Santos Limited (STO) Earnings Call Transcript & Summary

Thank you for standing by, and welcome to Santos 2020 Full Year Results Question-and-Answer Conference Call. [Operator Instructions] The call will begin with Kevin Gallagher, Managing Director and Chief Executive Officer, providing some opening remarks. We will then move straight to a Q&A with both Kevin Gallagher and Anthony Neilson, Chief Financial Officer. [Operator Instructions] I would now like to hand the conference over to Mr. Kevin Gallagher, Managing Director and Chief Executive Officer. Please go ahead.

Good morning, and welcome to the Santos results Q&A call. Joining me this morning is CFO, Anthony Neilson. We are presenting our results a little differently this year. Anthony and I recorded a video presentation on today's results, which you can find on our website along with the presentation pack. And I do recommend that you watch the video as Anthony thinks it's riveting viewing. And if anything is unclear in the video, we can upload a version with subtitles. It does cover what was a strong year for Santos despite the challenges of the pandemic. We delivered record production and sales volumes, strong free cash flow of $740 million and underlying profit of $287 million. We're not going to repeat the video presentation on this call. We will, however, be happy to take your questions. But before we do that, let me make a few brief opening remarks. As I said, we're pleased to release another strong set of financial results despite the external challenges of 2020. These results again demonstrate the resilience of our cash-generative base business and strong operational performance across our diversified asset portfolio. The improvements in our base business in recent years were perfectly illustrated in 2020 with an average Brent oil price of $43 per barrel, generating more than 3x the free cash flow as generated in 2016 at a similar average oil price. Our free cash flow breakeven was $24 per barrel in 2020, and we're targeting a similar level this year. At current oil prices today, the base business would deliver more than $1 billion free cash flow this year. The final dividend was USD 0.05 per share, in line with the previous final dividend. This brings full year dividend to USD 0.071 per share, representing 20% of free cash flow and delivers on the Board's commitment to review the full year payout at the annual results. I'm also delighted on the progress we're making on the Barossa project, and we're on track for FID in the first half of this year. All consents are in place for our 25% sell-downs in Bayu-Undan and Darwin LNG to SK. The deal is binding and subject only to FID on the Barossa project. We're also finalizing 12.5% sell-down in Barossa to JERA. And as was said on the results video, we've completed all the agreements with Darwin LNG for the processing of Barossa gas. The Moomba CCS project is FID-ready and only subject to the government finalizing the eligibility criteria for carbon credits, and we have set out a clear and credible road map to net-zero emissions by 2040. We have been and remain unrelenting and sticking to our strategy and implementing our disciplined low-cost operating model, an operating model that has proven its value by delivering consistent results, keeping the business resilient and performing strongly despite the challenges of the past year. We continue to generate strong free cash flows, maintain the strength of our balance sheet, provide dividends to shareholders, and we are now very well positioned to fund our growth as demand recovers and oil prices improve and to position Santos as a leading company globally, managing the energy transition. With that brief opening, we'd now be happy to take your questions. Thank you.

[Operator Instructions] Your first question comes from James Byrne from Citi.

Thanks for the brief presentation. Look forward to watching the video. So I just wanted to have a bit of a conversation first around what's happening in Papua New Guinea. Now last week, we saw Papua LNG have the fiscal stability agreement, and appreciate that you don't have equity in Papua LNG, but you've obviously got commercial agreements between Papua LNG and PNG LNG for the common use of that site. Just wanted to understand what the current status is of those commercial arrangements. And then from your perspective as an owner of PNG LNG, how does -- how do those commercial arrangements sort of tie in with timing of P'nyang fiscal terms? Or is it kind of -- does that not matter anymore because the time for Train 3 to be sanctioned is past us?

Well, thank you for that, James. It's a good question. Look, the -- a lot of questions within that one question around PNG. I guess what I would say is I'll agree and confirm that we're not in Papua LNG. So that's correct. And consequently, I'm not going to comment on anything around that particular agreement. In terms of what that means for PNG LNG joint venture, those discussions haven't really commenced yet, and we're not in a position to give any sort of clarity on the way forward for PNG LNG at this point in time. And we'll look forward to those conversations with Exxon and the joint venture partners in the coming weeks or months. In terms of P'nyang, look, we signed an LOI. As you know, we've never executed that agreement yet. It's still live. But the reality was that agreement was set in a very different time period with different long-term price forecast and things like that. And so ultimately, we'll have to sit down with the joint venture partners to review the merits of that and the conditions around that. And the other thing that's changed, of course, is when we did do that agreement, we were looking at P'nyang then as being Train 3. And in reality, it's probably moving more now as a backfill project than an expansion project. So I think there's a lot of discussions still to be had in all of that. And ultimately, for Santos, with our strategic vote to agree to the Papua LNG expansion, we need to always be mindful of the risk and benefit balance on any agreements before we'd say we've got a pathway to expansion.

Got it. But wasn't there the agreements between the 2 joint ventures already termed and priced? So are those...

No. There's no formal agreement. So -- I mean, basically, they were all part of the sort of LOI intent to lead to those agreements, and those agreements haven't been finalized.

Got it. Okay. Then just looking at the OpEx guidance for next year, you've effectively got the midpoint of your OpEx guidance slightly above what you'd achieved in calendar '20. And I look at your production, and it's slightly lower at the midpoint to what you achieved. So that kind of makes sense. But as I read the comments that you had made, Kevin, in the release that you're looking at further efficiency gains, improvement initiatives in the midstream, how do I think about the cost base of the business going forward when those efficiency gains aren't really reflected in the guidance?

Well, look, I mean you're right to point out that we will continue driving efficiency gains, and you've seen that we deliver quite a lot of those even in the last 12 months. Now all of that didn't come through in the unit cost because we also are fighting the upward pressure of FX movement during that time. And I always remind people to the fact that our revenue is in U.S. dollars predominantly, but our costs are predominantly Australian dollars. And so they tend to offset each other a bit, and that will be the same -- we would see that as being the same in 2021, hence, the guidance, the range that we've given you. And so really, it's about continuing to drive efficiencies across the operations. We've given you some guidance on what we see that being over the next few years through that midstream part of our business. And we'll continue to drive efficiencies in our upstream drilling as well, the onshore drilling, et cetera. But maybe I'll just ask Anthony to add to that.

And James, also in that range, we've got Bayu-Undan, obviously, at 68%. And it depends on your assumption around the sell-down timing to SK for that 25%. So that's another reason why we've got a broad range in there. And the assumption on the sell-down we're saying is in the first half, but obviously, later in that first half. So the first half will be -- assuming the sell-down occurs, the first half will be obviously a higher OpEx than the second half, and that flows through to the average for the year is that range.

Got it. Great. And then the last one from me just around the midstream infrastructure value and optionality described on Slide 31. Appreciate that disclosure. I'm interested in understanding a little bit about the capacity contracts that have been written. Can you help us understand like the benefit of that, firstly, to how it affects your P&L, such as volumes from third parties start to decline, that you still got a sticky revenue base, but then also how it might help you unlock some of that latent value that you see?

Well, look, I mean, I think you've sort of answered that for yourself, James, frankly. But across that midstream portfolio, we've set that part of the business up now to drive more of those term and capacity contracts just as any midstream operator would want to do. And that helps you plan your OpEx, your maintenance plans for years to come when you've got that certainty of revenue stream. Now we don't have that in every asset, but that's exactly how we've just set up Barossa with Darwin LNG. So that is a term contract for the term of the Barossa project with capacity commitments. And you would have the usual take-or-pay on both sides of those types of contracts, the usual take-or-pay conditions. We'd like to see more of that across the other midstream assets. They don't all have that. But ultimately, if you have that, then if you ever decided to want to realize some value by selling down some of that ownership, then that would help you crystallize that value.

Over what sort of time frame are we talking about in terms of getting take-or-pay over assets like Port Bonython?

Look, I mean I wouldn't want to put a time line on that, James. It really depends. Essentially, those negotiations with third-party providers will have to play out. And how they play out, I wouldn't want to forecast. In some cases, the provider may not want to agree to that. And hence, that would be a different tolling regime. If -- it's all about risk/reward at the end of the day.

Your next question comes from Daniel Butcher from CLSA.

Dan? I think he must be on mute.

Your next question comes from Mark Samter from MST.

A couple of questions, if I can. I mean, first one, going back on the infrastructure. Do you have a feel for when you're going to be time-wise in a position to think about crystallizing the value in some bits of this infrastructure? I mean do we think that could be a later 2021 story? Is it a bit longer beyond than that you might think?

Yes. Look, I would think it'd be towards the end of this year that we'd be in a position where we'd have the structures established that would allow us to consider that option, Mark. So that's probably as much as I'd want to say on that without trying to go down any rabbit hole on it. But ultimately, it's about setting up those structures -- ownership structures for that collection of assets that gives you the ability to do that. And Anthony, I mean, don't know if there's anything you want to add to that? But timing-wise, we'd see that taking the bulk of this year getting all in place.

As we said, Mark, at the Investor Day, this year is about establishing the business and really getting those arrangements in place, so that -- and good line of sight and see through to an earnings stream.

Cool. And then second question, if I can, just on Barossa and just thinking about FID time lines and the cost side there. One of your very illustrious peers just said a few minutes ago that there's, if anything, downward pressure on the cost side and LNG projects and time is their friend there. And if anything, costs are going to come under initial expectations. Are you seeing the same thing where you can just kick back and relax and costs just keep coming down at these projects?

I'm not biting on that one. But look, what I would say on that, Mark, is we've given guidance. A lot of our costs are locked in. It was an offshore -- predominantly offshore project. So a lot of the contract packages are locked in and the costs are locked in. We're pretty happy with those costs. What we would see in terms of foreign shipyard costs and stuff like that is that if we were to delay FID on our project, the scopes that we are talking about, we would see more upward cost pressure than downward cost pressure. And my fear would be that as governments put in stimulus packages going forward, that's more likely to drive inflation than not. And we've seen when everybody starts driving the -- or trying to develop the projects in the past, typically, you see wages and costs going only in one direction. So we're pretty pleased with where we are at with all of our terms on our major contracts agreed. And in terms of the timing, that's about really closing out the final documentation on really 1 or 2 big contracts, the biggest contract, of course, being the FPSO. That's the largest component. And as you know, we structured the contract -- the hybrid structure of that contract to help us deal with this particular issue and get that low cost of supply down to the lower end of the market to around $2 per MMBtu when we're in production. And so we're pretty confident in our costs. We've locked all of those in. And as long as we take FID in the time frame that we've indicated both in this update and the guidance we gave previously, we'd be very confident in that cost structure.

Perfect. And then I might just chuck in one last question, if I can. It's a bit of like a bigger picture one. Obviously, the macro world around us is improving, but diversity at a time when there's probably more and more pressure on asset owners for some hydrocarbon assets, without blowing smoke up your guys' posteriors too much, you guys have done a lot of great work on M&A you've done in the last couple of years. And obviously, you're a company that the market backs to do good and sensible deals. When we think about the future of Santos, do you see the scope to capitalize on maybe others' misfortunes as we go through the next few years?

Well, look, I mean what we've said about the previous M&A deals that we did, Mark, was that they were opportunistic, but they were on strategy. And we're very focused about building the strength around our core assets. And what that does is it limits the risk. It means things can go wrong, of course, but it limits the risk. We're buying producing assets, assets that we know and really just strengthening our position. And that allows us also to then look at how we can create value through synergies in both the Quadrant acquisition and the Conoco acquisition. We've delivered very significant value through synergies. And I think you see here, we're on track to meet that latest guidance of between USD 90 million and USD 105 million guidance we gave in December. And let me tell you, I'm pushing to be at the top end of that guidance, not the lower end of that guidance. So -- and I'm confident we can achieve that. So look, I think that's -- our approach is around our 5 core asset hub. We're not out there looking for wild, opportunistic, off-strategy acquisitions. Any acquisitions we do in the future will help keep us on strategy and be consistent with the 5 core asset strategy and the sort of clean fuel strategy we've rolled out to you guys previously. But what I would also say is, the first part of your question there is our focus is on cost of supply because we can't control price. And so as a company, we run our business on cost of supply metrics in each market that we operate in and want to be at the lower end of the cost of supply curve. And what that does, as you saw in 2020, is it does allow us then to be able to navigate the tougher times and still generate free cash flows and pay dividends, but hopefully, allows us to really take advantage of the upswing in commodity prices. And you started off talking about macro conditions. It is my belief that demand will continue to grow. We saw -- even in 2020, we saw some LNG demand growth. And so it is my belief we'll see continued growth for gas and LNG, particularly and for oil. It will drive oil prices up in the longer term. And I only see supply lagging, and I don't believe all the LNG projects that were suspended will come back. And as you can see worldwide, it's getting -- it's taking longer and longer to prove -- to approve, I should say, oil and gas projects. Hence, I think the supply side was going to struggle to keep up, and that normally means we can see higher prices in the longer term.

Your next question comes from Adam Martin from Morgan Stanley.

Probably a question for Anthony, just hedging. I'm just wondering if now is the time to get a little bit more aggressive hedging some of those '22, '23 volumes. Particularly, gearing is pretty high. You're about to embark on some bigger projects, hopefully, in the next 18 months. So just wondering there whether you pursue a sort of more aggressive hedging strategy.

Yes. Thanks, Adam. Yes, look, from a '21 perspective, as you've sort of -- we've already said and you can see, we've -- we're pretty full. We've still got maybe a little bit of capacity if we want to do a bit more in '21, but we like our position. We've got 15 million barrels this year hedged. And when you combine that with our domestic gas contracts, which is about 40% of the portfolio, that means we've got well over half of our current year production hedged and mitigated to the downside in oil. And so then we do want to start to flow that into 2022 and 2023, particularly as we approach the growth in FID decisions. We've actually started hedging '22 this week with the pop in the market. So you can see in the investor pack on Page 45, we've actually done 2 million barrels of hedges this week with a 0 cost collar and a $50 floor. So we are commencing the '22 and beyond program. So yes, we will look at that.

Okay. Good. Just now Cooper Basin oil production, we've seen that sort of down in [Technical Difficulty]. Really the same issues we faced recently in Western [Technical Difficulty], et cetera. But how are you thinking about sort of chasing oil production in the next 1, 2 years, please?

All right. Well, look, Adam, we're really looking at maintaining sort of current levels of oil production in the Cooper over the next few years. Our focus has been very much on gas development and horizontal drilling in gas fields and gas wells. And as a consequence of that -- that's why you've not seen us really chase growth in the oil. And in 2020, of course, that was very much around the economics. Oil prices as well drove that. If we see a pop in oil price, who knows? We might direct the rigs to drill some more of the oil wells. But at this point in time, very strong focus on gas and continuing to put more of those horizontal wells into Cooper, which you can see are delivering higher sort of returns in terms of ultimate recovery per well and production rates per well for lower unit costs.

Okay. That makes sense. Just final quick question. Looks like very close to FID at Barossa. What are the sort of news or the remaining things you need to get done in the next few months to make that happen?

Well, really, the big one, now that we've certainly met all the conditions on the SK sell-down -- and I'll just reiterate, that now is finalized or crystallized on FID at Barossa. All approvals and all conditions are satisfied. And that's for the sale of 25% equity in Bayu-Undan and Darwin LNG. We've got all the processing agreements in place. And really, the big deliverable for us now is just the finalization of the FPSO contract, which we informed you in December we had agreed to all the terms on that. And so we're just finalizing the contract. And we would expect that to be a matter of weeks rather than months, and then we're essentially there to take FID. We are progressing the SPA with JERA in parallel, and that's got some requirements from those contracts that need to be completed before we can complete that deal. But we're progressing that in parallel, and that's for the sale of 12.5% of Barossa equity to JERA. So look, we're in the home straight. We've marked -- we've tied up the offtake agreement for our share -- our equity LNG. We've tied up the sell-down to SK. All the other contract packages are in place other than the FPSO contract, which, as I say, will be there in a few weeks' time. And so we've ticked all those boxes. And yes, you're right, it's getting close. We'd expect it to be in the next few months.

Your next question comes from Gordon Ramsay from RBC Capital Markets.

Reserves -- your reserves update, you had a pretty large downgrade for Reindeer. Can you -- that 27 million barrels, what percentage of that was of the total book reserves that you had for Reindeer? Just trying to get a feel for materiality.

Sorry, you broke up there, Gordon. Can you just repeat that question, please?

Sorry, just the downgrade in reserves for Reindeer of 27 million barrels of oil equivalent, what percentage of that represents the total reserves of the field?

Yes. Go ahead.

We don't give the specifics by field. The best way to think of, I suppose, the WA gas business is, it's 1 CGU. So from that regard, you've got all of the different fields flowing into both Devil Creek and Reindeer, and you can swing them between and accelerate between that gas hub, if that's a better way of looking at it, Gordon. So when we look at the total reserves and total production profile and when it flows through into the ultimate impairment, it's looked at as 1 gas CGU is a better way of looking at it. Actually, there's a [indiscernible] a whole lot of the gas, if that makes sense.

Yes. Okay. So if we look at the Devil Creek gas plant, how much gas going into that came from Reindeer?

Now, all of Reindeer gas goes into Devil Creek.

Yes. So you're looking at now Corvus. Would that -- is it going to be fast-tracked because of the sudden watering out of part of the field?

Yes. Well, what we have said -- look, we've still got quite a few years left with Reindeer going through at Devil Creek. But you're right, there's a number of prospects there. I think all over -- between very offshore Varanus and Devil Creek, I think we've got about 1,200 PJs of 2C of -- of non-2C opportunities to develop around there. What we're planning to do with respect to Reindeer is drill the Dancer well this year to give us some more capacity around the Devil Creek facility. And so that would be the first prospect we're going to drill there, and we'll do that as part of that drilling campaign when we're drilling in that region later this year when we're drilling the Apus and Pavo wells, and it's part of that drilling campaign at [ Danton ]. Of course, as you know, we're doing Spartan around the Varanus Island facilities as additional backfill there. So we've got an awful lot of contingent resource, and what this really does is it's really said to us, we want to drill some of that up a bit faster and start building the inventory back up again, and then we'll start that process with this year's drilling campaign.

Your next question comes from Saul Kavonic from Credit Suisse.