks volumes to the benefit realized from accelerating the 4D data processing, which de-risks the campaign one wells. Drilling performance also continues to be top quartile in the industry, which is critical to production performance and provides confidence for future campaigns. During this campaign, quality of our data and geophysical analysis has allowed real-time Geosteering to accurately reach our reservoir targets while reducing risk and increasing production rates by accessing multiple target zones. Water injection remains a key element of reservoir management. In 2025, water injection capacity was increased to 300,000 barrels of water per day. We have headroom above our target injection rate of 230,000 barrels of water per day. Despite unexpected downtime in the second quarter causing water injection to be below expectations for the first half of the year, we still remain on target for the full year, and this is expected to be at the highest levels ever achieved in terms of water injection into Jubilee. Efficiency is also key, and we are optimizing injection allocation and distribution towards high-value producers to maximize oil production and enhance recovery. Furthermore, we are improving power reliability through direct remote monitoring and a sparing strategy, which includes the use of gas turbine generators from the TEN FPSO with Jubilee. In the first half of 2026, we have seen fewer production-related trips compared to the same period in 2025, and the Jubilee FPSO maintenance shutdown conducted last year is a significant factor here. The shutdown was used to address known vulnerabilities such as instrument reliability, which has improved the overall facility uptime. The eastern side of Jubilee experienced significant production instabilities during 2025, which were effectively addressed through riser-based gas lift. The subsequent start-up of J75, J76, and J77 further enhanced production stability and supported sustained field performance. On the western side of the field with strong production, we have been able to move from single riser operation to dual riser operation to reduce back pressure on wells. Through optimizing well configurations, we have been able to maintain this for much of the year and hope to continue until riser-based gas lift is installed on the western side of the field in November. Before I hand over to Richard to run through our first half financials, I want to reiterate that the cultural shift within Tullow and set of targeted actions are delivering meaningful and sustainable production results.

Thank you, Ian. In the first half of 2026, we produced 43,700 barrels of oil equivalent per day, representing a more than 7% increase compared to the first half of 2025. As Ian explained, this outturn was at the top end of expectations and makes us confident in being at the top end of our guidance range of 34,000 to 42,000 barrels of oil equivalent per day for the full year. Our average realized price before hedging was $95 a barrel and included the highest ever price for a Tullow cargo of approximately $130 a barrel, which was delivered in April. So far in the second half of the year, we have lifted a further four cargoes and again realized an average price of $95 a barrel. That included a cargo we priced at $119 a barrel at the start of this month, and we expect to lift a further four cargoes by the end of the year. The outstanding operating performance has translated directly into an increase in operating cash flow with $222 million in the first half of the year. We expect to deliver an even higher number in the second half based on a total of eight cargoes compared to six in the first half of the year. Capital expenditure is in line with expectations, and guidance for the full year remains $200 million. Decommissioning expenditure for the full year is reduced from $25 million to $15 million due to the deferral of the TEN decommissioning fund contributions. Free cash flow in the first half seems low at $4 million, but this is due to $70 million of one-off refinancing costs, CapEx being awaited to the first half of the year, and the fact that we lifted six cargoes in the first half compared to eight forecast in the second half. As previously reported in August, full-year free cash flow guidance has been upgraded to $170 million-$250 million between an oil price of $70 and $100 a barrel, reflecting the positive production performance, higher oil price realizations, and good progress on recovery of Government of Ghana receivables. We have continued to delever the business and made a $48 million bond repayment in June and expect a further repayment in November. We forecast year-end net debt of $1.2 billion inclusive of accrued PIK interest on the bonds and Glencore notes. I would now like to recap on the comprehensive refinancing transaction we completed in April of this year. The refinancing transaction we completed in April strengthened Tullow's financial position and provides a stable platform that allows us to pursue value-accretive investments and projects, which Ian will provide more details on shortly. We extended the maturity of our senior secured notes to 2028 and the Glencore to 2030. We have also agreed a $100 million new money cargo prepayment facility with Glencore to provide the company with a robust liquidity position. Our liquidity profile is further strengthened by the lowering of cash interest costs by over $50 million per year through the use of paid in kind and pay if you can interest. With enhanced value proposition and more time, Tullow is exploring longer-term refinancing options, strategic investment, or a value-maximizing divestment process as a backstop. Moving to the right of the slide, our hedging policy remains unchanged, targeting 60% downside protection whilst keeping at least 60% of production fully exposed to higher oil prices. We use a mix of puts, collars, three-ways, and we sometimes add put spreads to improve strike prices. We have not entered into any swaps, and as you can see from the table, through our use of three-ways, a portion of the upside giveaway is limited to a $10 a barrel range. This approach to hedging ensures we have a robust liquidity position in a low oil price environment that maximizes the exposure to high oil prices. Moving on to the next slide, I would like to reiterate our focus on cost efficiency and our significant oil price upside. The chart on the left-hand side of the slide shows four metrics I've shown previously, where we have made significant progress to optimize and streamline our cost base. Firstly, net cash G&A is 50% lower than two years ago, and we continue to target a run rate of $20 million a year. Operating costs increased in 2025 as a result of the successful planned 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. As Ian has explained, this has delivered tangible results already this year, including 99% uptime on the Jubilee FPSO. We expect further cost reductions following the purchase of the TEN FPSO. We were able to deliver 30% savings on operating and maintenance costs since taking over the Jubilee FPSO, and we're 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. The chart on the right of the slide highlights our updated free cash flow sensitivity for the rest of the year. Driven by the strong production, we have four cargoes left to price in 2026. With Dated Brent again trading at a premium to the front month of Brent futures, there is potential for free cash flow to exceed our current guidance. Every $10 increase above our guided range for the second half of the year would result in more than $20 million incremental cash flow. I will now hand back to Ian to look ahead at a refreshed opportunity set.

Thank you, Richard. In April, I presented the rich opportunity set we have at Jubilee and TEN across three scenarios: a 2P reserves only case, a business plan base case, and an upside case. I'm pleased to report that we are now able to present an improved outlook for each of these three scenarios. We have been actively working to mature projects and future drilling campaigns to add greater certainty and value to the 2P and business plan base case scenarios. In addition, the 4D seismic data has uncovered near-field potential in deeper horizons around Jubilee and TEN, and this has added material growth opportunities for the business. Looking first at Jubilee, our view of the mid-year 2P reserves position represents a reserves replacement ratio of more than 420%. This reflects the impact of the reserves associated with the Petroleum Agreement extensions, the maturation of the next two Jubilee drilling campaigns, and the TEN gas development. Following the success of the 2025 to 2026 drilling campaign, we are optimistic of the potential that the 2027 to 2028 drilling campaign can deliver once underway in the second half of next year. The business plan includes the multiphase pumps project and a well intervention campaign, both of which provide further opportunities for reserves additions. The multiphase pumps project continues to progress as it is now in the FEED stage. We also have a refreshed and expanded upside opportunity set. In addition to future drilling campaigns and reservoir management initiatives, we now include significant near-field and infrastructure-led exploration potential in Lower Mahogany, which can be developed from the existing sub-sea production system, and the Cenomanian, which is a deeper geological play below Jubilee. These opportunities can be pursued in a highly disciplined manner. Low-cost deepening of future development wells can de-risk the resource base before any material capital is committed for appraisal and subsequent phase development. Certain opportunities will require additional rights, and we are already engaged in early discussions with the government of Ghana to secure these. This is a clear result of the strategy I explained back in April as we look to convert 2C resources into 2P reserves, de-risk the business plan, and unearth new growth opportunities. Let's now turn to how this strategy and new 4D data has impacted the TEN fields. TEN continues to perform strongly with our view of more than 170% reserves replacement at the middle of the year. Within the business plan, key near-term maturation opportunities include reserves associated with the Petroleum Agreement extensions, Ntome Oil infill drilling, a well intervention campaign, and a non-associated gas opportunity across Tweneboa and Ntome. Following the FPSO purchase, which improves the economics of TEN, we continue to explore ways to maximize the potential of these fields and the existing infrastructure. As with Jubilee, the deeper Cenomanian play also represents a material longer-term opportunity which can be de-risked in a low-cost manner. I will now turn to the associated value creation potential. In April, we provided value sensitivities to oil price and discount rates across the three scenarios of 2P business plan base case and upside. This slide shows how these cases have evolved and grown in the space of six months. Since April, we have increased the Jubilee 2P case through the addition of a further seven wells across campaigns two and three, whilst also incorporating additional 10 drilling opportunities into the business plan. We have significantly refreshed the upside case. Across Jubilee and TEN, we now see multiple infrastructure-led exploration opportunities supported by high-quality seismic data and subsurface insights. Collectively, these opportunities can be de-risked in a capital-efficient manner, allowing us to maintain a disciplined approach to capital allocation that underpins our strategy. We've applied a single 12% discount rate and a conservative flat real oil price of $70 a barrel. Compared to audited year-end 2025 2P reserves of $1.2 billion, we see additional value delivered from our view at mid-year, and further value from our enhanced business plan. Additionally, our refreshed upside case demonstrates the potential for value to increase to more than $3 billion. Finally, to conclude, this slide summarizes everything you have heard today. We are delivering our strategy and seeing tangible results. The strong foundations laid and renewed operational focus are leading directly to improved and sustainable production performance, reduced costs, and cash flow generation. We have de-risked our business plan and realized 380% reserves replacement as a result. We are looking forward to further project maturation and getting back to drilling in Ghana in 2027. We have also refreshed our growth potential following a review of the 4D data set. Near-field exploration opportunities exist that could generate material value over and above our business plan. There is, of course, more work to do before we can realize this, which is why it is in the upside case. Nevertheless, we are excited by the opportunity and have a clear set of actions to help de-risk and unlock this value for all stakeholders going forward. Thank you. We will now take any questions you may have.

Thank you, Ian. As a reminder, if you would like to ask a question, please press star one on your keypad. We will take a moment to collate questions. There are no questions in the queue at this time, so we will call. We will give it a. Okay, we have a question. The first question is from Lydia Rainforth at Barclays. Go ahead, Lydia.

Thanks, Matt, and good morning, team. Very much appreciate the update. I have two or three questions, if that is okay. The first one, Ian, can I come to the operational performance? It clearly has been extraordinarily strong, and I think you talked about a number of the changes the team have made, but what is it that is really driving that? Is it a change in management? Is it a change in how you are thinking about the field? I am just trying to wonder what exactly it is that we have gone from a period where there have been problems with the performance to actually extraordinary uptime. Just helping me understand that a little bit. The second one was on the OBN side. Can you just walk us through in a bit more detail what that is actually showing you, how different that is to where your seismic has been in the past, and kind of just a little bit more detail on that. Richard, if we could, just in terms of the oil price realizations, I think you touched on the idea that one of the cargoes was $119 a barrel for this quarter. Just that difference between the physical pricing that we're seeing versus what we're seeing on the screen, and how you think about that as a CFO in terms of when you're planning things. Thanks. I know that's a lot of questions.

Okay. Thanks, Lydia. So take the first question you asked just on operational performance. Yeah, I think a lot of it's come down to a greater rigor and focus. I think clearly, as we've consolidated our asset base and focused more on Ghana, I think that's brought more attention to the business there. Very much a project delivery mindset on operations this year. Then specifically, I think what we've seen, a lot stronger well stability. The riser-based gas lift has helped in the east and will help in the west as well. I think a greater focus, as I said, on power, and the reliability of power and the sparing strategy. I think water injection has been a refocus of us. We always say, "Water injection today is oil production tomorrow." So we're very focused on that, creating additional capacity. Some of the well optimization has been very good. I think there's just more experience in the business in understanding how we match wells across different risers to create better stability. Then lastly, obviously, the drilling performance. I think when you bring in new wells on stream, getting those wells on schedule is very important. I think our drilling team continues to perform outstanding results compared to industry standards. So those are the real issues I think that have led to better performance. In terms of plant availability, I think we're realistic to recognize that continuing at 99% is probably unrealistic. But certainly, I think some of the high availability has been down to action. So, we're very pleased with the performance, but also we are realistic going forward on that. In terms of the seismic, just to be clear, the 4D has been processed and reviewed. It did have a significant impact on the campaign one wells. We actually changed one of the wells out. We moved locations, and I think the key benefit of the 4D was making sure that we didn't drill a bad well in that program. As far as the OBN, we're getting the process data in the back end of this year, will come in next year. We think in terms of the firm wells, we're very confident with the 4D identifying the firm wells in the drilling program next year. The OBN will be very key, in terms of our option wells. It's just going to improve the accuracy of the 4D data, perhaps provide a little bit more static data as well. So we're excited to see what the OBN gives us in addition. Your third question, I think I'll hand over to Richard. Thank you.

Yeah. Thanks, Ian. Historically, the front month of the forward curve and prices for prompt delivery have been relatively consistent. We have seen some material changes and volatility this year. The gap increased to about $20 a barrel in April, May time, and that closed completely over the course of the summer. In the last few weeks, that has opened up again to a $20+ in terms of the prompt deliveries. In terms of, I suppose how that impacts how we think about things from a financial perspective, all of our hedging is based on a Dated Brent price. That is probably one of our key measures for managing the volatility and price. As we, I suppose, look forwards, we are guiding $100 a barrel at the top end of our free cash flow range for the year. With the front month of the forward curve sitting at 107 and a $20 premium, there is a positive potential to even be above that top end of the guidance range.

Brilliant. Thank you all.

Thanks, Lydia. Our next question is from James Hosie at Shore Capital. Go ahead, James.

Hi. Good morning. Like Lydia, I've got a few questions, if I may. Firstly, just on the upside scenarios you presented for Jubilee and TEN, I'm just wondering how mature these opportunities are. Are there things you could do as early as next year if you had the capital available, or is there still a lot of work to do high grading and optimizing these exploration prospects? Secondly, just maybe a slightly awkward question, but the Ghana tax disputes. Obviously, I think the release today says you expect the tribunal ruling soon on one. You've increased the provision for these disputes by about $30 million, and I'm just wondering if we should be anticipating a meaningful cash outflow over the next 18 months to settle this, or can this settlement be netted off against some of the money owed to you by the government?

Okay. Thanks, James. In terms of the upside, I think, as I mentioned, this is upside opportunity. It's definitely longer term. I don't think it's anything we're going to get after in the near term in terms of large capital outlay. The reason why we've always looked at this as an opportunity, it's always been on our radar, but I think the thing that's made us most excited is the 4D seismic data. We're seeing bright spots on that. From our perspective, we've got plenty to keep us occupied in the near term in Jubilee and TEN and the potential there. But I think the exciting thing is, once that opportunity set is exhausted, we've got other stuff to get after. I think our focus in the near term on the upside is around de-risking it, getting access rights. This is exploration, so it is technically risky. The beauty of it is the exploration cost would typically be $100 million a well to drill in that area. We can deepen one of our development wells at a cost of about $10 million. So we've got potential wells in campaigns two or campaigns three, that we can get after and de-risk that. In terms of the tax disputes, we are still working with the government, as we said. We have agreed with the government to defer the next arbitration, the third one, which is the interest arbitration. That was due in September. That's been pushed back. I think that's a signal, I think, that there is still intent from both parties to try and resolve this amicably, and discussions are ongoing. In terms of the provision, I'll hand over to Richard.

Yeah. The uplift in the provision is based on, I suppose, where we are with current conversations with the government and where we see the most likely outcome. We still have a material balance of receivables with the government that we would be looking to offset against in any discussion.

Okay, great. If I just may, just one further question, just because you mentioned a longer-term debt refinancing solution. Are there any particular operational or financial milestones you want to get past before you embark on a refinancing?

Yeah, I'll probably hand that over to Richard. I think we've got a clear timetable in place.

Yeah. I think, James, we've, I suppose as we've set out today, we've largely achieved most of those. We've had really strong operating performance. Production's been fantastic. Free cash flow guidance has been uplifted, both on production performance, but also the higher oil price environment. And we've also seen a material uplift in reserves. The focus now is to look to secure a longer-term refinancing during the second half of this year.

That's great. Very clear. Thank you.

Thanks, James. Our next question is from Stella Cridge at Barclays. Go ahead, Stella.

Hi there. Morning, everyone. Many thanks for all of the updates. If I could follow with a couple more questions, please. Firstly, I just wondered if you could talk about how production performance has been in Q3 so far, particularly in Jubilee, and what you are expecting going into Q4. The second thing I wanted to ask was, there had been some press reports that Ghana was looking to ask some of the partners in the fields to sell output into Ghana directly to supply local refineries. I was just wondering if that had been happening so far in the second half of the year. Finally, just in terms of the refinancing, thanks for the details that you just provided. Do you see yourself trying to diversify the capital structure, perhaps bank loans and bonds, or are you perhaps thinking a little bit more about refinance bonds? Any additional thoughts would be really helpful. Thanks.

Yeah. Thanks for those questions. I think I will hand the last two to Richard. In terms of the first one, production performance, yeah, it has continued to be strong in the third quarter as well. Good availability. Jubilee is performing well. We did bring those wells on at the back end of the program. That is what has given us confidence to say today that we are very confident we are going to be at the high end of our production guidance.

Yeah. On the first question, Stella, the government have done a great job with some private capital as well in improving refining capacity within Ghana. We have actually sold the first ever Jubilee cargo to be refined locally in Ghana earlier this year, which is a fantastic achievement. That refinery at Sentuo has now become one of the, I suppose, more prolific buyers, not just with Tullow, but across the partnership and also with government crude as well. But very much done on a commercial basis. But obviously, an improvement from a freight perspective in terms of underlying costs. In terms of how we're thinking about the refinancing, I think, looking at a trader-led solution as we have done in the past. So working with a trader to support a refinancing. Probably, in the first instance, looking to work with banks to put, I suppose, a more traditional European E&P cap structure in to achieve the lowest possible cost. But that planning is well underway as we look to execute something during the second half of this year.

That's fantastic. Many thanks for those additional details.

Thank you, Stella. That brings our Q&A session to an end. Thank you very much.

Thank you.