Jadestone Energy plc (JSE) Earnings Call Transcript & Summary

Good morning, ladies and gentlemen, and welcome to the Jadestone Energy Management Briefing Conference Call. [Operator Instructions] This call is being recorded on Monday, June 29, 2020. And I would now like to turn the conference over to Paul Blakeley, President and CEO. Please go ahead.

Great. Thank you very much, Joanna. Ladies and gentlemen, good day to you all, and thank you for joining this Jadestone Energy Management Briefing. During which, we'll discuss this morning's announcement of the signing of the sale and purchase agreement for Jadestone to acquire a 90% operating interest in the Lemang production sharing contract onshore Sumatra, Indonesia, which contains the fully appraised Akatara gas field. I'm Paul Blakeley, Jadestone's CEO, and I'm joined on this call from Singapore by Dan Young, Director and Chief Financial Officer; Michael Horn, Executive Vice President of Corporate and Business Development; and by Robin Martin, Investor Relations Manager, who is with us by phone from Calgary. In this call, I'll be referencing slides in a presentation, which you can find on our corporate website by logging on to www.jadestone-energy.com where it was recently loaded under the Investor Relations section, or if you're using the webcast, then the slides should be available via the link on your screen now. I will start with some discussion from Dan and I on the contents of the presentation, which will be a listen-in-only section. And after that, with the help of the operator, we'll take any questions that you might have. But as usual, we include our standard disclaimers and advisories, which are provided on Slides 2 and 3 at the front of the presentation. And I'll draw your attention to the cautionary remarks regarding forward-looking statements and non-GAAP measures that are used in this discussion. Thanks. Okay. Now moving to Slide 4 where we summarize the highly accretive acquisition metrics associated with this asset, adding ready-to-develop resource at just under $0.70 per BOE in a very low-cost onshore environment that we know well. To put some context around it, this is an asset that we had identified over a year ago as being of interest to us, but the price expectation of the seller at the time did not make it attractive. In the interim, the world has changed. And though this doesn't affect the value proposition of a fixed price gas project, the seller, in the meantime, who has spent over $100 million on a deeper oil play, which has not worked as expected and which has been recently shut in, has now agreed to sell, which is at our price point and where a commitment to an immediate and certain cash sale was most important to them. Like all our acquisitions, this is an asset that we expect to leverage off our core strengths with a deep knowledge and experience of operating in Sumatra. Noting on the map, just to the southeast of Lemang, you might see the Jambi license, which picks up the nearby location of Jambi Merang. This is a very similar gas project executed by the Jadestone team during their time at Talisman. There are also benefits from key relationships in the region with nearby operators and infrastructure owners, which we anticipate may deliver further upside value, which we've not taken any credit for today. The acquisition has been structured with a number of contingent payments, the first one and perhaps the most important being $5 million at first gas and which can be funded from early cash flows. Further potential payments will rely on incremental value being added beyond the base case such as accelerated timing, reduced CapEx and exploration success, but which would all be accretive to the assumptions that we present today. As we continue to expand the Jadestone business, the addition of Lemang represents a strategic element, which is increasingly important as we search for value for shareholders. Diversifying the portfolio to include more gas; to add another PSC structure, which has no decommissioning liability overhang; and also to add fixed commodity pricing in a very volatile world are all good things for the business. Dan will provide some more detail on this later. Equally important, we acquired this resource with complete flexibility as to the timing for the development CapEx. We will develop Lemang with cash on hand, future cash flows and appropriate incremental debt and absolutely without equity, making this highly accretive on a per share basis. It will be developed at a time which fits in with other capital options optimized for maximum portfolio benefit and only when we can afford it. At half the CapEx of the Vietnam project, it also increases optionality for us as we seek to management investment growth to match cash flows from the business with what we expect to be a recovering oil price through 2021. Finally, on this slide, it's also worth highlighting the $126 million of prior cost pools that we inherit with the acquisition. This will drive significant value upside and incremental profit share with the first 2 years of production and revenue. Slide 5 summarizes the nature of the resource base at the Akatara field, acquiring over $17 million BOEs of very low risk, ready-to-develop resource. With 11 well penetrations in the gas-bearing sands, thanks to the previous development of the deeper oil play and an excellent quality 3D seismic. We have very high confidence in the reservoir quality, the sand distribution and gas in-place volumes as well as composition. This is validated by our external independent reserves evaluator, ERCE, and by other recent independent views from RPS and LEAP. Capital risks are constrained with a very high-quality FEED study already completed with access to existing well pads with roadway and pipeline route already prepared, with the ability to reuse some of the existing wells and the nearby pipeline egress with capacity only 17 kilometers away. All of this helps deliver a low-cost development at under $5.50 per BOE, which helps underpin robust returns. Sumatra is energy short and gas sales negotiations are already well advanced, providing us a clear understanding of price range, market sales profile. Dan, I think, will spend some time describing the Indonesian gas market dynamics in a moment. But to be clear on one point, we will have a signed and fully termed gas agreement in place before the project moves to final investment decision with first gas planned to be within 24 months of the FID date. There is further upside opportunity, which we have not quantified at this time from further capital efficiencies and potential shared facility use with adjacent infrastructure owners; also from some identified exploration opportunity, which will be refined through additional seismic; and one exploration well commitment, which will be drilled post first gas for maximum cost recovery efficiency; and from other synergy benefits, which may result from expanding the business further in Indonesia. Moving to Slide 6. I'd like to offer some thoughts on how Lemang fits with our sustainability model, which centers around energy efficiency, maximum reuse of existing infrastructure and maximum recovery of already-discovered resource. As always, we consider our framework of environmental, social and human capital, governance and leadership as central in the decisions we make to add value responsibly, reflecting on our impact and how it can be managed in the most beneficial ways, both socially and environmentally. I've already touched on the idea of minimizing new infrastructure, while extracting maximum resource in a region which is energy poor. This minimizes the carbon footprint and also the physical intrusion in the landscape with all above-ground access ways and sites already constructed and in use. We're pleased to reengage with local communities in this part of Sumatra where we've previously built strong relationships. The asset is very close to the Jambi Merang PSC, which many of us were involved with in prior experience, for example. And our approach then, as it will be now, will ensure we support local employment, both directly and indirectly, supporting local suppliers as well as the more lasting effect of training and development of the local workforce who will undoubtedly form part of the operating team. We're also pleased to have an opportunity to demonstrate once again our values at work and our leadership through asset operations in Indonesia. We're hopeful that through our corporate approach, we'll provide the highest standards of transparency and open dialogue for the benefit of local communities and governance at all levels. Slide 7. This provides a technical overview of the Akatara field. As discussed earlier in the call, the field was initially developed as an oil-producing asset, targeting reservoirs in the lower Talang Akar formation, which is of much poorer quality, a series of interbedded sands, which actually never met the previous operator's expectations. As a result, there's a large amount of unrecovered cost pools, which we've touched on, and a large amount of reservoir and well data from previous drilling, which we can take full advantage of. Now unlike the lower Talang Akar, the upper zones where the sand -- where the gas is contained are typically Darcy sands with exceptional porosity of around 18% and with well test data signaling great performance. We expect wells with 3.5-inch completion to produce at over 20 million standard cubic feet per day each, giving excellent redundancy in well deliverability. Around 80% of the gas is in the B1 to B3 sands in the upper TAF and has been determined on a gas down to basis only as no gas water contact has yet been established, thereby, providing further potential upside. As a result of all this, resource confidence is very high. And now Slide 8, which gives a bit more detail on the development scenario for the Akatara field in Lemang. While looking to optimize the development with as much reuse as possible, we were able to retain 2 of the existing wells and with very low-cost workovers turned them to gas producers in the upper TAF. Flow lines will be converted to gas, and the 2 new wells will also be drilled from one of the existing well pads. The reason for needing new wells is that the gas accumulation covers a broader area than the oil closure, and so the new wells are outside the area of the existing oilfield. A new modular gas processing facility with a capacity of 25 million cubic feet a day will be built in Indonesia and be transported by river and road to site. The design is to a global standard and sits on skids to be located and piped together on site. In addition to separating condensate as part of the process, ethane and butane will also be removed and sold locally, probably through Pertamina and largely used for domestic cooking purposes. We're assuming pricing linked to the Saudi CP benchmark. Gas will be sold to the national gas distributor, PGN, and gas sales negotiations are well progressed already. We're targeting a price in the range of $5 to $6 per million BTUs, and the gas will go into the main TGI pipeline just 17 kilometers away, which runs from Grissik to Batam. Condensate resources of 2.2 million barrels will be sold to Pertamina at an assumed price of Brent minus $5 per barrel and taken to the Plaju refinery. We minimize trucking by using a much closer tie-in point at Tempino but are also investigating alternatives and even more cost-effective facility-sharing arrangements locally. And with all of that, I'm now going to hand over the call to Dan to take us through a few more details, starting with Slide 9. Dan?

Thanks, Paul, and good morning to everybody. Slide 9 provides an overview of the Indonesian domestic gas market and some details on Sumatra specifically. At a high level, Indonesia is a country with growing gas demand in the order of 4% per year, forecast over the next 10 years. At the same time, the country is seeing reduced supply caused by a decline in domestic production, and therefore, the gap is being filled out of necessity by LNG, and that gap is growing. Sumatra itself has gas demand of around 700 MMscf per day. And you can see the Akatara field, shown on the map to the right of the slide, strategically positioned between 2 major gas transportation pipelines, the Grissik-Batam line that Paul mentioned, which carries 465 MMscf per day and the Duri-Grissik line, which carries 430 MMscf. So in Lemang, this will be a 17 million -- a 17-kilometer tie-in to the Grissik-Batam line, a major pipeline which has available ullage. So Lemang is producing gas in an area we know very well, which has extensive gas infrastructure, ample ullage and deep gas demand. Another attractive attribute for us, particularly in the current environment, is the fact that gas in Indonesia is sold on a fixed price basis with life-of-field sales contracts and which typically include high proportion take-or-pay provisions, circa 80% to 90%. That makes Sumatran gas production a natural hedge against volatile oil prices and provides important balance to the portfolio. The LPG market, too, is attractive with strong demand driven by the residential sector, primarily for use in cooking. This, too, is facing a growing deficit, which is being met by imports. And like gas, we are anticipating a life-of-field contract to LPG sales with pricing linked to Saudi CP. Turning to Slide 10. This illustrates the Lemang production profile as agreed with our reserves auditors, ERCE. The gas tranche is shown in red with a strong 6-year production plateau of 18.8 MMscf per day. The condensate is the top tranche in green, around 850 barrels per day on average over the plateau period. And in between is the LPG tranche, which also has the strong -- the same strong plateau profile of the gas, just under 2,000 barrels of oil equivalent per day. In aggregate, that generates a plateau period that will commence at around 6,100 barrels a day for the first year and average approximately 5,300 BOEs a day over the 6-year period, net to Jadestone's 90% participating interest. In keeping with the flexible nature of development timing, we've labeled the x-axis year 1, year 2 and so on and will make development timing clearer in due course and in conjunction with capacity of the balance sheet to fund the development. I will reiterate here, as Paul has mentioned, that we expect from FID to first gas production a period of approximately 24 months. Slide 11 underscores the various ways Lemang adds balance and diversification to the Jadestone portfolio. Firstly, the numbers shown here are 2P reserves plus 2C resources, but our 2C resource numbers do not include Tho Chu and SC56, which represent midterm resource commercialization for the group, rather than Nam Du, U Minh and Lemang, which are included and which constitute short-term candidates for resource commercialization. In the first row, we show our 2P reserves and 2C resources pro forma for the Maari acquisition. In the second row, we add Lemang to the analysis. If I talk about columns now, the first 2 pie charts in the left column shows that our combined 2P reserves and 2C resource will grow to over 100 million BOEs with Lemang comprising 17% of the total. And the reserves and resource concentration in Montara and Nam Du/U Minh falling well below 1/3 of the group total. The middle column demonstrates that the oil proportion of our portfolio will be reduced to 53%, while the pure gas component will increase to 37%. And since all of our gas, comprised of our Indonesia and Vietnam assets, will be contracted on long-term fixed price gas sales agreements, this means that around 37% of our hydrocarbon production will be fixed price, providing increased portfolio balance and downside protection in a period of crude oil price volatility. And the right column illustrates that our exposure to PSC terms will grow from 36% to 47%, again, providing further balance to the portfolio and greater downside protection through the cost recovery mechanisms built into the PSC. Slide 12 provides an illustration of a conventional Indonesian PSC terms. Lemang, for the avoidance of doubt, is a conventional Indonesian PSC, not a gross-split PSC. The source for this slide is data from Wood Mackenzie. Some explanatory text for you on the left-hand side. And on the right-hand side, we illustrate how the split of natural gas takes out between the contractor and the host nation. The chart on the top right-hand side is during the early stages where cost recovery is significant. And again, as Paul has mentioned, we're inheriting here $126 million of cost pools. The chart on the bottom right-hand side is during normal cost operations. That is where past accumulated historic costs have already been recovered. The first key element is first tranche petroleum at 10% due to the host nation. Cost recovery is uncapped up to 100% of revenue net of the first tranche petroleum. Profit share on the gas is 71% to the contractor, while on the oil, it is 36%. Total income tax, including branch tax and corporate tax, is 44%. You'll also note, there is no domestic market obligation or domestic market price discount for gas or for LPG. For condensate where, again, our profit share is 36%, the first 25% of that 36% is subject to a 25% price discount under the DMO. But that is also tax deductible, so it comprises really a 14% after-tax discount on the first 25% of the 36% share of profit condensate. You can see that in the chart on the right-hand side, during the early years of production, we will have an effective take of 90%, which certainly helps to enhance returns and with the inherited cost pools of $126 million. I'd also point out that under an Indonesian PSC, decommissioning costs are paid by way of the contractor, setting aside funds on an annual basis contributed to an escrow amount -- account on a unit of production basis. Those payments are fully cost recoverable, and ultimately, this mechanism means that when the license expires in 2037, the abandonment liability will have been paid in full with no further obligations from the contractor and in a tax-efficient way. On Slide 13, we present the key steps toward completing the transaction. We signed the SPA on Saturday, and we expect the transaction to close in Q1 2021. As you see on the slide here, the economic effective date is the same date as the closing date, at which time we pay the $12 million. Closing may be earlier than Q1 2021, but we want to allow sufficient contingency as we work with SKKMIGAS and with MIGAS to get the requisite approvals. After the government approval is -- the government approval, I should say, is really the key steps to achieve ahead of closing. It's a straightforward process and a path well drawn by Jadestone and our management, including our Local Country Manager, David Lamb, and his team who have maintained a strong relationship with the regulator and the ministry. It is also something well understood by the seller who have previously twice increased their interest in the asset. During the interim period, we expect to second some of the Jadestone Indonesia leaders into the seller's organization to ensure we have early influence in the asset. Their priorities will be to progress the development and finalize marketing arrangements. Paul also mentioned contingent payments. The main one I'd note is a payment of $5 million, which is due on first gas production. In addition, there are several additional contingent payments, which total up to a maximum of $26.7 million, but are tied, as Paul has covered, to certain upside scenarios on development timing, costs, prices and eventual exploration outcomes from the one remaining commitment well, which will be drilled at some point between now and 2037. With that, I'm going to hand the call back to Paul.

Very good. Thanks, Dan. And so to summarize, and I'm on Slide 14 now, I'll just say, once again, we're delighted to announce the Lemang acquisition, which is such a natural fit for our strategy, accretive on all metrics and for which we add significant value to our core portfolio, bringing diversity, flexibility and further upside value potential. As we've said before, our screening criteria is very strict, and we discard 90% of what we look at. But this is an opportunity we've high-graded for some time and gained entry only when the value proposition was right for us. By acquiring this asset, we're also reestablishing a foothold in a key hydrocarbon province in Southeast Asia, which offers exactly the sort of characteristics we see across the region with maturing fields and NOC, which is looking for both financial and technical support from international companies where incumbent operators are stepping away and where local markets are energy short. Therefore, this becomes a platform we can use to grow from. We have the leadership team on the ground, and we're very much looking forward to reestablishing our operating presence in country, working to reengage with Pertamina on Ogan Komering and other opportunities and establishing a significant business in Indonesia. I think it's particularly important to remember the low-risk attributes of the asset that we talked about earlier and the complete flexibility in timing that we deploy -- about when we deploy the development capital. As we continue to watch our balance sheet and preserve capacity, we're delighted to be able to add this resource at minimum upfront cost, which does not impact at all on our planned dividend payments nor the closing of the Maari acquisition, not even our ability to access further opportunistic acquisitions in the months and years ahead. And so ladies and gentlemen, it's a very exciting time for us, and we hope you can appreciate the value story ahead. Thank you. And with that, let's turn the call back to the operator, and we'll try to take any questions that you may have. Thank you.

[Operator Instructions] Your first question comes from David Round from BMO Capital Markets.

Just a couple for me. On M&A more generally, can you just run through exactly what you're seeing at the moment? Because I think last time we had a call, you noted that it had been a bit of a quieter period. So what are you seeing today? Has that changed? And what specific factors do you expect to drive future M&A? And secondly, you mentioned the previous old development reached economic cutoff. Obviously, the gas project looks pretty attractive on its own. But I was just wondering, once you have everything in place and assuming a portion of fixed costs, is there any thought to targeting some of the remaining deeper oil as upside?

Very good. Thanks a lot, David. So we'll take your questions in order. And to start with M&A, and I might ask Michael just to -- since he is with us on the call, just to give his thoughts. But by way of preface, just to say, yes, I think we did see over the latter part of last year and early into this year, a pretty quiet M&A market. I think certainly, as oil price collapsed in the first quarter, some M&A activity that we had anticipated was pushed back by the sellers in light of the circumstances. And that really is, I think, we're starting to see come forward now. And as we had always hoped for, there is some evidence that with some distress in the market, we might see other assets that were perhaps not planned coming forward. But I think, overall, I'd say the second half of the year probably looks busier than the first. Michael, would you -- how would you describe this?

Yes. Thanks, Paul. Indeed, we are now certainly aware of and participating in a number of opportunities and the evaluation of them. We've seen 4 processes commence in Malaysia that weren't present at the beginning of the year, a similar number emerging in Vietnam, 2 new large processes in Australia. So across the patch, certainly, a significant uptick in the more formal processes. And if that's indicative of where the market is going, then clearly, we're getting a very, very, very clear view. And we will look to see across all of those opportunities where best -- what we might pursue and what's best for the firm.

Great. Thanks, Michael. And bearing in mind that when we talk about these numbers, of course, as we've always said, we'll look at 10 to really be seriously engaged in one. And so it is quite encouraging with what we see right now. On to your second question on deeper oil. The lower Talang Akar formation is of much poorer quality and completely separate from the upper sands. There's no -- pressure communication completely sealed one from the other. And so we are only engaged on the gas development. Over time, might we see further opportunity within the lower oil sands, they are poor quality, David, and I'd be surprised, but never say never.

The next question comes from Jamie Carmichael from Berenberg.

Just a couple of quick ones. Just wondering, do you have a sort of target or preferred debt/equity split in mind for the development funding? I think you've been pretty clear where you stand on that for Nam Du/U Minh, for instance. And then just also on the PSC terms, can you confirm that the profit share splits that you've outlined in there are fixed rather than variable?

Great. I'm glad you've asked some questions that I can hand over to Dan to talk about. Thanks, Jamie. Dan?

So we will have a life-of-field gas contract with PGN, which, of course, is now a part of Pertamina as part of the Indonesian government essentially. It will have a high fixed take-or-pay quantity, fixed price over the life of the field. So it will be something that we will part fund. I'd anticipate actually something broadly similar with Nam Du/U Minh because it has many of those same characteristics. So something in the region of 60% to 2/3 senior bank debt and 1/3 from cash in -- on the balance sheet is what I'd anticipate. On the PSC terms, I'll say that the source of the information is Wood Mac, and it's an Indonesian PSC -- conventional PSC terms. And yes, it's reflecting fixed terms, fixed profit -- or fixed share of profit gas and profit oil.

Okay. Understood. And maybe just a quick follow-up. Appreciate it's early, but obviously, the biggest chunk of the contingent payments is based on exploration success. Have you got any early identified targets for that? Or is that much further down the line?

We do see from the seismic what, at this stage, we'll call a couple of bumps, which are encouraging, James. But indeed, we'd want to do some more detailed work, which we haven't done yet and, indeed, feel no pressure to do so right now. And of course, as I think Dan said earlier, we can get to that in a very tax-efficient way as well. And with one long-term exploration commitment well still outstanding, I mean, this is a relatively low-cost onshore well. Nonetheless, we will do that later once we've had chance to look in more detail. But there are -- yes, there are some encouraging signs.

The next question comes from Matt Cooper from Peel Hunt.

Would you be able to talk through the results upside here? In particular, interested on the potential size of upside there could be, if you use an offset well gradient for the water to define the gas water contact rather than the gas down to the -- you're currently using.

Thanks, Matt. So as I touched on earlier, because we don't see in any of the wells a gas water contact, it does mean, I think, essentially that it leaves us with some amount of upside, which we're not taking credit for currently. Our mapped volumes are purely on a gas down to basis. So I think that's encouraging. Whilst we don't -- we haven't done any more detailed work to assess how much upside there may be, I think on a 3C basis, we might add another 40% or so to the gas resource base if we were to think a little bit more broadly about potential gas water contact. But I'd certainly like to do more work before we were more definitive. And certainly, at the point of development sanction, I think we could speak far more clearly about ranges at that time. But I think on the whole, there's certainly feels that there's more upside than downside.

The next question comes from Chris Wheaton from Stifel.

Paul, I'm afraid this is a question for you rather than Dan. Could you talk about what you see as the conditions you'd need to go to FID? You've got a lot of flexibility here. You don't -- as you've said, the only commitment is 1 exploration well before you're expiring some license in 2037. I'm interested in what are the trigger points you'd want to see before going to FID after completion.

Thanks, Chris. I think -- I mean, it's relatively straightforward. Certainly, we want an absolutely fully termed and signed gas sales agreement. I think that's absolutely critical to us and, of course, a clear sight of the funding. All the engineering work that's needed is done, I think, to sufficient high quality. And as we've touched on, with reuse and so on, all that -- all of the capital perspective of this project is relatively well defined. So essentially, it's the marketing that needs to be landed with the buyer fully termed and signed and the funding in place. And so it could be and we have shown the principle of a seamless flow-through to completion and FID, but equally, we may choose to pause. And there is a broader context for us, which is we now have a number of capital growth options. And we want to see at the end of this year, as we move into 2021, the price outlook, the cash flow outlook and what might be our prioritization of the options ahead, okay?

[Operator Instructions] There are no further questions at this time. You may proceed.

Thanks, Joanna. Well, ladies and gentlemen, just remains to thank you for your interest in Jadestone and participating in this call, appreciate it. As I've already said, we are excited by the progress within the business to date and, of course, particularly to be able to announce the next growth step with Lemang acquisition. We'll be working very closely and cooperatively with the seller through to closing, and Dan touched on how we'll second our folk into the team to facilitate that and anticipate it sometime in 1Q 2021. And of course, we look forward to reengaging with Pertamina and other key stakeholders in Indonesia. And we'll look forward to providing updates in due course. And just to let you know that, as we transition to more typical U.K. reporting, we will be providing an operational update in a few weeks' time, ahead of our half year reporting, which is likely sometime perhaps in early September. But in the meantime, thank you, all, very much, indeed.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines.