BlueNord ASA

Good morning and welcome to Bluenord's results presentation for the first quarter of 2025. Over the next 30 minutes or so, we'll walk through our performance for the quarter, share our outlook and explain why we continue to believe Bluenord is well positioned, both in today's market and over the longer term. But before we get into the slides, I'd like to start by speaking a little bit about Tyra. We have made real progress in 2025. More wells have been commissioned, more wells have come online, and reservoir performance has been consistently strong, culminating in net production from Tyre exceeding 26,000 barrels of oil equivalent per day earlier in May. However, it's also fair to say that above ground performance has not yet met expectations. Several unplanned outages impacted uptime and as a result, Tyra has not yet reached a consistently steady operational state. Ramp up to plateau has therefore taken longer than expected. So where are we today? Up until last week, production was steadily increasing and we'd reached our highest daily output from Tyra yet. Unfortunately, a short unplanned outage then temporarily shut down the facilities and we're now back in the process of ramping production back up to those prior levels as quickly as possible. And where do we go from here? First, it's important to acknowledge that some level of disruption was always expected when bringing a project of Tyra's scale fully online. That said, it's also clear, and we're fully aligned with the operator on this, that facility performance needs to improve. Miriam will shortly outline the concrete steps we're taking, but I also want to be clear. Our shared priority is to stabilize operations and unlock the full potential of the Tyra hub. That's critical because the subsurface continues to outperform. The reservoir is strong, and that would have been a far more difficult thing to fix. These surface issues are of course frustrating, but they are solvable. And once they are, we'll be in a strong position to deliver the long-term value Tyra was designed to provide. And with that context, let's turn to the first slide and look at some of the key highlights for the quarter. So let's begin with base production. Across DAN, Halfdan and Gorm, we averaged 20.9 thousand barrels of oil equivalent per day in Q1, fully in line with guidance. This continues the predictable low decline performance that we've seen for several years now. And looking ahead, we expect this to be further supported by ongoing optimisation activity through 2025 and beyond. During the quarter, we also revised the timing of our next infill wells, which are now scheduled for 2026. This reflects two key factors. One, the sustained above-expectation performance from the Harold East Middle Jurassic well, and two, a clear focus on maintaining cost discipline and our disciplined approach to near-term capital allocation. This action in itself will reduce Bluenor's 2025 capex by roughly $50 million. And if we now turn again to Tyra, so while Q1 production averaged 8.9 thousand barrels of oil equivalent per day, by early May we had reached over 26,000 barrels of oil equivalent per day net to Blue Nord. And that's within our steady state guidance for the hub, which is defined by gas export being constrained at approximately 250 million standard cubic feet per day. So far, for that 26,000 barrels a day of oil equivalent, that reflects only around 70% of the total gas export capacity. The strong production levels have been driven by better than expected liquid volumes, and that's a clear signal that there's more to come from Tyra as we optimise the production. Once at full production, we expect Tyra to remain at plateau throughout 2025 and well into 2026, supported in particular by the continued outperformance from Harold East Middle Jurassic, which continues to significantly outperform our original expectations. On the financial side, Q1 performance was solid, although it was impacted by lower than expected Tyra production and one-off penalties related to gas nominations. These gas nomination costs are one-off in nature, and once Tyra is steady state, we do not expect these to reoccur. Still, our outlook is strong. With Tyra ramping up, we expect material increases in cash flow going forward. During the quarter, we also released $158 million of cash from escrow. And as a result, we're ending Q1 with $684 million in total liquidity, a combination of cash on hand and undrawn RBL capacity. So that gives us a strong platform to deliver on our key objectives. And with that, let's turn to the next slide and discuss objective number one, distributions. So while the cash flow we generate, particularly as Tyra reaches and maintains Plateau, supports all our stakeholders, our near-term focus is on returning meaningful value to shareholders through distributions. And the capital structure that we have in place gives us the flexibility and financial strength to deliver on this core commitment. Following our proposed 2024 distribution of $215 million, we're today proposing an additional $38 million for the first quarter of 2025. Both of these distributions sit at the top end of our policy range, representing 70% of net operating cash flow for the relevant periods, and that's a clear signal of our intent. It reflects our confidence in the business, our operational progress, and the strength of our cash flow. On the previous slide, we talked about what Tyra means from an operational standpoint. But Tyra is also the key that unlocks our distribution plan. It enables us to start making these returns a reality, and the threshold here is meeting the Tyra RBL completion test. Based on continued stable operations, we now expect to satisfy this test in early June, and once met, we'll be able to formally declare and pay these distributions, the first of which will total $253 million, covering both 2024 and Q1 2025. Now, if we turn to the next slide, I'd like to focus a little on the features that we believe position us particularly well in the current environment. Blue Nord is a business with a very clear and very focused strategy. Our objective is to maximise the cash flow from our producing asset base and then use this to underpin our material capital returns programme. We deliver on this through strong operational performance, through maintaining a conservative capital structure and through being proactive in looking for opportunities to manage risk and our exposure to volatile markets. The first few months of 2025 have been marked by significant commodity price volatility. But that's not new. It's a fundamental feature of the industry we're in. And that's why it's important to have a business model that thrives when prices are strong and remains resilient when they're lower. We believe Blue Nord is positioned to do both. And here's why. First, we're becoming a low-cost producer. Once Tyre is at plateau, our lifting costs drop to below $13 a barrel. Second, we're proactive. We took steps at the start of the year to adjust our cost base and lower our capex spend for the next 12 months. And third, we continually look to lock in future commodity prices when we think it's attractive to do so. We've added hedges, particularly during Q1, that will significantly improve our cash flow outlook. These things combined give us the stability to maintain a consistent equity story, one that will see us return 50% to 70% of our net operating cash flow to shareholders until the end of 2026. Now, I'd like to hand over to Miriam to provide some further details on our operations. Thank you.

Thank you, Euan. Today, I will take you through how we achieved the strong production for the base assets for the first quarter of 2025 and share the outlook for the remainder of the year, along with the updated Blue Nord production guidance for 2025. We have initiated a higher level of plant integrity work to ensure the facilities maintain high operational efficiency. This quarter, work has been carried out on GORM. As Eon mentioned, we have made strategic operational decisions to optimize the RUM workover and drilling program. I will provide more details in the presentation today. Then I will update you on the status for TIRA and the updated BlueNord guidance for TIRA for 2025. Let us first look at the production performance for the base assets for Q1 and the activities for 2025 supporting the production. I'm pleased to share that the Q1 production from the base assets of 20.9 MbuE per day net to BlueNord is meeting our guidance range of 20 to 22 MbuE per day net. The quarterly production was achieved despite a slower ramp up of GORM production after completing the planned integrity scope. I want to highlight the fact that we now have consistently met or exceeded our guidance for the last 17 quarters. In March, the installation of a flare recovery system was completed on Gorm, resulting in a reduction in flare on Gorm of approximately 30%. An evaluation of the performance of this project may enable flare recovery on Haftan. The ROM campaign on Haftan commenced in January 2024 and was successfully completed in January 2025 with 21 interventions on 20 wells. The Nobel Reacher rig is currently at the Haftan Northeast ACA platform executing the gas lift project, which will enable stable production for longer from the Haftan Northeast gas field. Workovers were successfully completed from the Shelves Drilling Winner on Halfdan in early 2025 to Safeguard Production. The Shelves Drilling Winner has been moved to DanFF, where several high-opportunity workovers are being carried out until mid-August 2025, adding volumes to 25 production and beyond. We have updated our 2025 production guidance for base assets to reflect the following strategic operational decisions based on ongoing efforts to reduce near-term costs. First, to optimize ROM work by completing the scope from the platforms. Two, to delay the drilling of the Valdemar Upper Cretaceous Well due to the success of the Herald East Mill Jurassic Well extending the tyre plateau. And third, to delay the Hafta and Ecofisk infill wells to mid-2026, providing direct learning opportunities to Valdemar Upper Cretaceous, reducing both time and cost. These decisions support the release of the two rigs. The deferral of 2025 production from the delayed infill wells is impacting Q3 and Q4 production guidance. However, there is an uplift from the DanFF workovers. Round 3 on GORM is planned to commence in Q3 from the platform. So in summary, production from Q1 was strong and we will maintain focus on keeping operational efficiency high despite production deferrals due to a higher level of planned integrity work. Let me now take you through the rationale for the strategic operational decisions. In a strategic move to optimize operations and reduce near-term costs, the decision has been made to release the self-drilling winter rig and not extend the noble reacher rig. These decisions build on the success of recent initiatives and focus on achieving significant near-term cost savings with minimal impact on our operations. The decision to release the rig is based on the success of the recently drilled Harold East Mill Jurassic Well, which is estimated to have extended the production plateau for Tyre by at least 10 months. This extension has consequently pushed the Valdemar Upper Cretaceous Infill Well out in time. Additionally, the two Haften Ecofisk infill wells are planned to be drilled in a campaign just before the Valdemar well delaying this campaign to mid-2026. Drilling these infill wells consecutively will provide direct learning opportunities, reducing both time and cost. In the five months leading up to the rig's release, a Dan FF Workover campaign with several high-opportunity wells has been included in the work program to be completed by mid-August 2025. Letting the rig go positions us to capitalize on future opportunities in an open market where cost savings can be realized when a rig is required mid-next year to commence the planned infill drilling program to support a low decline rate. The Noble Retail Rig was initially contracted back in 2022 to address a backlog of maintenance that had accumulated over some years of reduced activity. Over the past two and a half years, a combination of maintenance and ROM initiatives have significantly reduced this backlog and improved production performance. Several wells on DAN have been successfully brought back into production, and the executed run work on half-DAN have shown promising results. One of the key advantages of transitioning maintenance and well intervention from rig-based operations to platform-based solutions is a substantial cost reduction. By integrating new lightweight equipment, coil tubing interventions can be executed directly from the platform, eliminating the need for additional rig mobilization costs and saving time. The first platform-based ROM campaign is scheduled to commence on GORM in Q3 2025. Deferring the half-dan infill well from 2025 to 2026 is expected to generate a net positive cash flow of $13 million for BlueNord. Additionally, transitioning from RIC to platform-based ROM could add $11 million net to BlueNord. Jacqueline, our CFO, will give you more insights into CapEx spend for the year. And now let us look at the status of Tyra and an updated Tyra guidance for 2025. Tire is currently on stream and continues to ramp up, although the progress is slower than expected. We delivered tire production of 8.9 MbE per day net, which is below guidance of 26-30 MbE net for the quarter. The slow ramp-up is mainly due to minor operational issues like the one occurring 8th of May, but also a few incidents requiring longer shutdowns, like the damage to the mechanical seal on the IP compressor, halting the production circa two weeks in January, and the breaker failure impacting the LP compressor for circa four weeks from early March, where it was not possible to commission wells during the repair period. It is important to mention here that a change in production mode enabled production from Harald during the breaker repair, resulting in a gas export of around 30% of plateau rate, supported by the successful Harald-East middle Jurassic well. But despite the slower ramp-up, I want to highlight that the recent peak production level from the tyre asset was approximately 26 MbE per day net, which is around 90% of the BlueNord estimated plateau rate of 30 MbE per day. Delivering 26 MbE per day net with less than 50% of the wealth being online is a significant achievement and due to a better reservoir performance than estimated. The estimated oil plateau of 32,000 barrels per day gross was reached in early May after bringing Valdemar A wells online, which are wells that are more weighted towards liquids. At present, the gas export rates have had room to increase by more than 30% before reaching the maximum capacity, which is driven by the gas processing on Tyra being constrained by the IP compressor. To achieve this, we need more gas-weighted wells online and stable production. The Tyra production guidance is based on reaching the plateau for both gas and liquids in May and maintaining stable production through 2025. The guidance for Q2 has been slightly revised based on April performance and reaching plateau in May. Now let us look at the status for the tyre wells and the work being undertaken to ensure stable production. Recently, the tyre acid peak production was above the lower end of the tyre guidance for stable plateau production. This was achieved with 91% of wells commissioned and less than 50% of the wells on production. As mentioned earlier, this means that the reservoirs are delivering above expectation and we were already producing at our estimated oil plateau rate. However, to reach plateau production in May, we need 1. to increase the production potential of the tyre asset and 2. to achieve stable operations and high operational efficiency. In order to increase production potential, wells are being commissioned and subsequently put on production. We have almost completed the commissioning of the wells. The remaining wells to be put on production have minor issues, which is to be expected after more than five years of being shut in. Plans are in place to fix these issues, including gas-lift valves, chokes and hydraulic issues. Regarding achieving stable operations, the operator Total Energies are undertaking a reliability study to identify and address key factors impacting the facilities and thereby the operational efficiency. The study and subsequent actions are supported by specialist vendors. To conclude the operations piece today, I can confirm that the continued focus on tire progress, our strong Q1-based assets production, and the optimization of big activities to save near-term costs with minimal impact to operations are all key components of our strategy for 2025. Together with the operator, we are committed to achieving these operational objectives. I will now hand over to Catherine, our Chief Corporate Affairs Officer, who will present the long-term outlook for BlueNord. Thank you.

Thank you, Miriam, and good morning to everyone. I will now take you through the role of Blue Nord in Denmark, the wider EU, and also how we will deliver into the energy needs and contribute to security of supply. With Tyron Stream, we are one of the largest oil and gas producers in the EU. And Denmark is a net importer of natural gas, having been a net importer since 2019. From an emissions intensity perspective, piped gas is undefeatable considering the alternative energy source of imported LNG. You can see this clearly demonstrated on this slide. And from a security of supply perspective, last week the European Commission published their Repower EU roadmap with an intent to ensure EU's full energy dependence from Russia. As regard to gas, the upcoming proposal will improve the transparency, monitoring and traceability of Russian gas across the EU markets. New contracts with suppliers of Russian gas, both piped and LNG, will be prevented. And existing spot contracts will be stopped by the end of this year. This measure will ensure that already by the end of this year, the EU will have slashed supplies of Russian gas by one third. The Commission will further propose to stop all remaining imports of Russian gas by the end of 2027, all of which will impact the European gas markets in the future. This further underpins the strategic importance of the underground assets in the DUC and its current and future contribution in an EU context. Our license expires in 2042 and an extension of this can be key to further enable a full utilization of existing and future projects. For example, TyRA is only constrained by the license expiry. Maximizing the economic recovery during the next 25 years is not only important from an energy security perspective, it's also very important to Denmark. The oil and gas industry is one of the biggest contributors to Danish welfare. And the Danish think tank Erhvervslivets tenketank recently estimated the industry to deliver state revenues of circa 55 billion Danish kroner during the next 25 years. This is an upside of an additional 11 billion Danish kroner if further known resources are developed and utilized. And this takes me to the next page where we show the resources that sit in our portfolio. As Miriam mentioned, we have re-phased the drilling program of infill wells. This was a result of cost optimization and a reduced need of near-term additional volumes due to the success of the HemJ well, which will increase Tyra Plateau significantly. Despite this, the infill well opportunities are still in the plan to be drilled, with three wells matured to a 2P stage, two on Halfdan and one on Valdemar. These three wells have strong economics, with a unit development cost of less than $13 per barrel. And with the additional potential of infill wells, both on Svend and especially around the Taira hub, we have more than 21 million barrels in 2P reserves and 2P resources from infill drilling opportunities. In addition, we have three impactful development projects, Taira North, Halfdan North and Valdemarbo South. These require simple infrastructure with unmanned platforms and all three can be tied back to existing processing facilities. This allows us to utilize our infrastructure and it also supports the projects being competitive from a price point, especially with unit technical costs below $20 per barrel. Tyra North and Halfda North have already been progressed sufficiently to be partially included in our 2P reserves and together the three projects add significantly to our reserves and resources by circa 45 million barrels. And with the optimized drilling schedule mentioned and the expected contribution from the HemJ well, the production profile we show every quarter has some changes to it. We start at the bottom in blue, where we have the base assets continuing to deliver a stable production. Production from Tyra in dark blue was limited last year, and this year will be the first meaningful year of production, followed by an even more impactful contribution next year. As you can see in 2027, output from Tyra is also very high, and this is partially driven by the significant contribution from the HemJ well. In green, and especially from 2027 and onwards, we see the re-facing of 2P projects, and these will be significant contributors to maintaining BlueNord's output high from the year of 2027. During the same time, the near-term projects, currently 2C resources in dark grey, supports an above 50,000 barrels per day production for the company. And finally, we have less mature 2C projects in light grey, which have the potential to lift production closer to 60,000 barrels per day in 2029 and 2030. So the revised production profile, which previously had us exiting the decade at around 40,000 barrels per day, will now maintain a circa 50,000 barrels per day production. This will further support cash flow generation and distributions to shareholders, while at the same time deliver into the energy needs of Denmark and Europe. And I will now leave the word to our CFO, Jacqueline, who will take you through our financials.

Thank you, Katrine. So Ewan shared reflections on the quarter and the key highlights, including our path to plateau on Tyra, despite some challenges this quarter. He also shared our proposed distribution for Q1 2025 of $38 million, which is at the upper end of our policy. The strong base asset portfolio continues to deliver, and Miriam outlined some sensible, cost-effective adjustments to our work program for 2025, which makes sense in the current commodity environment. I will share more on the outlook for spend in 2025. And beyond Tyra, we have our portfolio of opportunities that Katrine presented, which are critical to Danish and European security of energy supply. So with that in mind, I will now take you through the financial results for the first quarter, underpinned by the operational highlights you've just heard about. So Q1 2025, underlying financial performance shifted down when compared to the fourth quarter. As Miriam outlined, underlying asset operating performance continues to be stable and Tyra volumes are increasing. And this can be seen in the revenue mix as well. However, due to some operational issues that were discussed earlier during the ramp up of Tyra, we have been affected by penalties on gas sales. This is driven mainly by unexpected changes in production when compared with our gas nominations. Now, as also mentioned by Ewan earlier, this is non-recurring, and once Tyra is stable, these penalties will diminish. So the impact on revenue of the penalties in the first quarter was approximately $11 million. Excluding this impact, we have lower overall sales volumes due to lower oil sales with the reversal of the over lift from Q4 and higher inventory, and this has been partially offset by higher gas volumes with Tyra ramping up. The over lift and inventory movements are timing related. So the effective oil and gas sales prices are consistent quarter on quarter. However, if we exclude the penalties, the gas pricing is actually closer to 45 euros per megawatt hour. Revenue for the first quarter is $171 million compared with $193 million last quarter. Underlying operating costs are consistent. However, partly due to the change in the work program that Miriam took us through, we have higher costs related to workovers during this quarter, and that was approximately $14 million. There were no workovers in the fourth quarter, and we expect to now have workovers during Q2 as well and part of Q3 until the end of the RIG contract. These are also adding to production, as Miriam mentioned in the production guidance for base assets. This higher OPEX is more than offset by the lower CAPEX cost, as you heard earlier, where we have delayed the infill wells that were scheduled to be drilled in 2025. I will cover more on CAPEX when we discuss cash flow shortly. OPEX for the quarter is $89 million, and OPEX per BOE on average is $33 per BOE. As a result, the overall contribution margin has narrowed in the first quarter but continues to be positive. Reported EBITDA is $80 million in the quarter, compared with $109 million in the fourth quarter. If we exclude the full year adjustment to ROM of $19 million from Q4, this brings the comparison to $90 million in the fourth quarter. So turning to the summary income statement, you can see the full earnings position now. And as outlined on the previous slide, EBITDA has decreased with lower revenue and higher OPEX when compared with the prior quarter. Again, if we exclude that full year adjustment from ROM and do that comparison, it is $80 million of EBITDA versus $90 million. The positive other production expenses, just to note, is mainly due to the reduction in overlift of oil, as mentioned as a part of revenue. So when adjusting primarily for the penalties on gas, our adjusted EBITDA, as reported, is $92 million. Below EBITDA, depreciation continues to increase as we now have TIRA volumes. We then have net financial items, which are affected primarily by the non-cash fair value movement of the embedded derivative in the BNOR15 convertible bond. In contrast to the last quarter, this went from a loss of $54 million to a gain of $13 million. As you can see, the valuation, it is very sensitive to the share price. And finally, a further non-cash volatility on the income statement is on tax expense. As with the last quarter, this is mainly driven by the foreign exchange movement on the tax losses, which are denominated in Danish krona, and this must be revalued each period end. This quarter, there is a positive effect of $17 million, compared with a negative of $58 million in the previous quarter. Due to the size of the balance, movements in the Danish kroner to US dollar do have a large effect. However, the underlying current tax expense is as expected. Overall, we ended the quarter with a net profit of $19 million. If we now consider the balance sheet, the main items to highlight relate to cash, working capital and derivatives. On cash, we are pleased to report a significant increase connected with the release of $158 million from restricted cash in relation to the cash call security with Total Energies. This cash security has been replaced with a $100 million letter of credit under the RBL facility. Regarding working capital, the higher receivables and payables are due to higher volumes of gas sold. This quarter, we also made our annual prepayment of insurance for the year and have higher oil inventory at the quarter end. Derivatives have moved in the opposite direction to last quarter with lower liabilities and higher assets. This is again tracking the trend of commodity prices by the end of the quarter. This reflects the downward movement in oil and gas prices since the end of the fourth quarter and compared with the prices we have contracted. So now turning to cash. We report an operating cash flow before tax of $70 million this quarter compared with $146 million last quarter. Operating cash flow is down since the last quarter due to the underlying business performance with lower oil sales volumes and higher costs, as well as working capital impacts. We paid $15 million of tax this quarter and have finance costs of $35 million related to the RBL facility and the BNOR16 bond. In addition, there is a significant inflow from the release of restricted cash, giving $178 million of cash inflow before capital spend. And as mentioned earlier, with the change in the work program and the plans for the rest of 2025, the capital spend for the quarter is significantly lower at $15 million compared with $63 million in the previous quarter. We now expect that capital investment will be around $50 to $60 million for the full year 2025, which comprises mainly of maintenance capex, the revised ROM work plan, and some other small projects. Overall, we finished the quarter with a net cash inflow of $164 million. This supports our liquidity position, which is strengthened to $414 million of cash available and $270 million of undrawn RBL facility, bringing our total closing liquidity to an increased position of $684 million. We did not have any changes to the capital structure this quarter and we maintain a slightly lower net interest bearing debt balance of $1 billion. Moving to the commodity price environment and how we are managing exposure now. So we continue to use hedging as a way to provide visibility over future cash flows and we add volumes where it makes sense to do so. Our focus for hedging has been mainly in gas this quarter, particularly when prices peaked with the Tyra volumes picking up. And our focus has been across the 25 and 26 seasons. However, if we take oil first, the average hedged oil price in the outlook for 25 is $73 per barrel, which provides good downside protection for this year. Positions for 26 and 27 will slowly be contracted as we monitor the market direction for good opportunities to hedge. For gas hedging, this period we have been able to secure a significant level of hedging whilst prices were attractive, adding approximately 38% more volume for the rest of 2025, and the prices averaged around 40 euros per megawatt hour. This has increased the average price per season as shown in the chart and remains consistently above the spot price in the year ahead. So we will continue to take advantage of the market and add hedges when it looks attractive to do so and of course within our policy. So to summarise the first quarter of 2025 from a financial perspective, our performance reflects a stable underlying asset base that supports our balance sheet. Tyra is ramping up and beginning to contribute to our earnings and cash flow. And once Tyra is stable with the revised work program for 2025 and underpinned by our excellent base hedging position, we expect a strong cash flow and earnings year. This underpins our ability to continue to deliver on our priorities. And with that, I will hand back to Ewan for closing remarks.

Thank you, Jacqueline. So to wrap up, you've now heard how the business has performed over the first three months of 2025. And before we move to Q&A, I want to leave you with three key takeaways. So firstly, Tyra's delivering. We have seen a steady ramp up in production with volumes increasing and the underlying reservoir continuing to exceed expectations. This performance gives us confidence, not only in the asset, but in the momentum it provides for the business as a whole. Second, we're close to executing on our distribution plans. With improved Tyra performance, we're approaching the point where we can formally declare and pay the $253 million in distributions proposed for 2024 and Q1 2025. That's a major milestone for the company and our shareholders. And third, our business remains robust. We're well positioned to manage through any near-term commodity price volatility. Our cost structure, proactive approach and hedging strategy all support resilience. And our commitment to returning value through our stated distribution policy remains firm. So thank you all for joining us this morning. We'll now pause briefly to allow any additional questions to come through and then we'll return shortly to continue the discussion. Thank you.

How big will the dividend be in 2027 and beyond? Can you please be a little more specific than meaningful?

So our focus at the moment is on the period to the end of 2026 and what our dividend policy looks like from 2027 onwards will obviously be subject to a number of factors that we'll know more about closer to the time. However, what I can say is that we would expect this policy to move to be more in line with where, frankly, some of our peers are. So if our policy is 50% to 70% of operating cash flow to the end of 2026, from 2027 onwards, we'd more likely be targeting something like 20 to 30% of operating cash flow.

And how is the company planning to deal with the convertible bond and when? Before or after the proposed dividend payment, especially given that the convert will be re-striked by that dividend payment? And what is the company's intention regarding this?

So we are actively considering how we may be able to restructure the convertible bond in a way that addresses the factors that have been outlined. I think it's fair to say from a company perspective we would like to come up with a new structure and a new solution. We'll of course look to have a solution in place prior to the first distribution. but equally achieving something here is not going to impact the timing of the first payment. So we're still going to declare and pay the distribution at the first opportunity irrespective of whether we have a solution for BNR15 by that point.

Can you please clarify if the company intends to pay the 250 million and the 38 million all in the form of dividends or is there an intention for part of this to be a buyback?

So we will finally confirm this closer to the time and once the completion test is met. However, our current intention is that the entire distribution, the $253 million, will take the form of a return of paid-in capital.

And then we have several questions about the same topic. Do you plan to make an extraordinary distribution outside the policy to distribute $258 million of cash received from the escrow release?

So I guess I'm going to start answering that question by kind of re-emphasizing something that hopefully has come across not just this morning, but in our story throughout, which is that our focus is very much on maximizing distributions to shareholders. However, we do also want to make sure that we maintain a conservative balance sheet. And as part of that, we need to be conscious of our leverage position while we are still in the Taira ramp-up phase. That said, our starting point is that we don't require a liquidity position of close to $700 million. And of course, we will consider the potential for an extraordinary distribution going forward and at the time when the RBL completion test has been met.

And should we expect 2025 dividend in the upper end of the 50% to 70% of the operating cash flow guidance?

So the first two proposed distributions that we've announced at 70%, I think pretty clearly signal our intent. We're going to continue to start from that place so long as our balance sheet supports it. But as we go forward, obviously, we'll have more definition around what the right level is.

Will we be seeing a higher dividend for the remaining quarters in the year of 2025?

Yes, that's what we'd expect. With Tyra at plateau, we will have significantly higher operating cash flow and that will drive, based on our 50 to 70% distribution policy, higher dividends on an absolute basis for the rest of 2025 and 2026.

Then a few questions related to the gas penalties. Some colour on the extent of gas price penalties in Q1 and are there any in Q2 or the rest of the year?

Yeah, so I think I mentioned in the presentation, so for Q1, it was $11 million that was impacted with gas penalties. So I guess maybe for context first, we do have some of these challenges with stability on Tyra. So when there are changes in the production expected, that does have an impact then depending on what we've nominated for gas. So there is some flow-on effect. Obviously, you've seen some of these changes or these stability issues arising in this early part of Q2. So that will have some impact. Again, as things stabilise, I do expect the level of penalties to diminish, of course. And once we're stable, that we shouldn't see that at all. So in that respect, it's clearly non-recurring as a part of our underlying business performance.

And how do you think around gas hedging when Tyra now is very close to plateau?

Yeah, so we continue to manage and monitor hedging with Tyra volumes in mind and looking forward. So that is obviously a part of how we do that. So it's a part of the planning of the hedging portfolio.

2025 capex corresponds to around $3 per barrel. Is that a level where we should expect 2026 and 2027 capex?

I mean 2025 is quite a low level of capex. There's very minimal maintenance capex in there. So I think in principle we would expect it to be higher in 26 and 27 when you consider the infill wells then being drilled and of course the work on the development projects picking up. So I would expect a higher level but currently not guiding specifically on the capex for 26 and beyond.

I think on that one, I think it's just worth also saying that as you've seen this quarter, we've taken decisions where we've looked at the outlook and decided to reduce capex. So I think that's the intention for sure. But I think as we get closer to the time, obviously we'll be able to make a more informed decision around what the right level of spending is.

And Miriam, should we expect any revision of peak rate expectations given the CEO says Tyra beating performance expectations? And is this outperformance a temporary flush production effect or something more permanent?

So there is an element of flush, and this may lead to slightly higher peak rates. And we also have more than 50% more wells to bring online. So this gives us confidence that we can deliver at our plateau level. And as highlighted, it's good to see vessel performance significantly above expectations. The gas export will be constrained by the IP compressor capacity. So if we get more gas in, we will just extend the plateau production.

You have yet another penalty of gas delivery as you had for some quarters ago. Is this so complicated that you cannot mitigate this?

It certainly has some complexity and it's mainly driven by the way nominations have to work. So they are done six weeks in advance. So I guess just to give that context, it does mean you have to take a little bit of an estimate on what the future holds. And as you could see, we did have some instability on Tyra with the volumes. But of course, that is something we then work on how we can mitigate that and more actively managing it as a part of our nomination process. So that's what we're doing going forward to mitigate.

Congrats on the strong results. Five questions for me. Based on production last days and weeks, what is the best case for when the completion test could be met?

So looking at where we are right now and also seeing the different issues that we have, we're looking into early part of June to be able to meet the completion test.

When do you expect 100% of tyre wells to be commissioned? Can you elaborate what kind of issues you're seeing on the remaining wells?

So we can say just splitting this out. So we have the commissioning of wells, so getting them ready to flow. We are almost there. So we said 91%, so basically seven wells to be commissioned yet. That is going to happen in a very short time. And then we have, like I said, we have around half of the wells or less than half of the wells on production. So the rest of them, after being shut in for five and a half years, they have different issues with the chokes, with the valves and other things. And these are operational things that they will fix as soon as they meet them. So we are talking quite a short time, but they won't see the issues before they try and flow the valves.

And which of the three subsea tiebacks could be the first natural candidate to reach FID?

That is absolutely the Tire North project.

Do you expect to pay the proposed $215 and $38 million separately or all in one go once the completion test is met?

All in one go.

Was the requirements for the escrow release materially different from the Tyra completion test? Can you elaborate on the requirements for the escrow release?

Yes, they are different tests. There were certain requirements around the completion of Tyra as a project for the escrow release. It's not linked to the production that is then delivered from Tyra. That's the main difference there.

Has lower commodity prices impacted the dividend capacity under the RBL facility, i.e. has the banks revised its price deck to a level where dividend payments will be restricted at some level?

We don't see that as causing an issue at this point in time. We obviously do a liquidity test ahead of being able to pay the distributions, but that is a combination of the price deck as well as the forward prices and, of course, our hedging that's in place that is taken into account.

Regarding the capital structure, as the monetary conversion in December approaches, could you please share your views on the CB and also outline your targeted leverage ratio?

So I think on this CB, I think I've given our thoughts on that, which is that we would, of course, like to address it and do so as soon as possible. I think on the targeted leverage ratio, I think there's almost two stages to this. I think at the moment, while we are still in the period where we don't yet have 12 months of full tire reproduction, I think we're very, very focused on the covenant level within our instruments, which is three times net debt to EBITDA. As we go forward, Our targeted leverage ratio is more in the region of one and a half times on a through cycle basis net debt to EBITDA.

On capex, how much have you reduced capex from your initial 2025 estimate now that you're guiding 50 to 60 million?

Yeah, overall, at the start of the year, we probably expected it's dropped probably around 80 to 100 million. There's been a few things, obviously, the infill wells and the ROM program we've talked about here. There's also some reductions around the timing for other CAPEX projects.

Have you added any additional hedges so far in Q2?

Pretty minimal. We're monitoring the market. We have put a few on for oil, but that's been a bit more limited at the start of this quarter.

Regarding your lifting cost expectation of $13 per barrel for 2025, what is the split between Tyra and base assets?

I think $13 a barrel is not necessarily a split where you can say some $6 comes from one and $7 comes from the other. I think what we can say, though, is that the levels of OPEX that we've seen to date reflected by Dan, Halfdan and Gorm, that kind of overall level would be expected to remain the same. So it's the addition of very low cost Tyra volumes that brings you down to the 13. So I think you can say that the majority of the cost decrease is driven by Tyra.

Regarding the Tyra facilities, can you give some color on why this has turned out to be so complicated to maintain at a high performance level so that we can understand what type of fix is needed and gain confidence in the whole plan?

Yes, so like we said in the presentation, so one thing when you start up this big project after such a long time, there are smaller issues are expected. And so we did expect that there would be something that we had to figure out how to run. And then we've had some other incidents that has impacted quite a lot more than we had hoped for. So combined that has given us the lower uptime and the difficulties you've seen. What we do see is that the operator is now doing this reliability study so they're going into all the different issues that they've seen and finding out why that happened and what's the best way to make sure that it doesn't happen again and that work is ongoing right now and they get specialist vendor support to do that so we have a good confidence in that they will be able to do that and we do see less of the smaller incidents lately.

When does Blue Nord expect to commence meaningful cash tax payments to the Danish government?

So Blue Nord is already a meaningful taxpayer in Denmark. We are consistently in the top 20 corporate taxpayers in Denmark, and that's just Blue Nord on a standalone basis. If you bring together Blue Nord, TEPDK, and then also Total Energies, and then also the North Sea Fund, actually the DUC becomes one of the largest corporate taxpayers in Denmark. From a Blue Nord perspective, We are one of the largest taxpayers while also being in a position where we have significant Chapter 3A tax losses. So we're effectively only paying 25% cash taxes. And then also my point around us being one of the largest taxpayers is also prior to Tyra having ramped up and reached plateau production. So we are contributing significantly to Denmark. From our perspective, though, one other point just to note here is that we are expecting that our Chapter 3a tax losses will likely be used up by around about 2027, so the end of 2026-27, and from that point onwards we'll be paying both corporate tax and the hydrocarbon tax.

Has Blue Nord any plans for buyback of shares?

So the distribution policy that we've announced is one that is framed based on distributions, and that includes dividends and the potential for share buybacks. As I mentioned earlier on, for the first payments, which will cover 2024 and Q1 2025, our intention is that this is structured as a return of paid-in capital. However, going forward, we'll continue to assess the potential for including buybacks as part of those distributions.

And final question, Shell has historically held the rights to market DUC oil and gas. What is the status of your offtake today? Is there any trader holding the rights?

Yes, that's right. Obviously, Shell held historically. They continue to hold 75% of the volume rights over the next four years or so. The other 25% is more open. Currently, it is contracted with BP. And yeah, all 100% is also then up in a few years' time and can be open to marketing.

And that concludes the Q&A session. Thank you.