Welcome to the Jadestone Energy Management Briefing conference call. At this time, all lines are in a listen only mode. Following the presentation, we will conduct a question and answer session. If at any time during this call you require assistance, please press star zero for the operator. This call is being recorded on Thursday, July twenty-eighth, twenty twenty-two. I would now like to turn the conference over to Mr. Paul Blakeley. Please go ahead. Great. Thanks very much, Pam. Ladies and gentlemen, good morning, if you're in Europe, and good afternoon, evening, if you're elsewhere. Thanks for joining this conference call to discuss the North West Shelf oil acquisition, which we announced earlier today. I know it's short notice, and so I do appreciate your time and in turn, we'll keep this brief. I'm Paul Blakeley, Jadestone CEO, and I'm joined on the line today by Phil Corbett, Investor Relations Manager, and Michael Horn, EVP of Business Development and Special Projects. 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. Then after that, let's open the call for a Q&A discussion. Slide two, of course, outlines our standard disclaimers. Let's move quickly to slide 3, which I'm going to use to summarize the acquisition that we've announced today. This is another small tuck-in acquisition to further boost the business. It's accretive on all measures and provides additional immediate production and with significant follow-on potential to add value. What I'd also like to say right up front is that this is an entry into a top-tier asset where we hope further interest will become available over time and for us to be able to further build our position here. Just for today, we are acquiring from BP a non-operated 16.67% interest in the Cossack, Wanaea, Lambert - Hermes fields, collectively CWLH fields, and the associated infrastructure offshore Western Australia. These oil fields are in close proximity to the gas fields which provide the feedstock for the North West Shelf LNG plant, which I'm sure you'd heard of. These are mid-life assets, having been producing since the late 1990s and with the potential for life extension well into the future, potentially up to 20 years. Combined, the four fields have a very large oil in place of around 900 million barrels and have produced approaching 500 million barrels to date. The fields have a very low rate of decline at around 6%-9% per annum, and we believe that there is significant upside to current reserves estimates, which makes this a very attractive acquisition for Jadestone Energy. Jadestone is acquiring 10.5 million barrels of production, reserves, and resource based on an effective date of 1 January 2020, for which we will pay an initial consideration of $20 million and a further $4 million in contingent payments over the next 2 years tied to oil price outcomes. Based on the initial consideration and contingent payments, we're buying this interest for a very attractive acquisition metric of $2.30 per barrel. Due to the free cash flow from the asset since the effective date, we also expect there will be a significantly positive completion adjustment, which should cover a material amount of the upfront consideration, as well as the first of the 2 payments we will make to an abandonment fund in respect of the acquired interest. In 2021, gross production from the CWLH fields averaged over 12,000 barrels a day or around 2,100 barrels a day net to the interest. We're acquiring at an oil price of $100 a barrel. On that basis, we estimate that the acquired interest would generate approximately forty dollars. Sorry, I beg your pardon. Forty million dollars of EBITDA in 2023 at $100 a barrel. The PRRT tax credits that are being acquired with the interest are forecast to offset PRRT payments on this interest through to the end of the assets life. We will also be pre-funding Jadestone's share of the decommissioning cost for the acquired interest. This is in large part a reflection of the heightened focus on decommissioning security in Australia following the issues surrounding the collapse of NOGA and the government's assumption of decommissioning responsibility for the Laminaria and Corallina fields and the Northern Endeavour FPSO. It also represents a safe and responsible approach to this key issue with the JV, the joint venture partners, and gives certainty to all stakeholders on this longer-term obligation. There are a number of key points to make around this. Firstly, much of the value impact of advancing the decommissioning security is actually paid for by the seller and therefore represents a short-term cash impact on Jadestone only. The purchase consideration reflects this novel approach to decom security and remains highly competitive and accretive as a result. Forward-looking cash flows from this acquired interest are therefore not encumbered by future decommissioning liabilities, providing a much longer cash, free cash tail, and as a result, also increases the potential borrowing base of the assets in the future. We see significant potential upside in this asset through two avenues. First, based on our engagement with other joint venture partners, we have a reasonable expectation that other interests in this asset may become available in the future, over which we would now have preemption rights. Second, we see the potential to materially increase the reserves from the fields by increasing recovery factors through infill drilling, cost optimization of the FPSO, and an extension of the asset's life well beyond the current view of 2031. Finally, from a sustainability perspective, it is worth pointing out that the emissions profile of the asset is comparatively low, benefiting from the principle that all excess associated gas from the fields after use for fuel is dispatched as feedstock to the North West Shelf LNG plant, and so flaring from the FPSO is minimized. We look forward to working with the JV operator on finding ways to further minimize greenhouse gas emissions from the field operations. You know, we also believe that core to our climate strategy is the principle that demand for hydrocarbons should be met as far as possible by maximizing the recovery of assets currently in production ahead of any new development. This acquisition is a perfect example of that. With that overview, we'll move quickly through the remaining slides. Let's please turn to slide four, which starts with an asset overview. The CWLH fields are located offshore Western Australia in water depths of between 75 and 135 meters. They are very large oil in place fields with high quality upper Jurassic sandstone reservoirs set in low relief anticlinal structures. All fields benefit from strong aquifer support, contributing to very high recovery factors. As highlighted already, with oil in place of approximately 900 million barrels and around 500 million produced to date, small increases in recovery factor have a material reserves impact. Now turning to slide five. The CWLH fields were brought on stream in the late 1990s with peak production around 120,000 barrels a day. Today, they produce in the range of 12,000-14,000 barrels a day, averaging 2,100 net to the interest that we're acquiring in 2021. We expect the assets to decline at very low rates, around 7% on average, due to the large stock, the strong aquifer drive, and high mobility ratio. The Wanaea field is the largest and most mature field of the four, with eight development wells having produced around 270 million barrels to date. Wanaea has excellent reservoir characteristics and has already delivered 65% recovery factor to date and is expected to increase further on the back of future production and the potential for infill drilling and the field life extension. This is a perfect analog for Cossack and Lambert and Hermes, which to date both have much lower recovery factors, under 50% on average, and yet have better reservoir quality. The other key takeaways from this slide are to note that there are 8 idle wells across the Wanaea and Lambert and Hermes fields. Secondly, that Cossack and the Lambert and Hermes fields each produce from only one single well. We look to work with a JV operator in exploring whether any of the idle wells could be brought back on stream efficiently at low cost, and whether they also identify further infill drilling locations as we do. Overall, we're targeting recovery factors approaching 70% on average across these assets, which, considering the size of these reservoirs, adds a lot of barrels and significant value. Please let's turn to slide 6, which provides now an overview of the Okha FPSO and the CWLH subsea facilities. The Okha FPSO replaced the original vessel that was on the field in 2011, and has a nominal 20-year design life which we believe can be extended through appropriate investment. The Okha FPSO has significant water and gas handling capacity, meaning it was designed and is ideally suited for mid to late life oil field operations. The vessel is also double hulled. As is normally the case, the FPSO undergoes a 5-year survey to establish the technical condition of the hull with the most recent major survey occurring last year. It has approximately 900,000 barrels of storage capacity with offtakes usually in around 650,000 barrel parcels. The barrels are lifted on an equity basis with the last lifting attributable to the interest that we're acquiring being sold in January this year on a price that was set in the prior month. On the right of this slide, you can see a schematic of the field facilities, noting that the subsea infrastructure already has capacity for the tie-in of future infill wells. Although, as I previously mentioned, we also intend to look at the idea of reuse of current idle wells on both the Wanaea and Lambert and Hermes fields, which could be a highly value-creative option. Slide 7 provides an overview of the facilities near-term work program and the opportunities. This is largely aimed at extending the life of the field beyond 2031, which is the current nominal design life of the infrastructure. This forecast activity is already reflected in the budgets for the CWLH fields and provides confidence that the fields can produce well into the 2030s. The decommissioning of the Okha FPSO and subsea equipment has been the subject of detailed studies by the operator, with the base case being full removal of all infrastructure. As always, we will look for areas where we can optimize the decommissioning plan and cost while always adhering to applicable laws and regulations. Finally, on this slide, on the emissions profile of the assets, the associated gas not needed for fuel on the FPSO, as I've said, is exported to the North Rankin complex and then onshore to the North West Shelf LNG project. As a result, flaring of gas on the Okha FPSO is minimized, which significantly benefits the greenhouse gas emissions intensity of the CWLH fields operations. There's also a focus among the joint venture group on reducing greenhouse gas emissions further, and we look forward to working with the partners on that, providing our own experiences from our own operations as well as hearing their perspectives. Slide 8 sets out the ownership structure of the CWLH fields prior to completion of Jadestone's acquisition of BP's interest. Woodside, now an indirect 50% interest owner following its acquisition of BHP's petroleum business and also operates the CWLH fields. The key point is that through this acquisition, Jadestone will have a preemption right in respect of any future sales of CWLH interests. Following preliminary soundings with other partners, we believe that other interests may become available over time, and this is certainly an asset where we would like to grow and exercise increasing influence in the future. Slide nine sets out the potential impact of the transaction on Jadestone. Based on 2021 average production from CWLH of 2,100 barrels per day, net to Jadestone's interest. Taking the midpoint of the 2022 production forecast for Jadestone for the fourth quarter, allowing for annual declines and the restart of uncertain in Malaysia, plus contributions from the STAG infill campaign, the transaction would increase our production by around 12% at the end of the year. Unit OpEx for the CWLH fields is estimated at around $22-$23 a barrel, which at the midpoint is 12% below the midpoint of Jadestone's unit OpEx range for existing assets in 2022, and therefore, again, is accretive. The potential EBITDA generation from the assets would also have a meaningful positive impact on Jadestone's financial performance. On the basis of a realized oil price of $100 a barrel in 2023, we would expect the acquired interest to contribute $40 million of EBITDA to Jadestone, which is an increase against our current analyst consensus EBITDA for 2023 of 10%. On the right-hand side, we set out the reserves and resource potential for the asset based on publicly available data from Gaffney, Cline & Associates, which is contained within the Woodside BHP independent expert report. Gross 2P reserves at end 2021 are estimated at 31 million barrels. There is a further estimated 23 million barrels in 2C contingent resource based on an extended life for the fields and also future infill drilling and workover activity. On top of this, we have identified a further 20 million barrels of upside associated with reactivating idle wells, additional infill drilling opportunities, and better than expected reservoir performance. As a result, we see a minimum of 100 million barrels of gross reserves and resource potential. You know, if we use simple recovery factor assumptions, however, this could easily rise to over 100 million barrels just simply representing a material prize for Jadestone, one that is worth us chasing hard and which, if realized, would have a significantly positive impact on the company, particularly if we're able to also increase our interest in the JV ownership over time. Finally, slide 10. We've set out the steps to complete this transaction. Here we show that we signed the SPA earlier today, and we paid a $2 million deposit on that event. The near-term focus now will be on obtaining the required approvals from regulatory authorities, principally NOPTA, the titles registrar, FIRB, Foreign Investment Review Board, as well as consents from the other North West Shelf partners under the coordination agreements governing the supply of associated gas from the CWLH fields. On completion, which is targeted for the fourth quarter this year, we would pay the $80 million of the initial consideration and the initial decommissioning payment of $41 million. However, we anticipate that the combined figure of $59 million will be significantly offset by an expected positive completion adjustment, given that the economic date of the transaction is the first of January 2020. Looking forward, an aggregate of $4 million in contingent payments are due in 2023 and 2024 based on oil price outcomes related to 2022 and 2023. The second decommissioning payment of $41 million, second and final payment, is due to be paid in two equal installments on or around the 31st of December 2022 and the 31st of December 2023. Ladies and gentlemen, that's a summary of the asset. We're really excited about it. Thanks for listening, and, I'll hand over to the operator to take any questions from those who are listening. Thank you very much. Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. Should you have a question, please press star followed by one on your touch-tone phone. You will hear a three-tone prompt acknowledging your request, and your questions will be pulled in the order they are received. Should you wish to decline from the pulling process, please press star followed by two. If you're using a speakerphone, please lift your handset before pressing any keys. One moment for your first question. Your first question comes from David Round with Stifel. Please go ahead. Thanks. Morning, Paul. First one, just you mentioned the reserves potential, but can you just talk about your perception of the appetite from the existing partners to go after this? I suppose I'm looking at the 70% recovery factor. Presumably, that is a Jadestone target, i.e., if Jadestone was involved and operating. Where do you think you'll end up if the partnership remains as it is? And then maybe just one on the cost structure, please. I appreciate it's early, but I suspect you will have had a look at this and, you know, part of your strategy is to drive down costs where the opportunities present themselves. I mean, is there anything you're seeing from the existing cost structure that looks like it's an area you might be able to strip out some costs? Can you give us any early sense of what a good outcome in, let's say, a few years, five years down the line might be for you? Thanks, David. I'll handle these questions in the order. I think you know all we can really say about the joint venture group's intentions on additional investment to capture additional reserves is what we see from their plans and forecasts. Certainly, you know, there are two things that stand out to me. The first one is the work that's being done by the partnership to extend the life of the asset beyond its sort of nominal 2031, speak to the notion that they do see more upside beyond that point. I think that's good news. The second, you know, while that activity, that first activity I've just described is captured in the budget. The notion of additional wells or well reactivations is not. Yet there is, in some of the joint venture documentation, you know, evidence and interest in looking at this. You know, just by the nature of this process that we've been through, we have not been able to, I'd even say allowed to, have conversations with the operator and the other joint venture partners, in detail about the asset. You know, this is an engagement that will start as soon as possible, you know, now that we have signed this SPA. You know, at some point in time after that, we'll see how much confidence we have in what, you know, what the current joint venture group are planning. B, how much opportunity we may have to influence that through, you know, demonstration of the quality opportunities perhaps. Of course, three, you know, how much interest there is in remaining on the license from, you know, from the other JV partners and whether that you know, offers an opportunity for us too. All of those conversations are to come, and not easy for me to be too specific at this point in time. In terms of cost structure, I mean, you know, again, we of course are allowed to see budgetary information provided to us by BP, but not to interrogate it in the detail that we'd want to. Suffice to say that, you know, if we were to think about taking some sort of control and influence on this operation, we would always anticipate, and this is our experience with other assets, you know, including Montara and STAG, we would anticipate to think about at least a 20% reduction in costs over time. That would be around, you know, eliminating certain, you know, inefficient processes, certainly reduced overhead. But we'd look for other operating efficiencies in the way maintenance is carried out and so on. Not reducing it, but just finding more efficient ways to do it. Of course, you know, we're at a point now with our existing operations where we can actually achieve some economies of scale. Those are all areas where I think, you know, we could add value. Okay. Very clear. Thanks, Paul. Your next question comes from Ruben Dewa with Jefferies. Please go ahead. Morning, Paul. I just want to say congratulations on this transaction. Just three quick questions from me. You mentioned infill drilling. I wanted to just get an idea on potential timing for this. Just looking at slide seven, would it be fair to say that the drilling is expected in this year, 2025 and 2026, as it seems to be higher than the other years? Second question, I just wanted to ask if this transaction impacts the plans you had of returning up to $100 million to your shareholder in terms of returns? Just being mindful of the decommissioning payments into the trust fund required between now and the end of 2023. Final question, page six mentioned the low sulfur oil. I was wondering, would you be able to receive STAG-like premiums on this crude? Thank you very much. Okay, great. Hi, Ruben. Thanks. In some respects, in answer to David's question, you know, until we can engage very specifically with the operator, it's hard for me to be precise about the opportunities for drilling and the timing for drilling. I don't see in the budget currently, you know, plans for immediate drilling activity, and so I don't think this is something that will happen either, you know, 2023 and, given lead times, you know, likely not in 2024 either. We've got some time to sit with the partnership and understand more clearly their plans and see how we can influence that. It's not a short-term activity. You know, bear in mind that these fields are on very, very low decline rates. You know, there isn't the same criticality, although you know, naturally, the sooner you carry out activity there, then you can benefit from it. Certainly it's something that we would like to see occurring sooner than later. But I can't be specific. Crude premiums. The question on shareholder distribution. Sorry, that was the second part. Ruben, this doesn't change our ability to deliver the shareholder distributions that we've talked about. It's a relatively modest acquisition size. We have worked very closely with BP and they've been very cooperative in supporting the decommissioning security being paid in installments, if you like, to manage cash flows and to leave us with you know, strong liquidity over you know, the next couple of years. For those reasons, we think that's that this acquisition doesn't change that. On crude premiums, this does sell at a premium to Brent, but it's not like a STAG crude. It's a very light crude. It's more, in simple terms, it would be more akin to Montara. I think what we see here is premiums in the order of $3-$4. Okay. Thank you very much, Paul. Very clear. Great. Thanks, Ruben. Your next question comes from Matt Cooper with Peel Hunt. Please go ahead. Morning, guys. Yeah, congratulations on the deal. Two questions from me. Thanks, Matt. Yeah, first one would be if you could give a little bit of background on the reason for the effective date being 2.5 years ago. Also, you know, maybe just talk briefly to the risk to the Q4 closing date being achieved. Second question is, yeah, I mean, the recovery factors here look, you know, seriously world-class. I just wondered why, you know, additional wells have not yet been drilled in Cossack and Lambert-Hermes to date. Are there perhaps some, you know, additional subsurface complexities to Wanaea? Hi, Matt. Okay, good. Let's take, you know, the effective date is a long time ago, which does seem to be something that we're experiencing in the region, certainly in Australia, New Zealand. The reason is all about the decommissioning security issue and the, you know, the subject of which in Australia, as I touched on in our earlier discussion, was this NOGA, Northern Endeavour fiasco, and which the government is now decommissioning, but is charging a levy to the industry for the cost of it. You know, in the face of all of that, I'd say... Well, all I will say is the joint venture partners. You know, this may be a broader issue that you know, will affect M&A activity in this part of the world. The joint venture partners were you know, extremely nervous around it. Not least, of course, you know, Woodside as the operator of this asset, you know, was the operator of Laminaria-Corallina and sold it to Noga. There's a huge amount of sensitivity and devising and developing a security arrangement, a decommissioning security arrangement that will satisfy them has taken a long time. Getting the partners comfortable with that, you know, was a burden on us, which in a different regime, you know, for example, in the North Sea, just simply would not be the same sort of issue at all. That's the reason. Having said that, you know, this now sets a precedent and, you know, we can discuss the merits, the pros and cons of the structure that we've devised. The bottom line is, I think it does set a precedent which should be, you know, very appealing to the government. Completely, you know, takes away the risk that of course they see in assets moving from, you know, large companies to smaller companies. To the second part of your question, we think this really does minimize the risks to closing. With the partnership now all on board and signed up, and of course, with this being a small interest with larger participants still on the license and the capital in a fund to cover the security, I think that takes care of it. We would hope on that basis that this would move relatively quickly to closing. Great. Thank you. In terms of reservoir. These are extraordinary reservoirs. Very thick, homogeneous sands, so very little structuring internally. That is the case in all of the reservoirs. In fact, Wanaea actually has the lowest permeability of all of the fields, and yet is already at 65% recovery factor and still going. That gives us a high level of confidence. Cossack, Lambert, Hermes porosities are more than double and up to 1.5 Darcy sand. These are excellent reservoirs. You've got a very active aquifer providing very strong drive and great mobility ratio. We think that's justified. The partnership, you know, they have enjoyed significant recovery from the existing well stock and just simply haven't thought about, you know, how to improve upon it. You know, given its history and the cash generation, it's not surprising. Plus, always remembering that this joint venture partner group is the North West Shelf partner group. Of course, this oil asset represents a very, very small part of the value in the overall asset. Hence why we believe it sits loosely in the partner's thinking. All of those, I think, you know, explain our strategy and our hope to be able to do more. Okay. Well, that's really helpful. Thank you. Yeah, congrats again on the deal. Great. Thanks. Thanks a lot, Matt. Ladies and gentlemen, as a reminder, if you do have any questions, please press star one. There are no further questions at this time. Please proceed. Great. Thanks. To conclude, to summarize. We continue to look to grow our business with accretive acquisitions which meet our investment criteria. I mean, it is interesting, while it's harder to do so when oil prices are as elevated as they are, nonetheless, the strategic transformation of the portfolios of the major IOCs continues. In the scenario with BP, we just, you know, we see it in action and stand ready to take full advantage of it wherever we can find it. This deal was agreed in late 2019 when oil was still around $50-$60 a barrel. Can you remember? BP have sought really a safe and clean exit from an asset that is immaterial to them, completely immaterial. We've provided the ideal framework for them. The structured decommissioning security arrangement that is now in place gives BP, you know, absolute comfort that there's no trailing liability to them. It fits within the framework of the North West Shelf Joint Venture, as well. As a result, provides us all with a forward-looking cash flow, and security that satisfies all stakeholders. Of course, for Jadestone alone, you know, the cash flow profile for us, significantly improves our business and, no overhang, at all. If you think about this in simple terms, you know, for comparative purposes, you know, if you were to look at North Sea producing asset acquisitions today, I mean, I dare say, and I've looked at some of the analysis, I dare say you'd be thinking, you know, $15 a barrel would be a good deal, flowing barrel. That's probably right. I've seen as high as $20 paid recently. Here, you know, we are buying at $2.30 plus, if you allocate the decommissioning security payment in advance of, let's say, you know, $8-$9 a barrel, at $10-$11 with no future decommissioning costs associated to the asset. I think this represents an outstanding deal. As we have discussed, this acquisition is accretive against all key metrics and represents just another excellent deal for the company. Thank you all. Thanks for joining the call, and have a great day. Thank you. 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.