Central Petroleum Limited (CTP) Earnings Call Transcript & Summary

Good morning. I'm Leon Devaney, CEO and Managing Director of Central Petroleum. I'm joined today by Damian Galvin, our CFO. This is our first webinar of the year, so we have plenty to cover. Let's start with some housekeeping. You should see on your screen an opportunity to lodge questions online throughout the webinar today. We will answer them at the end of the presentation. Today's presentation covers our first half results, our business strategy and the gas market dynamics that will impact the business going forward. As you'd be aware, we recently announced that the Northern Gas Pipeline, or NGP will be unavailable through June. This is a major pipeline that transports our gas in the NT to the East Coast customers, so it is having an impact on the business today. But the NGP outage is a symptom of a more significant change happening right now with the NT's gas market, which could elevate the importance of our gas production from the Amadeus Basin, so I do want to cover that in some detail later in this presentation. Let's start, though, by handing it over to Damian to discuss our first half results.

Thanks, Leon. Look, it's been another pretty solid performance for the first half of FY '24. Our sales volumes were up 9% on the equivalent first half of FY '23 and that was largely due to the impact of new Palm Valley 12 well, which we commissioned at the end of 2022. Now the chart shows that our sales volumes have, however, been lower since they peaked in the March quarter. And in particular, the last 2 quarters have been impacted by the intermittent closures of the Northern Gas Pipeline, so we were able to supplement some of the interrupted supply by redirecting gas to customers in the Northern Territory. Now Leon will provide some further insight into those pipeline dynamics shortly. From a revenue perspective, we've recorded $9.9 million of sales revenues for the 6 months, it's about 20% higher than the first half in the previous year and boosted by $2.3 million from the release of previously banked take-or-pay proceeds. Now realize gas prices across the portfolio have softened slightly to $7.23 per gigajoule equivalent for the 6 months or just over $7 for the December quarter. And that softening was partly due to customer mix and varying delivery points and all resulting from the NGP closures that we saw during the period. Importantly, though, our sales margin was up 35% at $2.64 per gigajoule equivalent for the half year.  In terms of the bottom line on an underlying basis, we basically broke even after you take into account depreciation, corporate admin, finance costs and $2.5 million of exploration costs. We've reported a half year profit of $13.9 million, which includes $13.8 million profit that we made on the sale of the Range Gas project and we're very happy with the result from that transaction, having contributed very little capital to the project. That sale has obviously boosted our cash balances because we've got to this great flexibility now for future growth and it means we won't need to source and allocate significant capital for further appraisal and development activity on that particular project. Now you may have seen that our largest partner at Mereenie has agreed to sell its 50% interest in New Zealand Oil and Gas and Horizon Oil for up to $103 million. Now it's worth noting that the valuation multiples implied by that transaction are some 60% higher than the value of the stock market is currently placing on Central's equivalent 2P reserves. So look, I'll leave you with that thought, and I'll hand you back to Leon to talk about the forward strategy.

Thanks, Damian. We completed our strategic review last month. One outcome was the sale of our Range project, which resulted in a $13 million profit, which is a great outcome. There are no other significant transactions coming from the strategic review process. However, as Damian highlighted, the subsequent sale at the Mereenie Gas field provides a very good direct valuation benchmark. The other outcome of the review was refining our business strategy. In a sentence, we will be prioritizing cash flow and cash retention in order to accelerate the timing of future dividends whilst preserving upside from high-impact growth activities. There are 3 areas we can focus on to achieve this: cost reduction, debt repayment and gas marketing. I'll hand it over to Damian to talk about cost reduction and debt repayment now.

Thanks, Leon. Look, we're seeing cost increases across the board over the past few years, just like everyone else, and we also have here with a range of new regulatory costs on top of that. So look, we've already started a comprehensive cost review and we do pride ourselves on being a low-cost operator and we've always had a pretty keen focus on controlling costs, both operating and corporate. So for example, over the past 18 months, we've reduced executive and senior management headcount by 20% just through attrition and rationalization of roles. And that's reflected in the December half year figures, where you would have seen corporate and administration costs were 24% lower than in the previous corresponding half year. So the business and trading conditions change and we obviously need to ensure we fit for purpose we're still prioritizing safety environment. It's critical business outcomes. And cost control is a continuous process, so while there may not be an obvious sudden drop in costs, we're going to continue to streamline our operations and corporate functions in search of efficiency gains going forward. In terms of debt reduction, that's another area where we're already starting to see some relatively significant positive cash flow impacts. We've already done most of the heavy lifting with respect to paying down debt and our gas in-kind liabilities. As the top chart here shows our net debt is $4.4 million at 31 December, and the bank debt is down almost 70% from its peak at around $25.8 million at December. So even after adjusting for the sale of 50% of our producing assets, it's 30% lower and that its peak. And so while the bank debt is low, it's really the less obvious gas in-kind liabilities, which is set to give us a pretty significant cash flow boost and that's starting this year. These liabilities relate to gas which we've presold or overlifted in previous years to fund the field development and we've been supplying or returning this gas with no incoming cash flow as we repay those debts, if you like.  Now the lower chart shows the cash impact of servicing the bank debt and the presale gas and the overlift of gas each year. Now we've fully repaid our presale arrangement and that frees up about 2.4 terajoules of gas per day for sale from January this year. And so that alone equates to more than $6 million of additional cash flow in 2024 when compared to 2023 or about $0.08 per share. And we've already also paid off over 70% of the overlifted gas and we're on track to have that fully repaid by May 2026, and that will free up a further 2 terajoules a day or about $5 million per year or equating to around $0.06 per share. So based on our current rates, the annualized cost associated with these liabilities is down about 60% since it peaked in 2019 and by the time the overlift is fully repaid mid-2026. Spending on debt service and gas in kind liabilities will have reduced by $22 million per year or $9 million if you adjust for the partial asset sale. As you can see, we have turned the corner, and we're quickly approaching a point where a significant portion of our operating cash flow can now stop going to third-party finances and instead we can start looking at returning some of that to shareholders. When you take that debt dynamic, along with cost reduction and successful gas marketing, we see that's going to maximize free cash flow and can accelerate the point in which Central is in a position to pay dividends in the future. Now, Leon got some good insight into the gas market, so I'll pass back to him.

Thanks, Damian. Gas marketing is another area that has a big impact on our cash flow. The East Coast market has been pretty stable since June last year with spot prices at Brisbane between $10 and $12 per gigajoule. The NT gas market has traditionally traded at lower prices in the East Coast due to the historical oversupply from offshore fields and transportation costs to the East Coast. I'll discuss this more later, but recent changes in the supply of gas to the NT have caused this gap to narrow. We have seen an increased interest in term gas supply, resulting in 3 new contracts over the past 6 months at prices higher than our historic average, including the supply of gas to the proposed Arafura rare earth mine from 2026. About 70% of our proved gas reserves showed uncontracted, which gives us the opportunity to contract more gas to what we see as strong emerging markets. Successful marketing strategies, along with the cost and debt reduction Damian spoke to earlier, will drive free cash flow and accelerate the point at which Central is in a position to pay dividends. Consistent with cash retention, we will also narrow our focus on growth activity. Strategically, we intend to sell or relinquish noncore or low priority permits that cost a lot to retain.  The Range sale is an example of this, as is EP-105, which is a low priority permit with increasing holding costs that we, along with our joint venture partner, Santos, are now in the process of relinquishing. We'll continue to hold permits with potential or ones that we think can significantly benefit from near-term exploration activity elsewhere. But the focus for growth will be on high impact near-term opportunities where we can attract partners under a promote structure to offset our costs. This list includes the Mount Kitty and Dukas subsalt prospects, the Mamlambo oil prospect and EP115, which includes the Zevon sub-salt lead and other potential conventional targets on trend with Mereenie and Palm Valley. I would also add appraisal of the Mereenie Stairway formation and progressing the helium recovery unit, both of which could lead to significant new reserve adds.  Moving to the Northern Territory gas market. Following our update last week, the NGP remains unavailable, and it is expected to be unavailable through June. As with past NGP outages, it is having a temporary impact on our sales with Mereenie production partially turned down as we remarket our NGP gas to customers in the NT. You might be wondering what is driving these outages over the past 18 months. The answer is that the NGP has a minimum flow requirement to operate safely. If you look at the Gas Bulletin Board, that minimum flow appears to be about 20 TJs a day, which means that the NT's total gas supply has to satisfy the NT gas demand plus 20 TJs per day in surplus gas in order to keep the NGP running. Whilst NGP outages are clearly challenging for NT suppliers and East Coast customers alike, the outages actually reflect more significant NT market dynamics that could end up positioning the Amadeus Basin as a critical source of NT gas supply. This chart of the Gas Bulletin Board data shows that the NT's gas supply mix appears to have changed over the past 18 months. A few years ago, there was around 120 TJs per day of Northern Territory gas supply from 2 main sources. Our production assets in the Amadeus Basin gas fields, shown in green, produces around 40 TJs per day. And the Blacktip offshore gas field is shown in blue, produced around 80 TJs per day. The NT demand is seasonal ranging from about 60 to 80 TJs per day. With these volumes, there was about 40 to 60 TJs per day of surplus gas in the NT, well above the NGPs 20 TJs per day assumed for minimum flow.  I'll take a moment to highlight that the Amadeus Basin produces over half of the NT gas demand. This is something that gets taken for granted during periods of surplus NT production. However, it changes very quickly when the NT experiences a gas shortfall. We are starting to see this dynamic now unfold in the NT. Over the past 2 years, as you can see in this chart, gas production from the Amadeus Basin has held steady at around 40 TJs per day. However, production from the Blacktip field has declined dramatically to around 20 TJs per day. INPEX LNG has supplied the market on limited occasions and tail gas from the now closed Darwin LNG plant has more recently provided supply to offset the Blacktip decline. The result is that the total NT gas supply has at times not been enough for both the NT demand and the minimum volume required to keep the NGP open. You can see a clear correlation between NGP outages shown in this chart as gray shaded vertical bars and periods of low NT gas supply. Perhaps more interesting is what happens to the NT's gas supply portfolio from here.  Over the remainder of this year, we expect the Darwin LNG tail gas supply shown in gold on the chart to end when the field shuts down in the coming months. The production from the offshore Black tip gas field could also stay flat or continue its steep decline or you could rebound in planned field activity is successful. Depending on these outcomes, there could be a range of market scenarios. NT supply could get back into surplus or alternatively, it could require other sources of gas to satisfy the NT demand. In the near term, these alternative sources would include further diversion of LNG into the domestic market, importing gas from the East Coast by reversing the NGP and increasing production from the Amadeus Basin through new wells. In the longer term, new supply from the [ Beetle ] Basin is also possible but that basin has not yet proven to be commercial and it would probably require years to move into full-scale production. On the demand side, new gas customers could enter the NT market such as Arafura's rare earth project, which, if developed, would increase the NT's gas demand by around 20% from 2026. In short, the NT gas market is in a state of transition with a wide spectrum of supply and demand outcomes possible in both the near and long term. If the NT's gas supply rebounds with sufficient surplus gas, the NGP could resume exporting gas to the East Coast. Under this scenario, Central's production would continue to access the East Coast market, the East Coast market, obviously being tight and widely expected to become more so over the coming years. So having the NGP reliably open would be a great outcome for Central.  Alternatively, under a low NT production scenario, the NT would need to rely on the alternative sources of gas I just mentioned, which would be a completely new paradigm for the market. Under this scenario, Central Petroleum's production from the Amadeus Basin would benefit from having a locational advantage where the Amadeus Basin is at the doorstep of a tight gas market. This would remove the $3 to $4 per gigajoule in cost that we currently pay for long-distance transport to the East Coast market, which given our current margins are only around $3 per gigajoule would also be an excellent outcome for Central. Obviously, there are a lot of moving pieces to consider as the market unfolds in the coming months but the Amadeus Basin has proved gas reserves in the ground, a long track record of reliable supply and established infrastructure to deliver that gas to customers. So it should play a key role in any market outcome and also be very competitive against alternative NT supplies like LNG and East Coast imports. Ultimately, there could be more short-term turbulence as the NT market adjusts, but also the potential for Central's operating assets to quickly experience a re-rating should gas market dynamics demonstrate a need for gas much closer to the Amadeus Basin.  Let's wrap up the presentation with a quick update on other activities. We remain in active farm-out discussions for our subsalt permits. If these are successful, we could see subsalt drilling within 12 months with Mont Kitty likely to be the first prospect drilled given well testing to date has indicated a world-class concentration of helium. We continue to work with our partners on a helium recovery unit at Mereenie. We are working to achieve a more turnkey type of delivery structure, which would minimize any capital from the Mereenie JV and accelerate completion of fit activities. Also, the government recently announced funding support for 2 strategic projects. I think the HRU project has similar national strategic benefits, which could greatly assist in making this project a reality. Our flare gas recovery project was recently completed. It ended up reducing Mereenie Scope 1 emissions by about 1/3 and increasing gas production capacity by about 0.5 TJ per day.  Finally, we announced an agreement with Arafura to supply gas to their rare earth project in the NT. The GSA is conditional and Arafura's commitment by 30 June 2024. However, they recently announced government funding support, which gives me a lot of confidence that the GSA will become unconditional. As I mentioned earlier, this project would increase NT's gas demand by around 20% from 2026, so it could play a very important role in the NT's gas market dynamics that I talked about earlier. At this point, let's open up the webinar to questions.

Thanks, Leon. Look, we do have some questions. But I thought first people might have noticed yesterday, AEMO released their annual gas statement of opportunities report, which may have some inputs for [indiscernible], I guess, for Central. So it might be ahead off any questions that might be around that. What does yesterday's statement means for Central?

Yes. Thanks, Damian. I expected this question. Obviously, the [ GS ] for 2024 came out yesterday, have had a chance to look through it. The [ GS ], I think, was a wake-up call for everyone who thinks the current path to renewable targets and its associated regulatory environment are good for Australia. For Central, specifically, I think yesterday's [ GS ] supports exactly what I've been saying over the past months and have said in this presentation. In particular, it highlights that the committed and anticipated supply in the NT indicates that we're headed to a low NT production scenario, which I talked about earlier. This slide that we're putting up summarizes our, I guess, key takeaways from the [ GS ] for those who haven't had a chance to read it. Specifically, it says some of the key points, gas, obviously, will be a key role in Australia's energy mix throughout the East Coast. The NT gas shortfall is already in place for committed and anticipated supply, which is how the AEMO has defined their gas forecast but importantly, it's rapidly getting worse by 2027. There's no major recovery forecasted from the Blacktip field. [ Beetle ] Basin is considered uncertain and, therefore, not included in the NT gas supply forecast. They do identify the NGP reverse flow as a project that's currently underway, which could import East Coast gas from mid-2024. And Finally, the Amadeus Basin, if you look at that chart is essentially the primary source of NT gas supply. And it's important to note, and this wasn't really highlighted by the [ GS ] is that the Amadeus Basin can increase production quickly. We've got the ability to drill wells at Mereenie and Palm Valley, which can add up to 20 TJs a day fairly quickly from existing reserves and therefore, really is lower risk sources of gas going forward. Also, we've got exploration and appraisal opportunities in the Amadeus Basin as you'd be aware, which I think will get a boost from the [ GS ] that was recently released yesterday. So that's sort of the summary of what we've got.  I think it's also worth mentioning that the [ GS ] forecast is very different from the forecast they put out in 2023. I do expect this report to have a fairly big impact on the market perception of Central and/or production in the Amadeus Basin going forward, particularly because AEMO is considered by market participants to be independent and highly informed. So it's one thing for me to go out and raise the alarm and show where we think there can be shortfalls in the market, where you get AEMO in a formal report done every year that's fully informed, saying the same thing, I think it does wake a lot of people up, and it could be a very interesting year for Central and the Amadeus Basin coming up.

Okay. Thanks, Leon. Okay. We might go to some other questions now. I've got a question here. Does Central receive any compensation from the Northern Gas Pipeline during any shutdown? And if not, why?

Yes. So we only have transportation on the Northern Gas Pipeline on certain occasions with certain customers. So not all the time, sometimes the customer will have that transportation. But typically, the pipeline agreements for transportation allow for permitted interruptions. As I understand what's going on with the NGP in terms of insufficient flow and the safety of the operations fall under what we call permitted interruptions. There is no compensation in that case, really what happens is both the supplier like ourselves and the East Coast customer are essentially been in a position to go after find alternative gas, but we don't get compensation for that disruption, so to speak. Okay.

So another question here. So did the series of NGP outages over the past 18 months have an impact on strategic review and what was happening at that time?

Yes. That's a very good question. I think it very well could have had an impact. Obviously, market and transportation uncertainty would have made forecasting production and revenues out of the Amadeus Basin more difficult and this obviously was occurring during the strategic review. I also think that the fact that the NT market is potentially heading towards a substantial shortfall has really come into focus probably over the past few months, and that was after the conclusion of the strategic review. So had the [ GS ] -- yesterday's [ GS ] come out in 2023, I think it's very possible we would have had a different outcome from the strategic review. But I also think that the Board's decision to not transact on any of our producing assets in the Amadeus Basin will prove to be entirely correct, given the current NT gas market dynamics, which really could completely rerate those producing assets as the market goes through this transition. And the Amadeus Basin is now recognized to be potentially at the doorstep of a market that's short on gas.

Thanks, Leon. So there's a question here around gas prices. Could you explain the impact on gas prices if the NGP flow is reversed, that is, will Central gas still be a more competitive source into the NT?

Yes, it's a good question. It's obviously something that once we understood that the NGP could reverse flow and actually start importing gas into the NT, that's a paradigm that had really never been considered when the NGP was built because [ ENT ] was oversupplied. If it does reverse flow and start to import gas, obviously, that provides very -- a much deeper market and source of supply for the NT customers but it is in all likelihood going to be much more expensive. And primarily, the reason is you move from having a locational disadvantage in our case where we have to pay transport to the East Coast, that reverses. We actually, in the Amadeus Basin, have a locational advantage where our transportation comes down quite substantially. But on the flip side of that, gas supply that needs to be purchased in the East Coast, for example, at Wallumbilla, and we talked about those prices at $10 to $12. That price would then also have to have a premium to accommodate the transportation cost to get it from Wallumbilla into the Northern Territory and we've talked about what some of those costs have been in the past. It's not a small amount. It is substantial relative to the delivered price, so very material. So I guess the upshot of it is we'll have to see how pricing plays out, how the mix of gas supply unfolds in the NT, but we are very comfortable that our production from the Amadeus Basin can compete very well with either emergency LNG imports, diverted into the domestic market or East Coast gas that's purchased and transported all the way into the Northern territory. So I think we're quite comfortable with those scenarios.

Okay. Another question here on the NGP. Are you expecting the NGP to increase capacity in the near term and what is the outlook for gas-fired generation in the NT and the wider East Coast in supporting renewable generation? And how might Central benefit from that?

Well, I think the [ GS ] has a lot of information on that, and I would suggest you go through that in terms of the energy mix on the East Coast going forward over time. For the Northern Territory gas generation is a major customer. It is managed the gas portfolio for generation, gas generation in the NT is managed by PwC, which is why PwC is one of our customers and a longtime customer because, obviously, that's a fairly substantial source of demand. I think the gas generation will continue to be there. I know there's a position there has been a push for some time to increase renewables. But if you look at the demand forecast in the [ GS ], there's really no substantive decline in NT demand for at least the medium term, maybe longer term, there might be a plant that closes or some other industrial drop in demand, but that's a long way off and probably highly uncertain. So I think for the foreseeable future, that generation mix is fairly well established, albeit obviously, a press of trying to get more renewables in, but there's some limits to that.

Okay. So a couple of questions here, just around what we can do to increase production from our producing fields this year. Are we now even more incentivized to go after new wells given the [ GS ] Northern Territory forecast yesterday. So because it comes around that question of drilling new wells at Mereenie and Palm Valley.

Yes. It's a question that comes up quite a bit, which is why aren't we currently drilling wells at Mereenie and Palm Valley to increase our production. As you can imagine, over the past 18 months, we've had a lot of uncertainty in terms of the NGP and its availability. Obviously, very difficult to contract with customers with that level of uncertainty as the market is in transition. We think that the -- what we're seeing now are price signals that are supportive of that new investment to increase production. And certainly, that has been the case in the past few contracts that we have signed up to over the past 6 months. So we're comfortable that the market signals are there, and we are very interested to increase production to help contribute to the NT's gas supply and mitigate that shortage. One of the critical things that we do need is confidence that we can get firm transportation on the Amadeus Gas Pipeline or AGP. And in particular, with the reverse flow and imports coming in from the NGP into the Amadeus Gas pipeline, understanding the pipeline dynamics and the pressure regimes there in terms of what that means for firm transportation to customers north of the NGP and in Northern NT. It's something that we have approached the NT government about, and we are working with them on that. I'm comfortable that, obviously, with the clear need for gas in the [ ENT ] and the really the critical role that the Amadeus Basin plays in supplying [ ENT ], which currently is over half the NT's demand that we will be able to get that confidence and clarity on transportation. And ultimately, we'll be able to quickly get into drilling and bring that additional production online and deliver it to a market and that clearly needs more gas.

Thanks, Leon. So just I guess, Randy, on that question on what sustaining capital is required this year to sustain production at current levels from our producing fields?

Well, we've got stay-in business CapEx that we incur each year just to keep the plants running it, safe and efficient and obviously, reliable. So we do incur those. Those seem -- those are typically pretty modest. Our big capital expenditures and other expenditures on major activities have tended to be more on the exploration or on the development well side. As I've said, we've got opportunities to drill wells right now at Mereenie and at Palm Valley. Those wells have been progressed, we've got approvals at Mereenie and started approvals at Palm Valley. We've ordered long leads, we can get drilling at Mereenie within 12 months. So depending on how the transportation part of the equation works out, we'll be looking to try and get those capital activities underway and obviously, the funding program around them is going to be a critical part to that. But I think with the price signals we're seeing in the NT, I think those opportunities to get funding for that are diverse, and I think there'll be good solutions for it.

Okay. A couple of questions here around Dukas. When do we expect to start drilling again and what can we do to make it happen?

Yes. So we are, as I mentioned, in active discussions with a party that those discussions are, I would say, mature and I think progressing very well. I'm optimistic that we will get a joint venture together to get subsalt drilling happening in the not-too-distant future this year. Those discussions and most of the discussions we've had with interested parties on subsalt have focused around Mount Kitty as a first well to be drilled, largely because it's a discovery, it's got world-class concentration of helium from the test results we've done in the past. It's lower risk, and it's really now not about so much whether there's the helium and hydrocarbons, it's really about if we do some lateral drilling in that formation, can we get the production rate up to commercial levels. So that's really the next step. Because of that maturity, it probably is going to be the first sub-salt well to be drilled. And because you learn a lot about the basin and the sub-salt opportunities, I think the lessons learned from Mount Kitty will be taken into account, and Dukas, obviously, will be the next cab off the rank, I think, should those results in Mount Kitty be supportive of further drilling of sub-salt. So I think it will be a phased approach. Dukas is certainly there, probably #2 in terms of the sequence and potentially Mount Kitty, the first one. Hopefully, we can get that. We've obviously done a lot of planning and prep for it. I think if we can get the joint venture and farm-out bedded away reasonably quickly, that drilling can occur within 12 months of that conclusion of a joint venture arrangement.

Okay. It's a slightly different topic around one of our shareholders, Troy Harry's, obviously, a major shareholder who's been buying Central's shares and has increased its holdings to around 9%. Is there anything happening there that you can share?

There's nothing happening that I am aware of. Obviously, Troy has increased his stake in the company, I think it's up to around 9%, which is a reasonable increase from where it had previously been -- Troy -- having recently been on the Board is obviously very familiar with the management team, our capabilities, the strategy we're working towards and some of the complexities and risks and opportunities that the business faces and obviously, he would have been aware of and following some of the NT market dynamics that are coming to light now through the [ GS ] but have been sort of building and evident over the past few months in particular. So ultimately, I think it reflects well on the company. And I would assume that his increasing his stake in Central Petroleum will be viewed by Central investors as a positive signal.

Okay. There's another question, Leon, how far away are dividends?

That's a very good question. And it's obviously one of the things that we have to manage when we communicate the strategy about paying dividends. I think what you've seen from presentation from Damien in terms of cost reduction, but in particular, the repayment of debt, really by 2026 is when we see that debt really fall off to a point where there's substantial opportunity for additional free cash flow. But playing into that, I think, critically, is our gas marketing and it's the reason I put that up there is a key cash flow driver. We've got a substantial amount of uncontracted gas, the marketing strategy that we employ and the success in our ability to market that uncontracted gas will become very evident beginning next year, but in particular, from 2026 and beyond. So I think depending on how all of those factors unfold. I would like to think that certainly, in that 2026 time period, we have started to position ourselves to consider dividend payments. How big and how soon those might be really depends on the outcomes of the work that we're going to be doing on cost reduction, debt reduction and critically, what the market looks like as we recontract gas that really starts to become evident from 2026 and beyond.

Okay. Another question. So what does Central look like in 5 years?

Good question. I think based on the strategy that we've outlined, we hope to obviously be in a very good position to pay dividends and would have at that point, have significantly increased our free cash flow. I would hope that the appraisal and exploration activities that we undertake over the course of the next couple of years, yield some results and obviously, that's critical to the growth part of our strategy. I would like to think we will be producing helium and a strategically important part of Australia's helium production -- domestic production, and obviously, that does help bring additional revenues to the field. I think there's things we can do to expand the Amadeus Basin, increase production. And obviously, the NTS market plays a key role in terms of what kind of marketing success we'll have over the next year or 2 and that translates very quickly into the kind of free cash flow we have. So my hope is that the strategy we put in place and the opportunities that lay ahead of us were able to successfully capitalize on. And I think if we do that, the timing and the quantum of potential dividends will both move forward and get maximized.

Yes. So just on those dividends, line, there was a question here. Will the Board likely target a payout ratio and will [indiscernible] be on a sustainable basis or one-off special capital return? And does Central have franking credits? So I can handle the franking credits No, we don't have any.

No, we don't. On the franking credits, I think the strategy is to get into a position where we have sustainable dividend -- the ability to pay sustainable dividends. I think everything that we've been talking about in terms of cost reduction, debt and liability repayment and gas marketing are not one-off things. These are things that we put in place and can benefit from each year and so the intent in doing all of that is to put in place a stable dividend payout program that can be repeated each year and hopefully grow as the company grows in some of these areas.

Okay. Well, I think, Leon, that's all the questions that we've come through at the moment. So I hope I did sort of amalgamate a few together on similar topics. I hope we covered that off for everybody. Obviously, if you do have any other questions, you can either shoot through a question or two to our e-mail address, which is, I think, [email protected] and we'll attempt to get back to you. So I think that's all we've got for the moment.

Yes. So thank you for your time, and thank you for your support those Central shareholders for those of you tuning in. And again, hopefully, this presentation has provided a bit of clarity on what's going on currently, but probably more importantly, where things can head and some of the positive changes that are quite possible in the very near term that we'll have potentially a significant impact on the Amadeus Basin, how those assets are viewed and the opportunity for us to generate more free cash flow and work towards the strategy of paying dividends in the future.