Central Petroleum Limited (CTP) Earnings Call Transcript & Summary

Good morning, and welcome to our webcast presenting our June 2020 quarterly report. I'm Leon Devaney, the CEO and Managing Director of Central. Today, I'm very lucky to be joined by our CFO, Damian Galvin; and our General Manager of Exploration, Duncan Lockhart. Before getting into the quarterly results, I'd like to set the scene more generally for the business. Whilst there's been some stabilization in oil markets, the global LNG market remains depressed. As a result, we continue to have very weak domestic spot gas markets on the East Coast. Wallumbilla spot pricing, for example, is currently below $4 per gigajoule, which is pretty much at historic lows. As I said last quarter, our immediate priority has been protecting the assets of this company through the downturn. Fortunately, over the past 5 years, we have built, from scratch, a solid operating business with contracted revenue streams that allow us flexibility to weather major market downturns like we see today. Our financial position also enables us to focus on growth activities going forward. But we need to be smart about what we do and when we choose to do it. This is especially the case with market conditions still weak and the renewed level of uncertainty around COVID. I'll now hand over to Damian to talk through our quarterly results.

Thanks, Leon. Look, it's certainly been a year of 2 halves, and I think not just for Central, but obviously for the industry and the economy globally. And I think amongst all that, we're very happy to be able to post a record annual sales volume this year of up 14% on 2019 at 12.3 petajoules. So very proud of that achievement. Obviously, it's lower than we would have liked, but obviously, the market weakness is something that we've had to adjust to, and I think we've done that reasonably well. We saw that weakness sort of flow through from the first quarter of this calendar year, I guess the third quarter of the financial year into the last quarter, the June quarter. Our sales were down slightly. We're down about 4% at 2.5 petajoules for the quarter. And that continues to reflect the continuing market weakness, but also we did have some lower nominations from our Dingo field this quarter, and that's probably seasonal given that we're supplying the power station out there. The good point to take away from that is that, that contract is covered under take-or-pay provisions. So any shortfall, we do actually receive the cash for in January of next year, so it's really just a deferral of cash flow from Dingo. We had some gas balancing fluctuations at Mereenie, and that's really just a function of the interaction between the various customers of ours and Macquarie, our partner out there. So we're on the wrong side of that ledger this quarter, made a slight difference. And there were some compressor maintenance at Palm Valley. So generally speaking, what we're starting to see now, as we did in March, is that we're falling back to our contracted volumes, and that's really providing us with a very solid base. The other takeaway, I think, was that the Palm Valley-13 well has continued to perform very strongly. It finally came off plateau in June, which is after a full 12 months, producing at 7 terajoules a day, which certainly exceeded our expectations on the upside and has given us some good momentum going forward into the new year. The revenue side of that obviously follows from the volumes. Again, we've seen record sales revenue for the year, $65 million, the highest for this company, were up 10% on last year. We would, at the start of the year, have expected to see a number of $70 million or more. Obviously, the market weakness has had an impact on us. But still, that's a very strong revenue number, which continues to provide a sustaining cash flow for our business even in this time of weakness. June quarter was down 8% from March. So following the revenues -- sorry, the sales volumes that we saw, there has been an additional, I guess, impact from the lag of low oil prices. Obviously, we've seen very low oil prices in the first half of this calendar year, particularly sort of February through April. We saw numbers sub-USD 30 a barrel, and that has sort of flowed through into our numbers for the June quarter. Fortunately, what we're seeing now, of course, is that oil prices have recovered somewhat from those levels. They're up at about $40 a barrel now, so we would expect to see some slight improvement in the next quarter. The average unit sales price for the year was $5.27 and was $5.55 for the quarter. And while that is slightly down on previous numbers, largely as a result of oil, I think what it is starting to show quite clearly is that our fixed-price contracts -- our gas contracts are really providing a very solid support base for the business going forward. And how that flows through into our cash numbers is worth dwelling on because it does paint a picture of some resilience in the market. And when we last spoke to you or when we went into March, I guess the world was all doom and gloom. And we took some fairly drastic action, as Leon pointed out, to conserve our cash and to preserve our ability to come out of the market uncertainty with our growth prospects still intact. And I think we've managed to achieve that. When you look at our cash balance, we've managed to hold it around that $25 million, $26 million mark throughout the first half of this year. And in fact, for the full year, we've increased it by $8 million. Now a large part of that came from the funds -- it came from the Range transaction. But even if you peel that away, what it does show is that our producing assets in the Northern Territory are really sustaining the entire business comfortably at this point. We're covering all of our operating cash flows, we're covering all of our corporate costs, we're covering all of our debt service and we're covering our discretionary exploration spend as well. And that's not just for the quarter. It's for the last 2 quarters and, in fact, really for the whole year, when you look at its entirety. And I think that's an important point that people do need to take away, is that even in these very difficult, challenging market conditions, we're still holding firm. And we do have spare capacity still at Mereenie to increase our sales without any further capital expenditure there. So we think we've managed to sort of weather the worst of the storm. I will spend a little bit of time on debt because I know there is some concern around -- in various quarters, around our debt levels and has been for some time. And I think the important thing to point out, I think, to people is that in the last 12 months, we paid back $11.5 million of our debt. Over the last 2 years, we've paid back over $25 million, and that's sort of 30% of our debt at its peak that we've managed to pay back. Our debt covenants are all well under control and within our forecast and continue to be so. We have a very favorable debt repayment schedule going forward. We only need to pay $1 million in this following quarter and $2 million each quarter thereafter. And so you can see from the cash flows that we're generating out of the Northern Territory is that we can easily sustain that debt service going forward because we've got that strong base of firm contracts to underwrite that. So we are quite comfortable with the debt position. We don't see any reason why anyone should be particularly worried. We're working on reducing it over time. We've got the support of our financiers. We're all well within covenants, and we're very confident that, that's playing an important role in this company's growth. When you look at the fact that we've managed to increase our revenues and our sales volumes from where they were over the last 18 months without having to tap shareholders, it plays an important role in the overall capital mix of the company. The other, I guess, exciting thing that came out of the quarter was that having been -- had the opportunity now to go back and look at the production from the field over the last 18 months since production levels were ramped up, is that having analyzed all that data, our external consultants have increased our gas reserves by 16% or 22.5 petajoules. And to put that in context, it doesn't sound like big numbers, but when you consider that we would generally sell our gas for over $5 a gigajoule, you're talking over $100 million of additional revenue that we would expect to gain in the future, which really, at the moment, accounts of about 2 years' worth of production if you look at this year's production numbers. And again, to some people, that may not be significant. But when the company's market cap is currently sitting at $60 million or $70 million, when you add a potential extra revenue of over $100 million, I think that is something that people should be aware of and put that into context. The other important thing that came from that, and it's worth drawing out, is that not only have we upgraded those 2P reserves, but we still have a very significant contingent resource of 2C, both in the Amadeus space and then also at our Range prospect in Queensland. So for example, there's 105 petajoules of 2C gas resources at Mereenie and Palm Valley that can be fairly efficiently accessed from existing wells. So for example, the Stairway Sandstones at Mereenie can be accessed through lateral drilling from existing wells. And similarly, at Palm Valley, we can attempt to replicate the success of the Palm Valley-13 well through lateral drilling from existing wells and from the proposed Palm Valley Deep exploration well. So that's quite a considerable upside, and when you add it to the potential Range contingent resource, we can really -- the potential is there to increase from 161 petajoules of 2P at the moment, up towards 400 petajoules relatively efficiently and I'd say with relatively low risk. My engineers will be taking the task on that. But compared to exploration, these are a different level of risk. But what we've done, I guess, in preserving and conserving our cash over the last 2 quarters was really to provide an opportunity to launch back into our growth prospects. And that's -- having had the chance now to look back over our results for the last couple of quarters, now it's time to look forward. So I'll hand you back to Leon and to Duncan to talk about some of those -- some of the upside that's ahead of us.

Great. Thank you, Damian. With that update on the quarterly, I'd like to spend a bit of time now talking about those growth prospects and provide a bit of update on them, specifically our exploration program, which is being fine-tuned in conjunction with our farm out process and discussions with potential farm out partners. Also provide an update on the Dukas exploration program and our Range project. And finally, touch a little bit about gas marketing. First, I'll hand it over to Duncan for an update on our exciting Amadeus exploration program.

Okay. Thank you very much, Leon. As briefly mentioned there by Leon, we are well on track to spud our first well in the exploration campaign in the first half of 2021. And as a result of that, we're very well advanced in our approvals and finalizing well designs for our proposed campaign. Based on feedback that we've been getting from potential farminees, we're now going to be focusing on the 3 highest impact gas prospects that we put forward in the exploration program, plus looking at addressing the Mereenie Stairway appraisal opportunity. Mamlambo, which was in the initial campaign, is an oil play. It's still being designed. We're progressing with the approvals, but it's not filtered to the top as a priority currently. But we will progress it and hopefully get into it in a later round of exploration. So if we look at the Mereenie Stairway, we're focusing on utilizing existing wells within the Mereenie field that have already exhibited excellent gas shows while drilling, but were not completed because the main prize at that point -- at that stage was the oil rim in the Mereenie field in the deeper Pacoota reservoirs. We're investigating the possibility of utilizing coiled tubing drilling techniques to drill a series of horizontal wells out of these existing wellbores of up to potentially 500 meters. By utilizing this technology, it would be very cost efficient, and it's a very flexible way of appraising the Stairway section. It means we can gather much needed data for any potential large-scale horizontal drilling in the future in an incremental manner. Success also in this campaign will be rapidly monetized because we'll be utilizing existing well and pipeline infrastructure within the field. Of course, this is subject to joint venture approval. This will start the journey, if you like, on converting our large contingent resource that Damian has mentioned from -- in the Stairway, in particular, towards reserves. With Palm Valley Deep, we've effectively got a 2-for-1 well design concept in play here. The well will be drilled to a deeper Arumbera target to test a potential mean resource of around 123 petajoules. This level has never been drilled before in the Palm Valley field. But after testing this interval, we intend on pulling back to the productive Pacoota Sandstone level and sidetrack horizontally from the wellbore that we've just drilled. Based on fracture modeling, we're expecting to emulate the Palm Valley-13 result with this lateral well. And as we know, Palm Valley-13 has well exceeded expectations. And we believe based on the fracture modeling work that we've done in this field, that the location that we've chosen here should provide a similar result to Palm Valley-13. The shallow sidetrack well can be very rapidly monetized by being connected into the existing Palm Valley facilities as well. And so while this well is producing, it will allow us in the success case at the deeper level to design a more comprehensive field development plan for the new Arumbera level if it comes in, in a success case. So this field development plan, it could incorporate utilizing existing wells in the Palm Valley field and just removing their completions and drilling down to the deeper intervals, and in so doing, providing a very cost-efficient development scenario. Orange 3 is by large, by -- well and truly the largest exploration prospect that we've put forward in this program. We -- the thing that is exciting about Orange is the fact that we've got a proven gas flow already from the same reservoir interval as Dingo, and it was originally drilled with -- overbalanced with mud systems. And we know that these formations in the basin are very sensitive to overbalanced drilling. And so we intend on testing this Arumbera section by drilling under balanced, which is a method that we have been quite successful with drilling throughout the Amadeus basin. We will also then continue on to the Pioneer and Areyonga Formation, both of which have not been tested either in the Dingo or the Orange field. The well will be deviated at 45 degrees when we get down to the deeper targets as we're expecting to encounter a fractured reservoir system similar to Palm Valley. And in the success case, like I say, Orange has the potential to be a very large discovery and potentially change the way we do things in the Amadeus basin. Dingo Deep is very similar to Arumbera, but we've located a new well in the Dingo field, which is updip from the existing productive wells at the Arumbera level. So we have the opportunity to complete the Arumbera at this particular location. In any case, if we fail at the deeper levels, we can at least complete at the Arumbera level and have an extra gas producer from the Dingo field. But as with Orange, we're targeting also the deeper Pioneer and Areyonga Formations. And likewise, this well will be deviated at these deeper levels to maximize the chance of intersecting productive fractures from those deeper intervals. So we've been very busy in-house, and we've been undertaking a lot of additional technical work, maximizing our understanding of the geological risk and the potential of the existing prospects that we have on our campaign. And as a result of this geological work, we have -- we will now target an additional play interval in Orange 3 and the Dingo Deep wells, which is the Areyonga Formation. The Areyonga Formation is excellent, gas shows from a fractured interval at the Ooraminna 2 well, which is the closest offset well. And this well, Ooraminna 2, also flow gas to surface from the Pioneer Formation. So the work that we've done on the regional basis and applied it into here has helped us actually get an increase of around 30% of the mean recoverable prospective resources just from these particular wells. And you can see those numbers there. The original targets that we had for Dingo Deep, Orange, Palm Valley Deep were an aggregate total of 454 PJs, and now we're up to potentially 593 petajoules as a target mean resource. Now the 2 of these 3 priority candidates, which are Dingo Deep and Palm Valley Deep, are to be drilled within existing gas field so they have the ability to leverage off the existing infrastructure which is in place within those fields. And as a result, given the fact that we've got shallower targets that will be completed, such as the Pacoota at Palm Valley Deep and the Arumbera at Dingo, they're quite easy to monetize. And the Orange field -- I call it a field, if it's a major discovery, it's directly on the pipeline route from Dingo into the existing [ back ] facility. So it can also leverage off the existing Dingo infrastructure. So look, this slide is just to illustrate how all the proposed exploration appraisal candidates that we've got in the campaign are drilling into proven exploration targets with each well being designed to have the ability to actually address multiple targets. So this maximizes our chance at success as opposed to if we just came up with single-target prospects where you only get one shot at success. You can see that Orange 3 is drilling through, like I've mentioned, the Arumbera Formation. Now that's already a proven gas discovery. It has actually flowed gas to surface by DST at a rate of 500,000 standard cubic feet a day even though this section was drilled with mud overbalance. So we're expecting to get at least a significant increase in the gas flow out of here by using underbalanced drilling. Like in the Dingo field, there's been at least 200% increase in flow rate just by utilizing underbalanced drilling. The deeper targets, which are the Pioneer and the Arumbera, as I've mentioned just previously, both flowed -- either flowed to surface in the case of the Pioneer at Ooraminna. Both had very, very strong gas shows in the Areyonga from a fractured interval as we've seen over in the Ooraminna 2 well. So although they are very much exploration targets, they're -- some of the risk has been reduced by the fact that we know that the working petroleum systems in these deeper levels and a lot of the risk has also been taken out by the fact that we know that we've got these large structures that we've already been able to identify because we have gas fields that are sitting on top of them in the same structural domain. As mentioned previously, Palm Valley Deep is going to be sidetracked into the productive Pacoota interval, which will allow an immediate tie into production facilities and rapid monetization while we design the field appraisal plan. And then it will also be drilling into the deeper Arumbera level, which this diagram shows you is actually at the same productive level that the Dingo gas field is actually producing from. The Mereenie Stairway appraisal plan is subject to JV approval, and it will be the sufficient use of existing wells and targeted designs that have already been proven to help gas bearing. So once again, it's relatively low risk, and we can monetize any success quite quickly whilst then utilizing that information for later drilling. So this waterfall is just to give you an idea of the high impact that success will have for this company in this particular appraisal and exploration campaign. It will completely change the scope of the company's reserves profile. And even in the risk case, it has the ability to more than double our reserves position. You can see here that the Orange prospect on an unrisked basis is by far the largest of these exploration opportunities, it really sticks out. And these numbers really do present a compelling case for us to get on and execute this program, and it is a potential major source of growth for Central if we can get after this. We haven't been dormant and focused just purely on the existing exploration campaign that we've put forward. We have also been looking at the rest of our exploration acreage down in the south. But one of the main blocks that we've really focused on is EP115, which is in the northwestern part of our -- of the basin in which we have 100% interest. This permit surrounds the Surprise Oil Field because the Surprise Oil Field, when it was discovered, was excised and became part of what we call L6, and it's immediately adjacent to the Mereenie oil and gas field. It contains the Mamlambo prospect in -- which is just immediately north of Surprise, although that's in L6. And the beauty of this particular exploration block is that it's probably where the best proven source rock interval is developed in the entire basin, and that's up in the Horn Valley Siltstone, which is the interval that has provided all the hydrocarbons to date for Mereenie and Surprise and even potentially Palm Valley. So we've got a lot of good potential conventional oil play-type acreage up there. But we also have -- you can see that very large orange blob. That's the Zevon lead, which is currently defined on limited low-quality seismic data and from gravity data. Now the Zevon lead is a very similar play to Dukas in the respect that it is a pre-salt Heavitree Formation and fractured basement target, sitting and surrounded by a seal, which is the -- which is a bit of springs formation. And although it's -- this is potentially much larger than Dukas. I say this, potentially. We will also be able to leverage off our learnings from the Dukas well. So with Dukas now being scheduled for the first half of 2022, this provides us with the ability now to potentially utilize the same high-pressure drilling route that's going to be imported or brought in to drill Dukas because we're aware now that this play potentially has very high pressures. And we can reduce the cost of drilling the well up here by showing the [ model we demo ] with EP 112. So to that end, we're currently in the initial stages of planning for a 500-kilometer 2D seismic survey in EP 115. Now that's going to primarily focus on Zevon and other conventional shallow prospects. And we're also looking at a number of other potential techniques as well. So right now, that's where we are potentially focusing a lot of our next stage of exploration. And with that, I'll hand it back to Leon.

Great. Thank you, Duncan. This exploration program, obviously, has the potential to be company changing. And I think we and all investors are looking very much forward to new exploration drilling next year. So very exciting stuff. At the moment, we are progressing planning and approvals from our free cash flow. But in order to undertake drilling in 2021, we plan to access capital through a farm-out. The farm-out process is underway and moving along well, considering market conditions. We are currently working to finalize nonbinding offers before final due diligence begins. We have a really good short list of credible parties, and I remain optimistic we can have a value-accretive farm-out agreed to before the end of the year. Part of those discussions are around what assets are included. We have those priority exploration targets of Dingo, Orange and Palm Valley Deep, which we would look to include in the farm-out in order to get those funded. Some of the other assets that we have with particularly significant upside, such as EP115 and Dukas, are not necessarily going to be included in the farm-out. But again, those are things that we are working through at this phase of negotiations. Moving on to our other growth activities. We recently announced a path forward for the Dukas exploration program with Santos. The JV is currently working to define a preferred drilling approach as we -- as well as associated costs for completing the program using specialized equipment that is able to manage high levels of overpressure. That should take us through to the end of the year with the next year focused on planning, approvals, long leads and rig selection. The target date for spudding the well, as we announced, is the first half of 2022. Just briefly, under the arrangement with Santos, we have an opportunity for a $3 million free carry toward Dukas drilling, that would be $10 million of drilling on a gross basis. To be clear, though, depending on the joint venture decision for a drilling approach and what Santos elect to do with EP 82, Central may be responsible for some funding, but we are confident we have sufficient time to work through this in line with the 2022 drilling schedule. With respect to the Range prospect in Queensland, we are working very hard to restart this important growth activity. In order to do that faster than what would be possible from our free cash flow, we are looking at structured funding options, and there's several of that we are considering. But it's important when we do this, that we do it in a way that doesn't overextend our balance sheet, particularly when we have continued challenging market conditions. So there is a balancing act there, but be assured we are looking to restart this as quick as possible. I'd like to quickly comment on a few recent media articles on our Range joint venture partner, Incitec Pivot, and their plans for Gibson Island plant -- their Gibson Island plant in Brisbane. We have a very good relationship with Incitec, and I have no doubt they're also fully committed to the Range project. I want to highlight that Incitec has several large gas supply requirements in Queensland besides their Gibson Island plant. As a result, I fully expect the Range project will be very important to Incitec as a source of cost-efficient gas supply for their operations in the East Coast moving forward regardless of their plans for Gibson Island in the future. Okay. Moving to markets. We continue to be very active in marketing gas. We have been selling small amounts of spot sales into the Northern Territory market when possible. We are also talking to customers about long-term gas sales. As Damian highlighted, though, we do have time and we do have flexibility. We are not desperate sellers, and I think that's important to recognize as we go through our marketing activities and strategy. We are looking for attractive, long-term gas contracts when they come up for tender. But we only plan to contract when it is in Central's best long-term interest. So obviously, negotiating these very significant contracts is important for the value of the company, and we intend to be very deliberate and smart in how we approach that. On the markets, as I've mentioned, spot markets still remain very weak. I do not think current spot prices are anywhere close to sustainable in the medium to long term. Our view is that we will see an improving gas market in 2021 with the market recovering from 2022. I also think an East Coast gas market correction will overshoot given the severe pullback in exploration and appraisal investment we're currently seeing in the sector. That means our list of growth activities that we've been talking about are actually well positioned to capitalize on this market recovery window. In summary, our growth strategies remain strong, and they remain very valid. We are working extremely hard to make those happen but also doing it in a way that is commercially and financially astute. For investors, it may seem frustratingly slow. But I can assure you, there is a lot happening right now that is just under the surface of the water. So stay tuned. A couple of final topics. We welcomed Dr. Agu Kantsler to the Board during the quarter. This is a great addition for the company. Agu has top-tier experience and really look forward to Agu playing a major role in our future success, particularly given our focus on growth through exploration and appraisal. And finally, saved the best for last. You'll notice our top highlight for the quarter was a continuation of our excellent safety performance. We maintained a 12-month total recordable injury frequency rate of 0. I'm very proud of every one at Central for the role they play in safety. And I particularly want to recognize the team working out on-site for their continued focus and efforts in this area. So well done and congratulations for that outcome. On that positive note, I think we're going to now turn it over to Q&A.

[Operator Instructions] I'll attempt to read these out to be answered.

There we go. Let me get to the disclaimer. We're supposed to put that up.

Came in from our legal people...

I was told by our lawyers that we can't forget to put this up. So please read it.

I'll let you read it at your leisure. But in the meantime, we got some questions whilst you're reading that. So a question here about production. What sort of production should be -- could we expect going forward from Palm Valley and Dingo? That is around 10 terajoules per day and decline for Palm Valley. Dingo is 4 to 5 terajoules a day. Will there be any step-up in Dingo production towards 10 terajoules per day as per the old commentary in the scheme booklet?

Yes. So I think the answer to that question is really going to be market-driven. We do have the opportunity with the success of Palm Valley-13 now to target other similar Palm Valley-like activities where we drill laterally from existing wells. Palm Valley Deep is certainly one those opportunities. The Palm Valley field can produce in the order of 15 to 20 TJs a day without significant capital cost. So that's a natural point to try and get production up to through that additional activity. But again, we are looking at market conditions and our term marketing activities to help shape those increases in production from that field as well as Dingo. Dingo currently has the ability -- notwithstanding the contract, has the ability to produce in the order of 5 to 6 TJs a day. Again, we are looking at the market. Subject to market conditions, we could -- and as you know, from the reserve base at Dingo, which is quite substantial relative to the current contracted annual volume, there's a very good opportunity to essentially double Dingo when the market conditions justify and get it up into that 10 TJs a day sort of level. So certainly, those opportunities are there. There are things that we are very much aware of and are out marketing. But again, as I've mentioned, our marketing activity is really -- we're not desperate sellers, and we do want to ensure that when we market gas, we are not doing it out of desperation. We are actually doing it in order to maximize the value of the assets that this company has longer term.

Thanks, Leon. So more broadly, I think, in the market, these questions. With renewable costs falling in wind, solar and battery sectors likely to continue to put downward pressure on demand for oil and gas, how does Central see about geopolitical market risk and risk by renewable energy? And what plans do we have to manage those ongoing risks?

Yes, that is obviously a risk that has been growing and certainly is front and center for everybody in the energy sector. Our view is that certainly, the move to renewable and reduced carbon emissions, obviously, is there. But we do see that natural gas is really the only valid transitional fuel as you start to focus on the higher carbon emission energy supplies, such as diesel oil and carbon. So we believe gas is going to play an important role. We believe the demand for gas is still going to be strong, particularly in the medium term as that transition occurs. We've heard a lot of talk about coal-fire generation being closed down earlier than anticipated. Gas is obviously the natural fuel source for that transition as it can provide very efficient and much lower carbon emissions when you talk about baseload generation and shoulder generation. And also, it is a fantastic fuel supply for peak generation. So I think it has a very solid position in the energy mix in Australia for the foreseeable future.

Okay. Leon, a couple of questions around exploration. Okay. So more generally a question here on what is the likely timing on the brownfield exploration in the Northern Territory, which is...

Yes. So that -- I'm assuming that is the Amadeus exploration program. So our schedule for that program is the first half of next year, so not too far away. And obviously, that's very exciting. We're pushing the planning and approval process now to stay on track for that. And with a farm-out process progressing, we anticipate closing that or having agreement on that by the end of the year. That keeps us on pace for that drilling schedule. So it's not too far away. It's actually, in exploration speak, right around the corner, and we're very excited for that.

I think more specifically, there was a question on PV, the success of PV-13. What would be the earliest we could monetize any commercial gas discovery?

So PV Deep is our next proposed drilling activity. Again, that's part of the Amadeus exploration program, as Duncan talked about. That is targeting drilling in the first half of next year. On completion of that well, that will be a production well. And as Duncan mentioned, one of the advantages of that well besides exploring the deeper formations, we are going to do a lateral production well into the currently production zones and expect to be producing immediately after finishing that well. We'll hook that up to existing facilities, and that capacity will be available at that time. Again, the further PV look-alike -- PV-13 look-alike so to speak, in terms of lateral drilling from other existing wells, will be then determined largely by market and when we need to have -- and it's appropriate for gas supplies to come into market for sales purposes.

And around Dukas, there's a question here. What's the targeted timing for selecting a rig and mobilizing -- announcement for mobilization at Dukas?

Yes. So as I mentioned, we're going to be selecting and working through the well design options and trying to have a resolution on that by the end of this year. That would allow us next year to work through all of the things in terms of planning, approvals, rig selection, all of that stuff through 2021. The timing, as we've announced, is -- the current schedule has us targeting the first half of 2022 for that drilling. So that's essentially the schedule. Obviously, quite a bit of work to do, as you can imagine, as we go through this year and next to get that all bedded down, and we'll keep the market updated as things progress. But it's important to know that work is active on that. The joint venture is very much progressing that right now.

A couple of questions just around the cost of our upcoming exploration programs. Can we shed any light on that at this stage?

Yes. I think at this point, we're still finalizing well design. Certainly for Dukas, it's difficult because it does depend on the approach that we are going to take for completing the Dukas program. With respect to our exploration program, we are in the process of fine-tuning those. We had given a ballpark for our original scope of the exploration program at around $50 million. We are now -- based on the technical work Duncan has done and also discussions with farm-out partners in refining that, the focus in terms of exploration activity is on those 3 wells, which is PV Deep, Dingo Deep and Orange. The costs will be obviously lower than the $50 million simply because of the reduction in scope. But as soon as we get a bit more clarity on the well design and what exactly we want to do with our joint venture partners -- or potential joint venture partners through our farm-out process, we'll make that evident and clear to the market.

So with the farm-out, there was a question here. Is the thinking that an incoming party participates in or recognizes the upside? Or do you run the risk of giving up this upside cheaply? So how does the timing of the exploration, the high-impact exploration, dovetail into a potential future farm-out?

Yes. Well, that's the -- that's what a farm-out is, it's really monetizing the opportunity for exploration activity. An incoming partner, obviously, pays for that opportunity in that upside, but also on the flip side, inherits exploration risk associated with it. In terms of pricing, we're obviously working hard to ensure we get a fair and attractive pricing for whatever assets we do farm out. The basket of assets for a farm-out is still in discussion. Obviously, the 3 exploration targets that I've mentioned would likely be in that basket as is Mereenie Stairway, which remains subject to joint venture approval. Beyond that, we'd have to ensure that we get a very fair value considering the huge upside associated with things like EP 115 and Dukas. So that gives you a bit of a flavor for where the discussions are, but they have not been finalized. And that's essentially kind of the process we're going through at this point in time, is really what value proposition we have for what specific assets that are included in the farm out.

Okay. And the Range project, I got a couple of questions around that. One question here, are we worried that others in the E&P space with Queensland CSG predevelopment projects will steal our thunder re domestic gas markets? There's lots of commentary around dysfunctional East Coast gas markets. Any comments?

Yes. So a couple of comments. I think our market analysis and certainly, our activities in the market for long-term gas supplies very much supports a market from 2022, 2023, that will be tight and not soon after that, short on gas. And we believe the pricing recovery from what we've seen in the current spot market will be very substantial. So certainly, our growth activities are targeting that window from 2022 to 2023. I guess my other comment is there are a lot of announcements about prospects in place, whether it's unconventional stuff or more difficult stuff in New South Wales and Victoria. I think the thing I would highlight is almost all of these projects have, as far as I'm aware or our view, have very high cost of production or significantly higher costs of production than what we would need to be commercial for our gas in the Northern Territory. You need to remember, our fields, our conventional fields, we rely on natural fracturing, so we are not planning at this point any fracking or anything of that nature. We have existing infrastructure. So for our exploration program, we will be leveraging off existing plant and pipelines, which brings down the marginal cost of production. So we think we're going to be extremely competitive against some of these proposed projects. And I also think ours is much more valid. I think we've got proven fields. We understand the basin as well as anybody. And the areas we're targeting have demonstrated gas shows, they're parts of the basin, which gives us a lot of encouragement that these are, as we've said, lower risk and very high potential exploration targets when compared to greenfield or early-stage unconventional, for example.

Just whilst on Range, a question here. I think you may have sort of answered this earlier, but it was around -- IPL seemed to be talking gas prices down in the media rather than focusing on the Range project. Do you know if they're trying to back out?

Yes. So it is not surprising to me whenever I see gas suppliers talking down gas prices. That seems to make obvious business sense for all gas customers in the East Coast. I think there is a recognition generally that the spot prices that we're looking at are not sustainable in the medium and long term, particularly when you look at some of the projects that have been announced and are hoping to come on-stream at some point in the future. Their cost of production are significantly higher than those prices. Incitec Pivot is -- does have other operations. Gibson Island, they're obviously going through a process to figure out how best to manage that asset and the future for that asset. But their other operations, they are in the market and do require cost-effective gas. Range is obviously an ideal candidate to provide that supply to them. So as I've said, I have every expectation that they are going to be very keen to get that project through FID and developed and have it available for their portfolio given it's a relatively lower cost of production.

A question here about the Northern Territories. Will you be competing for contracts and pipeline space with Northern Territory Power and Water?

Well, we not only will be. We do. They're another supplier or aggregator. They essentially buy gas from Blacktip and then sell it into the domestic market. And obviously, some of their volumes are going through the NGP, is the foundation for the Northern Gas Pipeline. We are located at the southern end of the pipe. So for us, we are essentially -- would be backhauling against any volumes they send south. So we believe there is physical space to get up to not only Tennant Creek, but through backhauls up into the Darwin market as well. The NGP, and this is all available on the Gas Bulletin Board, has currently spare capacity on an uncompressed basis. And obviously, the intent of that pipeline was to install compression, to increase it and it can increase fairly substantially. That unit cost of compression for pipelines is always much, much smaller than the original foundation pricing. So we don't see that. It's obviously something we work through as part of our business and work closely with transporters to ensure that our marketing strategy and exploration strategies all have a home to go to. So at this point, it is certainly something that we work through, but I don't think there's any particular issues at this point in time that give us serious concern.

So another question, what are the expectations on timing for agreeing long-term gas agreements?

Well, I mean, I think I've tried to address that in the summary earlier. Our intention, we'd love to contract this stuff out sooner rather than later. Obviously, it takes some of the portfolio risk out. We do have contracts going out through 2022, 2023. Really, through 2025 is when we've got our contract rolling out. So we do have some time to contract term gas. One of the things is you need to -- that people should understand is that when customers put out a tender for large gas supply requirements, they tend to do it at a point in time that is not too far ahead of when their contracts roll off. And obviously, those all roll off at different times. So part of what we are doing is staying close and keeping a very close watch on the gas markets to make sure we're in a position to be there and be competitive when major gas contracts come up. But the other thing is that the gas markets are at a difficult stage right now. The spot market is obviously very weak. We do see resilience in the term market from 2022, 2023. And I think that's been, I guess, reinforced by some of the comments from Incitec Pivot and other gas suppliers who were saying they just can't get cheap gas from that date for any significant period of time. That's consistent with our views of the market. So it is a bit choppy, to be blunt, when you have short-term markets below $4 and a term market in the future that's significantly higher. It does make it difficult for parties to land on a price and commit for long periods of time. So I think there's just a period of natural market uncertainty that will start to dissipate once we see a gas recovery start possibly at the end of this year or into next year.

Here's one a bit closer to the operations, Leon. Do you plan for a reticulated power supply on your well sites or use power generation, that is gas generators or a solar battery hybrid system?

Good question. I should hold to some of our operation guys. We do look at both, and we do certainly have gas and electric generation throughout our sites. It does depend on where it is, what it is, and we do look at the pros and cons of both of those. So I'd say at this point, looking forward, it will be project-specific, and we'll be looking to move forward with power needs in the most cost-effective and efficient manner for us.

Here's one more around our exposure. I guess could your company not benefit from a greater public exposure? By that I mean an effort to make the general public aware of who we are and what we offer to Australians.

Yes. I certainly think that is something that stands to reason. We are probably taking a different tack than this company has taken in its previous lives. We are really focused on creating real value in this company and driving growth, real growth from the ground up. We intentionally do not want to wave our arms and throw fairy dust around and make a bunch of claims that provide a sugar hit for the company. Our view is we want to under-promise, over-deliver and really create some real value, long-term value, and that's where our focus has been. Obviously, it's important we get that message of what we are doing because we have a fantastic story. Our growth prospects are, I think, incredibly strong, incredibly valid. We do see a lot of headlines and announcements from small caps and others that, obviously, are effective in soliciting investor responses. We try to make sure that what we put out and what we say we're going to do are real, and we believe in them and we're confident in our ability to deliver on those. So certainly getting the message out and investor communication is important, and we are working on that and trying to always improve. But I would couch it with our philosophy on how we communicate with the market.

Question here on debt, Leon. In the quarterly report, mention was made of a possible refi of $62 million debt in September '21. Could you elaborate how this might play out on the back of a farm-out? Is the tenor likely to be pushed out?

So the farm-out is separate. If we just take that, if we were to, say, farm out 50%, just to keep the numbers even -- we've currently got about $70 million in debt. If we were to farm out 50% of our producing assets, you would expect us needing to repay immediately at that time about half of the outstanding debt. That's just a pro rata reduction sort of thing. So we will be paying down debt as part of any farm-out. We're also trying to pay down debt naturally, as Damian had talked about, and we've done a very good job doing that over the past 18 months since the NGP opened up. It is something that we are -- we recognize investors have a concern about. I think optically, when you look at our gearing, it does stand out from our peer group. But as Damian, I think, did a great job highlighting, our debt was used to acquire producing assets. It was the only reason this company is sitting here today with an operating footprint of 3 gas fields and an oil field that generates cash flows even in a downturn market that is sufficient to cover all of the debt service, plus a spin-off free cash flow, which has kept -- allowed us to continue with discretionary spending like growth and other things like that without chewing into cash or being forced to go into the equity market and dilute existing shareholders substantially. So I think we've been able to use debt in a very smart way. I think it's been a good capital strategy for the company over the past 5 years. We believe it's a very efficient form of financing. And we don't see the debt as causing financial stress. And in fact, my view is I'd rather have some debt that's spinning off free cash flow from operations rather than having no operations, no revenue and burning cash flow and having to jump into the market just to keep lights on. So...

Okay. We sort of hit the hour mark. There's a couple remaining. A quick one, is the AGM to be virtual?

I don't know that we've formally decided that. I suspect it very well could be. But I think we'll have a look at that over the next -- probably the next month and advise shareholders on how we propose to deal with it. Obviously, COVID is a very day-to-day thing, to be honest. At this point in time, it looked like COVID had been somewhat stabilizing or there was some potential clarity on how COVID might get under control. But I think the events of the past week put a big question mark around that. So we don't have an answer right now on it, but we'll certainly advise shareholders on how we're going to proceed with an AGM. Okay.

So I think that's basically it. There was one question here around what sort of savings did we get from the headcount reductions that we were forced to make. I think the answer to that is it's potentially sort of in the $1 million to $2 million a year range. It does get shared, obviously, with our joint venture partners as well. So it's not easy to put an exact finger on the bottom line impact. Which staff were involved? Look, I think it's fair to say it was sort of broadly across the entire organization. It was spread reasonably evenly across operations, the exploration and corp.

I wouldn't say it's downsizing. The answer to that is we have been focusing on, obviously, reducing costs where we can. Our operations have always been fairly thin. So you would not expect a huge headcount reduction from the operations team. They were already structured to be efficient given the activities out there. Those activities have not changed, and if anything, given COVID, are actually more substantial. So it's not surprising that the operational part of the business is not being reduced significantly. We're producing a lot of gas. We've got the same equipment, and we're looking to grow and increase that. So from that side, the corporate side, we have been always looking at opportunities. And I think with the downturn, there's some focus in taking advantage of redundancies and people leaving and not backfilling or using other resources. It's not a dramatic -- and again, for us, we're not gutting the business at the expense of growth. We want to restart growth and get back into full growth mode. So as a result, we're not cutting the business. And as Damian has highlighted in the quarterly, we're not in a position where we need to gut the company and destroy shareholder value by transacting on assets at a downturn, which is a great luxury. And I think there's other companies out there in the small-cap space that aren't in that great position. We are, and I think it's a real testament to the operating assets that we've built over the past 5 years. Okay. I think with that, we'll be wrapping up this quarterly webinar, and I appreciate everyone's attendance. And we'll be in further communication with the market as exciting things unfold over the balance of the year. Thank you.

Thank you.