Karoon Energy Ltd

Thank you, Kayley. Good morning, everyone, and thank you for joining our 2024 Half-Year Results Webcast.

My name is Julian Fowles, and I'm the CEO at Karoon. And I have with me this morning Ray Church, our CFO; and Ann Diamant, our Head of IR.

Earlier this morning, we released our 2024 half-year report and presentation to the market, which we are now going to talk through. Noting the disclaimers on Slide 2.

I will move through to Slide 4, which provides an overview of the first half of 2024. Karoon's main focus during this period was on ensuring the safety and reliability and production from our base assets to support sustainable shareholder returns.

We also progressed our organic growth opportunities in both Brazil and in the USA. The 3-week shutdown of the Bauna FPSO was completed as scheduled and production is currently around 25,000 to 26,000 barrels of oil per day, in line with our expectations.

Meanwhile, Who Dat production reached more than 42,000 barrels of oil equivalent per day gross at the end of June. Looking at our organic growth opportunities, the Neon Foundation Project has entered Concept Select and work is underway ahead of a potential FEED entry decision in early 2025.

In the USA, the Who Dat East well was successfully drilled, while the Who Dat South and Who Dat West wells are both approved and expected to spud in the coming months. While Ray will go through the financials in more detail, I would like to highlight that the first-half 2024 financial results demonstrate the improved resilience of Karoon's operations following the acquisition of Who Dat, with profits generated by Who Dat partly offsetting lower profitability from Bauna.

As anticipated in our strategic review of 2021, having diversified sources of income has also allowed Karoon's Board to determine to pay Karoon's first ever dividend of AUD 0.04496 per share. The dividend will be fully franked, releasing the AUD 15.5 million of franking credits on Karoon's balance sheet at the 30th of June.

The dividend will represent a payout ratio of a little over 21% of underlying earnings, in line with our new capital returns policy. This half-year payment is equivalent to an annualized yield of approximately 5% at yesterday's share price.

It should be noted that the dividend is in addition to the USD 25 million on-market buyback, which commenced on the 12th of August. Company is in robust financial shape with low gearing and strong liquidity.

Slide 5 summarizes our safety and environmental performance. Safe and reliable operations are Karoon's highest priorities.

But unfortunately, we had a lost time injury and a medical treatment case in the first half of 2024. This is the first LTI at Bauna in over 18 months.

The team, together with our contractors is implementing further measures to improve this focus on safety as we believe all injuries are preventable. Turning to our environmental performance.

No spills were recorded in the first half of 2024. I'll come back to our operational performance and growth opportunities a little later in the presentation.

But now, I'll hand over to Ray to talk in more detail about our financial results.

Thanks, Julian. Good morning, everyone.

I'll start with a reminder that this is a half-year result on the new calendar year basis of reporting. So, comparisons are made against the transition year 2023, which covers July to December '23.

And just a reminder, we report in U.S. dollars.

So, all the figures except the franking account balance references are in that currency. Slide 7 reflects Karoon's transformation over the last few years.

Our investment in the Bauna intervention program and Patola project, together with the acquisition of interests in Who Dat, has led to an increase in production from 2.3 million barrels of oil in the 6 months to June 2021 to just over 5 million barrels of oil equivalent in the first half of 2024. This was accomplished and accompanied by a 5-fold increase in underlying EBITDAX from $58 million in the 6 months to June '21 to $266.8 million in the first half of 2024, as our assets have a largely fixed cost base.

I'd note that Who Dat's first 6 months' contribution almost fully replaced the production sales and EBITDAX deficits in the Bauna project. At the same time, this growth has been achieved while maintaining a prudent balance sheet with net debt and net gearing at USD 68 million and 6%, respectively, at the end of the 30 June, 2024, while also funding increased CapEx at Who Dat.

Moving on to Slide 8. I'll go through our first-half 2024 underlying results in a little bit more detail.

As we saw similar average oil price in both periods, volume sold drove most of the revenue movement, which was slightly lower in the first half of 2024 compared to TY 2023. The lower Bauna sales largely replaced by the Who Dat sales volumes.

Transportation costs increased $4.3 million due to a full period of pipeline tariffs related to transporting Who Dat hydrocarbons onshore. This was partly offset by $1.9 million of lower tariff transfer costs in Bauna, as the prior period experienced more weather disruption.

Operating costs shown here on an accounting basis, which includes production-linked amortization of capitalized leases at Bauna, where operating costs reduced by $12.4 million, offset by $13.2 million of production costs at Who Dat. And I'll mention this again on the next slide.

Royalties in the half were lower in line with revenues from Bauna. DD&A is higher between periods.

This was driven by the addition of Who Dat, which has a higher unit DD&A than Bauna, reflecting depreciation of the acquisition and development costs on a 2P unit of production basis. Finance costs were also higher in the first-half 2024, reflecting the cost of debt used to acquire Who Dat.

The increase in inventory expense reflects a reduction in inventory levels as no cargo is in transit at the 30 June, 2024. The effective rate -- tax rate in first-half 2024 of 29% now reflects a blend of Brazilian 34% and U.S.

21% income tax rates. Our reconciliation between underlying and statutory NPAT and EBITDA is provided on Slide 25 for reference.

Moving to Slide 9. This shows cash OpEx per boe after normalizing for AASB 16 effects.

This is a better representation of the production cost and aligns with industry practice. Unit OpEx in the first half of 2024 increased 22% against TY '23, largely due to lower production at Bauna and partly offset by lower unit OpEx at Who Dat.

I'd point out that the unit production cost of $13.51 per boe includes Who Dat OpEx of $8.74 per boe based on Karoon's net revenue interest production. This is after netting off government and third-party royalties.

So on a net working interest basis, consistent with how Bauna has reported, Who Dat unit costs in first-half 2024 were USD 7.18 per boe. You can see on Slide 10 that Karoon operations generated $202 million of cash and that covered our increased CapEx spend, mostly Who Dat development and exploration wells and the contingent payment of $86 million made to Petrobras, leaving $45 million of free cash flow for the period.

Slide 11 provides some color to our CapEx spend in the last 12 months and revised guidance for calendar year '24. We expect calendar year '24 CapEx to be between $150 million to $177 million, down from $170 million to $207 million, with $20 million to $30 million that was expected to be spent on SPS-88 well intervention in the second half now deferred to 2025.

As the Who Dat West exploration wells have now all been approved by the joint venture, CapEx related to this well has been moved from contingent to firm and all other CapEx guidance is unchanged. Moving to debt and the balance sheet.

Slide 12 summarizes our 2 available debt funding facilities. As I mentioned earlier, we have a prudent level of gearing on the balance sheet.

However, we do expect the balance sheet to work and in May, we accessed the U.S. 144A bond market by issuing an inaugural $350 million bond.

This supplements our RBL debt facility and expands Karoon's sources of debt, and does so with less onerous terms in the largest pool of capital for mid-cap energy companies. The proceeds of the bond were used to repay the RBL, and the bond was priced at 10.5% or 11.7% all-in cost including fees.

And that compares to 13.7% for the RBL when you consider hedging cost. Slide 13 reflects our revised capital allocation framework, reflecting the Board-approved approach to shareholder returns and clarity of the balance sheet strength measures.

Our highest priority remains on ensuring safe, reliable and sustainable business operations. We also aim to maintain a strong and flexible balance sheet, while making 20% to 40% of underlying NPAT available for returns to shareholders, subject to market conditions and Board approval, either as a cash dividend, a share buyback or a combination of both.

We believe this framework strikes the right balance between rewarding shareholders, while retaining sufficient capital to reinvest in the business. Thank you, everyone.

I'll now hand you back to Julian for update on the assets.

Yes. Thank you, Ray.

And turning now to Slide 15, the operating performance of the Bauna Project. First-half 2024 production was lower than TY '23 due to the 3-week shutdown and FPSO reliability issues, in addition to the continued outage of the SPS-88 well.

While we completed more than 99% of the works intended for the planned shutdown in May and June, the FPSO operator is currently undertaking a heightened level of maintenance activity to improve the reliability of the vessel and address some of the backlog of maintenance activities that built up during and post-COVID. We're also working with the FPSO operator to investigate the viability and benefit of bringing forward the Bauna Life Extension Project, currently planned to take place in 2026 into 2025.

This project is designed to extend the FPSO life from the current 2028 out until 2032. We expect to be in a position to finalize the scope of what is required and make a decision on timing in the next few months.

The workover of the SPS-88 well has been deferred into the first half of 2025. Since due to the IBAMA regulatory agency industrial action, we did not receive our environmental permit and the rig owner moved the rig we were targeting to other operations.

We have identified alternative vessels and are engaging with their owners with a view to undertaking the required work in the first half of 2025, subject to securing the intervention vessel, subject to regulatory approvals and negotiating suitable contracts. Now to Who Dat on Slide 16.

First-half production -- first-half 2024 production rates were lower than expected, largely due to delays in bringing new wells on stream and the capacity of the system to manage higher pressure flows. High-rate gas wells were also curtailed in the first quarter of 2024 due to low Henry Hub gas prices.

Who Dat production rates improved in the second quarter after implementing various opportunities to increase production, and the Who Dat FPS was producing at over 42,000 barrels of oil equivalent per day gross at the end of June, albeit rates are now lower due to planned gas compression maintenance. Our CY '24 Who Dat production guidance of 3 million to 3.5 million barrels of oil equivalent on a net revenue interest basis is unchanged and incorporates scheduled maintenance in 2H '24 as well as natural field decline.

The joint venture continues to look for additional opportunities to maintain and increase production. Some of the types of production opportunities being studied are highlighted on Slide 17 for potential implementation in 2025 and beyond.

Now turning to Neon on Slide 18. In March, the Neon Foundation Project entered the Concept Select phase.

The Neon team is currently reassessing all aspects of the potential development with a clear direction to establish if and how low case technical and economic outcomes could be mitigated. Existing 3D seismic has been reprocessed and is now being interpreted by the team.

Potential development plans that minimize CapEx, derisk uncertainties and reduce time to first oil are being considered. The next major milestone will be in early 2025, Decision Gate 2 involving potential entry to front-end engineering and design work.

Slide 19 provides an update on the 2024 Who Dat exploration and appraisal campaign. In the second quarter of 2024, Who Dat East was drilled and successfully intersected 45 meters of net pay, interpreted to contain liquids-rich gas-condensate as anticipated in 4 of the 5 Miocene reservoir intervals targeted.

The well was subsequently suspended as a potential future producer. As you can see in the Who Dat East schematic, there is potential for a continuous hydrocarbon phase in a number of high-quality sands correlated to the nearby MC 509 Exxon #1 exploration well.

The data gathered is being analyzed and will be incorporated into our 2024 year-end reserves and resources report to be released in early 2025. Updated Who Dat East well metrics will help the joint venture determine the commerciality of a potential development, most likely through a tieback to the existing facilities at Who Dat or Dome Patrol.

Meanwhile, Who Dat South is expected to spud in September and is expected to be drilled to a depth of approximately 7,425 meters and will test 2 targets in the Miocene section, with the shallower target similar to the reservoir in the G-1 well. The Who Dat West exploration well has now been approved by the joint venture and is expected to spud in late 2024.

Who Dat West will target 2 main zones, also within the Miocene section. The well is expected to be drilled as a deviated well to a little over 7,500 meters.

Moving now to Slide 20. Our emissions intensity increased in the first half of '24, reflecting lower production at Bauna spread over a largely fixed operational base, as well as the Who Dat East drilling campaign.

We remain committed to our target of being carbon-neutral for our Scope 1 and 2 emissions and have acquired sufficient high-quality carbon units to offset our TY '23 emissions and expect to do the same for the first half of 2024. We have also expanded our social programs, and the photos on the right that you can see here show 2 of Karoon's sponsorship programs for underprivileged children in Rio de Janeiro.

Slide 21 outlines our guidance for CY '24. The only changes relate to CapEx as covered by Ray.

As highlighted in our ASX release, Bauna production is expected to be towards the bottom end of the range. Slide 22 summarizes our first-half performance.

Karoon remains committed to safe and reliable operations as our first priority. Near-term catalysts include the 2 exploration wells in Who Dat South and in Who Dat West.

As noted earlier in the year, having achieved the objectives of our 2021 strategy with the delivery of the Bauna interventions, the development of the Patola field, Neon control well drilling, the acquisition of a second high-quality producing asset, the securing of additional funding sources and the announcement of our capital returns policy and now our inaugural dividend, it is timely for us to undertake a review of the ongoing strategy. We expect to complete the review this calendar year, and to be in a position to discuss outcomes early in 2025.

Karoon remains in a strong financial position with a robust balance sheet and low gearing. Despite production reliability issues during the first half, we have positioned the company to benefit from current oil prices, delivering strong cash flows and with access to a variety of funding sources.

Our assets lie in 2 of the most prolific and prospective hydrocarbon basins in the world and present a number of organic growth opportunities, although we do caution that supply chains have become stretched and the current CapEx environment remains inflationary. Assuming no major operational or oil price shocks, our production base and continued financial discipline should provide Karoon with the capacity to provide attractive returns to shareholders through dividends and/or share buybacks, as well as funds to reinvest into growing our business, driving value-accretive capital growth for shareholders.

I would like to thank all of our staff and contractors for their hard work and dedication to Karoon through this first half and to thank our shareholders for their continued support of the company. Ray and I will be very happy to take any questions now, first from the telephone lines and then if there are any from the online facility.

And I'll now hand back to Kayley, the moderator.

So, just thinking about that capital allocation, there's a sentence in the release that says there are several -- this is for Who Dat, there's several additional value accretive medium-term infield opportunities to potentially mitigate natural field decline. I was hoping you might be able to expand on what exactly that means.

I guess the thing that we struggle with in markets is how we should think about that production outlook and the amount of CapEx that's needed to underpin such an uncertain production outlook. And also, like when you look at allocating capital as a joint venture into that field, what do you think the learnings are from having drilled those G wells and the issues you've had with commingling?

Like, if you had your time again, like, would you still have drilled those wells? Are they still generating the kind of returns that you expect?

And therefore, as we think about these, "value accretive" infield opportunities, like, is that really the best use of capital?

Yes. Thanks, James.

And yes, thanks for the questions. Look, I think around the types of opportunities that we have at Who Dat, at the higher CapEx end of the scale, we have things like new infield drilling opportunities.

And we still have additional capacity in terms of slots on the facility and ability to bring new wells online. At the lower end of the CapEx scale, we have things like sliding sleeves, which we can move with intervention vessels.

And we also have in between those 2 extremes, we have sidetrack opportunities in existing wells that have maybe watered out or maybe declined significantly in production. So, there is a range of opportunities there.

All of those, of course, are assessed on their economic viability and potential risks, and that is sort of put into the mix in terms of the best or most optimal use of capital. Generally, those infield opportunities have very high IRRs.

They have very rapid payback times. We see that with the G wells, even though we had to curtail some of the production from those G wells earlier in the year due to the types of pressures that we were seeing.

Seeing the production from those wells now, they're very highly profitable infield opportunities that we brought on stream. So, we are looking at a variety of those.

We're work shopping with the joint venture actually doing that over the next few months to put in place what that opportunity set will look like from a prioritization point of view for both 2025 and 2026 allocation of capital and production profiles there. In terms of how you should think about that, obviously, we haven't yet come to the market with a 2025 profile.

Any opportunities that we see in Who Dat will likely not be able to be brought on in the first half of '25. They more likely be second half of '25 or later.

And obviously, those would be incorporated into those profiles. At the moment, I don't have clear visibility of how we'll prioritize those though.

So, I'm not able to give you any steer on that at this stage.

So, I guess in the past, though, we've talked about Who Dat being a sawtooth profile and now the language is mitigating natural field decline. So, does that now supersede this view of the sawtooth profile where you are sort of getting back up those higher rates as you do this activity?

I think without a doubt, we'll continue to see sawtooth profiles. I mean, it's a largely oil producing field.

Oil fields in Miocene reservoirs, the Gulf of Mexico typically have decline profiles that are somewhere between 10% and 20% per annum. So, I expect that we will see continued sawtooth type of performance.

And our challenge, I guess, is to make sure that we bring the right opportunities on stream at the right time to minimize the downsides of that sawtooth. That's really what we mean by maintaining production profiles.

So, yes, I'd like to see, at a certain point in 2023, production at a gross level in Who Dat dropped to between 20,000 and 25000 boes a day. I want to make sure it doesn't drop down to those levels that it saw previously.

But under our participation here, we can maintain things well above 30 and hopefully, maintain things closer to where we are today at that 40 -- 40 plus level.

Yes. Okay.

Then lastly, with the CY '24 production guidance, tracking towards bottom end of the range. Look, I mean, ourselves and consensus look like we're already there, so perhaps not a surprise.

But I guess, if I think about sort of year that we've had, and I hope you don't mind me describing it in this way, but it feels a little bit accident prone. I'm just wondering whether we're skating on thin ice here with respect to the production guidance that there is extra unplanned downtime, that it could actually lead to you falling below.

Do you think that's a fair statement? Or you're quite confident how the next 4 months is going to shape up relative to that guidance?

Look, I think, in the absence of unforeseen events, significant unforeseen events, we're comfortable with the guidance as it is, of course. There is always a risk that offshore operations, both in Gulf of Mexico and in Brazil that unforeseen events can take place.

We believe we have a very good program in place to ensure that we keep things moving on the FPSO at Bauna. If we have any indication that we're likely to drop below guidance, we will come straight to the market to update the market with that, of course.

At this stage, though, I think we're comfortable to sit within the guidance range. But as we say, down at the lower end of that, Who Dat, of course, sits in that range between 3 to 3.5 and it's tracking towards that range.

Can you please give a bit more color on the SPS-88 timeline? So, I just wanted to confirm that the environmental approved, the permits are still outstanding.

And how are conversations going regarding the intervention vessels? Like, does it look likely that you'll be able to access one when needed next year?

Yes. Look, it's a great question.

We were, I guess, a little bit put off by the IBAMA industrial election this year, which delayed that environment permitting. Not just for us, it delays permitting for everyone.

The estimates -- informal estimates have seen that it was costing the Brazilian state between $10 million and $25 million a day just in revenue to the state, let alone what would be coming into the companies. So, yes, they've resolved that strike action at IBAMA now, but not early enough for us to have maintained the vessel that we had planned for that activity.

So, we've gone back to the market and we do have a couple of options there. One of which is in, I guess, very well progressing negotiations for a particular workover unit that would be available in the first half.

There are 1 or 2 others that are also available in the first half. So, we're reasonably confident that we can secure a vessel.

My confidence around IBAMA regulatory approvals, typically, Karoon has not encountered issues with IBAMA on the regular side of things. The industrial action, obviously, threw us, as it did the rest of the industry.

It seems as though IBAMA is comfortable with the resolution they came to with the government, and we don't anticipate that they would restart that industrial action. We are hearing, though, that the overall regulatory agency, the ANP, has been considering industrial action because I think they didn't get the same deal as IBAMA that is not at this stage impacting the part of the agency that provides us with our permits.

And they already indicated that they would approve the permit for the intervention activities. So that's the broad regulatory permit.

The IBAMA permitting will need to go through another approval process with whichever vessel we land on. So, that usually is a 3-month process from start to finish for an activity like this.

I anticipate that we would be well positioned to do that within the timeframe that we're talking to the market in terms of first-half 2025.

Great. While we're on Bauna, can you talk through some of the enhanced maintenance programs that you're expecting to improve reliability?

So, just thinking about, like, what you're actually targeting and what you're expecting with that maintenance program?

Yes. Look, there's 3 or 4 key areas for that.

One is to do with gas compressors. So, we currently have one gas compressor that's up full time, but we've got a couple of gas compressors that are requiring some work.

One of those we anticipate will come back online in 2 weeks, and the third one a bit later in the year. It's good for us to have the backup with those gas compressors.

With only one operating, we probably have a few 100 barrels a day that we're not accessing because we can't quite get the volume of gas lift that we would like. So although that's not material, it's still important for us, and we'd like to see that back.

So, that hopefully, we'll see coming back on stream in the next couple of weeks. A second area is that we have -- around the production header, we have some corrosion within the pipework.

And that is subject of some ongoing investigation to look at the causes of the corrosion and to look to fix that. So, although we've got repairs in place and that's all producing securely and safely, of course, it's an area that I want to make sure is looked at, because if it's not looked at carefully now, it can come back and bite us during 2025.

So, we've got ongoing work there. And a third area of enhanced maintenance is around -- it's related to the dehydration units, which is important for the gas lift.

One of the issues we encountered with, at the time of SPS-88 going offline was that we were having problems with the dehydration unit on the FPSO, which was leading to us having a higher moisture content than is acceptable in the gas that we reinject into wells for gas lift. And that led to the formation of gas hydrates downhole.

That's not a good outcome. So focusing on that gas dehydration unit, making sure it's operating in as pristine a condition as possible is a key focus for us to ensure that the gas lift remains operating at the optimal level.

So, those are 3 key areas that we're really focused on.

Just first question, this Bauna Life Extension Project. There's sort of discussion in the pack about bringing that forward into '25.

What sort of -- does that have a production impact and what sort of CapEx? Just broad levels, what we're thinking there?

So, we don't yet have the scope and timeline for that defined. We're investigating what that scope might be and the potential benefits of doing that in '25 relative to '26.

Obviously, our objective there will be to minimize any impact on production that we might see and obviously, to ensure that costs are most efficiently allocated to that. I think in order to improve reliability, it is something that I would like to do rather than keeping it on the '26 timeframe, bringing it forward to '25, conceptually to me, makes sense.

In terms of CapEx, we don't yet have numbers for that. That'll depend on exactly the scope of work that is envisaged.

And, yes, the impact on production will also depend on the scope of work. We'll be as clear as we can about that later this year once we have the scope outlined.

And that will obviously be a key part of our guidance for 2025, both in terms of production and in terms of the CapEx involved.

Okay. And just in terms of Gulf of Mexico business, can you give us sort of a sense on maybe sort of a low case and a high case of maintenance CapEx here?

I mean, you talked about the 30,000 to 40,000 barrel a day range there, depending on what sort of activities you do. But can you give us a sort of range, what you're thinking would be annual CapEx and then also just sort of annual exploration as well, obviously, spending a lot this year.

But what should we expect going forward more in like a 3-year range because it obviously feeds back into free cash flow to do other things, whether that's buybacks, phasing in dividends, et cetera?

Adam, this is Ray. We look at Who Dat with a, I guess, a sustaining maintenance type CapEx of around $5 million per annum, maybe a bit less.

But there is the expectation to maintain the 2P production profile that every couple of years we have a couple of development wells to drill. So we expect, if you wanted to model longer term, you just average that at around $20 million per annum.

$25 million a year roughly for the maintenance drilling, is that fair? And then what's the maintenance exploration as well?

Is that one well a year or more or less?

Yes. Look, at the moment, we've got Who Dat East, South and West, obviously.

We don't currently have additional exploration targets defined. I think the work that we're going to do in the joint venture will be focused on, obviously, primarily looking to try and commercialize Who Dat East.

So, there may be scope for a further well drilled there that's not likely to be a 2025 well, but could be a '26 well if that proves to be the optimal development case. Who Dat South and West, of course, any appraisal and development there will depend on success or otherwise, and will be defined at that time.

All of those 3 -- well, the discovery and the 2 prospects, those are all within tieback distance, of course, to Who Dat facility. And that's one of the attractions of entering Who Dat and entering the Gulf of Mexico and the Miocene in particular is that the cycle times from discovery to tieback are generally 2 years to 3 years.

So, a couple of years shorter than they are in other locations. So, that's obviously something we're going to be pursuing.

But, yes, it'll really depend on what those appraisal and development plans look like in the case of success. We don't, at this stage, have additional exploration prospects defined around Who Dat.

Okay. That's good color.

And just final question just regarding -- look, the dividend structure looks good. Just regarding the buyback.

I mean, is there a certain leverage range targeting? Or -- because you could argue the share price at the moment is pretty cheap.

Is there a certain leverage ratio you're targeting? When can we see you sort of coming in with more buybacks over time?

How do we think about that?

Adam, I'll try and answer that again. Again, obviously, this is in the hands of the Board and so we follow their lead, but I'll talk to the leverage and gearing where we aim to keep the balance sheet, I guess, peaking at about 1.5x EBITDA.

And maybe in a lower oil price scenario, it might go to 2. But the Board will make the calls on how they allocate between dividend buyback and when they do buybacks.

So, I don't know if we can really put much words into their mouth on that.

Just wanted to follow-up on who that -- I know for Bauna, you mentioned current production is around 25,000, 26,000 barrels a day. With Who Dat, you said it was greater than 42,000 barrels of oil equivalent per day at the end of the first-half 2024.

What is it producing right now?

Gordon, at the moment, it's doing just over 40,000. We're going through a period of maintenance on the gas compression system.

So, we've got 2 big gas compressors on the FPS. We've just finished work on one of those and we'll start work on the second one of those in the next few weeks.

That generally takes out about 10,000 boes a day when we're doing that work. So, that's why I highlighted that the production that we're anticipating will be a little up and down for Who Dat as that planned maintenance work on the gas compression system goes ahead.

And we also have a planned full shutdown, which is around about a 7 or 8-day shutdown of the FPS as well a little later this year. I think the timing of that is still to be nailed down.

And I guess a question for Ray just on CapEx guidance. Other CapEx is now $20 million to $30 million lower.

You've got in the footnotes there that it includes signature bonuses paid. Is there any other reason for that?

Or can you explain why it's dropped in the guidance for investment expenditure for 2024?

No, that's pretty much the only change in the guidance. We've -- we've taken SPS-88 out of this year, moved it into next year, and the balance relates to some spend on Neon and then just some of the maintenance CapEx that we have.

[Technical Difficulty]

Are you able to step through how the Board approached the size of the dividend this half, whether this was impacted by cash flow outlook, SPS-88 timing? If you had more confidence in February, would you be looking towards a payout more at the top end of the range or another buyback?

Look, it's a good question, Henry. It's hard to predict where we'll be, obviously for the full year.

It'll depend on many, many moving parts, not all of which we have control over, including oil price, supply and demand, et cetera, et cetera. In terms of where we go to for this one, of course, it's focused around our outstanding imputation credits that we have.

Ray can probably talk a bit more.

Do you want me to fill in some blanks? I'll try.

We modeled long range. So, we're trying to make sure this policy can be sustainable.

So, we obviously modeled out to the end of the decade. And that, of course, was then correlated with or triangulated with what our peers are doing.

So the 5% yield is what we're -- what the Board was focused on. And then this -- so that roughly equated actually the size of the franking balance by pure luck.

And then the Board made the decision to reward shareholders for being patient with, and then I guess recognizing the value that we all saw in the share price, that the Board made the choice to apply some of the cash, I guess, of a similar size to the buyback. But I think it was simply a matter of modeling for the longer term.

Great. Okay.

And to expand a bit on the life extension, are you able to touch on what the motivation was to bring that forward one year? Are there any synergies we should realize for overlapping with other planned maintenance?

Does that relate to the Neon studies at all?

Look, it's not so much to do with Neon. Really, it's looking at the reliability issues that we're facing at the moment.

And I'd like to make sure that we get back to better reliability, more predictable reliability as soon as we can. And I'd sort of rather take the pain of the life extension work as soon as we can in order to improve reliability down the track rather than defer that, and potentially continue to suffer from Bauna reliability or FPSO reliability issues until that work is done.

So the study at the moment hasn't obviously landed on anything, anything specific in terms of timing, priorities and scope. That's still ongoing.

But really, it's to ensure that we can step back up into the top tier of reliability where we want to be.

Great. Julian, if I can try maybe a little bit further as well.

We already touched on a little bit, but do you have a current estimate of the current scope that might be required as sort of a percentage of current equipment that might need to be assessed?

Look, it's -- typically with FPSOs of this age, we know the things to look at, which includes tanks, tertiary, steel, obviously, the major pieces of equipment like the compressors, et cetera, and obviously, just the pipework, having a very good review of the pipework. You've got to remember there's over 100 kilometers pipework sitting on the FPSO.

So, there's an awful lot of steel to look at. In terms of how that will be prioritized, it'll really depend on, as I said, on the scope and the priorities for that.

So we don't, at this stage, have a feel for what those will be.

Just on the SPS-88 well intervention delay and the impact in terms of needing to secure an alternative rig contract. Just based on what you're seeing in your negotiations, is your prior workover cost estimate still valid or you need to rework the numbers?

We don't yet have an answer to that. Sorry, Michael.

We're in negotiations, as I said, with up to 3 different owners. One of those is probably more advanced than the others.

We haven't got to the point yet where we've finalized what the rates are likely to be. That is likely to be the highest cost element.

There are other services that we require as well, some downhole services, not just the rig. So, yes, it'll be a combination of those.

$20 million to $30 million is what we estimated before. I think at this stage, I'd be comfortable to stay with that range, but just with the caveat that we don't yet have rates finalized.

As soon as we do, obviously, we'll be in a position to inform the market.

And could you please provide some clarification surrounding the ongoing FPSO performance, reliability issues at Bauna, which were identified and if there are any risks to the previously flagged uptime range of 90% to 95%?

Yes. So, we target 90% to 95%.

That's where we'd like to be. We haven't been in that range in the first half of the year.

The reliability issues that we've suffered, I touched on a little earlier around gas compression specifically and also around some corrosion that we're seeing in the pipework, especially around the production header. That has -- we take a cautious view of that and obviously, curtail production where we believe that, that needs to be done.

So, yes, we want to get back up to that range, hopefully the higher end of that range of production reliability. But over the first 6 months of this year, we've been sitting well below that, I think, in the low-80s for much of the year so far.

So, that's not where we want to be.

And just one more, if I can. If you could please just provide an update on the production outlook in the Gulf of Mexico, just in terms of the liquids and gas production percentage splits in the second half of '24 and beyond, if possible?

So, yes. So, we guide for 2024.

We're not in a position to guide for '25 at this stage. Overall, 3 million to 3.5 million boes, net revenue interest Karoon share.

And of that, it's about -- it's a slightly better oil to gas ratio than we saw 6 months ago. It's around about low-70s percent oil.

So, perhaps that 70% to 75% oil is the range that we're in.

Can you hear me?

Yes, we can, Sarah.

I think someone left me on mute. So, just quickly on Who Dat.

So initially, we had guidance that the drilling cost would be about around $100 million to $120 million and now you have guidance at $120 million to $145 million. And I was just wondering if you could give us a bit of color on what the additional costs were for this campaign?

Yes. I will just ask Ray to have a look at that.

I think the answer is that we've now included Who Dat West well in that guidance, because nothing else has really changed since the last guidance update. We've improved that well.

Okay. And just on Who Dat West, I was wondering if the Crestal Exxon well was flow tested and if you had the opportunity to flow test Who Dat East, and if you could just tell us what the true vertical depth net pay was that you intersected for that well?

Somehow I knew you'd ask me that question, the TVD. So, we had 45 meters of net pay on measured depth.

That is -- the well was at about a 30-degree angle. So if my trigonometry is right, you'd multiply that by about 0.6 or 0.7, maybe a little more.

I can't quite recall. You can probably work that out better than me, Sarah.

So, maybe 30 meters of true vertical thickness. The overall -- I think the important thing is the overall net pay that we intersected was almost exactly the risked net pay that we anticipated.

So the well had about a 60% chance of success and 5 intervals we were targeting with a total net pay potential of about 160 feet, I think. So on a risk basis, we intersected about -- we should have intersected about 90 feet to 100 feet, which is pretty much what we got.

Maybe a little more than that we ended up with. So, yes, I think the result from a net pay perspective was on or slightly better than our expectations.

So, was there any flow testing from either Exxon or this well? Or did you intersect and condensate water contact?

So, we haven't intersected a contact. We've got an interpreted contact, I guess, from pressure measurements.

We haven't flow tested this well. And I don't believe the Exxon well was tested either.

I believe that there's good reasons for that, which is the Miocene reservoirs in this area are very well understood. And as I've said previously to the market, the main sand bodies that we intersected were high porosity and high permeability.

And with a relatively high pressure gas condensate in that reservoir, we would anticipate seeing, I think, pretty high flow rates from that based on the nearest offsets that we see around us. So in terms of well testing, that's not typically what we would do in the case of these near field Miocene type turbidites.

I just wanted to ask, now that you have the capital management framework established and a solid dividend, you're paying out those franking credits and the framework going forward is now pretty well understood. Could you just give an update on the M&A markets?

What sort of opportunities are you seeing out there? And are you thinking 2025 would be the year where you really turn your attention back to inorganic growth?

Look, I think there's a couple of things with that. First of all, we've got to make sure we get the production reliability that we want to see at Bauna.

That's really a big focus for us, is to make sure that we've got that and got that as secure as we can for the long term and hence, the life extension project. I think the same is also true at Who Dat, although there's no reliability issues there, but just ensuring that we've got a firm program of infill/infield opportunities to minimize that sawtooth effect of production.

Those are areas of key focus for us. If I look beyond that, obviously, those in Who Dat, there's the exploration, hopefully successes.

We've had at least one success and hopefully, that leads to a tieback. And then obviously in Brazil, we've got the potential Neon project that continues to move forward.

In terms of M&A, I think there are opportunities we see in the Gulf of Mexico. We see fewer of those in Brazil and we're certainly taking our time to look at and look for the best things we can in the Gulf of Mexico and the sorts of things that would make sense for Karoon in the medium term.

No short-term plans there at all. 2025, look, I think it's pretty hard to predict what would be the optimal timing of that.

We've got to be a little opportunistic. Certainly nothing in 2024.

And coming into 2025, I expect we will see a range of opportunities in the Gulf that we'll want to, to assess and to look at in more detail. But I think with the production base that we've got, we do have some time to look at things very carefully and ensure that we've got the right returns policy for our shareholders, ensure that we've got the right stability in our production profile before we step significantly into the inorganic growth market.

Thank you, Kayley. Yes, there are a couple of questions on the webcast.

The first is from Ed Shann. Will there be any possible tax benefits to shareholders from tax paid in the USA?

Thanks, Ed. I can probably deal with that.

The way we bring profits back to Australia is through dividends and repayment of interest. So, there will be taxable earnings to the Karoon Energy parent in the future.

But we don't expect material franking balances and taxes to be paid for a while. But obviously, as those debts are repaid and as the businesses over there grow, we would expect to see taxable profits start to incur tax liabilities in Australia and therefore, potentially offer franking again in the future.

But I don't think it's any time soon.

Thanks, Ray. I think the second question, which is from Hazmy Hazin is also one for you.

Why the change from EBITDA to EBITDAX? And what is the exploration expense for this year?

Okay. Thank you.

The reason for the change is simply that we have quite a lot of exploration drilling happening now. We have the 3 wells in Who Dat, and we don't have any major exploration costs that are being excluded.

But we're making that change simply so that if in the future one of the wells is not successful and is expensed, that we won't be making a prior period change to our investor presentations. We have in the guidance the exploration costs that are shown in, I guess, in investment expenditure that are in Who Dat.

And that's the -- if I exclude the -- if I exclude the development wells, then it's in the $100 million, $125 million -- $100 million to $120 million of costs for exploration in this year.

Thanks, Ray. There's a second question from Hazmy Hazin, which I think we've already responded to.

But how will Bauna extension -- Life Extension earlier from 2026 to 2025 impact the current production?

Yes. We don't have a firm picture of that yet.

That work is ongoing to define the scope and what those costs will be. So as soon as we have that, we'll obviously incorporate that into our previews for the market.

Thanks, Julian. The next question is from Alex Fitzgerald.

Please, can you explain the decision to pay out a dividend relative to buying back your stock at $1.75, which is circa 2.3x EBIT EV to EBITDA? Moreover, you've spent a meaningful amount of CapEx on exploration.

Do you consider this a better use of funds than buying back stock at current prices or a larger dividend payout?

In terms of the dividends, paying a dividend to shareholders rather than the buyback is driven by, obviously, the franking credit and returning that to shareholders is important. Otherwise, that will over time disappear.

So, that was a clear driver there. In terms of the value of exploration, the finding cost per barrel and the value of those barrels significantly outweighs -- is significantly larger than the benefit of buying back our own stock, the value that, that can add in the long term for Karoon.

In the case of these types of exploration prospects where they have relatively low risk, so all of the exploration prospects that we are drilling, Who Dat East, South and West have chances of success between about 40% and 65%. And that certainly leads us to want to do those and to spend money on those.

So yes, I think the value of those -- hopefully, with success, of course, we'll see. These are -- it's -- oil and gas still has risk associated with it, of course.

Thanks, Julian. And the final question on the web is from Louis Bannon.

Can you please share your range of expectations for cash flow returns on capital spent on CapEx? And how is this expected to return compared to the current yield available from paying cash as dividends to shareholders.

So, I think I'll try and pick that one up. As Julian mentioned, we expect the returns on exploration to be higher than, I guess, developed CapEx investments.

So operating fields, as we've said before, we generally invest in those in the mid-teens after-tax return whereas exploration should produce materially higher returns than that. And so that's why we're putting CapEx into those areas.

That should produce more returns for our shareholders than the buyback. The buyback though, as I said earlier, was driven by, I guess, largely by Board decisions and the Board analysis on what we see as -- what the Board sees as value in the company and an opportunity right now.

And then reverse, I guess, modeling what long-term cash might be required in the business and what was reasonable, the funds available. So, obviously, an opportunity and perhaps limited by the cash available in modeling that was done with the Board.

Thanks, Ray. That's all from the web.

I might hand back to Julian just for a few wrap-up comments.

Yes. Look, thanks, everyone, for your attention this morning and your interest in Karoon, thanks to our shareholders, of course, for your continued support of the company and a big thank you to our staff and our contractor partners for the contributions and hard work during the first half of this year.

We've got a lot ahead of us to do, and I look forward to updating the market when we get to the full-year results. Thank you.