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Earnings Call Transcript 2022-Q3

[Euan Shirlaw, executive]

Good morning. Thank you to everybody for joining our presentation this morning. It's a pleasure to be able to present another excellent quarter of operational and financial performance from Noreco. On the production side, we've had strong performance driven by specific actions that have been undertaken by the operator, like the HCA restimulation campaign. We've also had strong operational uptime and we've had a well-managed shutdown of the NOGAT pipeline.

And that's allowed us to deliver a record set of financial results, which culminated in free cash flow generation of $131 million in the quarter. It's important to bear and that was also delivered against the backdrop of roughly 1 month of shutdown of our gas export capacity as was expected.

On Tyra, we've taken several leaps forward during the quarter. We completed the offshore installation campaign with a world record setting lift that we'll go through in a little bit more detail further on in the presentation. but that's an important derisking event for Noreco and given it was delivered ahead of schedule, it also positions the project well as we go through the hookup and commissioning campaign.

So with that, let's turn over to the first slide, which may be a reminder for some of you, but for anyone joining new, it will be a good introduction to Noreco. Noreco is a material oil and gas producer in the European Union. We have a 36.8% working interest in the Total energies operated DUC, that's the Danish Underground Consortium.

From that asset base, we have roughly 200 million-barrel portfolio of 2P reserves and our current production through the first 3 quarters of 2022 was 26,700 barrels a day, of which 22% was gas. Once Tyra, the redevelopment project comes on stream, that production will almost double to roughly 50,000 barrels a day, and our production mix will also shift to be 45% gas.

Beyond Tyra, we also have significant attractive future growth potential. So that can come from the well reservoir optimization and management programs that we have going on right now, which have been successful infill drilling, a portfolio of medium-term development projects and also a remainder of the 2C portfolio, which is being continually reassessed at current commodity prices. So it's an attractive and valuable asset base. But importantly, it's also 1 that has a lot of strategic merit to it.

So against the backdrop that while there has been recent volatility, the landscape is still one that is dominated by a focus on secure, reliable and affordable access to energy. So energy security in other words. And the DUC and Noreco have an important role to play here. We're already producing significant oil and gas volumes from our existing production base, and we have tangible growth on the horizon through Tyra.

Beyond that, we have a willingness and a desire to do more. And the long-term theme of the European Union being short gas and having an unbalanced supply demand dynamic will continue and Noreco will do what it can to help deliver against those aims. And this overarching context shapes how we are focused. So turning on to the next slide. We first told you in the first quarter of this year around where our focus was, so delivering operationally, delivering Tyra and delivering our potential.

And I think it's worthwhile just taking stock in the third quarter of where we are and how we've delivered against those objectives that we set. Our production in the third quarter was 25,100 barrels a day, and that was above the guidance that we had stated in September, so roughly a month ago. But importantly, it was also significantly above the Q3 guidance that we communicated as part of our Q2 results, which was 21,000 to 24,000 barrels a day.

It's allowed us to generate significant free cash flow that was $131 million in Q3. It was a roughly 30% increase in free cash flow versus what we delivered in Q2. And that's allowed us to exit the period with meaningful liquidity of $473 million, which provides us with significant flexibility. We're also delivering the Tyra project.

We communicated during the quarter that the schedule has been revised as a result of the overhang from COVID and that first gas would now be in winter 2023-'24, but recent steps have shown that we're delivering well against that revised schedule with the offshore installation campaign complete, a significant derisking event, and we're moving towards first gas on a P50 basis in December '23, with $235 million of CapEx remaining.

In terms of our long-term potential, we're going to look to maximize the value of our underlying organic portfolio but doing so in a way that makes sense for Noreco, makes sense for our capital structure, and also makes sense for our stakeholders. The priority remains capital returns once Tyra is on stream, but it's important to also bear in mind that the current environment provides a dynamic where there is the potential for significant value creation from the existing resources that we have.

And turning on to look at those topics in a little bit more detail. As I mentioned, our production for the first 3 quarters of 2022 has been 26,700 barrels a day. That is flat versus the first 3 quarters of 2021, which is a strong performance in and of itself, but it demonstrates the fact that TotalEnergy, our operator, is managing our asset base well and undertaking the activities that are necessary in order to keep production at the levels that it currently is.

It's also allowed our fourth increase to production guidance for the year. to 26,500 to 27,000 barrels a day. And just to give some context for that, that compares to the initial production guidance that we had for the year at the end of Q4 2021. The initial production guidance was 23,500 to 25,500 barrels a day, and it also compares favorably to the full year production number from 2021, which was 26,900 barrels a day.

Importantly, that strong operational performance has also translated to a significantly positive financial return. So our EBITDA generation for the first 3 quarters of this year, which was $471 million, is, broadly speaking, double what we delivered for the whole year of 2021. And it's also allowed us to generate significant free cash flow in the period. So this backdrop provides a strong base for us to build upon.

And let's move on to look at Tyra in a little bit more detail on what the impact of that asset is for us. So Tyra is core to Noreco''s growth story, but it's also core to EU energy security, given it is one of the largest fields under development that will produce gas in the region. And as a reminder, it's a top size redevelopment that has a well-understood reservoir with wells that have already been drilled.

And I think where we are now is a fair reflection of the progress that has been made since the FID was taken in 2017 and construction started in earnest in 2019. So we revised the project schedule in August of this year, which led to the first gas date shifting to winter 2023, 2024. And against that revised baseline, we've been making good progress with the offshore installation campaign being complete ahead of schedule and also a revision to our expectation around the amount of carryover that will be associated with TEG.

Marianne will take you through that in more detail coming up, but I think it's important just to bear in mind as we look to where we are at the moment. Once the hookup and commissioning concludes in mid-2023, we'll have state-of-the-art facilities with an asset that is only constrained by the current license expiry in 2042. For Noreco, it will result in an almost doubling of our production on a volumetric equivalency basis, and are more than doubling based on current gas prices and the forward curve, if you look at it on a commercial basis.

It will also lead to a significant reduction in lifting costs once Tyra is on stream on a per unit basis, and similarly, a significant reduction in emissions intensity. So in summary, Tyra strategically important not just to us but to the EU as a whole, and the progress that we are making brings us closer to delivering the finished product. But Noreco's contribution and offering doesn't stop there. So let's move on to talk in a little bit more detail around what our long-term potential is.

And our focus is on maximizing shareholder value and also progressing those activities that do that. The key theme that underpins this is our prioritization of capital returns to shareholders once Tyra is on stream. And the financial framework that we've set will manage capital returns against deleveraging, but also providing the potential for future organic growth.

And I think the table on the right-hand slide of this slide gives a good overview of where we see the organic potential within our existing portfolio. So we have the well reservoir management and optimization activities. That's similar to the HCA activity that we saw in Q3 of this year. And we're estimating roughly 90 million barrels of potential to come from that.

We also have near-term infill wells, which will be sanctioned in 2022 and 2023. They are gas-weighted short-cycle investments and will contribute roughly 20 million barrels of resources to Noreco. We have a portfolio of medium-term development projects. They are being prioritized on a gas-weighted basis and continue to be progressed. And then as I mentioned at the start, there is also further 2C potential within our portfolio, that's continually being reassessed against the current commodity environment.

And with that, I'll hand over to Marianne to give a little bit more detail on the operational performance. Okay.

[Marianne Eide, executive]

Thank you, Euan, and good morning to all. I'm very pleased to tell you about another quarter of strong operational performance today. The absolute highlight of this quarter is the Halfdan restimulation work. The gains significantly exceeded our expectations and the timing of increased gas production coincided with record high gas prices. So this had a very positive impact on our cash flow for the quarter.

Operational efficiency continues to be high and year-to-date is above 90%, also including the NOGAT shutdown in September, and this is world-class performance. The operator, TotalEnergies, also did an excellent job on managing the shutdown of the NOGAT gas export pipeline in order to maximize oil production. So production during this shutdown also exceeded our forecast.

Looking forward, we have taken actions to ensure this strong production performance continues for the rest of 2022 and 2023. We will continue well stimulation work. We have just done 7 of the Gorm wells now in October, and we have plans for further Halfdan simulation and we have bed capacity on the Maersk Reacher to execute what we need to do.

We have also extended the contract for the DUC Jackup rig Noble Sam Turner with another 2 years until March 2025. And we will, within the next weeks sanction, the first two infill wells of over 7 well infill drilling campaign. From a production guidance point of view, we had the guidance for Q3 between 24,000 barrels of oil equivalents per day and 25,000 and we ended up slightly above at 25,100, which is caused by the very positive results from Halfdan stimulations and reduced losses during the NOGAT shutdown.

Looking at our guidance for the full year, we have had a cautious approach and normally included production from specific activities when we had certainty that this would actually materialize. We have narrowed our range for Q4 to between26,000 and 27,000 and we have also removed some downside in our full year '22 range, which is now between 26,500 and 27,000 boe per day.

I'll just go into some more details on the HCA gas restimulations. As you can -- 6 gas wells were selected in order to try to boost gas production through restimulation, which is injection of asset not only into the wellbore, but it's also pumped into the reservoir in order to increase the productivity of the well by removing obstacles to flow. From 4D seismic, it was possible to identify sweet spots where the reservoir had not been produced and the new technique was also used where additional pressure was applied and diverters were used to make sure that the asset got all the way into the toes of the wells.

In addition, a new stimulation vessel type with larger tanks was also used to ensure sufficient volume of asset injection. The expected gains were based on the last restimulation campaign that took place in 2014 with the old methodology. And as you can see on this plot, the actual gains exceed all expectations. And in particular, the fact that we were actually able to access new parts of the reservoir without having to drill new wells, has made a huge contribution, and we are looking for additional well candidates as well.

On Gorm, we also had success with the scale squeezes where we treated the wellbore only, but where we changed the recipe for injected fluid and we have seen additional gains from the scale squeeze that we did at the end of last year through all of 2022, and we have just now done 7 new scale squeeze in October. Both scale squeeze and restimulation are very low-cost activities that we will be repeating on a regular basis.

In addition to ongoing well optimization activities, we also have a 7 well infill drilling program starting in March next year. We expect to take FID on the first 2 wells within the next couple of weeks, and we will then continue the maturation of projects and build a continuous drilling sequence combined with high value gains well workovers. The 7 infill wells, they're all profitable wells with the unit development cost around $10 per barrel.

And as infill wells, these will not attract additional OpEx. From a subsurface risk point of view, these are low-risk wells drilled in reservoirs that we know well, and we have many years of production history from. The drilling of these wells will also slightly increased the gas weighting of the production from our assets. Again, we expect to start drilling in the spring.

And for the first two wells, we will see first production in the same year in 2023. The resources for these opportunities are not carried in Noreco's 2P reserves at the moment. So this will be an addition. We are also continuing to do well interventions, and we have a portfolio of attractive opportunities that give healthy gains. Again, asset stimulations has been excellent, but we will also do other interventions like re-perforations, water shutoffs and reinstatement of wells, which has been shut-in due to mechanical failure.

This program of well interventions and infill drilling, combined with the very high operational efficiency, will be a strong fundament for production in '23. Moving on to Tyra. Even with exceptional performance this year from the base assets in the South, Halfdan, Dan and Gorm, it is Tyra that will transform the DUC asset. With Tyra, we will unlock development of around 200 million barrels of oil growth of existing discoveries by establishing a gas processing capacity of 300 million standard cubic feet per day or 60,000 barrels of oil equivalents per day.

While we today produce around 80% oil and 20% gas, with Tyra on stream, that will change to around 45% gas. The emissions intensity will be significantly reduced by installing state-of-the-art facilities, and we expect the operating efficiency to further increase. With Tyra, we will also be extending the production life of the DUC asset, and we will be phasing in additional developments as processing capacity becomes available, and we will see a significant reduction in unit operating costs.

So the TEG processing module, that is the heart of the Tyra redevelopment. We left the yard as scheduled 1st of September. The journey was smooth through the Suez Canal and then full speed ahead to make the weather window in Denmark. Just hours after arriving at the offshore location the world's heaviest offshore lift from a floating crane was made, and we then completed the remaining three lifts within a week.

And on the photo, on the bottom right, you can now see the new Tyra East skyline. Starting from the left, we have the 3 Tyra East wellhead and riser platforms in the background with the Red Lakes, you can see the flotel Haven, which is not permanent. You then have the TEG process unit and the TEH accommodation platform to the very right. I'm now very proud to show you this movie that speaks for itself and it makes me very proud every time I see it.

[Presentation]

[Marianne Eide, executive]

That was amazing. And with the offshore installation behind us, we have significantly derisked the project, and we can now focus on completing the offshore hookup and commissioning. We are off to a very good start. We had allocated 3 weeks for the offshore installation in our P50 schedule, and we did it in one week, so that's two weeks ahead of schedule.

So back in August, we showed you a total offshore hookup and commissioning scope of 2.5 million manhours. This was the basis for our rebaseline of the project back in August. It's important to note that what the operator, TotalEnergies, are using as basis is -- for this reporting is gross offshore manhours. This is around 13 hours a day, includes toolbox talks, lunch, coffee break, shift handover, walking to the site, et cetera.

Other operators would use net offshore manhours, which would be approximately half of the growth. So, that means that, realistically, we have remaining around 800,000 of real hands-on tool times before reaching first gas. Our analysis indicate that we reached a maximum manpower of 460 between February and August 2023. With respect to bed capacity, we are in a good place, with more than 500 beds available between the three locations, TEH, the accommodation on Tyra and the over two flotels, Haven and Crossway Eagle.

We have also secured the personnel we require now with TEG arrival. Since the replay baseline that we did back in August, we have also had some positive news, McDermott really picked up speed during the last few weeks ahead sailaway, so the estimated carryover work has been reduced with around 200,000 hours, a reduction of 30%.

The accommodation module has been in regular use, and the hookup and commissioning work has been completed on budget and ahead of plan. The team from the accommodation module has now moved on to Tyra West. It's early days, but 5 weeks into the campaign, we are slightly ahead of schedule. And on Tyra East, work is progressing well, and we have reached more than 50% completion of the scope.

Back in August, we reported remaining CapEx at the end of June of USD 390 million and USD 300 million remaining CapEx to first gas. With a $65 million expenditure in Q3, we're now down to $325 million expenditure overall and $235 million expenditure remaining to first gas. There is no change to our first gas prediction. This will happen in the winter 2023, '24, with a range between October '23 and March '24.

This slide is showing the upcoming key milestones for Tyra. We are off to a good start with the living quarter and the offshore installation, both being delivered ahead of the P50 schedule. The next milestone this year is safe access to the TEG process module and having temporary power in place, which is required to deliver the volume of hook-up work. Getting the crane in operations is the first key milestone for 2023.

Looking further out in time, we have our P51st gas date in December '23, with first gas exported to Nybro and plateau production to be reached in the summer of '24. So this is what I have on Tyra, and I'll now move on to talk about future growth opportunities.

With Tyra on stream and our cash generation further strengthened our first priority will be paying a dividend to our shareholders. We also have several high-value organic opportunities in particular, 3 significant discoveries very close to existing infrastructure, which are already matured and are ready to go.

We are also investing in the energy transition. Our priority today is reducing our emissions from our existing operations. With the DUC portfolio of discoveries, we can provide a supply of gas on a longer-term basis, and we can phase in Adda, which is a gas discovery, 70% gas, 30% oil, when Tyra goes off plateau, to maintain that gas production rate of 300 million standard cubic feet per day or 60,000 barrels of oil equivalents per day.

We can then follow on with the Valdemar Bo South, which is an oilfield with around 35% gas and then Halfdan North. These three field developments are straightforward, low-cost developments, which will be tied back to existing infrastructure. The only investment required are simple wellhead jackets and the drilling of the wells.

We can fully utilize the investments that we have already made in the Tyra processing facilities. Our main priority is, obviously, to get the Tyra on stream. But after that, it will be all about keeping the Tyra processing unit operating at full capacity.

I will now be handed over to Cathrine, Noreco EVP, ESG and Investor Relations, who will talk you through what we are doing to reduce emissions from our fields.

[Cathrine Torgersen, executive]

Thank you, Marianne, good morning to everyone. In Noreco, we are committed to support Denmark's energy transition by reducing emissions from the DUC to the fullest extent possible. We believe that oil and gas production should be viewed through a global lens. As long as the demand side continues to be strong, if you then reduce or remove the production in areas with low to medium emission profiles, you end up moving the supply side to areas, which has much higher intensity.

This is exactly why it's so important for us to continue to produce at the same time as we chase the incremental CO2 unit reductions. To further integrate the ongoing ESG work we're doing, Noreco was one of the first companies who formalized our commitments through the largest part of the capital structure, the RBL. We have specific ESG-linked KPIs, which will lower the margin we pay under the RBL.

And as you can see on the right-hand side of the slide, our unit emissions is expected to lower significantly over the next 5 years. Tyra will naturally be a big contributor to this, once it's on stream. It will lower emissions by 30% and reduced flaring by about 90%. And given the magnitude of the step change in production from Tyra, this will have a permanent and dramatic overall impact on our greenhouse gas emissions.

During this year, we have continued to focus on the current production on Dan, Gorm and Halfdan. And one of the most important ways to reduce the footprint here is by improving the energy efficiency. This means that we need to operate the facilities in a leaner and simpler way and also incorporate the use of new technologies.

Minimizing flaring to an absolute minimum also remains a top priority. And the operator has put in place a strategy to ensure flaring to only when absolutely necessary and as safety measure. Other areas where we chase improvement is on the actual emissions monitoring on fuel reduction and discharge to sea, which we have reduced significantly over the past couple of years.

If you look on the top right-hand side, the forecast for 2022 is about 32 kilos per barrel. However, year-to-date, we are somewhat below this number, and we expect to cut our unit emissions in half during the next 5 years. This is exactly in line with our strategy to chase the important incremental reductions. And with that, I will hand over to Euan, who will take you through our financial results. Thank you.

[Euan Shirlaw, executive]

Thank you very much. Let me just go to the financial summary slide. I think everything that we've talked about so far today, particularly on the production side, you can see what the impact of that has been on our financial performance. So it's been extremely strong during the quarter.

We generated revenue of $294 million, which, year-to-date, is $737 million. And we also generated EBITDA of $198 million, leading to a year-to-date number of $471 million. Looking at the report, which isn't shown on this slide, but one of the things that also we announced or is incorporated within that report is our OpEx level. So that ticked up marginally during the third quarter.

But I think it's important to look at the OpEx level in the context of the production performance because the reason why that OpEx level is higher is because, for example, the cost of the HCA restimulation campaign and the cost of the ROM program on Dan is included within our OpEx. And I think that's absolutely what we should be doing in the current commodity price environment, which is making sure that when we are able to produce more volumes and there's a strong economic rationale for doing so, then we have an operator and we have a partnership that is willing to get over -- get after those contributions.

On the cash flow side, I think the profitability from revenue and EBITDA is, obviously, important, but I think it's also helpful to see that, that translates through to cash flow generation. So in the third quarter, we delivered $215 million of operational cash flow and $131 million of free cash flow prior to a voluntary and redrawable repayment that we made on our RBL. So we repaid $100 million in order to minimize our borrowing costs. And that's something that is still available to be redrawn and still goes into our liquidity position, which is $473 million at the end of the quarter.

If we just turn on to the next slide to look at our commodity hedging position. In the third quarter, we added significant proportions of gas hedging to our portfolio. And we did that at extremely attractive prices. So we hedged in Q3 for volumes out to winter 2023, '24, at prices between EUR 240 and EUR 305 per megawatt hour. And what that means is that for winter '22, '23, so i.e., Q4 and Q1 next year, we have a gas hedge price of EUR 166 per megawatt hour.

Then in the summer period, so summer '23, we have a hedge price of $161 million (sic) [EUR 161 per megawatt hour]. And then for winter '23, '24, we have a hedge price of EUR 260 per megawatt hour. And I think the volumes decreased through time, but I think it's still an important benchmark that we have secured a portion of our revenue at extremely attractive prices. One of the other things that we achieved in Q3 was a revision to our hedging policy.

So we were looking to make it more -- this is the hedging policy under the RBL. We wanted to make it more fit for purpose, but also give us the opportunity to take more spot price exposure. That won't necessarily change our approach to hedging because we will still look to hedge when we think it makes commercial and economic sense to do so, but what fundamentally it means is that we have more flexibility.

So the previous policy required us to hedge 50%, 40% and 30% of 1-, 2- and 3-year forward production, and that was measured on an oil equivalency basis, and the revised policy requires us to hedge 50%, 40%, 10% of our oil volumes, but only 20% of our 1-year forward gas volumes. So I think, all in all, a positive development of our hedge book from a commodity perspective during Q3.

And one of the other things that we also wanted to highlight given the macroeconomic backdrop, was the interest rate swap that we put in place in the middle of 2021. So if we turn to that slide, you can see that what we did was we fixed our floating interest rate exposure from the middle of 2021 until the middle of 2024 at roughly 40 basis points, so 0.4%. And as a result of that, we have no floating interest rate exposure within our capital structure.

And if you look at where the relevant underlying interest rate has moved, so that's the dark red line on the chart. If you look at that, you can see that, obviously, that has spiked significantly through 2022, and is currently around about 400 basis points. And if you look at the difference between those 2, it's roughly 360 basis points and on a $1 billion RBL -- sorry, $1.1 billion RBL, but the size of the interest rate swap was only $1 billion, then that's roughly $36 million per year in terms of the equivalent interest saving.

And I think that's important just to give a sense of how we have thought about what we're doing with the interest rate exposure, because, fundamentally, where we are now is we're able to take advantage of higher commodity prices, which has been one of the key drivers of the underlying inflation environment, without being exposed to the increasing interest rates that have been required to try and address that increasing inflation position. So it positions us well as we go forward.

And if we turn to the next slide to look at our capital structure in a little bit more detail, I think the simple message is that it's a robust capital structure. It has stability with no principal maturities pre-Tyra. We have a strong liquidity position with $473 million available at the end of Q3. As a result of that, we are strongly fully funded to Tyra first gas, and we're currently generating cash flow at a level that is significantly above our previous expectations, but is also significantly above what we expected to be able to do prior to Tyra coming on stream.

And I think that point -- just to finalize there, I think that point is important. The shape of the business and the shape of our cash flow generation profile has meant that the existing assets that we have, have started generating significant cash flow, and it's less about waiting for Tyra to come on stream before we are in a position to generate that cash flow. And obviously, as you can see from the liquidity profile, that provides us with a lot of flexibility going forward.

And just to close, I'm going to leave you with a reminder of where we started, which is our focus. We have a set of clear objectives, and we're already delivering against these. So underlying production has been strong. financial performance has been robust, bringing Tyra on stream is something that we've progressed significantly in the third quarter and also maximizing our potential. So taking advantage of the underlying value that we have in our portfolio, both organically and in terms of defining and delivering a shareholder return profile once Tyra is on stream.

Our focus remains continuing to deliver and doing more and doing that build upon our strong base of existing production. And with that, I'll thank you for allowing us to walk through the third quarter presentation and hand over if there's any Q&A. We'll just take our one-minute break to allow people to submit any questions that they have, and then we'll come back and have the Q&A session. So thank you very much.

[Cathrine Torgersen, executive]

So first question, great work with the restimulations. Is the upgrade to production guidance driven by oil or gas production? And if the gas production, is it the volume of gas or the value of gas equivalent?

[Marianne Eide, executive]

So the operator prediction is driven by gas production, absolutely, and it's the volume of gas.

[Cathrine Torgersen, executive]

Are there any costs associated with an early redemption of the RBL?

[Euan Shirlaw, executive]

No, there are no direct costs associated with early repayment. And as you'll see through time and based on our forecast cash flow profiles, we delever quite quickly. We've taken the first step to repaying $100 million on the basis that, that minimizes our borrowing costs. But in principle, when we look at our refinancing going forward, we delever quickly, and there's no cost associated with refinancing the existing facility.

[Cathrine Torgersen, executive]

For your guidance of $13 per barrel OpEx after Tyra first oil, what do you assume for OpEx per barrel for, one, Tyra; and two existing production?

[Marianne Eide, executive]

So what I could say is that the improvement of the unit operating cost with Tyra on stream is relating to new much more efficient facilities with higher volumes as well.

[Cathrine Torgersen, executive]

Euan, is it possible to sell forward and/or hedge any of the Tyra volumes? Or is the market too thin for 2024 and beyond?

[Euan Shirlaw, executive]

I think, generally speaking, it's very difficult to sell forward beyond at least the next 18 months. I think in theory, that brings you into next winter, which could theoretically be hedgeable. I think from our perspective, we very much look at hedging as something that mitigates risk and gives us security over our cash flow. I think before Tyra is on stream and we're closer to first gas, I think it's not an asset that we would like to hedge the production from a commodity price perspective before we have certainty around start-up.

[Cathrine Torgersen, executive]

It's positive to see the recent production increase. Should we expect higher production in '23 versus '22?

[Marianne Eide, executive]

So I think what we have seen in '22 is the effect of a very active reservoir management of the three fields that we have got. We expect TotalEnergies to continue this in '23 as well, but it's too early to give a guidance on '23 production.

[Cathrine Torgersen, executive]

And on Adda. Is Adda booked as 2C resources or 2P resources so much?

[Marianne Eide, executive]

Yes. So Adda is in 2C. And I cannot disclose the actual number.

[Cathrine Torgersen, executive]

In previous quarters, you used to provide a cash flow generation forecast slide. Should we assume no update to your previous forecast for liquidity levels and leverage ratios?

[Euan Shirlaw, executive]

We haven't taken the approach of publishing every quarter. We won't take the approach for publishing every quarter outside of liquidity and leverage forests. Where we've published those in the past has been around specific events or for example, the revision to the Tyra schedule. I think also what you can see quite clearly is that if you look at the inputs to that liquidity profile and the current liquidity position that we start from, I think it's very clear that the outlook is very strong. And then also you can look at what the leverage profile is even pre-Tyra coming back on stream and it delevers very, very quickly. So it's not something that we're going to update every quarter going forward, but generally speaking, you can get a sense from where we are today.

[Cathrine Torgersen, executive]

And are you able to monetize your interest rate hedge to the extent you are repaying your RBL?

[Euan Shirlaw, executive]

So we -- effectively, we do monetize it because, although, we have repaid $100 million as of the RBL, we still get the benefit of having the delta between the underlying interest rate and the hedge rate. So we benefit from it even though the facility is not drawn to that level.

[Cathrine Torgersen, executive]

I think that was the final question and concludes the Q&A session. Thank you, everyone.

[Euan Shirlaw, executive]

Thank you.

[Marianne Eide, executive]

Thank you.