Karoon Energy Ltd

Yes. Thank you very much, and good afternoon, everyone, and thanks for joining our call and to those on the webcast.

As introduced, my name is Julian Fowles, the CEO at Karoon Energy. I'm joined today by Ray Church, our Chief Financial Officer; and Ann Diamant, who heads up our IR.

Earlier this morning, we released to the market our results for the first half of FY 2023, including a slide pack that we'll run through now. And we'll really just focus on the highlights, given that people have had a chance to look at and digest the pack already.

So if we can move to Slide 4, noting the disclaimer on Slide 2. This represents the first half highlights and our achievements, and I'll go through those as the headlines, first off.

So the headlines are, we had a very strong first half, both operationally and financially, during which we also delivered on our key growth projects in the Bauna interventions and in Patola. We managed to fund those activities through existing cash and cash flow from operations, meaning that we minimized the draw on our debt facilities, thereby reducing unnecessary spend, while also retaining a high degree of liquidity.

Safety, of course, remains top of our priorities, especially given the broad front of our current operations.

Some of the key highlights are that relative to the first half FY '22, we achieved a 275% increase in our underlying net profit to $82.4 million, driven by both higher production and higher oil prices. Our Bauna interventions have performed better than expected, and the 2 Patola wells also came in with better-than-expected reservoir quality.

Patola remains on track for first oil during March. And once on stream, we expect our gross oil production from BM-S-40 to reach over 30,000 barrels of oil per day before natural decline resumes.

We also upgraded our reserves just following the end of the half with a 23% uplift in 2P, meaning we've achieved an overall reserve replacement of 259% since we first took over operatorship of Bauna. And finally, on this slide, as we announced last week, the Neon-1 well reached TD in mid-February.

And the decision was taken based on the encouraging results of that well to drill Neon-2 once the operations at Neon-1 are complete. After Neon-2 has been drilled and completed, the data acquisition completed, our intention would be to release the rig.

So if we can move to Slide 5. This slide summarizes the progress we've made against our strategic objectives.

It's very pleasing to say that we've achieved much of what we set out to do 2 years ago. Although some of the work is still ongoing, most notably, the Patola tie-in has yet to be finished and Neon to be progressed through the drilling of Neon-2.

We have established Karoon's reputation as a safe, reliable and responsible operator, delivering on our promises and building value for our shareholders.

I'll now hand over to Ray and let him talk to our financial results.

Thank you, Julian. Good afternoon, everyone.

I also aim to point out the highlights that provide more detail of the presentation rather than talk to all the slide contents. And I think the main themes driving the financial results are the strong oil price, growing production and high uptime in facilities, controlled fixed costs, strong cash flow and sound liquidity position.

Moving quickly to the financial highlights for the year -- for the half year. You can see that all key financial metrics reflects continued improvement in performance compared to the same period last year.

The key drivers behind these positive outcomes are our reliable operations performance with high uptime levels, higher prices for our products and disciplined cost management in OpEx and capital projects. I'll flag that operating cash flow of $167.1 million showed a high rate of conversion of underlying EBITDA, and this funded all of the significant cash investment in our 2 major programs and minor CapEx associated with plant and equipment, office and IT hardware, while leaving liquidity largely unchanged at $342 million -- sorry, $343.2 million.

Just a few points to note on the income statement. Growth in revenue to $299.4 million was driven by 2 components.

Volume represented $61 million of this improvement from the comparable period with 7 liftings compared to 5 liftings from the Bauna field, while oil price growth represented a further $51.9 million increase in revenues from the first half of FY '22. Other income of $1.1 million comprises of interest on our cash balances across the period.

The reduction in unit OpEx for Bauna reflects increased production from the interventions program as well as largely fixed contract rates that have escalated annually for U.S. inflation.

In addition, we've seen modest procurement gains, savings through [ caught-on ]maintenance operations, intra-period weakness in Brazilian currency impacts on local costs and deferral of some activities into the second half. Costs also include $6 million of inventory movements driven by the increased production rate at the end of December.

Royalties of $30.3 million reflects the 35% increase in production and higher oil price. And included in this cost are also special participation and R&D levies, which were 1.1 and $1.7 million, respectively, and which currently offset the royalty rate reduction of $2.3 million in the half.

As production increases in future periods, the royalty reduction should exceed the R&D and special participation levies and become more visible.

Depreciation and amortization has increased to $48 million as a combined result of [ prior ] production and commencement of amortization of capitalized Bauna interventions cost. Corporate exploration and other costs totaling $14.6 million reflects some planned costs having been avoided, completed at lower cost or deferred.

Finance and interest costs of $3.7 million reflects not only the full 6 months cost of RBL commitment fees, interest and amortized borrowing costs, but also $2.1 million of noncash costs associated with unwinding of the discount on restoration provisions, which is an expense driven by changes in the U.S. 10-year treasury rate.

Underlying income tax expense of $43 million is affected by $1.3 million impact of noncash share-based payments and nondeductible costs in Australia, offset by a $1.3 million noncash benefit from FX movements affecting value of the Brazilian real dominated tax assets -- sorry, denominated tax assets. As these offset each other, the underlying effective tax rate reflects the Brazilian income tax rate of 34%.

And I'd like to point out that we have no remaining carryforward Brazil tax losses. The resulting underlying profit was $82.4 million for the half.

Slide 9 demonstrates the cash-generating capability of our operations as operating cash flow, including FPSO lease payments and finance cash costs grew to $144 million in the half. I'd like to note that this excludes $40.5 million cash for an early December lifting, which was collected on 3 January.

Payment for a second December lifting of $38.7 million was also received on 20 January. This net cash flow fully funded our major CapEx investments of $139 million without further requirement of debt drawdown.

This resulted in a growth of closing cash on hand from $158 million to $163 million through the half. This sets us up well for the balance of the Patola development and Neon control well cash flows and also provided adequate cash for the first contingent payment to Petrobras of $84.5 million in January 2023.

So moving on to liquidity on Slide 10. This means that the debt facilities haven't changed through the half with no further draws required since the establishment of the reserve-based facility in November 2021, $180 million remains, therefore, undrawn against this and the accordion facilities.

As you can see, these facilities begin to roll off from end of 2023 and with expectations of having successfully completed the Bauna interventions and Patola developments, and the resulting higher production that will support potential refinancing to begin later this year after production from Patola is brought online and Neon drilling is completed. With cash on hand of $163 million and overall liquidity of $343 million, this is more than adequate for remaining drilling and development cash flows, which is estimated at $160 million to $190 million through year-end as well as the Petrobras contingent consideration payment made in January 2023.

Looking ahead to guidance for the full year. While full year production guidance remains consistent with previous guidance, several items on this slide reflect our focus on cost management through procurement, optimizing maintenance operations, identifying avoidable costs and timing additional costs to align with production growth.

Consequently, full year forecast unit production costs are anticipated between $13 and $17 per barrel. While the first half unit production costs are slightly more than the full year range, this was driven by timing for production increases from Bauna interventions, and we're confident that we'll complete this year within this range.

And that unit cost should fall in the second half as higher levels of Bauna production will be present for the entire second half with additional ramp-up from Patola contributing further to unit cost reduction. Depending on Patola volumes and production uptime at those peak levels, we may be at the lower end of full year guidance, and that will be reviewed in the third quarter.

Other operating costs are expected to be between USD19 million and USD23 million for the full year with $9.2 million incurred in the first half. Finance costs, which include facility commitment fees and interest have increased to $9 million to $10.5 million for the full year, and this growth mostly in the second half is predominantly driven by the increase in the discount rate, which creates a noncash cost as Bauna and Patola restoration provisions are unwound.

Note that as Patola wells were completed in the half, although not yet tied in, $23.8 million was added to the restoration provision on the balance sheet, which also contributes to this noncash cost in the second half.

Unit DD&A guidance for the full year has reduced to $12 to $14 per barrel, driven by recently announced increases in reserves, partly offset by a higher amortizing cost base as Bauna interventions and Patola costs are commissioned and capitalized. In terms of investment expenditure, the Bauna intervention and Patola project costs for the full year are also now anticipated at $200 million to $220 million, and Julian will talk more about these programs shortly.

Other plant and equipment spend is now expected to be $4 million to $8 million as some contingent items will not likely be required, and we expect reduced spend on IT and cyber-related projects as cost of these projects are lower than anticipated.

Moving on, Slide 12 provides a reconciliation from underlying to statutory NPAT and EBITDA. As in the past, noncash movements in fair value of contingent considerations have been removed from the underlying result as have accounting-driven noncash FX movements on U.S.

dollar cash balances held in Australia. As our hedges were out of the money in July through November, while Brent crude traded above $90 per barrel, we recorded a realized loss of $7.1 million in statutory net earnings.

The tax rebate or social investments of $1.8 million were also represented in tax expense within underlying profit. These social projects investments achieved a 100% reduction in the income tax payable in Brazil.

So the costs and associated tax effect complications have been removed from the underlying pretax result while they remain in the after-tax earnings results or presentation curves.

I'll now hand back to Julian. Thank you, everyone.

Thanks very much, Ray. If we move now to Slide 14, which covers our Bauna operating performance.

What I'd like to highlight here is that we've managed to maintain a very high level of operational uptime despite introducing significantly more fluid into the FPSO, and that itself makes significantly more demands on the system than it had experienced in the recent past. We did see some equipment downtime, which brought down our performance from the previous high levels of over 99%, but with our uptime of 97.5%, this is still an outstanding result.

I would caution though that as we bring the Patola liquids into our processing [ trains ], I expect that we shall see further stresses in the system and hence, our target range of uptime going forward is a more normal range of 92% to 97%.

If we move now to Slide #15, this covers Patola. So following the drilling and the completion of the 2 Patola wells, the focus has now moved to laying the flow lines and umbilicals, tying those into the FPSO and undertaking in parallel the modifications that are required on the FPSO in terms of some additional piping and taking the product through into our processing trains.

Assuming no major weather or other disruptions, we do expect the field to come onstream in March. I'd also like to mention that for both the interventions and for Patola, we expect costs to come within the revised budgets that we announced last year.

Moving now to Slide #16. This presents our updated reserves and resources at Bauna.

The uplift we've announced reflect the reservoir and operational performance at Bauna that we've talked about over the last year or 2 as well as the higher reservoir policy that we encountered at Patola. It's quite a significant increase that we're seeing in our reserves, taking our 2P total at Bauna to 55 million barrels.

And as I mentioned before, this represents a 259% 2P reserve replacement since we took over operatorship in November 2020.

We go now to Slide #17. This summarizes Neon with the diagram on the left representing a schematic of the Neon-1 and the Echidna-1 wells together with the planned trajectory for Neon-2.

You can see Neon-2 in the left-hand side will be a well that's drilled at an angle, and it's drilled essentially under the flank of the Salt Zone. So quite a difficult zone to see on seismic, but a zone that may hold some significant quantities of oil.

So hence, we're keen to try and tie down what may be there. The result of Neon-I demonstrated that we had the presence of a single pressure regime between Echidna-1 and Neon-1.

And also, of course, we had the intersection of the oil-water contact, which sat below 25 meters of net pay. That's all good news, and that will help to reduce the uncertainty on the resource potential at Neon with an updated resource evaluation due to be the subject of further work once we've drilled and gathered the necessary data at Neon-2.

We're expecting the rig to complete operations at Neon-1, where we're currently doing some P&A and that will move to the Neon-2 location before the end of this month.

If you go to Slide #18. So Slide 18 highlights our sustainability work, focused on mitigating our carbon footprints and implementing a number of new social projects during the half year.

Our first sustainability report was released in August 2022, and I would encourage all the listeners that we have on the call to take a look at that to understand more about our efforts to reduce emissions in our operations, about our commitment to offset our Scope 1 and 2 emissions and also about our social and environmental projects. As Ray has also touched on, we've invested further funds as a tax incentive scheme into these projects towards the end of the half year.

Going now to Slide #19. This provides a summary of our progress in building shareholder value through delivering on our strategic commitments.

A strong commitment to health and safety lies at the core of our operating philosophy, while financial discipline remains a key element of the way that we work. We continue to seek out new and attractive opportunities for growth beyond our organic portfolio in our areas of interest through the application of a clear set of metrics, which any new project must meet.

The Board has committed that shareholder returns will be addressed in the second half of calendar year 2023 following the completion of our current capital-intensive projects and when the results of our production growth projects are fully known, and we have a clearer view of further capital priorities.

So with that, I'd like to hand over now to any questions that we have, and I'll hand it back to the controller. Thanks.

Just wondering, in terms of the Neon drilling, you've restated the resource numbers from [ 2019 ] and said there's no -- not aware of any data that affects those numbers. So is Neon-1 then basically completely in line with expectations, not really changing even 1C or 3C numbers?

So Dale, at this stage, we haven't had the opportunity to review in detail the wireline logging, which, of course, is the definitive results, nor have we yet had a chance to look at the 57 meters of core that we cut in Neon-1. So we haven't yet got any information from that data that will enable us to firmly change our view.

However, of course, those data points will be absolutely critical together with the Neon-2 results once we've got all of that data together to be able to put together a resource update. So I would expect that we will see an update to our resource figures.

Exactly what the direction of that update will be, I can't point you in that direction yet. But yes, over the next couple of months, I would expect to be able to get to grips with all of that data and then work on what that resource update will look like.

Does that then mean that it's too early to tell what the most likely sort of development case, if there is one at all, for Neon is?

That's correct. Yes.

We can't give a direction on that at the moment. As you know, we have currently 2 different scenarios for developing.

Neon-1 is standalone, which would probably stand up with higher resource volumes, whereas a tieback would probably be the preferred concept for -- towards the lower range of the resource.

Okay. And then -- sorry, just one other question, just the absence of a dividend guidance that was sort of discussed that, that was possible this month.

Just wondering sort of why that hasn't completed -- that process. And should we be inferring that there's other compelling opportunities to be spending money within the organization?

I would say there's definitely other compelling opportunities to spend money on. However, that might not hold back the Board's determination to pay money back to shareholders.

We're not yet through the end of our capital expenditure program. The Board really wants to see us get through the end of Patola and get through the Neon drilling program.

As you're aware, Dale, some of these programs carry risk -- operational risk and expenditure can be -- sometimes can be higher than budget. We don't anticipate that at this stage, but the Board is certainly taking a conservative view here and not wanting to put out there a message about dividends, which they may then have to dial back, should our performance not continue the way it is.

Great result, Julian. Just on the Patola production startup, how are you going to release information on that?

Are we going to get an announcement on initial production volumes or we have to wait till the quarterly?

So that really depends on timing, Gordon. At the moment, we're busy with the tie-in of Patola.

And there's a number of elements to that. We're laying flow lines, there's a gas lift line, there's an umbilical to lay.

We need to throw a winch on the FPSO, we need to pull those flow lines into the risers, and we then need to hook up those to the new pipe work that we've got on the FPSO. And then we need to go through a period of commissioning those facilities, which is not going to be a lengthy period.

It will be, I expect, a week or 2.

But all of that might mean that we end up with numbers of production, which we see in March and some stabilized production that's probably late March or April. So at this stage, I don't want to commit to when we will tell you about production outcomes for Patola until I can see a clearer line of sight to when we'll be completing those commissioning activities.

At the moment, as I've said, we're absolutely on track to get Patola onstream in March. The way we'll be doing that, we'll actually bring 1 well on first and then there'll be about 10 days or 2 weeks until the second well comes onstream.

So it will be somewhat staggered, which is useful from a production point of view, but it also helps the crew on the FPSO manage that production stream as it comes into the FPSO itself.

Okay. And also on the M&A strategy, the activity going on there, obviously, you looked at various opportunities.

Is the focus still primarily on Brazil? I'm assuming North America is also included as well.

Can you just explain a little bit on where that sits at the moment?

Yes. So Brazil absolutely is a focus.

It's the place where we have our operational team. It's -- we have a team also in Australia that is looking at opportunities, of course, especially those North American ones.

But the Brazil team that's focused on M&A, obviously, is focused into Brazil opportunities. But it's probably been -- there are fewer opportunities coming through in that landscape at the moment, probably because Petrobras has stepped back a little bit from its divestment program with the new government, the Lula government coming in.

They obviously will want to know what the lay of the land is under the new direction from Lula's administration.

Are you also looking at potential disposals by, let's say, some of the majors in Brazil or in other places? Is that still an active area of interest?

Yes, that absolutely is. We still see opportunity amongst the majors.

We've -- we see them as motivated sellers, although perhaps in some cases, especially amongst the super major group, perhaps they're, how would I put it, back pedaling some of that divestment strategy a little bit and focusing more on where they're making money. But certainly, we still see a number of motivated sellers amongst major oil and gas companies throughout the Americas, to be honest, as they consolidate some of their portfolios.

Okay. And just lastly, a question for Ray, just on the hedging.

The banks have given you some [ leave ] on the hedging requirements. Can you just remind me what kind of timing that is?

We have a redetermination coming up through the next 6 weeks. So we'll have a decision on the next one shortly.

You're asking about the next quarter, is that what you're thinking, the next tranche?

Yes. Yes.

I mean you basically had a reprieve on hedging I think over the last 2 quarters.

Yes. We're going through the redetermination now.

Obviously, production and assumptions around oil price contribute to that, probably the 2 main items, we're just working through with them now. But we should have -- we are applying for a waiver, as you'd expect.

And we'll know that in the coming weeks.

Just a question back on Neon-2. From the cross-section map you provided, it sort of looks like you're expecting compartmentalization at the Neon-2 location.

Is that the right way to read that?

Yes. Nik, one of the things Neon-2 will be assessing will be some pressure data.

So we'll take some pressure readings in the sections that we penetrate, specifically the Paleocene section and hopefully also down in the Maastrichtian. There is always -- as you get closer to the salt wall in these types of structures, there is the risk of increased -- or an increased risk of compartmentalization.

It's really pleasing that we didn't see any of that between Neon-1 and Echidna-1, but it certainly is possible in Neon-2.

However, I've got to say that you see on the map there, there's a little bit of offset, especially deeper down against that fault. And that reflects our interpretation at that location.

If you track that fault in 3 dimensions to the north and to the south of that location, the [ throw ] on that fault actually trends to 0, which means that you'll have in 3 dimensions, you'll likely have pressure communication. That doesn't mean that you would have exactly the same pressure communication over a production time frame that you would see in this respect over a geological time frame, of course.

But it would point to having things in communication and there being the possibility of pressure support. But the truth is we really don't know what that will look like.

The seismic imaging as we get closer to the salt becomes a little bit more difficult to interpret. And so that's one of the things targeted by Neon-2 is to try and address that.

Do you think there's likelihood you'd need to return to do a further round of appraisal at Neon before committing to FID?

Look, I -- would we drill more control wells? I mean, never say never, but I think it's unlikely, to be honest.

I think if there is a significant upside potential that we were to realize with Neon-2, then we may be tempted to have a further penetration at some stage of deeper levels. But in terms of the Paleocene interval, which is the main reservoir at Neon, I expect that Neon-1 and 2 will provide us sufficient information to make -- to take through a decision on what the potential concept might look like.

That would then take us into a more detailed engineering phase, which would really cost up what the potential development could look like.

And then on the back of that, we would make a final investment decision if that was warranted, of course. So there is still a bit to play out here.

But yes, these wells are critical to getting us to -- through those decision gates. So I'm answering your question, I think it's unlikely for the Paleocene.

If we get an upside with Neon-2, there may, in the future, be a further deeper penetration that we want to do to essentially appraise potential deeper volumes. I don't think that's going to be something that we would do prior to trying to make a decision about Paleocene development or not.

Got it. Just a couple of very quick questions, hopefully, for -- maybe for Ray.

Just the comment on your Slide 10, you say plans for refinance underway based on larger borrowing capacity. Just thinking about, you're going to be -- I mean you are already net cash and once you get through this CapEx campaign, you should be strongly net cash thereafter.

So in terms of the need for a larger facility, can you just walk us through the thinking there? I mean, given -- I can't see the opportunity set in the near term, given the reserves are all developed after Patola.

So outside of M&A, why do you need a larger facility?

I expected that question. Thank you.

Obviously, I did say it was potential and the potential is really related to if we have a need for capital. So it's really dependent upon what opportunities we might see for the use of those funds.

That's really the -- it's potential if we see the need. As you say, if we are simply -- if we don't have a need then we wouldn't refinance necessarily.

Got it. And a very exciting depreciation question for you, Ray.

Just around the FPSO vessel depreciation in the half, can I just confirm that on a unit of production basis? And then, going forward, assuming that's correct, given we've just had quite a material reserve increase, should we expect that unit of production rate to come down in the second half of FY '23?

Okay. So we obviously don't own the FPSO.

So our assets are everything attached to it. But your question is correct.

I'll just clarify. With the reserves growth, you're right, the units will be more, therefore, the rate will decrease, but production will -- has gone up.

So the production increase in the short term outruns the rate decrease in DD&A. And then, of course, our asset base will take the investments to date and then the Patola costs on to the balance sheet.

So you'll have a larger cost base to depreciate as well. So in the near term, it's not likely to see that it reduces.

And I think our full year guidance reflects that while production stays up as it is. So eventually, you're right, it will start to drop as production winds off, but it's outrunning the rate reset with the reserves growth at present.

Congratulations on the result. Just following Gordon's question.

In terms of M&A -- if that's acquiring [indiscernible], if at all?

We couldn't quite hear the question. Would you mind repeating that?

I was just saying, following Gordon's questions, what kinds of M&A are you looking to do, if that's acquiring assets or farming in? And what kinds of partners are you looking at?

Yes. Look, it's a great question, and it's something that we addressed during our strategic review sort of 18, 24 months ago.

Primarily, Karoon is in the business of producing oil. So we're looking for oil assets primarily.

It doesn't mean that we're never going to be looking at gas and in the right marketplace. I think that's certainly something we would take a good close look at.

We're primarily looking also at assets that would be offshore. We think our development and production capabilities are in that area.

And we're looking geographically, of course, in the Americas.

In terms of operated versus nonoperated, I'm pretty agnostic on that, to be honest. We like to have a good sizable stake and have some influence in a joint venture.

That's really important for us. If we're operating, that's great.

We've got a lot of confidence about how well we can operate. But if we have a good reliable partner operating who is aligned with our values and aligned with the way we see things technically, then I think that, that certainly is something that we'd be very comfortable with.

So yes, look, I think the primary things are oil, offshore and near-term production. So if it's not already in production, then it has to be -- there has to be a line of sight to production.

People use the term shovel-ready, post-FID, whatever you want to call it, there has to be good line of sight to production.

And in terms of scale, I think that's another important point. We're not really looking for things that would be [ 1,000 ] or 2,000 barrels a day, more on the order of 5,000 to 10,000 barrels a day.

If some of that is gas as well, of course, that's okay, but primarily, of the scale that would be material for Karoon and Karoon shareholders. With the primary elements in our analysis really being about creating value for shareholders, so we have to see a pathway that creates really solid long-term value for our shareholders.

And I just have one more question, if I may. Congratulations on the first Neon appraisal well.

I'm sure you're very keen to log that core that you just took. And I was having a look at the 2019 pack that you had, that had what looked like a 3D surface of Neon -- with that DHI up to the salt side -- I was just wondering if your seismic is being supported by what you found -- and just what the key risks...

I'm losing a little bit of your question, but I guess it's about the seismic and what the risks are around the size of interpretation?

Yes.

Yes. So yes, you're right.

We have a very good seismic response, which is one of the things that we were testing with Neon-1. We've reprocessed the seismic since we last had operations ongoing at Neon.

And we've been, I guess, to some extent, testing the quality and the interpretability of that seismic. What the well at Neon-1 showed was that the oil-water contact is predictable.

So we were within a few meters of the predicted oil-water contact on the basis of the seismic interpretation, so the DHI that you've mentioned, what we actually saw the oil-water contact in our core. And although we haven't logged that yet, that's something that we were able to see on the rig itself.

So that's given us a lot of confidence around the seismic.

However, as you get close to the salt diapir, as you said, that imaging tends to be not quite as good. And that's a function of the orientation of the seismic survey.

The seismic survey was shot obliquely to the wall of the diapir, which means that it's a little harder to get a definitive line, if you like, that would define the edge of that diapir. And that's one of the things that Neon-2 will be looking at as it get -- the bottom of Neon-2 is a little closer to the salt than the top.

It's a few hundred meters closer. And at that scale, we're only a couple of hundred meters away from potentially where the salt diapir is.

In conjunction with that, with the sonic results that we're getting at Neon-1 and also at Neon-2, that will go back into a reprocessing of a seismic, again, to give us another look on where best to drill our potential future development wells and what the orientation of those should be. So we're gaining a lot of confidence in the seismic interpretation, especially around its ability to predict fluids and fluid contacts.

And yes, that's a direct result of Neon-1, and we'll get further calibration in Neon-2.

I'm going to have to maybe re-ask some of the same questions in a different way. You touched on it a bit, Julian, with the super majors, so I guess, you have maybe realized the world is not going to stop consuming hydrocarbons tomorrow and 20% [ IRRs ] are better than 2% IRRs.

Do you think that changes the M&A landscape for you? Do you think you need to look more towards some of the mid-tier, small-tier operators and sellers?

Or you think there's still viable deals to be done with it?

Yes, Mark. Look, that's a good question.

And definitely, we're seeing, I think, a subtle movement in the landscape there at the moment with respect to how the majors -- super majors especially, of course, we've seen that from BP, how they're positioning themselves. And that has not [ got an ] effect into the -- some of the smaller companies.

And of course, you talked about smaller companies in the U.S. Gulf of Mexico setting.

Those are still $10 billion or $20 billion companies. And there's many private companies in that space as well.

So I think that you're right, there's a rich set of opportunities that also exists in some of the smaller ones. It's not just the big guys.

And we've, I think, had good communications with a lot of the players in those sorts of companies. And from 2 perspectives, both from the point of view of Karoon as a potential partner in the future in, for example, Gulf of Mexico things, but also if any of those are looking at an entry point into Brazil, then potentially, once we've come through our Neon program, we may have some opportunities for them there to look at as well.

Can we just confirm as well? I don't know, there's a change in language from the previous time from the Americas to Brazil and North America.

I don't know if that was just a geographical clarification rather than no change in sentiment, but it sounds like you're pretty definitively saying at the moment, just offshore as you go up into North America, you're not looking at anything onshore North America?

Never say never. I think looking onshore North America, there are some good things there.

I don't think we would likely move in -- as the next step in Karoon's growth, I don't think we would move into the onshore area. That doesn't mean that it's something that we don't see ourselves doing further down the track.

So maybe if the next move is our second move, then maybe a third or fourth move could be into something more attractive on the onshore side as well.

And then maybe just quickly one for Ray would be refinancing. Are we expecting to avoid having to hedge as much oil price exposure for debt that at the moment seems like you're never going to use?

I'm trying to put in place, if we do refinance then we're looking for a lot more favorable structure. I suppose, hedging would be one of those.

We have a bunch of other, I guess, conditions in the current facility that are associated with, I guess, the age of the company at the time and the asset itself that was new, so good reason to have them there, but we'd like to remove that. So hedging is one of them, and then there are others as well.

So I think the short answer is yes if we can achieve that.

Just a couple of quick questions for me. Just -- we're another month down the track, just post the intervention work.

So just keen to see how those Bauna wells are performing now. Are you still seeing that steady sort of decline, if at all, unfolding as you expected?

Yes. Look, it's a good question, Adrian.

We have seen some initial decline at those interventions. And as we anticipated over the first few months of production, given the higher rates that I guess they declined reasonably quickly from those peaks that were above 25,000 barrels a day to where they are now between 21,000 and 22,000 barrels a day.

That seems to have -- the curve there seems to have flattened somewhat, and we're anticipating decline rates there that are sort of more stabilized to where we were prior to the interventions.

So around about that 12%, 13%, 14%, 15% mark per annum is sort of where we are now. When we bring in Patola, the data on that will be -- it will be a little more patchy because, of course, we've got Patola coming in at virgin pressure.

To get the decline rates on individual wells, we actually have to put them on tests. We don't have individual monitor equipment on each well.

So we have to take each well out of sequence and put it on to the test separator. So we'll have less continuous data about the decline rate from specifically Bauna and Piracaba, given that some of that picture will be clouded somewhat by the new production coming in from Patola.

Yes. That's very clear.

And just one more on Neon. Assuming Neon-2 is successful, and it does boost your confidence in the resource exactly to plan, just assuming, but just say it does, is there potential for Neon to compete to become asset #2?

Or is it more asset 3 to 4 in the long term? I've always appreciated the clarity you guys have on strategy.

So just interested in where it could possibly compete for capital...

Yes. Another good question.

Look, another good question. I absolutely hope it is competing for capital for -- with a good M&A project.

I would hope, under the right circumstances, to be able potentially to do both, partly, I think, because Neon -- a final investment decision is not going to be taken in 2023 -- not in calendar 2023, right? We've got quite a lot of work still to do around what the concept is likely to look like and then around costing that up.

And as you know me, Adrian, I don't want to come out with sort of blue sky numbers about what may or may not be the cost of a potential project. I want to be able to get those so that I can talk knowledgeably to shareholders, to analysts, to the market.

So that's going to take a little bit of time to get there.

And if we're doing some good M&A, I would hope that we can see some of that M&A through the next sort of 18 months. And that would be prior to -- or towards the end of that certainly is getting around when we would potentially be targeting a Neon FID.

Having said that, Neon, of course, if it gets to FID, it has the potential to be a good farming target for a potential joint venture partner. So that could end up having a lot less capital requirements than you might think for otherwise, at least for Karoon, if we were to hold it 100% relative to farming it down.

So I think that there's ways that we can look at financing that aren't necessarily going to put it in such strong competition with potential M&A.

Yes. Look, thanks to everyone, and thanks, everyone on the call.

I'd really like to say a big thanks to the teams in Australia and Brazil, both our onshore and offshore teams and our key contractor partners have been really so instrumental in working with us to deliver the good outcomes that we're seeing now and hopefully continue into the future. Lastly, of course, I'd like to thank our shareholders for their continued support during this critical growth period of the company.

And I look forward to be able to update the market with the outcomes of the Patola tie-in and the Neon-2 drilling results over the next few weeks and months. So thank you very much.