Central Petroleum Limited (CTP) Earnings Call Transcript & Summary

Good morning. Welcome to our August webinar covering Central Petroleum's June quarter results and updates on our various business activities. I'm Leon Devaney, CEO of Central Petroleum, and I'm joined today by our CFO, Damian Galvin. [Operator Instructions] Let's begin with our quarterly highlights. As I mentioned in my quarterly report cover letter, we've had a few cross currents impact the business. Oil and gas markets have reached historical highs, and recent market reports suggest that tight energy markets will continue into at least next year. On the other hand, we continue to see cost pressures across the business. We did a great job managing these costs within our operations as evident in our financial results, but escalating costs have had a big impact on our current drilling program at Palm Valley. The budget for the Palm Valley 12 well was put under further pressure by very difficult drilling conditions at its crestal location. In response to these factors, we revised our drilling program to focus on capital management and near-term production, which I'll talk to more later on in the presentation. We had other wins during the quarter as well. Our team did a great job keeping operating costs low and production up, which has underpinned our solid quarterly financial results. We completed our debt extension, which is a great result given the many challenges our sector is experiencing in the debt capital markets at the moment. And we also secured nonfirm transportation, which was just in time to supply gas into a very tight East Coast gas market which has really helped to offset other cost increases within the business. At this point, I'll hand it over to Damian to present our quarterly financial results.

Thanks, Leon. Look, it's another strong quarter. The high demand for gas has meant that we sold pretty much everything we could produce. That's 1.2 petajoule equivalent in the quarter. Now this was 6.5% lower than the previous quarter though, as the Northern Gas Pipeline was down for maintenance for more than a week in late May, early June. And while volumes were lower, the sales revenues were significantly higher, were up 18.7% on the March quarter at $10.1 million. Obviously, it's been hard to miss the turmoil in the energy markets this winter. We've seen regulators cap electricity and gas prices as off-line coal-fired electricity generation was replaced with gas field peakers. Fortunately, for May, we've been able to supply all of our uncontracted production, that's about 15% of our production capacity to support customers in the spot market. And as a result, our realized gas price was up 31% on the March quarter average. Now there's some transportation costs to be borne out of this, but those spot sales have added approximately $2 million to our top line in just 2 months. The other 85% of our production is contracted at fixed prices over varying terms with CPI escalation courses. So that continues to provide an increasing revenue base as well. Oil prices, obviously, also remained high through the quarter. They're up 9% on the March quarter. You can see on the chart that we've seen steady revenue increases over the last 2 quarters. Notwithstanding that volumes have been relatively steady, we booked revenues of $42.2 million for the full financial year. [indiscernible] to compare that to the $60 million in the previous year due to our reduced ownership interest from October. But if you get your calculator out and you pro rata last year's revenues, we're up about 13% on a like-for-like basis off the back of like-for-like volumes that are 2% lower due to field decline, et cetera. So overall, we certainly experienced some market tailwinds this quarter, and that's reflected in our June quarter cash flows. We've got $6.8 million of positive cash flow from our production operations, and a June cash balance of $21.6 million. In addition, we've got about $21 million of carry funds still available to complete the Palm Valley well, which is currently drilling, and for future development. Looking at our debt quickly. Our $31 million debt and net debt of $10.2 million at June is the lowest level for many years, and we've just recently extended with our 3 years on very similar terms. So we've reduced the principal repayments down to about $1.1 million per quarter. And we've included a provision to increase the facility to provide flexibility and additional development if required such as the additional financial flexibility going forward. Just to round off on the strength of the market. You can see from the pricing chart here that we've seen several months of extraordinarily high prices. And it's only since May that we've had in place to transport gas all the way around to customers in Southeastern Australia. So previously, all of our gas was delivered in the Northern Territory, but with some of our customers [indiscernible] and beyond, if required, which some of them did. These new arrangements mean that the 15% of our gas, which is currently not committed under firm contracts, can be sold to customers in Melbourne, Sydney, Wallumbilla or anywhere in between. So as a result, whereas we may otherwise have sold that gas in the Northern Territory for $5 to $6, $7 a gigajoule, in the June quarter, we averaged $34 a gigajoule for that excess gas at various delivery points in Eastern states. Now that pricing is not going to last forever, and it has probably already peaked for this winter. But you can see why there is an additional incentive for us to do what we can to increase our gas production in the near term to supply into that strong market. So may I hand the mic back to Leon at this point to get his views on where the market's at.

Thanks, Damian. I'd just like to add that our commercial team did a great job pulling together the transportation and access arrangements that allowed us to sell into the spot markets over the past few months. And as you can see from the chart, the timing was incredibly fortunate. We are also negotiating term sales for firm gas supply from 2023. Not surprisingly, the term market isn't as elevated as the spot market prices that we've seen over the past few months, but it is still very strong even compared to what we were looking at a year ago with most forecasts suggesting continued tightness in the gas market. There has been some recent discussion of government intervention in the domestic gas market, which I think will keep a lid on the very high spot prices going forward. But fundamentally, global energy markets are tight, and I think this will continue to flow through to domestic markets and provide a strong incentive for gas suppliers like Central to increase near-term production. Unfortunately, the regulatory and political challenges facing new gas exploration and development in Australia continues to increase, which will ultimately reduce supply and drive volatility in higher domestic gas prices. A sensible energy plan needs to be developed by government, which promotes new supplies of gas and recognizes the gas industry as a transition fuel in support of the development of more robust renewable energy solutions over the long term. Moving on to our drilling program update. Let me start with the recent changes we made to the drilling program. In short, we swapped the deep exploration target at Palm Valley with an appraisal lateral into the Pacoota 2 and Pacoota 3 formations. And we also removed the Dingo exploration well from the program in order to free up funding for projects that will increase near-term production at Mereenie. There were several things driving these program changes. First, we are tracking well over budget for the Palm Valley 12 well due to general cost increases and very difficult drilling conditions. We did anticipate some fractures, but what we ran into at the Palm Valley 12 crestal location was really on another level. And each time we hit a major fracture, we essentially had to stop and fill it with cement. This had a huge impact, both on the schedule and budget. The second consideration is that our drilling program is being funded through a free carry, which is capped at $40 million. This means that we have to essentially adjust our activities to fit within our budgets. And in doing so, we really want to make sure that the investments we do make give us the biggest bang for the buck. Third, we did see gas shows and fracturing in the P2 and P3 formations when we drilled vertically through them, which made it a very attractive target for new reserves at Palm Valley. It's potentially comparable in size to the deeper exploration target that we did give up, but it has lower risk, and it is easier to develop in a success case given it's much shallower. So for those reasons, it's a very compelling alternative to continuing to drill to the deeper targets. And finally, the gas markets, as I've talked about, are providing clear incentive to quickly increase production. That's something we can't easily do at Dingo, but we can through projects like recompletions and new development wells at Mereenie. Personally, I very much wanted to get to the deep exploration targets in this drilling campaign, but the targets are still there. And the revised program does give us the best chance to have the financial capacity to be able to come back to those exploration targets without massive dilution to shareholders. The current status of the Palm Valley 12 well is that we are about 2,070 meters in measured depth. We're still building the bend from vertical to horizontal. And we are just in the early stages of penetrating the lower P2 sandstone target. We have about 900 meters of lateral yet to drill for this appraisal part. So really, it's just the beginning of the appraisal drilling for this particular location. Besides the presence of gas, which we have already seen in the P2 and P3, there are 2 key things that we're looking for over the next couple of weeks as we continue our lateral drilling. The first is we want to intersect as many significant fractures as possible. And the second, we want to see good gas pressure within the formation. As I mentioned before, the P2, P3 target at Palm Valley could be similar in size to the original Palm Valley Deep exploration target, and at half the depth, it would be much easier and quicker to develop. As has always been the case, if we don't have success drilling the P2 and P3 lateral, we will drill a lateral into the shallower P1 formation and have another crack at increasing production, which is really the key objective given current markets. Let's take a look at the Range Gas project. We continued our pilot testing over the quarter. So far, the pilot wells have been on test production for about 120 days. Gas production has ramped up to around 40,000 standard cubic feet per day, indicating the presence of fully saturated coals. But water production rates are lower than anticipated, which suggests longer dewatering and gas ramp-up time frames. We expect the peak gas rate is some time away. So the plan, at this point, is to continue testing the pilot wells through the end of the year. It is worth noting that we have recently entered into a data swap arrangement with a neighboring permit, which should give us some really interesting and useful technical insight on the field. Turning our attention to sub-salt exploration. The sub-salt exploration program has been moving forward. Our joint venture meetings with Santos as operator demonstrate that all 3 sub-salt wells are being progressed, and the program is on track for commencement next year. A rig tender invitation will be issued shortly, which will help obviously firm up the drilling schedule. We recently announced a further extension of the Peak farm-out completion to the end of August. Obviously, we want the transaction closed as soon as possible so we can start to benefit from the free carry. But I am comfortable that the transaction will complete soon, and the recent extension isn't slowing down the drilling program in any way. This map highlights our current key activities. I've already spoken to the committed activities shown in blue. So I'll just say a few words about the activities that we have not yet committed to, which are shown in green. You'll see we've added the recompletions and development wells at Mereenie following the announcement of our revised drilling program. These still need to be approved by the joint venture, but they appear to be compelling investments given current gas markets. Planning has begun. And I think these will be approved by the joint venture for completion over the next year. Seismic and exploration drilling at our Zevon prospect remains subject to funding. We are currently progressing cultural heritage approvals for the seismic program and are actively pursuing farm-out opportunities. Much like our 3 sub-salt prospects in the South, the Zevon prospect is also targeting hydrocarbons as well as helium and hydrogen. This is a potentially very large structure, which complements our sub-salt exploration in the South, gives us a great sub-salt portfolio across the basin. The Mamlambo prospect is another near-term opportunity that remains subject to funding. This is potentially a very large oil prospect that could open up our Western Flank for further oil exploration and appraisal. We are, again, actively pursuing farm-out opportunities to make this exploration well possible. And finally, it's not on the map, but the Amadeus to Moomba Gas Pipeline is still a serious goal for the company. It will, however, require exploration success and significant new reserves to underwrite the project. Under our revised drilling program, these near-term opportunities will revolve around our current P2, P3 appraisal at Palm Valley as well as the sub-salt exploration drilling program next year. In wrapping up, it has been a very busy quarter. We've had high energy prices and high cost pressures driving us to be flexible and reprioritize our drilling program to focus on lower risk, near-term production. We are actively drilling an exciting appraisal target at Palm Valley at the moment. We're also pursuing further growth activities through farm-outs. And our sub-salt exploration program is progressing toward commencement in 2023, which has enormous potential, including a diversification into helium and hydrogen. On that note, I'd like to now open up the webinar to questions.

Thanks, Leon. We've got some questions here already. [Operator Instructions] Okay. So questions in no particular order. But a question here on how much extra gas can be repriced in 2023?

I'll -- we are out marketing currently for firm gas supply from 2023 through 2025, which is where we're seeing the main appetite in the market. I've got Jon Snape, who's our Commercial Manager, who is at the coal face on that. So I might ask him to just comment on what sort of volumes we're out looking to reprice or recontract in that period.

Thanks, Leon, and thank you for the question. Look, it's an interesting question. Obviously, there's a lot of demand in 2023 at the moment and certainly based on the forecast by the ACCC. At the moment, we're out marketing 3 terajoules a day of firm gas in 2023. And we are, I guess, working with a couple of parties on selling that gas. The price is above what we'd normally sell it for. So that's a good outcome for us. I mean, obviously, we've got to conclude those negotiations. And we will also be selling gas on a spot basis now that we have, as Leon mentioned in his presentation, that those sort of 15% of volumes that we don't sell on a firm basis. So I mean our production -- so we're really looking at anywhere up to 5 to 7 TJs a day depending on, I guess, customer nominations at that point in time. We are also looking closely at what's happening with Palm Valley because obviously, as Leon mentioned, the ability to get Pacoota 3 and volumes commercialized fairly quickly and certainly by 2023 is something we're certainly very excited about because we know that there's a lot of demand there, and we are talking to our customers for those volumes in 2023. Well, so really, it comes down to what we get out of the potentially market selling volumes in '24 and '25. So we're engaging with parties on that as well. And that pricing is generally quite a bit higher than what we've historically contracted our gas for. So it's been quite a fruitful exercise going out early and selling that gas. Obviously, we haven't concluded those contracts as yet, but they are well progressed.

Thanks, Jon. Just to add a couple of things. The volumes in 2023, obviously, as our contracts roll off, that creates additional uncontracted capacity to sell into the term market. 2023, as Jon mentioned, a fairly small number for us in the context of our portfolio. That number increases as we go to 2024 and 2025 as more contracts roll off. So certainly, the repricing impact on our portfolio will increase over the next 3 years. And the other one that Jon touched on which is really important is the -- getting production out of our Palm Valley 12 well. We've got a 50% interest in that if it behaves similar to our Palm Valley 13 well. That was producing a gross number at 7 TJs a day, 3.5 to our benefit. So that's the kind of number we also add to these figures that Jon was talking about earlier.

Just to be clear, the numbers I mentioned before were gross numbers for the joint venture.

Okay. Another question here. Around this year is over $30 million gas revenue, approximately how much of this was derived -- was term derived versus spot derived? How much is spot related given the 85% to 15% allocation. So I think just on those -- the new spot sales, if you like, there was $2 million worth of extra revenue in the last 2 months. So it was running at about $1 million a month at those pricing levels, and it has continued through July at that same rate. Obviously, that will come off, we expect, in coming months. But that gives you some idea as to the split from the new spot contracts that we're able to access.

We also did sell some as oil gas over and above those 2 months through the year. So you'd expect that to be at least I want to mention over $1 million.

Yes. Our normalized available contracts are similarly priced to our term contracts. And I think over the course of the year, that percentage sort of swung from 85% to 90%, maybe even as high as 95% fixed earlier in the year. But that's -- as we roll new contracts in that percentage tends to change. The question here on planned maintenance. Are you aware of any planned maintenance on pipelines in the next couple of quarters? And how would that impact our volumes? Jon?

I can -- so if you're talking about external pipelines, we're not aware of any planned maintenance certainly over the next quarter. So we hope to be able to sell as much gas as we can over that period.

Okay. A question here on the Amadeus to Moomba Gas Pipeline. Could we please get an update on the status of the AMGP, especially in accessing the East Coast market? Does the current GTA for spot markets partially negate the need for the AMGP?

Yes. I did mention this in the presentation. And the AMGP is still a priority objective for the company over the long term. The access that we've gotten now to the spot markets, which is fantastic, doesn't necessarily negate the commercial driver we have for direct access into Moomba. Having that pipeline will dramatically decrease the transportation cost. So I would say that we are still incentivized to get that piece of infrastructure developed. As I mentioned, it really comes down to consolidating enough uncontracted reserves to underwrite the project. At this point, that's going to require us to get some success in exploration. And we are looking at things like the P2 and P3 appraisal as well as the sub-salt work that we're going to be commencing next year, plus other drilling and exploration activities that we're working on through farm-outs, et cetera, to try and cobble together enough reserve base to make that happen. And I've mentioned previously that we do have some uncontracted reserves at our existing fields, but we probably need about 200 petajoules or so to really get the AMGP into a serious position to progress.

Thanks, Leon. A question here on cost pressures. Where are the cost pressures coming -- actually coming from? Is it drill casing, supply chain, logistics or people? So I think I can probably answer that one. Look, probably the biggest cost we see at the moment is diesel on our drilling campaign. Obviously, the rig mud pumps can't everything out there is powered by diesel. So it's been a significant jump in cost there, which you may not think is significant, but we've been at it now for 3 or 4 months, so it does mount up. Obviously, the supply chain is the other thing we're seeing now. Obviously, we've got all the casing, et cetera, we need for this campaign. But as we start planning for our next lot of wells, particularly at Mereenie, we are seeing that there are longer lead times for just simple things like valves that might come out of Canada, drill casing out of China or where [indiscernible] it's the lead times as well as starting to be impacted.

I'll also add on that, that certainly, the disruptions we've had from supply chains and COVID, in particular, have made the logistics of getting crews and service providers efficiently at site has been a challenge. So there's been a number of instances where there have been delays and that results in cost for service providers that are on site, ready to go that have had to wait. And it's just -- it's been that inefficiency, which has added quite a bit of cost to the overall program.

Question here, Leon. Is there an identified path to market for any helium discovery that might come from the sub-sold exploration program?