Jadestone Energy plc (JSE) Earnings Call Transcript & Summary

Good morning, ladies and gentlemen, and welcome to the Jadestone Energy Full Year 2021 Results Conference Call. [Operator Instructions] This call is being recorded on Monday, June 6, 2022. I would now like to turn the conference call over to Mr. Paul Blakeley. Please go ahead.

Very good. Thank you, Pam. And ladies and gentlemen, good morning or good afternoon, and welcome to Jadestone Energy's Full Year '21 Results Conference Call. I'm Paul Blakeley, Jadestone's CEO, and I'm joined in London today by our Group Finance Manager, Derren Parsons; and by Phil Corbett, Investor Relations Manager. We also have on the phone from Singapore, our Group Commercial Manager, Ha Nguyen; and our ESG Manager, Paulina Poray. Let me just open by saying it's great to be back in London again after more than 2 years of pandemic-related travel curbs. And I really look forward to reconnecting with many of our investors and analysts during the course of this week. In this call, I'll take you through a presentation, which was recently uploaded on our website at www.jadestone-energy.com. It's in the Investor Relations section, or you can view it via the link on the webcast. And after that, let's open the call for Q&A. I might also point out a refreshment of the Jadestone branding on the website and other presentation material, which I hope you'll like. As many of you are aware, we're reporting our full year 2021 results later than normal, which is due to the process of obtaining relief from Canadian reporting requirements and the related relief from Canadian accounting board registration for our auditor. This is a one-off departure, and we'll get back to our normal reporting schedule, including first half 2022 results in September of this year and full year audited 2022 results in April next year. Now Slide 2, which outlines our standard disclaimers and, in particular, the cautionary remarks regarding forward-looking statements and non-IFRS measures that are used in this presentation. Okay. With that, let's get started with Slide 3, which lists the highlights of 2021 and some important new developments in the business that we've announced this morning. 2021 was characterized by a return to growth after the cost cutting and activity deferrals of 2020 in what had been an extraordinarily tough year. We responded quickly to the improving macro environment by sanctioning and executing our largest-ever offshore program at Montara. These activities were concluded late in the year, and so while they contributed to a 10% year-on-year production increase, along with the Peninsular Malaysia acquisition, the full benefit was only really seen at year-end with the high exit rate and in guidance for this year, up a further 37% at the midpoint guidance. Financial performance was similarly very positive, bolstered by a strong recovery in both oil's prices and in premiums. Our average realized oil price rose 66% year-on-year. Under no hedging impact, revenues increased 56% to a group record. Adjusted EBITDAX was up 61%. Cash balances increased 44%. And with no debt, our balance sheet was in very strong shape by year-end. During 2021, we established an important footprint in Malaysia through the acquisition of 12.5 million BOEs of 2P reserves across the collection of offshore assets from SapuraOMV. The purchase price of $20 million, but after adjustments at closing, we received a cash inflow of $9 million, making for exceptional deal metrics. Though relatively modest, these assets have great upside, and production decline has already been arrested while we plan drilling our first infill wells there next year in 2023. We also made significant progress on major commercial milestones for the Akatara gas project in Indonesia, with momentum carrying over into 2022, and I'm now delighted to report that we have taken final investment decision on the project, which will be Jadestone's first organic development, though we are reusing some existing wells, surface facilities and infrastructure. The speed and strength in oil price recovery has been quite dramatic so far this year, a function of the distressing events in Ukraine but also fundamentally a result of several years of underinvestment in upstream production capacity. Being unhedged, our financial position continues to benefit from rising oil prices and premiums. And at the end of May, cash balances, including proceeds of liftings in May, which will be received in June, stood at approximately $180 million. With oil prices consolidating above $100 a barrel, we forecast cash balances will continue to increase, though this will be partially offset by a capital program heavily weighted to the second half of the year. Nonetheless, after careful consideration and with regard to several factors, including preserving balance sheet strength for M&A and funding of organic growth, we believe that Jadestone can significantly increase returns to shareholders over the next 12 months, and we intend to deploy up to $100 million in the form of ordinary dividends, share buybacks and/or tender offers. This does not imply a change in strategy. We firmly remain a growth business with a raft of new investment options ahead of us. But with so much financial flexibility, including access to debt for our projects and for acquisitions, as well as in recognition of our growing cash position, we believe we are striking the right balance. And so with those opening remarks, I'm now going to hand over to Phil to walk you through our ESG performance and recent net-zero commitment.

Thank you, Paul, and good morning or afternoon to everyone. On Slide 4, I'll take you through the highlights of our recent ESG performance. Last week, we made a key announcement delivering on a commitment to introduce a net-zero target for our business by the end of the first half of this year. In doing so, we've pledged to achieve net-zero Scope 1 and 2 greenhouse gas emissions from our operated assets by 2040, and I'll describe that in more detail on the next slide. In our 2021 sustainability report, which was published this morning, we significantly increased the extent of our sustainability reporting and disclosures, in particular, increasing our alignment with the TCFD recommendations. As a result, we carried out our inaugural climate scenario analysis, which sets out the impact on our cash flow generation in several climate warming and carbon tax scenarios, including the IEA's net-zero emission scenario, while inevitably, there is some impact on our cash flow generating capacity, particularly in the IEA's net-zero scenario, it is not material in the near term. So consequently does not undermine our ability to continue to execute our strategy. Further highlights in 2021 were an increased oversight of sustainability-related matters by the Board, including new recruitment of appropriate skills at Board level, a significant increase in funding for community programs, zero lost time injuries and added scrutiny of safety performance during a challenging year of COVID impact and a reduction in the aggregate oil in water discharges from our Australian assets. Now unfortunately, our absolute greenhouse gas emissions and our emissions intensity increased in 2021 compared to 2020 levels despite a target of a 5% reduction. This was driven by an increase in flaring at Montara due to reliability issues with the field gas reinjection system in the first half and the impact of drilling and workover campaign in the second half of the year. Consequently, our 2021 target was not achieved. And whilst our Australian assets did remain within the flaring consents from the regulator, we've undertaken a detailed analysis of the reinjection compressor downtime to identify potential actions to mitigate the impact of similar events in the future. Now if you could turn to Slide 5, which sets out the detail of our net-zero ambition and climate strategy in more detail. Having stated our commitment to achieve net-zero greenhouse gas emissions from our operated assets by 2040, our retention will now switch to the detailed work needed at the asset level to identify the opportunities and costs associated with emissions reduction measures. That work will be the basis for a net-zero road map, which we will aim to publish in 2023 and which will set out interim targets for greenhouse gas reductions from our assets and the estimates of the costs associated with those targets. Our strategy of acquiring assets in the middle of their producing lives means that our greenhouse gas emissions intensity may be higher than our peers. However, we will aim to drive down emissions through both improved operating practices as well as with carefully targeted investment. We've also set out in a climate strategy statement, our corporate strategy is positioned over the longer term in the context of the energy transition. For example, Jadestone has never been an explorer because the company's strategy and skill set is in identifying upstream producing assets where it can deliver great returns through performance optimization and investment. This complements a key finding of the IEA's Net Zero by 2050 report, which promotes the idea that investment in existing oil and gas fields is necessary to avoid an energy crisis but without new exploration or large new greenfield developments. The IEA projects that this can satisfy declining global hydrocarbon demand in a net-zero scenario. With majors and larger independents exiting producing assets in favor of energy transition assets, we believe we're well placed to grow, deploying our skills to maximize the recovery of upstream producing assets whilst minimizing their greenhouse gas footprint. And with that, now let me hand over to Derren to take you through the financial performance summary for 2021.

Thank you, Phil. And turning to Slide 6. Firstly, the achievement of our 2021 guidance. As Paul previously mentioned, production increased 10% to 12,545 BOEs a day for the year. And this was achieved on the back of a successful Montara activity campaign and the Peninsular Malaysia acquisition. In the accompanying chart, you can see the increased production during the second half of the year. The blue chart bar on the far right represents the midrange guidance for the year. Major spending was $103 million, with a combination of capital expenditure of $56 million and Skua workovers of $47 million. Together with OpEx per barrel of $26.22, both were within the guidance range. The growth of Jadestone highlights during the year that the completion of the Montara activity campaign, signing and close of the Peninsular Malaysia acquisition and the acquisition of the remaining 10% of the Lemang PSC, which is expected to close later this year. Finally, on this slide, Paul has already covered the cash balances at the end of the year. And we remain debt-free and [Audio Gap] after the final repayment of our reserve base loan in the first quarter of 2021. Turning to Slide 7. Revenues were driven by an increase in production and higher realized prices, of which I'll go into more detail shortly. Production costs increased year-on-year due to the Skua workover costs, which were once in a field life type of activity and very unlikely to be repeated. The workovers were completed in late Q4 of '21, which with the impact that '21 incurred the expense for '22 and beyond incurs the benefits of the additional production. Production costs also include the Peninsular Malaysia acquisition since August, and maintenance costs doubled year-on-year, reflecting the deferral of some noncritical maintenance associated with Project Clover. We anticipate that this will flatten out going forward. Staff costs and other expenses were in line with expectations, delivering reported EBITDAX of $90.3 million, which is 126% increase year-on-year. To get a better understanding of the underlying financial performance, therefore, nonrecurring -- several nonreocurring transactions have been reversed to generate an adjusted EBITDAX of $157.9 million compared to $62.6 million in 2020. Now turning to Slide 8. It sets out the cash bridge for 2021. With the opening cash position of $89 million and our closing cash position of $118 million, revenue was $340 million, of which Montara was the most significantly contributing. Cash operating costs were $153 million, excluding nonrecurring repairs and maintenance of $6 million and the Skua workovers of $47 million, which we classify as major spending alongside the capital expenditure that fuel the Montara infill well. Staff costs were in line with expectations of $24 million, and G&A includes a $4.6 million nonrecurring loss on hedges that we undertook in H1 of '21. Cash tax paid includes both Australia and Malaysia. It was less cash, so the cash tax paid increased both Australia and Malaysia. There was less cash tax paid in Australia during the year due to the 100% deductibility of the H6 well and corporation tax associated with investment allowances in response to COVID and the PRRT refund at Stag. Major spending includes CapEx spend of $56 million on the H6 well and some smaller spend across the rest of the portfolio. In addition, it includes the Skua workover cost of $47 million, impacted by rig performance and downhole equipment failure, generating a total spend of $103 million. Finance and Leasing includes the $7 million repayment of the reserve-based loan in the first quarter of '21. And after an increase in working capital of $19 million, the year-end cash position of the underlying business was $126 million. And after the 2 dividend payments during the year of $5 million and $2.75 million, the year-end cash balance was $118 million. Moving on to Slide 9, which sets out, in detail, the drivers behind our increasing realized prices. The main factors include the increase in crude benchmarks following the global economic recovery from COVID-19, several years of underinvestment in upstream capacity and the disruption of global energy prices as a result of the conflict in Ukraine. We are also seeing strong underlying demand fundamentals in the premiums of our oil sales. Both Montara and Peninsular Malaysia crude sales are benchmarked to Tapis, which averaged $1.14 through '21, but since the third quarter of last year, the Tapis premium to Brent has significantly increased. The most recent lifting in April '22, we sold a premium of $5.57 in Peninsular Malaysia and $3.52 in Montara, which has a slight difference in the pricing because it has a 2-month price line. We are seeing real strength in pricing at Stag, where the last cargo in April sold at a premium of $23.72, realizing a total price of $128 a barrel. That crude continues to be in high demand from the marine fuels industry, giving its low sulfur content, which makes it an attractive blending fuel. With Stag's annual shutdown behind us and good uptime and production performance from the field over the past month, we're attempting to maximize the company's exposure to strong pricing demand. The next Stag cargo is likely to be lifted in either August or September of this year. And with that, I'll now hand back to Paul.

Great. Thanks, Derren. So I'd like to put, first of all, some context around our announcement this morning that we intend to significantly increase shareholder returns over the next 12 months. In the latter part of '21 and into 2022, our unhedged oil production has been generating significant cash, as you've heard from Derren, and by the end of May, unaudited cash balance, including proceeds from liftings in May, was $180 million. With oil prices consolidating above the $100 a barrel mark and are all selling for increasing premiums, cash generation is likely to remain strong, though, as I pointed out earlier, it will be offset to some extent by up to $100 million of capital program, which is set for the second half of this year, largely at Stag with infill drilling and the Lemang project, the Akatara project. We've always taken a prudent approach to the balance sheet, an approach which has served us well in volatile times, aimed at maintaining flexibility to fund investment in our organic growth portfolio and also to capitalize on further attractive M&A opportunities that might present themselves. There is also lumpiness of the cash inflows due to timing of liftings, which means we also need to keep a minimum working capital balance of around $50 million, depending on timing of capital programs, too. However, taking all that into account, based on current cash balances, no debt and after careful consideration, the Board has supported a meaningful increase in shareholder returns over the next 12 months, with a total payout of up to $100 million. This does not change our approach to either cash management, where we will remain prudent, or our intent to grow with a bigger hopper of M&A opportunity emerging as we've ever seen and we'll touch on in a moment. We've not yet decided on timing and structure to deliver this return, although we have had clear feedback from shareholders that growth comes first and the buybacks and tender offers are preferred over special dividends. The actual amount returned to shareholders will, of course, primarily depend on the path of oil prices and also operational performance, business development activity and the fact that our 2022 activity program is back-end loaded. The first step in the shareholder return proposal is to raise the final '21 dividend by 25% compared to the second 2020 dividend. This sets a base dividend for the future and has been tested down to $55 a barrel and will be paid in early July, providing it is approved at the AGM on the 30th of June this year. The additional returns will be assessed and put into context over the months ahead, balancing, as I've said, outflows, oil price and performance, share price and M&A, and we'll report back and make announcements on this later in the year. Now let's turn to Slide 11, which sets out reserves and resources at the end of 2021. Reserves increased by 20% in 2021 as the inclusion of the Peninsular Malaysia assets was only partially offset by production during the year. I'm pleased to say that there were no negative revisions across our producing assets, reinforcing the quality of the business and our thorough technical approach to reserves analysis. The right-hand side of the chart puts the 2P reserves in the context of total group resources where we show significant organic growth potential in the portfolio. Following the final investment decision announced today, we can expect to transfer most of the Lemang resources associated with the Akatara gas field to 2P reserves at the end of this year. Completion of the Maari transaction would also provide a meaningful boost to reserves as would commercializing the Vietnam resources, which remain a key goal of the group given the significant resource pool that there is within the license there and which we'll discuss in a moment, too. So to Slide 12 and turning our attention to individual assets. I'd like to provide both a summary of '21 activities as well as an operational update of this current year so far. And starting with Stag where operations were impacted by COVID-related travel restrictions preventing timely well workovers throughout '21. It's only in the last 3 months that we've caught up and seen production rising back to around 3,000 barrels a day and uptime performance of the facilities has been good at almost 98%, and we've successfully concluded the planned shutdown earlier this year on schedule and budget. However, prior to the shutdown, the platform had to be demanned, not due to weather but the number of cases of COVID-19 among both contractors and core crew. This was quickly stabilized, and operations are now running well. Workovers all completed, with focus now turning to well slot recoveries in preparation for the drilling operations for Stag 50 and 51. It was a busy year at Montara in 2021, with the H6 infill well and the Skua subsea workovers, all of which were successfully completed. Though as Derren touched on, equipment issues did impact schedule and final cost, but some of this has been recovered recently. Nonetheless, all wells came on strongly as predicted, and there was a good production run over the year-end, taking advantage of premium pricing. The unplanned compressor outage in February was disappointing, particularly since the motor which failed had been planned for change out later in the year. Nonetheless, this is now being addressed, and the future shutdown has been shortened to just 1 week as a result of completion of this major work scope. With the increase in oil production at Montara, we're also seeing more associated gas production, which requires handling, and work is now underway to assess facility modifications to deal with this. As we continue to look to maximize production from our assets, it is a recurring theme to find system bottlenecks to be dealt with, and we'll talk more about this later in the year as we develop appropriate solutions. The new Malaysia team has come together well and got to grips with the operated assets following the acquisition from SapuraOMV last year. During the 12 months prior to the acquisition, production potential from the PM323 license declined by nearly 25%, which actually created opportunity for us. We've reviewed every single well on the assets and instigated a number of interventions, idle well restorations, recompletions and gas lift optimization to arrest production decline and even reverse it. As a result, we've seen no decline in production during the last 6 months, providing confidence and greater understanding of the assets ahead of planned infill drilling on PM323 in 2023. On PM329, the response has been even more marked, and after prior declines of 10%, this is now being turned into an increase in production potential, thanks to more well interventions and optimization of gas handling at the field. The current outage of the nonoperated Peninsular Malaysia assets resulted from the leased FPSO, which processes and stores crude from the nonoperated Peninsular Malaysia assets, failing a class inspection, with the required repairs scheduled to be completed in July, August. However, the Jadestone-operated assets are now outperforming our expectations by around 800 barrels a day, which goes a long way to offsetting the underperformance of the nonoperated assets, which normally produce around 1,000 BOEs a day, and we're predicting to meet plan on current forecasting. So now moving to Slide 13 and an update on the gas assets and Maari. I'll start by saying how delighted we are to announce project sanction of the Akatara gas field as we signed the final agreement on Friday. This is a major milestone, delivering a fully termed project just 18 months after acquiring the interest and maintaining project schedule and costs in a challenging environment. And I'll talk more to this in a moment. In Vietnam, against a backdrop of sharply rising oil prices, the commercial argument for development of the Nam Du and U Minh gas fields has never been more compelling given that Vietnam imports significant quantities of gas on an oil-linked formula. We estimate that Vietnam is paying in excess of $14 per million BTUs currently for oil price-linked imports and will pay significantly more through imported LNG, with all the required capital for import terminals, et cetera, on top. Recently, we felt renewed momentum on the commercial work streams, with the downstream buyers being directed by the government to enter into direct negotiations with Jadestone for the sale and purchase of production from Nam Du/U Minh. We're hopeful that these negotiations could signal renewed momentum to progress towards a gas sales agreement, which would be the catalyst for the project to move ahead. This has more than price benefits for Vietnam as we've discussed in the past, providing energy security, supporting the country's growing economy, providing jobs and revenue and assisting in the country's energy transition following Vietnam's commitment to carbon neutrality by 2050. On Maari, our acquisition of the 69% operated interest in the field is still not completed and, of course, is a source of great frustration for us given the significant time and effort expended to provide the New Zealand government with comfort on Jadestone's operatorship credentials and decommissioning security provisions. In late 2021, the New Zealand Parliament passed the Crown Minerals Amendment Bill, which, amongst other things, introduced a trailing liability regime for upstream licensees in the country. During 2022, year-to-date, we've been working to address additional questions and requests from the regulator as it applies to this new legislation. While the timetable to completion remains out of our hands, Jadestone and the seller OMV remain committed to the transaction. And so finally, back to Akatara on Slide 14. As in Malaysia, the team in Indonesia have done a great job in moving this project forward so quickly following the acquisition of the Lemang PSC in late 2020. The field contains approximately 19 million BOEs of 2C resource, the majority of which is gas and with around 35% to 40% being condensate and LPG. Once developed, the gas will displace coal in regional power generation while the LPGs will be used locally for domestic purposes. Following significant progress on the commercial side of the project in 2021, with the gas sales agreement signed in December, we've also progressed the project this year with an EPCI tender and award to PT JGC and with regulatory approval received just late last week. This will signal a significant increase in activity at the field, while in parallel, work is still ongoing to finalize the remaining commercial work streams as well as applying for various permits, mostly associated with the gas pipeline from the field, which will tie into a trunk line approximately 17 flow meters away. Slide 15 sets out the time line for Akatara gas field development in order to deliver first gas on schedule in the first half of 2024. The EPCI contract execution will commence immediately, with the ordering of long-lead items and the construction of the sales gas pipeline scheduled to start in the fourth quarter. Well activity will commence next year, with a program of workovers existing wells and 2 development wells, and planning for all of this has already begun. Slide 16 sets out the base case economics of the project, with 3 revenue streams from fixed price gas and variable price condensate and LPG providing balance to cash flows and underpinning the economics of the project. Payback is expected in just over 2 years from the start of production, with revenues and cash flows front-end loaded due to the cost recovery under the PSC. OpEx at less than $9 per BOE reflects the onshore location of the asset and the relatively straightforward nature of the development. However, we hope to reduce this further by eliminating some trucking of condensate. CapEx to first gas is broadly unchanged from our previous announcement of $94 million growth and potentially up only around 3% to 4% in a world which increasingly is seeing both raw material and equipment costs increasing. The local governments have 10% back-in right, which we anticipate will be exercised but note an improvement in economic return due to higher liquids pricing in the near term. PT JGC, the selected contractor, has a proven capability on EPC projects in Indonesia and Southeast Asia and has worked on some major gas projects in the country. We know them well and look forward to working with them and other stakeholders to deliver a successful project. And so moving to Slide 17. We'll give you an update on the regional M&A outlook. While total M&A activity was very high in value terms last year, this was actually dominated by the 2 corporate mergers of Woodside Petroleum and BHP Billiton and Oil Search with Santos. Excluding these, it was a year of slightly increasing activity, but we fully expect this to increase and even accelerate in 2022 and 2023. We believe it's highly likely that the major corporate deals in the region last year will also stimulate further local M&A activity as combining portfolios are optimized and assets are earmarked for disposal. On the right-hand side of this slide, we've set out active and anticipated M&A opportunities color-coded for potential size. And I can acknowledge we are assessing a number of them through data room processes. However, and just to remind you, we are not going to sacrifice our rigorous evaluation criteria simply for the sake of doing deals, and we'll approach this from a number of aspects, including an accretive value proposition, ESG impacts including emissions and growth through follow-on investment. And so now turning to Slide 18, which reiterates guidance for 2022. We've already delivered on one key commitment this year, which was to introduce a net-zero target for our business, and we'll continue to work on elements of the detailed road map while providing more detail and visibility of the pathway to net zero. On production year-to-date, we produced around 15,700 BOEs per day [ set this ] far, with early volumes impacted by the compressor outage at Montara in February, March this year as well as the suspension of production from the nonoperated PenMal Assets. With recent performance back at 17,000 BOEs a day and even while excluding the non-op interest in PenMal, this provides the spot production levels being supportive to meeting guidance. And so this remains unchanged. The final outcomes for the year, of course, still depend on the impact and timing of the Stag infill drilling, the timing of the return of the PenMal nonoperated assets and ongoing work to maintain maximum oil production at Montara and at Stag. Both unit OpEx and CapEx guidance are unchanged, with the majority of the 2022 capital expenditure being incurred in the second half of the year. And finally, on Slide 19, let me summarize the outlook and catalysts for the business. As discussed, operating performance in the first half of 2022 was, frankly, not where we wanted it to be, but we're addressing this, with good production in recent weeks likely to benefit in the second half from the return of the non-op PenMal assets and Stag infill. We continue to plan for further investment in our producing assets, with infill drilling planned at PM323 in Malaysia and Stag also next year before the potential to drill wells in Skua in 2024 and potentially further infill drilling on PM329. Development sanction of the Akatara gas field crystallizes the value proposition and, once on stream, will bring significant benefits to local and regional communities as well as provide further diversification of production and cash flow for Jadestone. Finally, the shareholder returns proposal we've announced today is founded on prudent balance sheet management in recent years and a highly cash-generative portfolio at current oil prices. The M&A landscape is exciting, and we're actively engaged in seeking out the next growth opportunities for the companies. This remains a priority for the business. And I'm also hopeful to be in a position to announce the appointment of a new CFO for the business very soon as we work through normal regulatory clearances. And finally, we are working diligently to progress both Vietnam gas and Maari deal and hope we can report some progress in due course. So ladies and gentlemen, this has been a long call. My thanks for listening. And with that, I'll ask the operator to open for Q&A. Thank you.

[Operator Instructions] Your first question comes from David Round with Stifel.

My first question is just on Vietnam, please. You're talking about engaging with a different counterparty for the gas contract. Obviously, we'll keep our fingers crossed for that one. But does it change your expectations around price at all? And also, given the current inflationary environment, does that get factored into price discussions as well? And then the second one, just on Australia, please. Just obviously, change in leadership there, whether you could please comment on any potential implications. I wondered if there was anything that might actually work in your favor. I was thinking maybe about pushing from more collaboration between operators that may facilitate an export route for gas at Montara. Is there anything like that, that you might think of as a positive? And obviously, any kind of risks around that?

Dave, thanks very much. So taking your questions in order. I think in Vietnam, the real issue has been about the inability of Petrovietnam as sort of the middleman to broker an arrangement to get a gas sales agreement in place. And increasingly, they've looked quite elitist and unable to provide the sort of service that we used to expect from Petrovietnam in the past. And so I think given where we stand -- and this really is largely a result of weak leadership, to be honest, and recognize more broadly, the government is taking the step. And by the way, it's not a precedent. There are 2 other precedents in Vietnam for a direct negotiation between the provider of gas and the direct end user. And so what we see here, of course, is a counterparty who is more motivated. In terms of pricing, I don't think that really changes anything. In the end, prices flow through, and the alternative and, certainly, the end users will be struggling with the high cost of import gas. In the end, this is gas, which is highly competitive against any alternative sources. And so with that, I don't think it undermines where our price expectations lie. Suffice to say, it still remains highly competitive.

Okay. And you're comfortable just with your return on that project given what -- maybe what you're seeing from the cost environment at the moment?

Yes. Yes, we are. All of this, of course, will be worked through, and the team are reengaging with the contracting community. But actually, there's more availability, more interest today than when we first engaged in this project 2.5 years ago around, for example, provision of FPSO. And so in a more competitive environment, I'm hopeful that we'll find the right pricing structure, which will generate really strong returns. And all of this is principled on an early gas volume, which is actually very conservative. And our view of upside gas volumes, I think, ultimately will provide significant value upside. On Australia, new government, I suppose, one of the risks that we've been asked about is the risk of tax change. Unlike the U.K., Australian marginal tax today is already at around 58%. And therefore, we don't see this as a significant risk. It's a resource economy, and certainly, the incoming government has shown strong support for investment in jobs in all of the resource sectors. So I think that's -- that seems relatively low on the risk radar. In terms of potential benefits, I think it's really too early to say. In a way, most of progress in the offshore scene is around motivation of counterparties, stakeholders active on the shelf and the regulator, NOPTA and NOPSEMA. So we're not anticipating significant change being able to work within that environment. And it's a challenging environment, I think, is a competitive edge, and as I touched on in my remarks, I actually do think we'll see some significant new opportunities emerging, particularly post the 2 mergers of Woodside, BHP and Santos and Oil Search.

Your next question comes from Matt Cooper with Peel Hunt.

I've got a few questions on the key items affecting 2022 production. So starting with Maari. I just wanted to check all the gas volumes there increasing faster than expected. And if so, what do you think that's due to? And a follow-on question with that is how much do you think you'll cost to install an additional compressor? And was this considered when setting the 2022 CapEx guidance?

Matt, congratulations. Just to take on the questions, I think we're talking about Montara as we've increased -- sought to maximize oil production, we've certainly seen a ramp-up in gas volumes. Not -- I mean some of it was expected, but perhaps in our modeling, we're seeing more than we thought. And of course, it's a balancing act between maximizing oil production and minimizing flaring. And so that's the line we're trading. And it's one of the reasons why we believe the installation of additional compression will have a double benefit both to increase production and also to reduce emissions. Very early days. We don't know if this is the right solution. We're still working through options. It's not unusual in our strategy to maximize production from assets that we find the limiting bottlenecks in the system and systematically have to remove them at Montara, for example, in early production. Our early production of the asset, we found water handling was the bottleneck, and we had to deal with that. Subsequently, we found gas reinjection was a bottleneck, and we had to deal with that. And now we're seeing gas handling is probably the next bottleneck. And so that's sort of a normal part of the process for us. We'll report later in the year once we've finished assessing and sought the right solution. I personally think we're, perhaps, leaning towards small additional single skid-mounted compressor electric drive using bags of generation capacity on the facility, so it will be efficient. Cost, it's a bit early to say. It would probably be in the order of $20 million or slightly less, I would say, just based on some early screening analysis. But that's how we should think about it. Is it expected? I mean this is just part and parcel of working hard to get the most and maximize production out of facilities and, certainly, is accelerated by the drilling of Montara H6, which we expected. So it's just the magnitude is something that we just have to deal with. In value terms, any incremental installation of, for example, compression would be very accretive. And it's really important to note that there's no reserves impact here either way. Eventually, all the volume comes, but I'm quite keen that earlier production has more value. Does that get to your question?

Yes, that's helpful. Just to double check, so the -- you said roughly $20 million first pass, that would be over and above the $90 million to $105 million guidance that you gave today.

Yes, and nor would it be this year? If we're talking about a compressor unit, that will be a lead time of 12 to 18 months, I would say. And so that's not something that would be in capital this year most likely.

Okay. Got it. That makes sense. And with that lead time, is there a risk that you might need to choke back your production at Montara due to the gas handling?

We still need to do some more work. I don't think it's right to say choked back. I mean we are -- we just work to maximize oil production and playing around the wells, subsea versus platform wells, playing around with inlet pressures. There's lots of things we do constantly looking to maximize production. So we'll be maximizing production whilst reflecting the right amount of reinjection capacity and gas handling capacity.

Okay. Understood. And my second question was just around the repairs at the non-op Malaysia FPSO. Are they fairly routine, so you can be pretty confident of a restart by August? And what's the likely net cost to you of those repairs?

Yes. Of course, we're the nonoperator. And whilst we have offered support and the benefit of our experience with FPSOs to the operator, which they've accepted and appreciated, in the end, it's their job, and we have to take our judgment against the work scope that they're carrying out. Our judgment is it's reasonable. It should be effective. Ultimately, it will be the decision of class in reinstating the FPSO. There's nothing super special about this. It's integrity, basically, and it's mostly around welding and new steel. So all of that's being done. The cost isn't that significant, and the cost to us is less than our equity share. As an agreement with the operator, they're bearing a disproportionate share of this period of outage.

Okay. And then final question, just quickly. What rates are you expecting from the upcoming Stag wells?

Typically, we'll see early production from the Stag wells sort of 700 to 800 and maybe even briefly 1,000 barrels a day. Typically, that's relatively short and flush. And for the longer haul, let's say, an average over the first year or 2, they will generally settle in between 500 and 700 barrels today. So the 2 wells, over a prolonged period, which should certainly add something like 1,000 barrels.

Your next question comes from Ashley Kelty with Panmure Gordon.

Most of the points I had were being covered off already. But I was going to ask about, obviously, there's a lot more repairs and maintenance in Australia last year, obviously, catching up on a lot of stuff post COVID. Just wondering, is that program essentially complete now? And could we expect a significant drop off in the sort of production costs going forward in Australia?

Ashley, thanks for the question. Yes, we certainly took a judgment in 2020 to defer certain noncritical maintenance activities where it made sense and where it didn't impact regulatory requirements, facility integrity and so on and so on. And so there is a catch-up. The way I think about this is I've sort of -- I've assumed that within the overall operating cost budget in Australia, $40 million has allocated to the annual, what we'll call maintenance budget, and history would indicate that typically, it should be $20 million to $25 million. So we are spending almost twice as much this year as I would think in the long haul, we should be assuming, and that catch up when it's completed. And it will be through this year -- may run into next year. I haven't -- we just have to see how the budget comes together. But thereafter, in the longer term, we should see it come down for sure.

[Operator Instructions] Your next question comes from Mark Wilson with Jefferies.

My first question is just a detailed point. You guide very clearly CapEx and also OpEx, but as I understand it, workover costs all in between those 2 are reported in operating costs. Could you remind us of the expected amount of workover costs we should include as well this year?

For this year -- Mark, thanks. Of course, last year was extraordinary because of the 2 subsea workovers at Montara at Skua completed. There was a small spillover into this year, which included the repair of an umbilical connection to those subsea wells. With that now behind us, workover maintenance at Montara is de minimis. Occasional sale buys with a small ROV on the subsea wells and occasional platform visits to the Montara platform for routine maintenance on wellheads and trees, so very, very small at Montara going forward. And with Stag, it's all a function of how many wells we work over. Again, I think in our narrative, we talked to a catch-up post COVID. And we were certainly impacted. I think we've described by getting hold of both equipment and people to the Stag platform to do those workovers. We are now up to date. And so going forward, I hope we'll return to the sort of 6 to 7 workovers a year, which, in simple terms, a pump change out is that you should just think of as around $1 million, and something more complicated when you find downhole issues with erosion of casings or whatever and have to do various downhole repairs, patches, that might run to double that cost. And so if we think about an annual program of workover cost at Stag, I would say what we're looking to do is to restore it to the $10 million top $12 million mark, I would say. And of course, one of the objectives of drilling new wells and recovering this -- the oldest of the well stock, the well stock that's caused us the most cost and trouble historically, it is to ultimately reduce future workovers by having essentially new wells in place. And so over time, I'd expect to see an improvement over that. But if I think -- if you want to think about 6 to 7 wells per year and if you want to think of something that might look like around $10 million, that will be the way I would think about workovers.

Got it. Okay. And then bigger picture, Paul, and great slide on the M&A outlook. We've obviously been through the years of COVID, and then we've moved into a world of inflation and energy security and higher and volatile prices. How would you say that the sellers' outlook on the market has changed as where we sit here? And for instance, the slide you show in terms of opportunities, would you say that is materially different than one you would have been looking at a few years ago? And indeed, following on from that, the big consolidations you talked to -- you point to, Woodside, BHP, Santos, Oil Search, do you think these will create additional opportunities for Jadestone in the coming years?

I'll try not to spend 20 minutes giving you an answer because it is a complicated picture and just trying to pick off some of the questions that you're asking. Firstly, I'd say the opportunity slate is significantly more significant -- is significantly larger, I should say, than we've seen in the past. There's a number of factors around that, none of which will surprise you. The mergers and the sort of fallout of opportunities from that, for sure, is one -- to another one of your questions. But that sort of continued exited majors from mature opportunities from mature assets, the drive on emissions and so on. All of that is having an impact that, I think, is positively driving a wider slate of M&A. There is a counter to it, though, which still hasn't been wrestled to the ground in some cases. And that, of course, not least is what we're seeing with Maari following the Tui-Tamarind debacle in New Zealand and, of course, the NOGA-Northern Endeavour issue in Australia, it highlighted the sort of the hole in legislation around decommissioning security. And so whilst the legislation has now been put in place in both countries to correct that, the way in which the operators and the regulator will manage it hasn't established a pattern yet. And so we're sort of a bit of a -- we're in the vanguard of trying to find sort of workable solutions between all counterparties. So that, I think, is going to take some time to work through in Australia and New Zealand. In Southeast Asia, none of that conundrum exists. And we're hearing and starting to see some more material opportunities coming forward. And that's far less complicated in a way, but because it's less complicated, we'll expect to see more competition. So there's pros and cons in all of this. In the end, we have to stay true to the whole value proposition, which is fundamental to us and actually is not so impacted by current oil prices because the whole point of an acquisition is the follow-on reinvestment potential over several years. And most price forecasts has the industry back to $65 a barrel or so within 2 to 3 years. And so what we're looking at is not a typical price spike, which can be addressed through smart negotiating and the usual story around contingent payments and such like. So all of this does make for a complicated arena, but the competition is light. There is growing momentum to transact, and we're encouraged. We'll see what happens over the next 12 to 18 months.

Okay. And then so one final point on that. Could you remind us of the long stop date on the Maari transaction? And indeed, could you envisage a point where that long stop is -- just got too long and there's other opportunities you could be going to while you wait for that to transact?

So a long stop date is no longer part of the story here. It's -- it would -- it has no impact on whether the counterparties remain committed to the deal. It is all about OMV wanting to sell and Jadestone wanting to buy. And as long as that dynamic is in place, the counterparties will work together to find a solution. To your question, could that change in the future? I don't know if we'll be talking about Maari in 3 years' time. That would be -- it's a dreadful thought. So there does come a point in time when both parties, it probably makes less sense. All I would say is that today, what we see is an ideal opportunity for Jadestone. There is a large number of reinvestment options on the asset. It has a very large oil in place and a low recovery factor in a fiscal regime, which supports and encourages investment. It's the sort of thing we want to try and do. But Mark, there will come a point in time when exhaustion might set in.

There are no further questions at this time. Please proceed.

Sorry, thanks. You were waiting for us. I beg your pardon. Well, thanks very much to everybody for the questions. We really appreciate it. We have taken quite a long time, and I thank you for that. And just in closing, I'd just like to reinforce, I think, the benefits of the business that we're pursuing. We are enjoying, of course, significant cash with unhedged barrels and high-value barrels. I mean let's not forget that. We are looking at strong growth in the portfolio, having seen a significant bump this year and looking forward to further growth with infill drilling and with the Lemang project and more opportunity to come. I do hope we'll be able to add further inorganic growth in the near term. It's certainly a key objective. The feedback is very strongly a view from shareholders that the interest in Jadestone is about the way in which we operate assets and our ability to grow through activity and M&A, and we're committed to that. And the track record and a commitment to returns to shareholders is something that is a balance that we're trying to strike. And it's a balance that has shifted largely because we see exceptional pricing in today's environment, but I do want to reemphasize this has no impact on our overall business objectives or strategy. So we're pursuing a business model in a part of the world with energy needs and supply shortage. We're declaring a path to a just and orderly energy transition, and we operate our assets with integrity and with an intent to maximize returns and to support local communities and stakeholders in the activities we conduct. With that, I'd just like to say thanks for your support and look forward to keeping you up to date with progress as we develop our ideas around the return story and as we develop our opportunity set going forward. So thanks very much, and have a great day.

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

Thank you.