Jadestone Energy plc (JSE) Earnings Call Transcript & Summary

Good morning, ladies and gentlemen, and welcome to the Jadestone Energy Inc. Guidance Update Conference call. [Operator Instructions] This call is being recorded on Friday, February 26, 2021. I would now like to turn the conference over to Paul Blakeley, President and CEO. Please go ahead.

Great. Thank you very much, Colin. Ladies and gentlemen, good morning, and welcome to our guidance call for '21. I'm Paul Blakeley, Jadestone's CEO, and I'm joined on the call today from Singapore by Dan Young, our Chief Financial Officer; and on the line from Calgary by Robin Martin, Investor Relations Manager. I'd like to open this discussion by recalling what an incredibly challenging year we've all been through, not least for our industry. But with a recent and rapid recovery in oil price, which may or may not be sustainable, we believe Jadestone is incredibly well positioned with a strong balance sheet to reintroduce capital activity and to restore growth, both organically and inorganically to the business. First, on Slides 2 and 3 of the presentation, a little bit of housekeeping, where I'd like to offer a quick reminder of our standard disclaimers and advisories and amongst all this narrative, I'll just draw your attention to the cautionary remarks regarding forward-looking statements and non-GAAP measures used in the discussion. Also during this call, I'll be referencing slides which you can find on our corporate website by logging on to www.jadestone-energy.com. Here, you'll see that our 2021 guidance was recently uploaded under the Investor Relations section. Or if you're using the webcast, then the slides should be available via the link on your player screen. And I'll just add that since I'm sure there must be a growing fatigue from endless meetings on various virtual platforms over recent months, our aim today will be to try to keep this discussion brief and move quickly through our presentation to take questions at the end. Thank you. So now let's move on and turn to Slide 4 with an outline of our priorities for sustainability and how we play a part through the energy transition to a lower carbon future. Maximizing recovery from existing developments while minimizing the footprint and environmental impact is our key contribution as well as maximizing local opportunity, jobs and security of energy supply while seeking to operate safely, efficiently and without incident. This year, we're expanding our ESG goals, providing more detail and more tangible targets and Slide 4 highlights just a few examples across the spectrum of environment, social and governance topics, emphasizing a target zero aspiration. That means, among other things, a year with zero instances of noncompliance with environmental regulations, zero recordable incidents and zero violations of the governance and ethic standards that we hold ourselves to. As we mature our approach to sustainability in general, we're bedding in more quantitative targets wherever we can, all of which will form part of the management team's KPIs, impacting directly on performance pay alongside operational and other objectives. Among them, our reductions in greenhouse gases through less flaring and fuel use, improvements in overboard discharges, which are already half the regulatory requirement and increasing alignment with the task force and climate-related disclosures framework. Social and human capital priorities rely on strong HSE performance; workforce development, including fostering new talent, both apprentices and graduates; increasing diversity and on hiring local nationals wherever possible. Our governance and leadership model has been expanding under the QCA Governance Code, which we adopted at the end of last year, consistent with our pivot towards corporate practices more typical of the U.K. company, while we also introduced additional measures, which demonstrate corporate resilience through balance sheet management, debt levels, et cetera. And now Slide 5, which summarizes the key guidance targets for 2021 and which I'll run through quickly before I hand over to Dan to get into a little more detail, particularly on costs. As a backdrop, it's worth remembering that within a month of this time last year, we saw the impacts of a global pandemic reducing benchmark oil prices into the teens or less. And we moved quickly and decisively cutting capital by 80% at a time of enormous uncertainty. Our thesis has always been to protect the balance sheet versus short-term production and preserving investment value until prices recovered. The strategy worked, and we more than doubled our free cash during the course of the year, reducing debt to almost nothing and which now presents us with a great opportunity in 2021. So while we still expect a lot of volatility in the months ahead, it's now time to get back to investment and growth to match the rising price environment. Production will start to recover through the year and it will feel slow because we have to wait for the drill rig, for example, but we plan to deliver more than a 50% increase in volume in the second half versus the first. This is a result of drilling the Montara H6 infill well followed by 2 workovers at Skua-10 and 11 and overlaid by an anticipation that the Maari transaction will close around midyear. Operating costs will rise slightly this year, in part because we inevitably carry over some maintenance activity from last year, impacting around $1 a barrel and in part because of the weakening U.S. dollar as well as a broader catch-up on asset integrity investment, but Dan will pick these up in a moment. The actions we took to find ways to reduce operating costs under Project Clover last year will benefit our operating cost base in the years ahead and around 25% or $8 million per annum of underlying reduction will endure into the future. Finally, our commitment to continue with our program of shareholder distributions in line with our dividend policy remains as a firm conviction, remembering that we believe our business model supports this without any sacrifice to growth, both organic and inorganic and which remains the primary driver to delivering exceptional shareholder returns. Slide 6 provides more detail on our production expectations for the year, with full year guidance of 11,500 to 13,500 barrels a day. This assumes 10,000 to 12,000 barrels a day from Stag and Montara. Production growth comes in the second half of the year with the arrival of the Valaris 107 drilling rig late in the second quarter and the likely sequence of activity which will be the Montara H6 infill well first, followed by the 2 workovers at Skua. H6 should come on stream later in the third quarter, with initial rates expected to be around 3,000 barrels a day, and the schedule for Skua then assumes contributions to production in late September and in October. And while Skua-10 and Skua-11 wells also have the capacity to jointly produce around 3,000 barrels a day due to flow constraints within the subsea system, including the ongoing production from the Swift/Swallow fields, we anticipate a net addition of between 1,000 to 2,000 barrels a day from these wells. Additionally, in the second half, we've modeled a contribution of approximately 1,500 barrels a day from our 69% interest in Maari based on an assumed transfer of operatorship around midyear. Importantly though, the economic effective date for the acquisition remains the first of January 2019, meaning we will ultimately receive all economic benefits from the project back to that date and therefore, throughout the course of 2021. The current operator plans to commence a workover to the MR6 well in late March, April, which is one of the 2 most important wells within the Maari complex. With the completion of the workover in early May, there is scope for additional upside on our production guidance for Maari. This well was averaging over 1,000 barrels a day in the last months prior to its shutdown. All in, this lists second half production by over 50% and will help underpin a strong recovery from 2020 and generate significant free cash to help fund the gas developments in 2022 and beyond. And with that, I'm going to hand the call over to Dan to provide a little more detail on costs. Dan?

Thanks, Paul. Turning to Slide 7, which tells the continuing story of Project Clover which was the company-wide cash flow savings project we initiated in early 2020 and remains as an ongoing initiative today. In 2020, savings from Project Clover amounted to around $33 million compared to plan and after radically cutting our CapEx program by 80%, which collectively ensured we protected our balance sheet during the worst period of the COVID-related oil price crash. Importantly, we continue to see benefits from Project Clover, too, and about 25% of those cash flow savings are structural savings that are reflected in our budget for this year. These savings are reflected within the green and gray bars in the middle chart of Slide 7. And as you can see here, the team continues to work on various initiatives, which, for one reason or another, could not be implemented immediately when the project kicked off on the 10th of March last year. Approximately $11 million of the 2020 savings of $33 million were the result of rephasing activity and we expect that to move into 2021 as a mix of both CapEx and OpEx activity. On the right hand of the side -- on the right-hand side of the slide, you will see that one significant and separate category of Clover savings was a deferral of Australian corporate tax. This was actually corporate tax in respect of calendar 2019. Again, this helped to protect the balance sheet in 2020, but we'll see about $4.5 million of tax expense paid in 2021 from this rephasing and a larger portion in 2022. Project Clover was critical to the success of the company's positive cash flow generation in 2020. To remind everyone, and despite the catastrophic drop in oil prices in much of 2020, we paid off around $43 million of gross debt outstanding and yet the business still generated positive equity free cash flow during the year. This enabled us to continue to execute inorganic growth via the Lemang acquisition, which closed in mid-December, earlier than our guidance of Q1 2020 due to the concerted efforts of the team on the ground in Jakarta. Closing Lemang resulted in an additional $12 million capital payment in the year. And our group net cash position more than doubled from around $40 million of net cash at the beginning of the year to $82 million net cash at December and after the Lemang payment of $12 million. Gross cash was around $100 million at the beginning of the year, and we ended the year with around $90 million of cash, reinforcing the positive equity free cash flow for the underlying business or a net reduction of $10 million after the Lemang consideration of $12 million. Slide 8 shows our OpEx guidance for the year. For comparison, we show here the 2020 OpEx per barrel, which was within 2020 guidance at a bit over $23 a barrel, despite the lower production in the year with the deferral of last year's offshore drilling plans. You'll see a small negative orange wedge at the bottom of the 2020 total and also reflected as a small net add to Stag and Montara and to group 2021 guidance, which reflects the portion of the Project Clover savings in 2020 that constitute OpEx rephasing year-on-year. Overall, we're guiding for a range of $25.5 to $29.5 per barrel OpEx this year. Taking the midpoint of that range, that's about a $4 barrel higher increase year-on-year, which is a combination of 3 factors which are unique to this year. The first is the rephased Clover savings, which I just mentioned, of around $1 a barrel. The second is a stronger Australian dollar and Kiwi dollar, which contributes around $1.50 to $2 a barrel of higher costs this year as a result of the weaker dollar -- U.S. dollar. And the third is an abnormally elevated level of repairs and maintenance this year. Examples of that include a 1 in 5-year recertification of the subsea corrosion protection at Montara and a 1 in 5-year replacement of the under buoy hose, the hose at Stag that connects the pipeline on the seabed to the buoy. Collectively, this elevated level of repairs and maintenance is also just over $1 a barrel of cost. The Clover rephasing and elevated R&M costs are not sustained higher costs and if you expect the Australian dollar to return closer to USD 0.70 in due course, the neither is that. Moreover, as we get into the second half of the year, and our production increases by more than 50%, as we've just foreshadowed, the OpEx per barrel will decline, and we expect Q4 levels to be at around $20 a barrel or even into the high teens. Slide 9 presents CapEx guidance. And like we did in 2019 when we had an abnormally higher level of offshore activity, which included elements accounted for as OpEx, in 2021, we're going to talk about spend again because the Skua workovers constitute a significant portion of costs even if technically, they'll be treated as OpEx. And since our OpEx per barrel excludes workovers, it's important to capture them here rather than overlook them. Again, they are a planned predefined investment into the portfolio, but not CapEx and not typical OpEx either. As can be seen in the pie chart, the costs associated with the H6 infill well in green and with the Skua workovers in blue, represent the large and lion's share of activity this year. We have $8 million to $9 million of CapEx rephasings from Project Clover, which are now back in the program, and relatively minor amounts for pre-sanctioned development work at Nam Du/U Minh in Vietnam and Lemang in Indonesia. With that overview, I'm going to hand the call back to Paul.

Great. Thanks, Dan. So Slide 10, which is a brief update on the 2 gas development projects, which will bring significant midterm growth to the group. Both of these projects continue to be core constituents of our portfolio, providing balanced, significant value and are important catalysts towards our ESG credentials. They are within the Southeast Asia PSC environment versus the royalty tax regimes in Australia and New Zealand. And both are gas developments with fixed price life-of-field contracts, providing strong and predictable cash flows. At Lemang, our 2021 focus will be on negotiating the headline terms of a gas sales arrangement, which will ensure the gas is allocated, and we can then move to sign a fully termed gas sales agreement. The development time line remains fully flexible with the PSC contract expiring out in 2037. But with our balance sheet and access to debt financing for such a project, we will look to advance this towards FID as soon as practically possible. At Nam Du/U Minh, our engagement with Petrovietnam is ongoing, though there was a pause earlier last year as we sought to contain capital commitments. Momentum has now picked up in the last quarter before the Lunar holidays. And we're now working towards an agreement on gas sales profiles, including first gas date. This, again, will lead to signing a gas sales contract followed by approval for the field development. Whilst we're now keen to push this forward, both buyer and seller need certainty and commitment to the project, and this will be the key deliverable for 2021. In the meantime, we're working in the background in preparation to retender the FPSO contract, which is the longest lead time element of the project in order to maintain a 2-year project execution schedule. Slide 11 summarizes the activities across the business in a Gantt chart format, showing near-term activity. But we've not taken a view as yet on the medium-term work plan outlook, particularly with respect to further drilling at Montara, Stag and Maari, but it's something we will do later this year. And finally, Slide 12 highlights some additional corporate initiatives. First, our commitment to expanding the agenda around sustainability, as I've already talked to, and the role we play in ensuring maximum efficiencies delivered from infrastructure already in place, together with a series of targets to force continuous improvement in how we manage our operating business. Since a part of sustainability is corporate resilience, we will also be measuring balance sheet strength, debt ratios and other financial measures, which helped us manage one of the worst periods our industry has had to endure during the course of the last year. Hedging plays a role, too, and we've taken some modest price protection during the first half of 2021 only, principally to provide balance sheet protection and funding certainty as we run-up to our capital program in late 2Q. That also sets us up well to continue pursuing inorganic opportunities, always on the previsor that our screening criteria are met. And as the exit of the majors from the Asia Pacific region continues, we're excited about the next 18 months while there are limited credible counterparties and competition, therefore, remains modest. We've also maintained capacity to comfortably pay the second part of the 2020 dividend program and are looking to continue with our shareholder returns policy, which is to grow dividends in line with cash flow, but not to the extent it would impede our objectives for further growth. And lastly, we're making good progress towards our planned relocation of the corporate residence to the U.K. This is driven by an opportunity to unlock further savings and efficiencies, remove withholding tax risk and will ultimately see us become Jadestone Energy plc at some point in the second quarter. Ladies and gentlemen, it's been an extraordinary 12-month period for us all. And fortunately, Jadestone has taken full advantage to strengthen the balance sheet, embed some additional structural cost reduction, implement the strategy which provides returns to shareholders and get back to significant growth in 2021 and beyond. Thank you for joining our call today, and I'll now hand back to the operator to assist with questions-and-answer session. Thank you. Colin?

[Operator Instructions] Your first question comes from Nathan Piper from Investec.

A couple of short ones from me, hopefully. First of all, on the deal in New Zealand and the Maari transaction, I assume that you may have to extend the -- am I right to assume that you're going to have to extend the long stop date that you'd agreed at the end of April? I guess, secondly, on the gas sales agreements in Asia. I mean could you characterize where the discussions are with both? It feels in Indonesia it's a fairly straightforward discussion given the maturity of the market there. But in Vietnam, could you help characterize how much enthusiasm there is on both sides of that discussion, please? And if you would hope to conclude the gas sales contract this year on Vietnam? And then lastly, on the dividend, will the increase in the dividend be proportionate with your increase in cash flows? Or does it remain relatively discretionary as to how much you will pass-through to shareholders if oil prices remain at current levels?

Great. Thanks, Nathan. We'll take your questions in the order. So New Zealand, both OMV and Jadestone remain committed to the deal. Sometime before Christmas, we felt extending the long stop to the end of April was adequate. Government decision-making has moved very slowly for a variety of reasons, which we've discussed. I think whilst we both remain committed to the deal, the practical and sensible thing will be to further extend the long stop date. It's still a couple of months away, and that's just one of the discussion points. On gas sales, I think to your point, it's probably fair to say it's -- that in Indonesia, the gas contracting market is a little bit easier to navigate. It's -- the gas goes into a very, very large infrastructure system and a pool of different gas supplies and the market is extensive. So the process is reasonably defined and we're going through those steps right now. With respect to Vietnam, as you know, the gas goes to a single source to the Ca Mau industrial complex. And the simple question, since there is no alternative supply available beyond that provided by PM3, at what point in time does the government of Vietnam and the NOC Petrovietnam recognize the ullage that will be created as a result of PM3 declines, which are absolutely clear. So we're just working through the -- what the profile will look like to take up that ullage. And it'll all become clear, I hope, over the course of the next couple of months. Certainly, there is a more -- or how should I describe it. There is a more -- a greater willingness and more intense discussions recently. I think there is perhaps growing recognition about the need for gas supply. Of course, during the Lunar holiday, everything shuts down for a few weeks. We will be picking that up again here in the course of the month of March. And I hope in April, when we provide our next update to the market, we'll have some more tangible news. But the short answer, Nathan, is there are no alternative gas sources. And both the power complex, the fertilizer plant represent really important infrastructure for Southern Vietnam. And finally, on dividend, I'm going to ask Dan if he'll address that.

Thanks, Paul. Yes. And Nathan, we -- as we said, we're going to look to grow the dividend with cash flow or in line with cash flow. We're not going to be mechanistic about that, of course. As we said at the outset when we initiated the dividend policy, the business strategy, the focus of the group remains on a balanced portfolio of producing assets and discovered resource that we can quickly bring to production. That's a business model and a portfolio that should be cash-producing. And as I just described even in 2020, we were equity free cash flow-producing and we will prioritize that cash flow for reinvestment into the portfolio. But after we've done that, we should be in a position to return some cash to shareholders. We said that we would not do that at the expense of growth, in terms of inorganic growth as well, and we've announced 2 acquisitions since we initiated the policy, and we've closed one of those in December last year. So I think the answer is we will look at the end of the year. Bear in mind the balance sheet at that point, where we are with Nam Du and U Minh and Lemang and the inorganic opportunities we see before us, but we certainly have every intention to grow it with underlying cash flow, bearing in mind those other aspects at that time.

Your next question comes from James Carmichael.

Just a couple of quick ones. Just on the tax unwind in '21, like you said, that was about $4.5 million. And maybe a larger portion in 2022. Could you just give us maybe a sense of the overall extent of that deferred tax? And does it all unwind over the next sort of 2 or 3 years? Or should we expect that to be done in '22? And then I guess just revisiting Vietnam, I think the current sort of guidance is early '22 at the -- sorry, late '22 at the earliest for first gas. It feels like that's becoming increasingly challenging. Is that fair? And I think my perception is that it sort of -- it moves in 12-month increments because of monsoon season. And so should we really be thinking about sort of late '23 for first gas there now?

Very good. Thanks, James. I'll let Dan touch on the tax unwind first, and then I'll talk to Vietnam.

Good. James, so yes, the tax rephasing that we negotiated with the ATO, again, it applies to 2019 corporate tax that ordinarily would have been due in the European summer of 2020 and it's around -- there's around USD 4.5 million this year that we'll pay. And it's about Aussie -- it's around AUD 35 million that we'll pay off next year. So yes, the remainder will be paid off next year.

Okay. And with respect to Vietnam, actually, you are right that in effect, because of monsoon, you do need to think about -- if you miss the season, so to speak, you are more or less pushing a project back 12 months. And we -- the last guidance that we provided was really in saying that we're delaying the sanction by at least 12 months and therefore, first gas by 12 months. It is inevitably, as we move into '21, looking to be longer than that. And so the best way I can describe the forward view is at the point of FID, you should really think about these as 2-year projects through to first gas. And so if the purpose of this year is to get to a gas sales agreement and therefore, be able with a tailwind to get to sanction the projects sometime next year, then your thought of late '23 is about right and indeed could even slip into '24. The key objective for us is to get the gas sales agreement signed. We've learned many times that, that now represents the critical milestone and project execution of a project of this nature is relatively routine. So it's all about commercial. And that's the objective in 2021.

Your next question comes from Matt Cooper from Peel Hunt. So I guess we'll skip to the next question, which comes from Chris Wheaton from Stifel.

Two questions, if I may. Firstly, on Maari and the production guidance and the work program for this year. What do you see are the risks, both on downside and upside, for Maari this year, given you've said 3,000 per day net to you, which is about 4,300, 4,400 ba/d. Production was a bit higher than that last year. So I'm interested in sort of the risk factors you see around that production. And then secondly, a question on M&A. You from several times, including right at the beginning of the call, Paul, talked about inorganic growth in the portfolio. Given where the majors are, there's a lot of assets coming on to the market, but a lot of them are a bit bigger than you would think Jadestone would be potentially interested in. Are there possibilities for partnering with bigger companies to increase the potential acquisition side of the business that all the assets you could go after?