Central Petroleum Limited (CTP) Earnings Call Transcript & Summary

Good morning, and welcome to our presentation covering Central's financial results for the first half of fiscal year 2025. I'm Leon Devaney, CEO and Managing Director of Central Petroleum. I'm joined today by Damian Galvin, our CFO. You can lodge questions online throughout the presentation, which we will attempt to answer at the end. Please take the time to read the legal disclaimer, which applies to this presentation. We had a good first half to fiscal year 2025 and have been building momentum over the past few months with a successful drilling program at Mereenie and the benefits of a new higher price contract starting to become visible. We also continued to cut costs and maintained a strong cash and net debt position. I believe this momentum is just getting started. Our long-term gas supply agreement with the NT government only started on the 1st of January, and the increased production from our 2 new wells at Mereenie have only recently come online with the second one commencing just late February. We will cover these topics along with other updates in our presentation today. But now I'd like to start by handing it over to Damian to cover our first half results.

Thanks, Leon. First, I want to touch on the balance sheet, which remains very healthy in comparison to previous years. We had a net cash position of $1.6 million at 31 December. That might not sound much, but as you can see on the chart on the left, we've made some very significant progress on reducing our debt since its peak back in 2017. You'll recall that we restructured the loan facility late last year. It was due to mature in September this year, and we've extended it now until the end of 2029. So it removes any refinance risk for the next 5 years. Now importantly, we've built in some significant flexibility around debt service for the next 2 years. There's no principal repayments required until March 2027, and we can elect to capitalize the quarterly interest payments, effectively giving us access to an additional $4.6 million of funding over the next 2 years if we needed to invest, for example, increases to production capacity. We can also make additional repayments of principal to pay down the debt earlier as a capital management alternative. The chart on the right illustrates the expected debt service profile in coming years after the loan restructure, and includes the return of over lifted gas over the next 18 months. This is significantly less of a burden than in previous years, and it's about 65% or $19 million per annum lower than in 2020, that's a pretty significant boost to our cash flow, particularly when combined with the higher expected revenues. So we've now got a number of capital management options to consider going forward, including investment in new wells, exploration and shareholder returns. Let's have a closer look at the results for the half year. It was a pretty solid underlying operational performance and a good recovery from the first half of calendar year '24, which was impacted, if you recall, by the closure of the Northern Gas Pipeline. So this is reflected, firstly, in the sales volumes, which were 10% higher than the preceding June half but 5% lower than the corresponding first half of FY 2024. And that was largely due to the natural field decline since last year. We did lose some sales volumes early in the period, those at the back end of winter, which is a seasonally low period for electricity and therefore, gas demand in the Northern Territory. So we were exposed to as available contracts through the 6-month period. But we will have more gas on firm contracts next winter next year, and therefore, we should be less susceptible to seasonal fluctuations going forward. Revenue at $18.9 million was down 5% on the December 2023 half, reflecting that underlying volume, with the average portfolio price consistent with the June half year at $7.96 per gigajoule equivalent. Now realized prices have subsequently jumped dramatically in January, and I'll come back to that shortly. So importantly, we're able to increase our gross margin, excluding depreciation, back to almost $4 per gigajoule equivalent. That's up 22%, again, from the preceding 6 months to June. Again, the margin per unit is expected to increase quite significantly from January as those new higher-priced contracts replace the lower-priced legacy contracts and production from the new Mereenie wells has added. Underlying EBITDAX for the 6 months is $8.6 million. It's defining the lower revenue. It's actually 7% higher than the December '23 half year, and that reflects lower corporate and administration costs and improved recoveries from our joint ventures. And that flow -- that EBITDAX flowed through to statutory profit, which was $1.5 million. More than a small $64,000 profit we booked in the first half of 2024. Lower exploration activity contributed to that result. It was offset by the higher finance costs, which included the cost of refinancing the loan facility. So look, I think overall, a respectable outcome, but the more exciting story is the improvements in the second half that are just starting to become visible. And that improvement has really been driven by gas prices in the Northern Territory, which have shifted upwards as a result of that recent market dislocation that we've seen up there. And that's reflected in our new firm gas contracts, which came into effect from 1 January this year. So as a result, we've already seen our average portfolio price in January jumped by over 21% to over $9.70 per gigajoule equivalent. And the chart on the top right illustrates that movement just for the month of January. So it's a large portion of our operating costs are fixed, we're going to expect to see most of this price increase flow through to our operating margins, and that's what the chart on the bottom left is illustrating. It's showing that, obviously, the gross margin. If you ignore depreciation, it could potentially increase by circa 30% to around $5 per gigajoule equivalent in the second half of FY 2025. And that depends on the availability of the NGP, which we know will be closed for at least the first 3 months of this half. Our free cash flows from January are expected to receive a pretty significant boost, therefore, not just from the increased margin, but also from the more reliable volumes secured by those firm offtake agreements by the increased volume from the 2 Mereenie -- new Mereenie wells and the reduced debt and liability costs. Now I've used this chart a few times before, but it demonstrates, I think, pretty well the growing impact of our new gas contracts. These are firm contracted volumes. So for 2025, for example, we've got over 4 petajoules of gas contracted on a firm basis. And that excludes any as-available sales that we expect to make over the year, which would be over and above these firm volumes. So this compares to total sales of 4.4 petajoules in FY 2024. So that is -- we've got over 93% of last financial years, total sales volumes are now sold under firm contracts in 2025. And so that gives us excellent protection against risks like pipeline closures that we saw last year, which negatively impacted our revenues. The other impact is price. And so let me take a few moments to try and unpack that impact. As I highlighted on the previous slide, our average portfolio price in January was over $9.70 a gigajoule equivalent compared to the $7.96 average in the December half year. And so that headline price includes oil, and that tends to be higher than gas on a gigajoule equivalent basis. So for example, in January, it was about the equivalent of $20 per gigajoule equivalent. So it sort of boosts that average portfolio price a little bit. So our average portfolio gas price in January is a bit lower than that $9.70 blended portfolio average. We expect our average portfolio price to continue to rise as those new contracts replace legacy contracts. Now the legacy contracts, so that's those at the lower historical prices, they represent sort of anywhere between 34% to 65% of our firm contracted portfolio in 2025 depending on the availability of the NGP. And so that's the blue volumes on the chart and the hatched is sort of that swing between the 34% and the 65%. So in January, the NGP was closed. We're at the lower end of that range, closer to the 34% of legacy contracts as part of the portfolio mix. And you can see the proportion of these lower-priced contracts decreases further next year, and that's in 2026, to about 21% of our firm contracted portfolio. And so that reweighting should, again, boost our average portfolio price further. And that ongoing blue block, if you like, through to 2030, that's our CPI-linked Dingo contract to supply the Alice Springs Power Station -- Alice Springs. Now we also get a boost from increased production volumes from the new Mereenie wells. So they really only start beginning to contribute in full from the end of February. And so that new production increases our production capacity by about 30%, and it's sold obviously into the newer GSAs, the newer higher-priced ones, and therefore, increases the proportion of our new contracts relative to the legacy contracts by a similar amount. So we should start to see the partial impact of our new contracts and the increased Mereenie volumes on our average portfolio price and operating margins in the March quarter results when they come out in April. So this new market paradigm, if you like, it's given us -- obviously gave us a lot of confidence to invest, for example, in 2 new wells in Mereenie. These were successfully drilled and brought online in January and February this year. So they're now supplying that much needed gas into the Northern Territory market. So the improved cash flow and the market conditions that we're seeing also provide an opportunity to further boost supply. So we're looking at further optimization at Mereenie and possibly new wells at Palm Valley. So look, from a financial perspective, it's clearly a much improved position with the expected improved cash flow from new contracts and the restructured debt service. For the first time, we've got some capital allocation options, be that new production wells, field optimization, accelerated debt reduction or return to shareholders. So with that, it's over to Leon for his thoughts on the market and forward plans.

Thanks, Damian. Our first half results reflect the success we had last year in remarketing our East Coast gas contracts into the NT, whilst the NGP remained closed. The NGP remains closed at this time. And as this chart illustrates, the NT gas market continues to weather low production from Blacktip through a reliance on offshore LNG fields. Notwithstanding more than half of the NT gas demand is currently being sourced from Central's operated gas fields in the Amadeus Basin. The NT gas market dynamics continue to remain in flux with a new well at Blacktip being drilled that may deliver some production over the coming weeks. The offshore LNG fields continue to fill the market gap left by the decline at Blacktip. However, these sources do not appear to be long-term supply options for the NT, and we would expect gas from these fields to be significantly more expensive than the historical NT gas prices. We expect to see some indicative results from the Beetaloo Basin over the next couple of months. Although we know drilling appears to have been problematic so far and the fracking programs somewhat reduced and delayed so we'll have to wait and see. Fortunately, for the NT gas market, our recent 2-well drilling program at Mereenie was a success. We came in ahead of schedule, under budget by around 10% and with production rates about 50% above target. We are currently selling around 9 TJs per day in production from these wells on an as-available basis. However, we have the option to increase our Northern Territory government GSA by up to 6 TJs for sale on a firm basis to accommodate it. Production from these new wells is now supplying around 10% to 15% of the NT's gas demand, reducing the reliance on LNG production, which is obviously good for all parties involved. With the Mereenie drilling program now behind us, we are well placed to look at opportunities to generate more value from our producing assets. Specifically, we are considering new wells at Palm Valley with 2 well locations already identified and permitting and approvals well advanced. The Palm Valley wells are anticipated to have higher production rates and elevated economics relative to the development wells at Mereenie, plus Central has a 50% interest in Palm Valley, so 2 new wells at Palm Valley could have a material and positive impact on our future revenues and cash flows. The recent success we had drilling at Mereenie also gives us confidence that the field has more to give than we initially thought through optimization and new appraisal. In addition to further development wells, we can look at using things like 3D seismic to help us better target drilling in areas of enhanced productivity. We're also looking in the merits of an appraisal program for the Stairway Sandstone formation, which could unlock significant new 2P reserves at Mereenie and increase the fields' target plateau rates and extend Mereenie's field life. We also could use fracking to enhance flow rates and recovery at Mereenie. Whilst we don't have any plans at the moment to frac any wells, fracking is now common in the NT. And it's certainly something we could use to optimize recovery from Mereenie to create further value from that asset. Other possible paths to increase near-term production from the Amadeus Basin could include things like expanding the Dingo gas field and connecting it into the Alice Springs pipeline. I want to highlight that all of these potential investment opportunities are subject to NT gas market conditions, gas contracting, capital allocation decisions and a final investment decision by the relevant joint ventures. The NT gas market is in flux with most of the NT's gas supplies highly uncertain at this time. We are watching the space closely and are well positioned to respond quickly to any change in market conditions. We have a good cash war chest, strong contracted revenue streams, reducing liability costs, and further debt capacity available if needed. Moving to exploration. We continue our efforts to resume exploration and appraisal drilling within the Southern Amadeus sub-salt permits with a focus on drilling the Mount Kitty and Dukas prospects. Interestingly, the tightening NT gas market has elevated interest in lower-risk conventional oil and gas exploration in EP115, which is in the northwest portion of our permits and contains our prospect at Zevon. EP115 remains very underexplored with [ sparse ] usable seismic. The permit is on trend with the Palm Valley and Mereenie fields and provides a real opportunity to find potentially the next major oil and gas field in the NT. Where the NT gas market remains structurally short, we expect strong gas prices to provide a compelling incentive to explore for new gas in proximity to our existing producing facilities. Consistent with our strategic review, however, we want to progress both sub-salt and conventional exploration through third-party farm-out arrangements that minimize cost for Central. To summarize our business strategy, we are focused on positioning our operating assets to respond to an evolving NT gas market, maximizing our cash flow, funding exploration through third-party farm-outs and progressing a capital strategy to support near-term shareholder returns. The evolution of the NT's gas market over the remainder of this year will impact the quantum and timing for various investments within our producing assets. This will then allow us to develop an appropriate capital strategy, including opportunities for shareholder returns in the upcoming months. Finally, we have accomplished a number of key milestones over the past year, specifically locking in strong gas prices under a long-term GSA, refinancing our debt to be fully repaid by 2030, and successfully completing the Mereenie drilling program. Looking at our remaining key activities for fiscal year 2025, our focus is on progressing new Palm Valley wells to a FID decision within the joint venture, progressing opportunities for further drilling and optimization at Mereenie, restarting sub-salt and conventional exploration through third-party farm-outs and managing our capital and cash flows to ensure we can respond to market opportunities and accelerate potential shareholder returns. Following a good start to fiscal year 2025, we have been building strong momentum through this third quarter with increased production and some early visibility of our improving financial metrics. As I have said before, I believe this is just the start to what could be a transformational year for the company. At this point, I would like to spend some time answering any questions. [Technical Difficulty]. Sorry about that. Apologies. Some technical issues we've been trying to resolve. Hopefully, everyone can hear us now. I'm not sure how much of that was able to be heard previously. So we might quickly go back.

We're going to just start. Yes. Let's go back to the first question.

I appreciate those hardcore individuals that have stuck around through this. I appreciate that, but we'll get this on the website so everyone can hear it at a later point as well.

Yes. So first question, Leon, was about Blacktip. So is there any industry chart or information around the timing of Blacktip and when results might be known?

Yes. So we've got the same information others have in the market. We obviously keep an eye on it and are very interested to see where that's at and how that's progressing. Our understanding and there's nothing we have that's not available in the public. Our understanding is that drilling program should be wrapping up soon, if not already. And production should be coming online, we would assume, over the next month or so. And we'll be watching the gas bulletin board, like many others, to see what those production rates are both initially, but a real test is how those production rates hold up over 30, 90 days. So it's really a wait-and-see sort of thing.

Okay. Question around gas overlift arrangements. Does that continue until the end of FY '26? I understand it means from FY '27, we get an uplift.

That's right. So we had a presale that has been paid off as of the beginning of this year. The GBA overlift is one of our other gas and kind liabilities that we are paying off. That expires in the next...

We expect to have -- will delivered by May next year.

May next year.

Yes.

So once that rolls off, again, that's another uplift to our financials and cash flow, which will be a positive development.

Yes. Sub-salt exploration. So previous updates seem to imply advanced negotiations around that and the farm-outs. Have we gone backwards on this? Or have we got -- are they being delayed? What's -- where are we at?

Yes, it's been -- it's been something we've put a lot of work into, ourselves and Santos, who are also looking at the market. We are interested in getting sub-salt kick back off. Again, we're focused on farming it out and reducing our cost exposure to it. It has been challenging. We've had a number of conversations, some of them got fairly advanced. I think there are a few pounds forward, but the future and how we're going to deal with relaunching sub-salt exploration, I think, will start to be crystallized. And by that, I mean how we're going to approach it and how we're going to move forward over the next few months. So it is something we're actively working. Unfortunately, we haven't been able to close a transaction as has Santos. It's been a difficult run, but something we're working towards, and I'm still optimistic we'll get something in place to move those exploration prospects forward over the course of this year would be my expectation.

Okay. A question around the Beetaloo basin, Leon. Can you provide some insight into the possibility of scheduled cost overruns in the Beetaloo? Do you think the experience of the U.S. shale sector is directly transferable to the Northern Territory?

Yes, I wouldn't be comfortable putting views forward on it simply. I just don't feel I'm fully informed on those topics. I would say, though, that generally transplanting experiences in the U.S. to the NT has some challenges. It's a very different market, different cost structure, a different regulatory environment. And obviously, the rocks are different in the NT and the Beetaloo Basin than they are in many of the places that they point to for those kind of projects in the U.S. So obviously, they appear to have had some challenges on the drilling. So that obviously makes it more expensive when we get into the development program, if there are issues or it's not easy drilling. And they've obviously reduced and delayed some of the fracking program. So I think what you can glean from it is it's not as simple of a project as you might think it would be if you look at the U.S. example in a mature state with a very well-developed support system around those activities.

Okay. Other question around gas profile in Arafura. So if Arafura is delayed, can that gas be shifted to the Northern Territory government gas contracts?

The answer is potentially good. We don't have an as of right to flip it to the NT government. If Arafura project does not proceed, we will have that block of gas available for the market. One of the obvious parties to go to would be the NT government and fold it into the other GSAs we do have with them, but we'll probably go out to market for that volume and test it and find the appropriate buyer for it. But at this point, I think NT government could be in a position where they need that kind of volume at that point in time. And that would obviously let you have a good opportunity to sell that to the NT government on a similar basis that we've done previously.

Okay. A question here. The last analyst coverage was in November last year. With the new pricing and recent drill success, when are you looking to have another one undertaken? So I think I know MST have updated one of this. I think there should be one on the website there from February, which is the most recent one. And I think generally we try and get those done every quarter. That's with the commissioned ones. Obviously, other brokers may put their own timing. Okay. So a question around share price. So with the significant disparity between the share market price and the derisked valuation or intrinsic valuation of the company, the obvious question is why and what can be done to get our company's story in front of the investor cohort? This person thinks we're extremely undervalued yet the share price remains flat.

Yes. Well, certainly, I think in the past few years, we've done some of the really hard yards. We've paid down our debt and our other liabilities. We prioritized that and brought that liability cost down significantly. We've obviously weathered challenges in the gas market. We've weathered the NGP closure which really impacted us over the past year or 2. I think we've come through all of that and are in a really good position. If we look going forward with our new contracts, it's really into the future that we're going to start to see the impact of a tight NT gas market on Central and on our operating assets. And as Damian talked to in the presentation, that's starting to become visible. I think that's going to be something that becomes more and more visible over the next 12 to 24 months. And my expectation is as that becomes reported and people can get their head around what that exactly means, there'll be a bit more confidence in the valuation and my expectation is that an evaluation gap will start to close through this year and maybe into next year as we roll into a higher percentage of those new contracts. Again, I think the NT gas market is still in a state of flux. That could have an impact. It certainly will drive our intent to accelerate and invest in new production growth activities. If everything goes really well on that front, we could have another leg up on production and obviously the flow-through on our financials. The other thing I think that's important is, as we've talked about, we are looking at a capital management strategy, and that does include the opportunity to return funds back or value back to shareholders, and there's a few ways to do that. We are considering that, we've got that, I guess, opportunity this year, and it's something we haven't had in the past to start considering that alongside other uses of capital such as investment in the field to take advantage of the market or even paying down debt on an accelerated basis. So we're weighing all that up. I think the key catalyst is going to be how the market shapes up over the next 2 to 6 months. Once we understand that, that's really going to drive our capital strategy, and flowing from that, how we might return funds or value to shareholders.

Okay. Thanks, Leon. I mean, just on the -- whilst on share price, there was a question here, someone had observed that micro parcels of shares closing out or causing a negative price impact. It appears to be having frequently has been noticed by the company. I think the answer to that is most listed companies would say they're frustrated by those types of trading patterns that they see come through ASX. It's been brought up with ASX many times and years gone by. They put it down to algorithmic trading and other all sorts of excuses. But unfortunately, there's nothing much we can do about it. It seems to be a feature of the ASX. So we'll leave it with them.

I think our job is to communicate with the market and over deliver on what we promise and drive the fundamental value. And with that, I think the market will then start to reset the valuations they have for Central. And I think these sort of trades are kind of noise in the background, if you get the fundamentals right and you've got a very compelling story and you deliver on what you say, the market will appreciate that and start taking that into account. I think that's the phase we're in now. And my goal is to certainly both communicate what we're doing and the advantages Central have at this point in time and some of the tailwinds we've got and then deliver on those. And I think if we do all of that, we'll put Central in a very good position in some of these small trades at the end that flip pricing around. I think that will be noise in the background.

Okay. All right. From a capital allocation perspective, could you elaborate on whether future Mereenie infill wells will be prioritized over Palm Valley? Or could you do both in tandem?

Yes. I think they are part of the mix. Obviously, we've just completed 2. We've achieved more than the plateau target rate, which is a great outcome. It does give us a lot of confidence that there's further production to be gained and production increases in drilling at Mereenie. We're going to take a look at the results in the production and do some [ sub-salt ] modeling with these new wells. We'll also look at other things that we can bring to the table to try and help optimize any further development in that field. It is certainly something that's an opportunity that the joint venture is looking at. But like I said before, we do have a number of options that aren't necessarily mutually exclusive, but we do have to weigh up in terms of capital allocation. I think Palm Valley wells look pretty compelling. As I mentioned before, the production rates and recovery are very strong there. We've got a 50% interest. And again, [ brownfield ] economics, we can tie those in pretty quickly getting on production and those tend to be pretty compelling economics. So it's really going to come down to how we want to -- what are the market signals, what are the opportunities we have, how do we high grade them, what sort of capital constraints do we have, and what is the capital management strategy including returns to shareholders that we want to employ. So key to that is the market. Like I said, over the next few months, we'll start gaining clarity on that. And I think these things will come together in a smart package that the Board is certainly going to consider and put forward at that time.

Okay. Thanks, Leon. So a question about Dingo, I think we answered it before when the audio wasn't so good, but can you elaborate on the expansion plans at Dingo? What does that entail or cost?

Yes. So the opportunity there is drilling other well. We've got a good reserve base at that field. We could increase production from Dingo by drilling another well, doing a bit of work on the pipeline up to Brewer Estate, expanding that facility, and there's a number of permutations. Some of it is driven by the market and we are working with the NT government and PwC about what that market looks like and what sort of demand profile it's going to need over the next 10 years or so. And depending on market conditions will shape an optimal expansion program for Dingo, see if that stacks up against the other investment alternatives we have, particularly in light of the NT market conditions, and we'll go from there. And that could be anything from a fairly minor increase through some optimization all the way through to doubling the production out of that field. Again, if the market is strong, the signals are there, I think there's some incentive for us to explore that opportunity and see if we can do it efficiently and bring some additional gas to the NT market.

Okay. Thanks, Leon. So a question here, the previous MST access analyst report suggested a valuation at that time of $0.19 per share. And obviously, our share price is at $0.068 is far from this, and the share price has historically been low for many years. Can you provide a bit more clarity around whether you're leaning to buybacks or dividends to better align the share price to value in a bit more detail around expected timing?

Yes. So you might want to comment on some of the broker reports and what the thoughts are and what you're seeing there. And I can tackle the other 2.

Yes. Look, I mean, I think the broker report obviously takes an aggressive view on production profiles and pricing going forward, which I think is all perfectly okay to do. So it's really -- and when we agree, certainly, there's a big gap between what we think the share price is and what the underlying value is you can just see that from the -- for example, that underlying transaction last year where Macquarie sold to Horizon and Echelon sort of valued the Mereenie field around $100 million, I think, was that transaction for 50%. So even on that metric, you're sort of looking at just the Mereenie field alone being worth more than our market cap. So there's obviously a number of pointers and metrics that point towards us being undervalued. And I think as our results start to flow through -- the March quarterly coming up, we'll start -- hopefully start to see people starting to book that into their own valuations and the share price, hopefully, will start to reflect that. In terms of dividends and buybacks, I guess, Leon, perhaps you've got any thoughts on that?

Yes. Look, we're looking at all forms of shareholder returns. Those are 2 obvious ones. As part of that, we are looking at what we think the inherent value of the company. Obviously, a share buyback when you believe it is undervalued, can make some sense as an investment by the company into the shares for shareholders. So we are looking at that. We are also looking at obviously an appropriate time to start a dividend program or return to shareholders in some form. We do want to make sure that if we do that, it is sustainable. We're not looking to do one-off sort of distributions. We're looking at something that the company can continue and grow on a sustainable basis. So that's important. Critical to all of this, and this is part of the decision process that we're going through, is understanding what the NT gas market is going to be in the near and medium term. Like I said during the presentation, that's in a bit of state of flux. We know it's short now. We certainly have taken advantage of that by locking away our firm contract in terms of new investments to take advantage of any other price signals that we see going forward. We'll have to look at our capital availability and where we want to apply it. And so we're going to weigh all those up. And like I said, I think that clarity will start to appear over the next few months as we see the market move our financials rolling through in the next quarterly and we'll be able to make some decisions and share that with the market at that time.

Okay. Thanks, Leon. There's a question here around our debt facility. Can you elaborate on how we, Central, can elect to exercise the various options under the debt facility regarding capitalized interest? Is that locked in stone? Or can you repay it earlier? So I think I can probably just touch on that. I mean, the facility we've put in place now is 5 years to run, so -- and we should be for fully repaid at the end of that. So that's quite a good achievement given that debt markets are still very difficult for junior oil and gas producers even despite our good cash flows. So it's great that there is a bank out there that still supports the sector. But this particular facility at the moment, so what we've done is we've basically brought a heap of flexibility in the first -- the next 2 years. We can repay interest if we like or we can capitalize it each quarter. So that's a quarterly decision that we'll make. The actual principal repayments, the default at the moment is there are no principal repayments for the first 2 years. But again, we can elect any time to make earlier repayments so we can pay back anything we want any time we like, not just in the first 2 years, but over the full 5 years. So we've got a lot of flexibility. And that was really designed, if you recall that slide, to try and dovetail a little bit with the remaining gas balancing or the gas overlift agreement that we had where we still got some gas to repay between now and May next year. And so the idea was to try and push the debt repayments out past that so that we could level up that sort of debt service on more sort of level sort of a sustainable level for the next -- for the rest of the term. So we've got a lot of flexibility there. It just depends really on what we want to do in terms of drilling, et cetera, in the next couple of years. And it may be that the decision is to pay the debt down more aggressively. That may be a better return than some other options. But obviously, we're looking to see at the moment, just what the market's going to look like in the NT, we've locked away what we can at very good prices. And then if we want to add more capacity, we just need to be sure that there's a decent market for that going forward. And hopefully, that will become a bit clearer in the next few weeks or months as the Blacktip field comes back on.

Yes. I think it's great flexibility. It's probably the most important thing is we've produced or eliminated our refi risk, which we've had for a number of years, having to go back and refi these facilities in a market where, quite frankly, the Australian institutions have completely abandoned the sector, which I find just staggering that the big 4 and others just will not participate in the debt funding for companies like ours. We have found a good partner in Macquarie. And obviously, this restructure has taken away the risk on being able to refi down the road. This is a fully amortizing extension. So -- but how we treat this facility, it's got great flexibility, both in terms of deferring some payments, additional headroom for further debt or prepaying early and getting rid of it quicker. So we're going to weigh all that up, again, market dynamics and competing demands for capital, what those investment opportunities look like, how -- I guess, how much incentive or how much economic benefit we get from those on a risk return basis are going to be keys to how we treat debt as well as our other capital going forward.

Okay. This question here just to answer a bit more detail around our cost of sales number that we have in the accounts. And what does that balance consist of? Is it royalties and field OpEx? So yes, it is all of those things. I don't have the breakup for the half year right in front of me at the moment. But if you were to grab our annual accounts from last year, there is a note to the accounts, which does give some breakup of some of the larger components of that cost of sales number. So I hope that helps. Another question. How should we think about the annual gas flow depletion rates for the fields?

Well, I think you can certainly look at the Gas Bulletin Board, that's a fairly transparent view on sort of a longer-term trend around field decline, and that should give you some indication. Obviously, there's a lot of things that happen on the field week-to-week that do impact production rates and those move around, but longer-term trends should be available in looking at the gas bulletin board. There is a natural decline. Obviously, at Mereenie, you've seen that. And that's why we do look at drilling additional wells to maintain a plateau. Similarly, you'd see that at Palm Valley, we drilled our last 2 wells. They are very successful. Production has been declining there and hence, are revisiting or having to look at 2 additional wells to bring that capacity back up. So I think those are numbers the market can get a sense of. It's not a number we have pegged down and put out. It does depend on the performance of the wells, and it's a bit of uncertainty around longer term what that decline rate is and it's something that's difficult to predict or forecast. But it's -- conceptually, it's an important part of what we do in terms of managing the forward forecast for production and trying to preserve a plateau and a certain volume for sales over time.

Okay. All right. Well, I think, Leon, at this stage, we've pretty much reached the limit of all the questions. So thank you for everyone for logging in today. And I do apologize for the audio issues we had there. I hope we've managed to patch that up satisfactorily, but we will get a clean version up on the website in due course for anyone who wants to try and pick up anywhere and anything they missed out on.

Great. And again, thanks for everyone attending and sticking with us through the technical problems. Appreciate your support for the company. And like I said in the presentation, I think this is just the beginning. We've got some great momentum. The fundamentals for this company was fantastic. And I think there's some really exciting growth opportunities to even build on top of that. So I do think it's going to be potentially a very transformative year for the company as this information comes out and the market starts to crystallize and some of these decisions around capital strategy become decided and communicated to the market. So stay tuned. It's going to be a very interesting year, and I think a very positive year for Central. So we're excited. A lot of good momentum here in the office. I think everyone is quite pleased with both the drilling result but also the state of the -- or the fact that the Amadeus Basin can be a major contributor to the NT gas supply at a point in time where it is very short on supply from its traditional suppliers. So thank you again.

Thank you.