Harbour Energy plc

Good morning and welcome to the Harbour Energy 2025 Half Year Results. Today's presentation will be hosted by Linda Cook, CEO, and Alexander Crane, CFO. After the presentation, we will take questions. Linda, please go ahead.

Good morning. Welcome to our first half results call. With me today is our CFO, Alexander Crane. Turning to the agenda, I'll walk you through our operational performance, Alexander will cover our financial results, and then it's back to me to wrap up, and we're aiming to leave plenty of time for questions. But first, let me hit the highlights for the first half. Today's strong results reflect the continued execution of our strategy. The Winter Saldanha transaction, which completed 11 months ago, has significantly enhanced the scale, the resilience, and the longevity of our business. Perhaps the most obvious evidence of this is our production in the first half. At 488,000 barrels per day, it's almost three times where we were one year ago. These results are also supported by excellent underlying operational performance. Production efficiency was strong, our approved capital projects are on track, and we've made progress maturing our substantial 2C resources. At the same time, we demonstrated discipline when it comes to costs and capex, taking action to protect cash flow in response to a very volatile commodity price environment earlier in the year. We also strengthened our financial position, addressing near-term maturities and materially reducing net debt. The progress made in the first half enabled us to improve our cash flow outlook for the year, to $1 billion. As a result, we're pleased to announce that in addition to our interim dividend, the board approved a new $100 million share buyback. This will bring our expected total shareholder distributions for 2025 to $550 million. Moving on to operations. Safety remains core to everything we do in Harbor Energy. With respect to occupational safety, while we continue to be better than peer average. Our incident rate has increased since completion of the Wintershaw Daya transaction in September of last year, reflecting the different levels of performance in some of our new countries. And in process safety, we're running about average so far this year. So clearly, as always, more work to do in both areas. A key part of our integration process that follows each acquisition is to assess the safety processes systems, competencies, and culture in newly acquired locations. This helps us to identify any areas that are not up to harbor standards and to prioritize actions for improvement. For the Wintershaw DEA acquisition, this process is now complete, and we're taking steps to address the identified gaps and strengthen performance, in particular in new operations in Germany and Mexico. While it will take time to see real results, I am encouraged by the strong commitment demonstrated by our team across the company. In terms of emissions, the Wintershaw Day acquisition actually helped deliver a step-change improvement in our greenhouse gas intensity, which is now down by more than one-third to 12 kilograms per barrel, taking us below the peer average. Now on to production. As mentioned earlier, we averaged nearly half a million barrels per day in the first half, split roughly 35 percent Norway, 33 percent UK, and 15 percent Argentina, with the remainder from Germany, North Africa, Mexico, and Southeast Asia. The results, of course, reflect the acquisition, but they also reflect the impact of new projects and wells on stream, including in Norway, the UK, and Argentina, and also improved reliability. In particular, we benefited from strong delivery at our largest operated hubs in the UK, including from the Talbot project that started up in late 2024, and also from high local gas demand in Argentina. While some of our annual planned maintenance in the UK is now behind us this year, the majority is set for the third quarter across both the UK and Norway. As a result, second half production is expected to be lower than first half. Also contributing to this is the divestment of Vietnam, which closed on July 9th, and which averaged 5,000 barrels per day in the first half. But with a solid six months behind us, the uncertainty around our 2025 forecast is now reduced, and this gives us confidence to narrow our full-year production guidance upwards for the second time this year, this time to 460 to 475,000 barrels per day. Turning to the next slide, unit operating costs reduced by more than 30 percent to $12.40 per barrel, reflecting the addition of the Wintershaw DEA portfolio, strong production volumes, and an increased focus on costs, which more than offset the impact of a weaker U.S. dollar. Notably, our U.K. team has done a great job delivering top quartile unit cost performance. Unfortunately, however, as previously announced, we are again reducing our Aberdeen workforce. This is to align with lower levels of UK investment going forward, given the ongoing challenging fiscal and regulatory environment in the country. The reorganization will complete later this year and deliver cost savings from 2026. In terms of the acquisition integration, it's going well. We now have the keys to various Wintershaw Daya IT systems and are running those ourselves, and we remain on track to exit the transition services agreement by the end of this quarter. And then the second phase begins, the rationalization of these with Harbor's legacy systems, removing duplication and making us more efficient. While most of this effort will lead to savings only over 2026 to 2027, I'm pleased that we've already been able to leverage our increased scale with a couple key contractors to capture supply chain synergies, and there's likely more to come over time as additional contracts come up for renewal. Given the first half performance and outlook and the exit from Vietnam, which was the highest unit operating cost country in our portfolio, we're lowering our full-year OPEX guidance from $14 per barrel to $13.50. This is despite the not insignificant FX headwinds, which Alexander will talk about in a moment. Turning to the next slide in our capital program, we spent $1.1 billion in the first half and are on track to meet our previously narrowed CapEx guidance of 2.4 to 2.5 billion. Looking at CapEx on a per barrel basis, if we compare our full year 2025 outlook to the first half of 2024, which was before the acquisition. It's down 33%. In terms of focus, the money we're investing this year is largely aimed at converting 2P reserves into production, predominantly in Norway, the UK, and Argentina. In Norway, first half highlights include startup of the harbor-operated Maria Phase 2 project in May, and solid progress with other subsea developments currently in the execution phase, including Solvig Phase 2, a three-well tieback to Edvard Grieg, due online in the middle of 2026. Our harbor-operated Davala North project, where we recently completed installation of the umbilical and pipeline, keeping us on track for first gas late next year. And importantly, after one million hours worked, there were no recordable safety events. something our team is rightly proud of. And at Ossahaanstein, Equinor recently installed a new top-size module in preparation for receiving gas from the airport development towards the end of next year as well. In the U.K., we continue to focus on quick payback opportunities around our largest operated hubs, J Area and Greater Britannia, or GBA. Here we've significantly improved drilling efficiency. Our two J area wells online in the first half both delivered best-in-class performance. And in Argentina, at the Guadalpechana Este, or APE, concession, onshore Vaca Morta, we drilled nine 3,000-meter lateral wells in the first half with the 10th well drilled since then. And we successfully completed and connected six new wells, each with 50 fracs. Here, the operator continues to improve performance and has reduced total well costs compared to the 2024 campaign. We've now paused drilling on the license until early 2026 with sufficient gas from the existing wells to keep the processing plant at capacity and to meet local gas demand. In another success story, we also drilled a CO2 storage appraisal well in Norway. The well was a commitment well entered into by Wintershall DEA when securing the Hofstern storage license. It was drilled safely and under budget with top quartile performance and was also successful in terms of proving up the licensed CO2 storage capacity. So we're now moving on to explore various potential commercialization options. Turning to our 2C resource base. which includes a balance of short-cycle near-infrastructure investments, the scalable Vakamorta shale in Argentina, and longer-term conventional offshore growth projects. We're prioritizing efforts to focus on our best projects, enabling the high grading of the portfolio and to underpin long-term cash flow. In Norway, we prioritize the Goa subsea projects, where we target FID in mid-2026, and also development concept studies for the Cuvette, Adriana Sabina, and Storio discoveries. In the Vaca Morta, we've booked 600 million barrels of 2C resource, but see the potential to almost triple this. At APE in the gas window, we have 90 producers and 500 million barrels of booked 2C resource, but there's potential to significantly increase this with line of sight to 1,300 locations. What's needed, however, is a market for the gas, and that's why we've entered the Southern Energy LNG project. The two-vessel, 6 million ton per annum project took FID on the first vessel in May, making it the country's first LNG export project. It will provide our Vakamorta gas with access to global markets. as well as, through the new RIGI legislation, access to investment incentives and offshore U.S. dollar revenues. Startup of the first vessel is expected around year end 2027, while startup of the second vessel, approved by partners yesterday, is anticipated around year end 2028. Our second license in the Vaca Morta, San Roque, is in the oil window. Following a successful four-well pilot, we're preparing to apply for the unconventional license. And once received, it will enable development activities to commence. With around 1,000 potential well locations, we believe there's more than 500 million barrels of net resource to target, of which less than 100 million barrels is on our books today. In Mexico, our stakes in the conventional shallow water Zama and Khan projects together could yield reserves equivalent to more than two years' worth of our production, illustrating why these are priorities for us. After the recent successful appraisal drilling at the harbor-operated Con Discovery, we increased our gross resource estimate by 50 percent to 150 million barrels. Today, we're focused on development concept selection so we can move into the feed phase as soon as possible. And at Zama, with a 32% interest in gross resources of 750 million barrels, discussions with partners are underway around a potential phase development. Before I hand over to Alexander, it's worth underlining that the Wintershaw DEA acquisition not only delivered a step change in scale of our production, but also in the resilience and longevity of our cash flow. Over the next few years, we expect new production in Norway and Argentina, to substantially offset the managed decline in the UK, with additional support from Mexico from 2030. As a result, we're confident in our ability to continue to produce at scale and generate material cash flow well into the next decade. This is supported by our nearly 20-year reserve and resource life, with additional potential not captured here in respect of exploration success and M&A. And now, let me hand over to Alexander.

Great. Thank you, Linda, and good morning to everyone dialing in this August morning. I will start with a few financial highlights. Against a challenging macro environment, we delivered a strong set of financial results, reflecting a full six-month contribution from the Vintage Zaldea portfolio, an excellent operational performance. We materially increased the underlying earnings of our business, generated significant free cash flow, and we reduced our net debt. We also successfully pre-funded all maturities to 2028, further strengthening our financial position and have increased our full year free cash flow outlook to $1 billion. As a result of all of this, we are well-placed to continue to deliver against our capital allocation priorities and have therefore announced additional shareholder returns with a new 100 million share buyback program. Let's start with some market context on slide 13. The first half saw significant oil and gas price volatility driven by geopolitical and economic factors. Brent was 15% lower than that of the same period last year, averaging $72 per barrel. In contrast, European gas prices were 40% higher, averaging $13 per mBTU, or approximately $80 per BOE for those that prefer that. We continued to hedge our commodity price risk and were able to capture particularly attractive gas hedges during the period. whilst also taking advantage of brief periods of all price spikes to hedge some crude. We also saw a significant depreciation of the US dollar, which has weakened by almost 15% versus the euro, making it the worst start to the year for the US dollar in more than 20 years. This impacted our financials as we report in US dollars. As such, a weaker US dollar incrementally improves our free cash flow, as more of our revenue is in local European currencies than costs. However, the weakening of the US dollar also increases the US dollar value of our Euro-denominated debt, which you will see later. In summary, we expect continued volatility and uncertainty. As you can see from the graphs here, July was no exception, with US dollars strengthening again. And it is at times like these, a diverse portfolio, a prudent approach to risk management and an investment grade balance sheets are critical. Turning now to the income statement on slide 14. For the first time, we are reporting adjusted performance measures, which we believe provide a more meaningful comparison of the underlying performance of our business and brings us more in line with peers. You can read more about these adjustments in our financial statements. Post-hedging, we realized prices broadly in line with global benchmarks for our oil and European gas for the first half of 2025. Our realized European gas prices for the same period last year were impacted by lower legacy hedges, the last of which expired in the first quarter of this year at less than 50 pence per term. Our reported revenue and EBITDAX for the first half more than doubled, reflecting the step up in production and significantly higher realized gas prices. This was only partially offset by lower realized oil prices. In terms of costs, as Linda mentioned, our unit operating costs have reduced by over 30% year-on-year to $12.4 per BOE, supporting resilient margins. This reflects the addition of the lower-cost Ventes Aldea portfolio, strong volumes, and good cost control, offsetting the weaker U.S. dollar. Net financial items were impacted by the U.S. dollar movements I mentioned on the previous slide. resulting in foreign exchange losses of 0.5 billion, partly offset by gains on foreign exchange forward contracts to hedge our FX exposures of approximately 0.3 billion. There's a detailed note six to the financial statements for anyone looking for a breakdown of these financial items. Adjusted profit after tax for the period increased to 410 million, while adjusted earnings per share doubled to 22 cents per share compared to the first half last year. Now in terms of adjustments, there are three main items to note. First, impairment, which totaled 186 million, and are predominantly related to a small number of mature UK oil fields reflecting lower near-term oil price assumptions. Secondly, foreign exchange losses of 193 million due to the revaluation of intercompany balances driven by the weaker US dollar. To be clear, this is a purely intercompany effect we are adjusting for. And thirdly, we've adjusted for the 300 million charge related to the extension of the energy profits levy in the UK. So collectively, these three adjustments result in an adjusted tax rate for the period of 80%. This is more in line with what you would expect given the 78% statutory tax rates in Norway and the UK. Turning next to cash flow. During the period, we generated 3.8 billion of operating cash flow. We spent 1.1 billion on total capital expenditure, and we paid 1.4 billion of taxes. We also benefited from a 0.2 billion working capital movement. This resulted in a very healthy free cash flow generation of 1.36 billion for the first half, significantly de-risking our improved 1 billion full-year free cash flow outlook. Further, our dividend is now covered down to prices of $35 per barrel Brent and $8 MCF European gas in the second half of the year. The first half weighting of our free cash flow reflects the Q3 planned maintenance programs, higher capex in the second half with increased activity in Norway, and an expected part reversal of the positive 200 million working capital movement. However, the largest driver is timing of UK tax payments, with first half tax payments equating to around 40% of the total expected payments for the group for the year. We've also been proactive with our debt refinancing, with net bond issuances amounting to $1 billion during the period, and repayment of our RCF such that we were undrawn at the period end. I will now turn to the bond issuances in more detail on slide 16. During the first half, we issued 0.9 billion dollars of senior notes and 0.9 billion euro of subordinated notes, concurrently repaying 0.3 billion of legacy high yield bonds and 0.6 billion euro of the subordinated notes. This means we were able to effectively pre-fund all our senior debt and subordinated note maturities to 2028 and strengthening our balance sheet with an additional layer of subordinated notes. Thanks to the very strong free cash flow generation in the first half, we reduced net debt by 0.9 billion to 3.8 billion and leveraged to 0.5 times, comfortably below our internal one times target. The impact of the weaker US dollar, which increased the value of our pre-swap euro-denominated bonds by 0.7 billion, was partially offset by the net addition to cash balances of 0.4 billion from the subordinated notes issuance and repayments. Now further, at June 30th, we benefited from a 0.2 billion mark-to-market gain on our cross-currency interest rate swaps. This offsetting gain is not included here in the net debt calculation. Whilst we only have about 20% of our debt denominated in US dollars, on a post-swap basis, our debt exposure to US dollar is now around 60%. This mimics our US dollar versus Euro and British pound revenue, with approximately 40% of our production being European and UK gas. We ended the first half with over $5 billion of liquidity, and having pre-financed all maturities to 2028, we're in a strong financial position. Moving to our free cash flow outlook for the rest of the year on slide 17. We've increased our free cash flow outlook to $1 billion, driven by our continued strong operational delivery across the board further offsetting the impact of lower commodity prices. As a result of this, in our strengthened financial position, we are pleased to announce a new $100 million buyback. Along with our $455 million annual dividend, this means that roughly half of our free cash flow in 2025 is expected to go towards reducing our net debt and the other half to our shareholders. And our sensitivity to movements in Brent and European gas prices for the year remains the same. Before I move to our guidance, a quick look at our commodity hedging on slide 18. Our strong financial position and balance sheet is supported by the diversity of our revenue mix. In addition, we aim to hedge approximately 50% of our economic exposure to commodity prices in year one and 30% in year two. We use both swaps and non-linear structures. This helps to protect our cash flow through the commodity price cycle whilst maintaining upside participation. For the 18 months through to the end of 2026, we've hedged approximately 40% of our economic exposure to Brent and 50% of our economic exposure to European gas prices. As you can see from the graphs on the right here, we've locked in some good pricing above the forward curve, leaving us with a pre-tax mark-to-market position of around 0.4 billion as of June 30th. So what does this mean for our guidance and outlook? Well, we've lifted the lower end of production guidance for the second time this year, now set at a range of 460,000 to 475,000 barrels of oil equivalent per day. This reflects continued high reliability across the portfolio, increased production from our operated UK portfolio, and strong volumes from Argentina. Collectively, more than offsetting the impact of the Vietnam divestment. APEC's guidance has been lowered to $13.5 per BOE, despite a weaker US dollar. This reflects strong cost control year to date and the sale of the higher cost Vietnam business post period and as mentioned by Linda. We are reiterating our previously narrowed total capex guidance of 2.4 to 2.5 billion as we continue to challenge our portfolio and high grade it. And as mentioned a couple of times already, we have increased our full year outlook for free cash flow by 100 million to 1 billion, enabling us to increase expected shareholder distributions to 555 million for 2025. Now, my last slide is just a reminder of our capital allocation priorities, all unchanged from our update earlier this year. We will continue to invest in our business to improve our portfolio, prioritizing our best and most competitive projects. We will deliver attractive through-cycle shareholder returns, as further evidenced by today's 100 million buyback announcement, meaning we will have returned 1.8 billion since listing in 2021. And all of this while maintaining financial discipline. So thank you. That's all from me, and I will now hand you back to Linda.