Good morning. Thank you everyone for joining our presentation. I'm Euan Shirlaw, the Chief Executive Officer of Noreco, and I'm joined by Marianne Eide, our Chief Operating Officer. We will have a Q&A session at the end of this call, and I'd encourage you to submit your questions throughout, including if you have any follow-up. This morning, we announced first gas from the Tyra Redevelopment Project is expected to be delayed from summer 2023 to the subsequent winter season. The main purpose of our presentation today is to walk you through what has changed and why, but also to share our perspective on why we continue to firmly believe that despite today's news, Noreco continues to be well-positioned in the current environment with strong operational performance from our three producing hubs, significant profitability and meaningful cash flow generation, a robust liquidity position with material headroom, and a stable capital structure that continues to be set to deliver Tyra. With that, let's turn over to the first slide. To summarize where we are today, the onshore fabrication phase of Tyra is complete. The sail away of TEG from Batam is now imminent and expected to occur around the 1st of September this year, with loadout starting this week and the heavy transport vessel GPO Emerald already on-site. What this means is that from October, all eight modules will be installed offshore Denmark, and importantly, they will also be fully within the control of TotalEnergies for the remainder of the hookup and commissioning phase. However, as it continues to also be felt globally, supply chain constraints and a remaining overhang from COVID-19 have impacted yard-based performance, particularly for TEG. While TotalEnergies has focused on motivating McDermott to maximize the extent to which work is completed onshore, when TEG sails away from the yard in Batam, it will be incomplete with work therefore carried offshore. However, recognizing the current context and the importance of ensuring gas supply, first gas critical carryover work will be prioritized so that we can hit this milestone as soon as possible. At the same time, hookup and commissioning, which is already underway, has also been impacted by the broader market conditions, particularly with regard to mobilizing skilled workers. While TotalEnergies recognizes the challenges this presents, they're already taking active steps to address. However, they have revised down their forward productivity assumptions to take account of performance achieved to date. What is important to bear in mind here, though, is that the phased nature of an offshore hookup and commissioning campaign like the one we have here, provides ample opportunity to improve, and TotalEnergies is focused on doing this by learning the right lessons from progress to date. As a result of this context, the operator has used completion of the onshore fabrication phase as a catalyst to undertake a review of the overall cost and schedule outlook for the project. That's a process which concluded this morning with publication of a remit announcement that first gas from Tyra is delayed until winter 2023, with a P50 estimate of December. With a longer horizon to first gas, the operator has also updated their cost forecast for the project. Based on guidance from TotalEnergies, we expect that the investment cost to first gas will increase from DKK 22 billion, which was our previous guidance, to DKK 24 billion in the P50 case. Given also that certain activities will be prioritized to achieve the earliest possible first gas date, some costs will remain to be spent post first gas. As a result, we expect that the total investment to complete the project will be DKK 25.7 billion on a P50 basis. For Noreco, this corresponds to CapEx remaining from the end of June 2022 to first gas of approximately $300 million. The following slide, which we can turn to now, highlights the position we're in today using some high-level metrics related to carryover and hookup and commissioning. Starting with TEG carryover and including a contingency of 25%, the operator estimates roughly 165,000 man-hours remain that are critical to first gas. Again, including a contingency of 25%, the estimate of total hours to complete TEG, which includes the first gas critical hours, is roughly 580,000. Marianne will take you through how these hours will be liquidated in more detail, but one of the key inputs here are the offshore productivity assumptions. As noted, based on the achieved performance TotalEnergies has realized to date, they have they have revised down their expectations. The chart on the bottom left-hand side of this slide gives some insight into why this has been necessary. With progress both on the Tyra East wellhead and riser platforms and TEH currently behind plan. The combined impact of both these is shown on the right-hand side of this slide, where the P10 estimate for first gas is now October 2023, the P50 estimate is December 2023, and rounding out this range, the P90 estimate for first gas is now March 2024. Now let's turn over and take a look at what this means for Noreco in the current environment. The strength of BlueNord's underlying business was shown clearly in our second quarter results. Production of 27,500 bbl a day of equivalent in the first half of this year was up roughly 1,000 bbl a day versus the same period in 2021. While clearly disappointing that the contribution from Tyra will be lower in 2023 than previously expected, Noreco and the DUC partnership are actively pursuing opportunities to accelerate near-term volumes through ongoing work, including interventions, workovers, stimulations, and reinstatements, an ongoing well reservoir optimization and management program. Also pursuing additional short cycle investment opportunities like infill targets, where we've identified seven wells to be FID'd through 2022 and 2023. All this means that we continue to expect to generate material profitability and cash flow in the pre-Tyra phase. Against this backdrop, it's important to note that we also remain fully funded with material headroom based on the current forecasts, and have a stable capital structure that continues to be set to deliver Tyra. Now I'll hand over to Marianne to walk you through the current position in more detail. Okay. Thank you, Euan, and good morning all. I will start with a brief recap of the Tyra project, and then move on to give you more details on the status and completion of the project. The investment decision on Tyra was made back in 2017. In 2019, production was shut in. The old topsides were removed and construction was started of the TEG module in Batam in Indonesia. We also had construction of the accommodation module in Italy and the wellhead and riser modules in Singapore. The three Tyra East wellhead and riser topsides were lifted on and installed in August last year, and we had a big successful campaign in the spring this year, where we installed the three Tyra West wellhead and riser platform topsides in addition to the living quarters. We have been making significant progress with seven of the eight topsides installed, and work is well underway to hookup and commission these seven installations, and we expect to start using the living quarters with 80 beds in September. With the arrival of the TEG module, we will have concluded the yard construction phase and our operator, TotalEnergies, is in full control of delivering the remaining scope. Moving on to the next slide, giving you some more detail on the TEG module. We are very close to a loadout of the TEG process module, which is the heart of the Tyra Redevelopment. This process module will enable us to process 300 million standard cubic feet per day when on stream. The construction phase is coming to an end with sail away from the yard first week of September, and we have now started preparations for load out and sail away. We did the weigh in the middle of July, and we were spot on 7,000 tons. The heavy load vessel GPO Emerald has been on location in Batam for a few weeks already, and we're starting to add grillage to the deck where the TEG unit will be placed. The TEG unit will be skidded onto the Emerald this weekend. We expect Sunday, but it could maybe come a couple of days earlier. We then need to do all the sea fastening to prepare for a voyage, while in parallel completing as much work as possible. We will sail through the Suez, and we expect a voyage of six weeks duration, so we'll arrive in Denmark in October, where, with the Sleipnir, which did an amazing job on the four lifts in April, will be waiting to do this final lift for us. Moving on, giving you a bit more on the current status. We are announcing a delay to the first gas today, and the TEG module will leave the yard with carryover work. We expect around 650,000 offshore hours of work remaining, and out of these, we expect 165,000 to be critical for first gas. We expect to be leaving 95% mechanical complete, but we have not been able to complete all commissioning, which is the testing of the system. We expect to have done approximately 80% of the commissioning at sail away. What is positive is that we have successfully completed all leak testing, which would have been adding a lot of hours to the offshore phase. What went wrong? We had a motivated yard. McDermott managed to deliver around 100,000 man-hours every week. However, due to issues with quality, we experienced a lot of rework. On average for this year, even if we had 100,000 hours worked in a week, we only achieved 50,000 hours of progress. We can point this back to COVID. Due to COVID restrictions, workers were doing their work in isolation, so had less supervision than normal. We have also seen a gap in the skills of the workers, both in disciplines like pipe fitting, but in particular on the leadership level of the foremen. Travel restrictions also meant that a lot of the factory acceptance tests where we accept key equipment from vendors had to be done virtually, and this also led to quality issues and rework. A number of mitigating actions were taken. McDermott increased the numbers of workers at the yard. TotalEnergies strengthened their site team and also brought in staff from the commissioning contractors to add to the level of supervision and also to enable a good handover from the yard to the offshore stage. We also put in place additional incentives for McDermott to ensure that first gas critical items were prioritized. We did consider delaying the sail away from the yard, but this would have created a longer delay due to the weather windows for installation, combined with the availability of the Sleipnir heavy lift vessel. Looking at the carry over work in some more details. As you can see, we have added 25% contingency to accommodate the hidden carry over. Again, around 40% of the carry over work is first gas critical. Around 165,000 hours to reach first gas and 580,000 hours in total. Looking at the current status at the offshore hookup and commissioning stage, we did start this phase with the installation of Tyra East back in August last year, and with the TH accommodation module arrival together with Tyra West in April this year. As you can see, we have not been able to deliver according to the schedule that we had at the start of this campaign. On Tyra East, we had a difficult start and had problems getting both power and cranes to work. On TH, I would say we had a fantastic delivery on the commissioning side, but we still had some challenges on the hookup with Noble, which is doing the work to connect the new topsides with the existing infrastructure already in place. The reasons for these delays have been an issue with mobilizing skilled workers. We had two optimistic assumptions for the offshore productivity, which has now been revised. We have incorporated all of our learnings into this revised schedule and also added the additional contingency to the base hookup and commissioning scope. We now have a robust and realistic schedule that we can meet. Again, moving into this hookup and commissioning phase, TotalEnergies is in full control, and they are looking back in detail to ensure that they can learn and improve as the hookup and commissioning progresses. We have had a growth in the hookup and commissioning scope since FID. The estimate at the FID in 2017 with 600,000 hours was clearly not correct. Our previous estimate of 1.3 million hours for the base scope has increased with 300,000 hours or 23% to have a contingency for additional hidden work, and it's based on learnings from the hookup campaign to date. We now have a good understanding of the remaining work, and the execution have been planned in detail with job cards developed for both the base scope and for the carryover scope to ensure that we have a good, efficient, offshore execution. As a result of this schedule delay, we are also seeing an increased spending. The overall budget is expected to increase from Noreco's previous estimate of DKK 22 billion- DKK 25.7 billion, which is an increase of 17%. The main increase is in offshore hookup and commissioning, which is a result of more hours to be executed over a longer period of time. That means that we need more workers for longer, and we also need the accommodation barges for a longer period. We also need the project management team for a longer time. To date, we have spent DKK 18.5 billion, which means so that we have a total of DKK 7.2 billion remaining expenditure. Out of this expenditure, we have DKK 5.5 billion to be spent before first gas. That's approximately 75%. 25% will be spent after we have achieved first gas. Looking at the Noreco net numbers, that means that we have around $300 million of net Noreco spent before we have first gas production, and then an additional $90 million to spend after first gas. I would like to remind you of the very strong performance of our base business. Through world-class operational performance and successful optimization of production, we are increasing the 2022 production compared with 2021. We are doing well interventions with the Noble Sam Turner rig, and we're also using the Maersk Reacher to enable further well intervention activities. We're seeing really good results from our efforts, which is setting us up really well for the rest of the year. Our base business is very profitable on its own, and in the second quarter, we generated a free cash flow of $156 million before investments, and we had a free cash flow of $95 million after the Tyra investments. We have a robust capital structure with a liquidity of $342 million, and as you saw from the Q2 results, we are fully funded, and we have a lot of headroom for the revised schedule and budget on Tyra. Looking forward, we have several gas-weighted opportunities that we are progressing, which will set us up for strong production in 2023 and 2024 as well. Just as we did acid stimulation on Gorm back in December with a huge success, we have now started on Halfdan, where we have scheduled seven stimulations. The first five gave an initial boost of 35 million standard cubic meter of gas or an increase of the gas production of 10%, and we still have two interventions to go. We are prioritizing gas-rich opportunities when scheduling all of our well interventions. We will also commence a seven-well infill drilling campaign started in the spring next year. We will take the FID for the first five wells later this year and the final two wells next year. As you can see from the chart, the first five wells will increase the gas share of the DUC production. All these opportunities are low cost, around $10 per barrel, and fast payback, since we are drilling from existing infrastructure. I will now hand back to Euan, who will talk us through the financial impact. Thank you, Marianne. As shown on this page, our capital structure remains robust. At the end of the second quarter of 2022, we had $242 million of cash on our balance sheet, and we had total liquidity at the same time of $342 million, which includes $100 million of undrawn RBL capacity. In addition, we continue to have $140 million on escrow with TotalEnergies, and that's funds available that can be used in the unlikely event that they're necessary to meet DUC cash flows. These funds will be released when Tyra starts production, when they can be replaced with a $100 million letter of credit. The result of this position is that we are fully funded based on current forecasts, and that's a position that is further supported by the material cash flow generation that we have seen from our currently producing asset base and expect to continue to do so going forward. As mentioned, our capital structure also remains stable. Our RBL redetermination was completed at the end of June, and the borrowing base was confirmed above the maximum amount of cash drawings, which is $1 billion. We have no cash principal debt repayments until H2 2024 when amortizations are scheduled to start on the RBL. Finally, leverage levels are expected to remain within the covenants based on our current forecasts. The following page provides more detail on this outlook and supports the conclusions that I've just run through. As you can see on the left-hand side of the slide, our liquidity, which is shown excluding the CCSA, remains well above the minimum required levels, even at downside commodity prices. You can then see on the right-hand side of the page that our leverage also remains within covenant levels and is expected to continue to do so even once these step down to the long-term levels of 3x net debt- to- EBITDA from 2024 onwards. In conclusion, and before we move to the Q&A, I'd like to reemphasize just where we are today. We fully recognize the importance of Tyra II, not only to Noreco, but also as befits the project of such strategic importance also to Denmark and to the E.U. more broadly. Our focus and that of the DUC partnership remains on securing and expediting first gas, and we will take an active approach to identifying opportunities to do this in the context of the project. While we would obviously much prefer to be announcing completion of the onshore fabrication phase against an otherwise positive backdrop, it is still an important milestone that all eight modules will shortly be installed offshore Denmark and will be fully within the control of TotalEnergies. As I mentioned, and from a Noreco perspective, our underlying business remains strong, where our operational performance remains positive. With a strong outlook, we're generating significant profitability and cash flow generation, and we are fully funded with a robust financial position. With that, I'll thank you again for joining this morning's presentation and we can hand over for Q&A. Thank you for waiting. First question, why would you choose to do extensive work offshore when you could do it in a yard? Won't it be much higher cost to do the work offshore? As I briefly touched on in my presentation, we have two limitations with respect to the installation of the TEG module. We will need a weather window to be able to install, and we'll need a heavy lift vessel that can handle 17,000 tons. Looking at those two limitations, we saw that taking the module out and completing it offshore would give us the quickest path to first gas. Do you consider adding to gas hedges at current prices? Yes. I think, you know, as our hedging profile has developed, you know, we've clearly looked to take advantage of where there are attractive opportunities to hedge. I think given the current market environment and particularly the near-term outlook, I think it makes a lot of sense, to certainly consider adding further gas, particularly when we can reduce risk by doing so. To what extent will the planning for future development projects, Halfdan North and Valdemar Bo South, be affected by this further delay? We do not see a direct impact on the timing of Halfdan North and Valdemar Bo South. We are prioritizing infill drilling, which is a low cost in the short term. How do you assess Noreco's ability to potentially enter into long-term floor price take-or-pay agreements with Denmark or the E.U., given the current gas crisis? Given, if nothing else, the geographic proximity of the DUC in Denmark to the rest of the European Union, I think, you know, strategically, it clearly makes sense to maximize the indigenous production that you have coming from the region. Noreco has, I think it's fair to say, an important role to play there. We have, as you would expect, active discussions in Denmark and are progressing the potential for what we can do to help meet those requirements. I think it's particularly relevant at the current time, given there is an increasing recognition that the issues we face today of ensuring strong gas supply are not going away. I think to specifically address your question, I think it's clear that from a Noreco perspective, in order to progress and effectively sanction the ability to produce further gas, what we'll be looking for is a way in which we can reduce our risk profile. As you mentioned, you know, potentially floors on gas prices are clearly one of the variables that are available there, but there are others. I think what I'd say that, you know, the ability to lock in the current environment and the current recognition of how important these volumes are is something where we're continuing to build alignment with various stakeholders and the relevant parties within Denmark. What measures can it take to increase production in the short term in order to benefit from the current high gas price environment? To increase gas production in 2022, we have already done five of the acid stimulations on Halfdan, which has given very good gains. We will continue with the two remaining stimulations, and we will also do other well interventions in order to increase the gas production. Are you seeking compensation from McDermott? That's not something that we can comment on. According to the expected investment phasing, there are quite significant investments also after first gas. How can we expect the production profile to develop after first gas, and what will be the ramp-up time from first gas to plateau? We are expecting to be on plateau during the summer of 2024. That's the summer gas season, just to be clear. The revised guidance of DKK 25.7 billion is a P50 estimate. Is it possible to provide a P10 and a P90 estimate of this parameter? On the liquidity forecast page, we outlined just broadly what the incremental CapEx in the P90 case is, which was roughly $25 million net to Noreco. The spread is reflective of the fact that with all the modules offshore, the work that is required to be done is relatively well understood. What the focus is on getting that work done as quickly as possible. While there is some incremental uptick in the P90 case or reduction in the P10 case, the broad area of total CapEx remains consistent. That's in P90, for example, the number is not 25.7, it's DKK 26.2 billion. Why do you take the TEG module directly to offshore rather than going to an alternate location and complete the module? Do you trust the numbers from TotalEnergies given their track record on this project? Again, because of the availability of the Sleipnir heavy lift vessel, the most optimum schedule was to go directly offshore. That will give us first gas as early as possible. Are the numbers you show for remaining hours in CapEx Noreco's estimates or Total's estimates? These are Total estimates. Yes. Does the delay and cost increase impact the way you think around hedging before Tyra first gas? I think what it does do, it doesn't fundamentally change how we think about hedging, which has always been to ensure that we have secured our cash flow position and secured delivery of the Tyra Redevelopment. I think as you can see through the presentation today, it's clear that our liquidity position remains to be robust. As I mentioned, though, I think the reality is given where the gas markets in particular are at the moment, where there are opportunities to further reduce risk and lock in attractive prices, we will continue to do so. Securing that cash flow profile to Tyra remains extremely important and will be a key focus. Any updates on Q3 performance, is it within the range of expectations? We don't have any guidance specifically on Q3. I think, given we haven't provided any other update, I think you can conclude that we're still within the guidance of what we've previously published. When we look at the financials, we do not see the deferred tax assets utilized. When will the company be able to utilize the deferred tax assets? You're absolutely right. The deferred tax asset shows up on the balance sheet as an asset, but doesn't give clarity on when it'll be utilized. Given the current commodity price environment that we are in, we would expect it to be utilized relatively quickly, so we're talking within 18 to 24 months. I think this is one of the circumstances where, given we have a defined deferred tax asset, the reality is that it is to our benefit to use it up as quickly as possible because it's reflective of the fact that the business has been strongly profitable and cash flow generative. Do you have accommodations to increase workforce offshore? We have two flotels, the Haven and Crossway Eagle, in addition to the TH accommodation module. We do believe that we have sufficient accommodation. In Q2, you guided for the leverage ratio to reach zero by Q2 2023. Now this is expected to remain around 2 x well into 2024. What are the reasons for this? The reasons are twofold. One is that the reduction in leverage ratio to the levels that were referenced in the question were reflective of the fact that we had a path towards Tyra startup that was shorter than where we are currently. Secondly, we also have the incremental CapEx that we've announced today. $120 million of CapEx net to Noreco over that horizon. That was the final question. Thank you for listening in.