Santos Limited (STO) Earnings Call Transcript & Summary

Thank you for standing by. And welcome to Santos 2021 Half Year Results Question-and-Answer Conference Call. [Operator Instructions] The call will begin with Mr. Kevin Gallagher, Managing Director and Chief Executive Officer, providing some opening remarks. And we will then move straight to 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. .

Thank you, and good afternoon, and welcome to the Santos Half Year Results Question-and-Answer Call. Joining me is our CFO, Anthony Neilson. Anthony and I recorded a video presentation on today's results, which you can find on our website, along with the presentation pack. I do recommend that you watch the video if you get the time out, as it is certainly a riveting viewing. 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. Let me start by saying that I'm pleased to present another strong set of financial results that demonstrate the strength of our disciplined low-cost operating model. Good operational and cost performance delivered USD 572 million of free cash flow and underlying profit of $317 million. This was despite lower average LNG prices due to the lagged oil linkage in our long-term offtake contracts. The Board has declared an interim dividend of USD 0.055 per share fully franked, a significant increase from the previous interim. The dividend represents 20% of free cash flow and is consistent with our sustainable dividend policy, which targets a range of between 10% to 30% payout of free cash flow. The business performed well in the first half, and I'd particularly like to call out a record first half production and sales volumes, which enabled us to increase guidance to the upper part of the range. Our sales revenue increased 22% to just over $2 billion, which is a record for the first half. Our lower unit production costs, focus on safe, low-cost and efficient operations is continuing to drive reductions and is reflected in production costs of $7.97 per barrel of oil equivalent. I am pleased that our continued focus on costs sees a lowering of our production cost guidance despite cost challenges across the industry. EBITDAX was up 24% to $1.2 billion, driven by higher oil prices and lower unit costs. And our value-accretive low-cost supply of offshore infill projects at Van Gogh and Bayu-Undan have delivered excellent results, with strong initial production rates into our existing infrastructure. And finally, our very successful maiden debt issue in the U.S. 144A market where we raised $1 billion at a very competitive long-term interest rate. This was an excellent result for Santos and showed strong support from the capital markets for our disciplined growth strategy and industry-leading ESG position. We have now delivered more than $4 billion in free cash flow since 2016. And to recap, between 2016 and now, we've had to navigate 2 oil price crashes, an earthquake in PNG, a global pandemic and ongoing government threats of intervention and domestic gas markets. This demonstrates the strength and the resilience of our portfolio and our disciplined low cost operating model. In 2021, we are targeting a free cash flow breakeven oil price before hedging at around $25 per barrel, the same level as last year. At current oil prices, we would generate over $1.1 billion in free cash flow this year. And for every $10, the oil price is above our free cash flow breakeven price. The portfolio generates around USD 330 million in free cash flow before hedging. When I spoke to you in December at our Investor Day, I set out 5 strategic priorities for this year. I am pleased to say that we have ticked off 3 of these already, and the fourth to FID remember CCS project is on track for the second half as promised. Our first priority, of course, is maintaining a safe and strong base business with a free cash flow breakeven of less than $25 per barrel. We want to keep the business functioning efficiently and keep it low cost. And that's where our long-life assets with steady production profiles allow us to do. All activities within that base business are self-funded within the rules of a disciplined operating model. The second priority was to take FID on Barossa, which we did in March. Barossa is a world-class LNG project with a very competitive cost of supply into Asian markets. Barossa fits perfectly with our strategy for disciplined growth utilizing existing infrastructure around our core assets. It is also a tangible benefit of our acquisition of the ConocoPhillips assets in the region. And it is one of the lowest cost new LNG projects in the world and will give Santos and Darwin LNG a competitive advantage in a tightening LNG market. We're targeting a cash cost of production of around $2 per mmBtu, including the FPSO service contract costs. Barossa is basically an offshore scope with an FPSO and a pipeline tied into the existing Darwin LNG plant. Importantly, around 80% of the capital cost is protected under fixed price contracts, so we are not materially exposed to cost pressures seen across this industry. And the project is off to a great start with first steel cut for the FPSO turret in July and manufacturing of subsea flow lines and trees already underway. We are on track for first gas in the first half of 2025. I'd like to take this opportunity to thank our Barossa partner, SK E&S for their support in taking FID earlier this year. And we're also finalizing the sale and purchase agreement for JERA to acquire a 12.5% interest in Barossa. Our third priority was to take FID on the member CCS project. CCS is a key pathway technology to achieving our medium-term emissions reduction targets with the Moomba project now ready to take FID. All we need is for CCS to be eligible for carbon credit units in Australia. We're extremely encouraged by the draft methodology released by the clean energy regulator for qualification for Australian carbon credit units. With that consultation process now complete, everything remains on track for the government process to be completed in the next month, and then we will deliver on our commitment of taking FID on our Moomba CCS project. Moomba is the lowest cost and one of the largest CCS projects globally, as it benefits from existing separation equipment and depleted gas reservoirs with proven rock seal. We forecast a life cycle cost of less than $24 per tonne of CO2. Moomba CCS paves the way for a significant carbon reduction story for Santos and for Australia. It also means we are able to explore a 3-hub CCS strategy that covers Moomba, Bayu-Undan and potentially, offshore Western Australia. This infrastructure footprint potentially provides more than 30 million tonnes per annum of CCS capacity across 3 Santos operated hubs. Moomba will be the first project to hit the go button, but I am especially excited about the potential we have to repurpose Bayu-Undan as a CCS hub in the region. We estimate a storage capacity of around 10 million tonnes of CO2 per annum in Bayu-Undan once production from the field CCS. Our studies indicate existing wells and pipeline can be repurposed for CO2 service. And I would remind you that at Bayu-Undan project start-up over 1 Bcf of gas a day was injected into these high permeability reservoirs. So they are some of the best offshore reservoirs in the region for gas injection. Bayu-Undan CCS would contribute to decarbonizing Barossa from project start-up as well as opening up other resource opportunities and complementary industry opportunities in Northern Australia. We look forward to working with our joint venture partners and our host government to bring an exciting project to fruition. Fourth priority was to launch FEED on the Dorado oil and gas project, which we did in June. We plan to develop Dorado in 2 phases, an initial liquid phase followed by a future gas development providing supply into a domestic gas infrastructure in Western Australia. Entering FEED is a significant milestone and has the project on track for FID around the middle of next year for the phase 1 liquids development. FID on the second phase of gas development to backfill our domestic gas infrastructure in WA is likely to occur in the second half of the decade. Dorado is a very low CO2 reservoir with approximately 1.5% CO2 and with all gas reinjected in the initial phase. This makes it one of the lowest emissions intensity oil projects in the region. Potential tie-in opportunities to Dorado, starting with the Pavo and Apus prospects to be drilled early next year, could easily be tied back into the Dorado infrastructure and materially increase the value of the project. The fifth priority and the one we have not been able to progress as planned was to commence appraisal drilling at Narrabri. While Narrabri achieved state and federal environmental approvals last year, an appeal has been lodged against the state approval. A hearing on the appeal is scheduled for later this month, with a final decision not expected until the end of the year. The proposed merger with Oil Search is consistent with our disciplined strategy to grow around our core assets. It represents a compelling combination of 2 industry leaders to create an unrivaled regional champion of size and scale with a unique diversified portfolio of long-life, low-cost oil and gas assets. The merged company would have strong cash generation from a diverse range of assets, which provides a strong platform for sustainable growth and shareholder returns. The merger also builds on our industry-leading approach to ESG through the combination of Santos' net 0 pathway with Oil Search's unique social and community investment programs in PNG. As I have previously said, I believe that our industry must be in a position to self-fund growth and the energy transition to cleaner fuels. I believe this merger will create a company, which is better placed to achieve this goal than either of us stand-alone. I also believe the merger will unlock material shareholder value in 3 key areas: first, substantial combination synergies to the benefit of all shareholders using Santos' proven ability to deliver incremental value; second, through partner alignment in PNG to unlock incremental value just as we have achieved at Darwin LNG and Barossa following the Conoco acquisition and subsequent sell-downs; and third, options and flexibility for portfolio optimization in the Merge Group, including continuing with Oil Search's sell-down process in Alaska. We are currently undertaking exclusive due diligence on each other and expect this will be complete by the end of this month and are targeting to have the scheme vote and all approvals in place before the end of the year, which will position the merged company to hit the ground running at the start of the following year. Santos has a proven track record in delivering integration synergies from acquisitions. Both the Quadrant and ConocoPhillips acquisitions delivered over $160 million in synergies from areas like duplicated overhead and corporate costs and OpEx and CapEx savings through applying a low-cost operating model. From the Oil Search merger, we'll use the same approach and the same team, which we expect will deliver significant synergies for the benefit of all shareholders. We will be able to provide further guidance on potential synergies once we have completed due diligence. Something I've been very pleased with this year has been our success in delivering incremental value from assets that we have acquired. In the case of both Bayu-Undan Phase 3C and Van Gogh Infill Phase 2, these are projects that represent upside value over and above our acquisition cases. They are perfect examples of our strategy to deliver incremental value from short-cycle, low-risk opportunities around our core assets using existing infrastructure. Both projects have delivered better-than-expected reservoir outcomes and strong initial flow rates from the first wells. We look forward to completing the remaining 4 wells on these projects over the course of the second half. This focus on driving incremental value from the assets is something we will bring to the Oil Search merger. In summary, it was a strong start to the year for Santos. The business is performing well, and our operating model sets us up for disciplined growth. The potential merger with Oil Search creates an exciting opportunity to create a regional champion of size and scale. And with size and scale comes the opportunity to accelerate our aspiration to becoming a clean fuels company and reaching our net 0 commitment by 2040. With that brief opening, we'd now be happy to take your questions. Thank you.

[Operator Instructions] Your first question comes from James Redfern from Bank of America.

I just want to ask a couple of questions about the proposed merger with Oil Search. Assuming the merger goes ahead, Santos will have a 42.5% equity interest in PNG/LNG. I was just wondering would Santos be happy with that level of equity in the project? Or would you be interested in selling down? I guess if you were looking to sell down, what would be Santos' either equity interest in PNG/LNG? And I've got one more after that.

Well, look, I mean I think all I would say on that, James -- and by the way, thanks for the question -- is that I think when you put the 2 companies together, it gives you the opportunity for portfolio optimization, and we've said that from day one. 42.5% is a very high equity level in a project, so that in itself creates the opportunity for further alignment in PNG and the ability to optimize that portfolio, strengthen the balance sheet and support the growth plans going forward. Look, I'm not going to say what the ideal equity level in the project would be. I think for any particular asset, we'd only talk about that once we're in that position where we know what the opportunities look like.

Okay. Okay. Well, I mean I might try one more in relation to the Alaska oil assets. Any comments you can make around, your view on those assets and whether you'd be happy to give up operatorship of the picker unit, assuming the merger goes ahead and the proposed sell-down?

Yes. Look, I mean, what we have said is we'll continue with oil searches sell-down. We believe that perhaps we can have more flexibility than was offered previously during the sell-downs. And that -- we're not wed to operatorship of any asset if the deal was right at the end of the day, and that includes in our current portfolio to date. So look, I mean, I think all I would say is that we'll continue with Oil Search's plans to sell-down, and we'd be very flexible on what that would look like in terms of operatorship.

Your next question comes from Dale Koenders from Barrenjoey.

On the slide that mentions on PNG/LNG, the JVs recommenced discussions in July on expansion. And obviously, you flagged a strategic rationale to realign JV interest. Is there also a scope to revise the current proposal of the 2 small trains? Are stakeholders open to this? I'd assume there's obviously greater value and greater capital efficiency if you can bring Total into the foundation project to move back to larger train designs.

Well, look, I mean I think that's all yet to be seen, right? And I wouldn't want to predict how any of that plays out deal. Look, I think the bottom line is that all of those options are there in terms of looking at how we optimize the portfolio, how we optimize the equity positions and how we optimize the development projects going forward. We're going through the DD process right now, and in that, we're getting a better understanding of the expansion project. But it's too early to make comments like that. I'm actually surprised at your question, Dale. I thought you were calling up to say I told you so about Arcadia and how good the Arcadia fields are developing, which I would have to give you credit for. But so that's all I can really say on the PNG stuff at this stage.

Okay. I might try my luck not on Arcadia, but on the synergies. It sounds like you're trying to avoid quantifying them. But can you talk about the areas for cost synergies? Is it just around corporate costs from Oil Search? Or is that there are other areas, given there's limited gas marketing when we're trying to think about how big these could be?

Look, I mean, most people think of synergies in terms of just people, right -- people synergies. I'm sure there's a component of that. But as we saw both with Quadrant and with ConocoPhillips, we were able to realize significant synergies, not only in the corporate areas but in areas like IT, our direct OpEx. One of the benefits of having a number of facilities, midstream and upstream facilities that we operate, is that we can centralize a lot of the engineering and maintenance planning efforts and we get scale benefits that are quite considerable. We've seen that across many of the assets that we're operating here around Australia. Now if you think most oil and gas companies have 1 or 2 assets to operate. We've got 7 midstream assets we operate around Australia, and that's been able to realize very -- or we've been able to realize very significant scale synergies and benefits from that. And then there's other things contractually. With scale, you typically get better global contracting arrangements and outcomes, and we've been able to see benefits there also, as we've brought in the ConocoPhillips and the Quadrant organizations into Santos.

Interest insurance, treasury sort of areas, Dale. So across the board, little bits and pieces, they all add up as we start to get inside and have a look. But we're in the middle of the due diligence at the moment, so we're still going through to get that quantification. So we want to try and do that at the end of the DD period.

And so when we look at the sort of synergies that we realized in both those previous acquisitions, we can see significant potential here. And you're right. I'm not -- I don't want to give guidance on that yet until we've completed the DD process because there's always pluses and minus when you go through DD in these things, and then we'll give the most accurate guide as we can once we're in a position to do so, hopefully in just a few weeks' time.

Your next question comes from Mark Samter from MST.

I've got 3, if that's not taking that too much. First 1 on the -- just a bit more detail on the infrastructure side, obviously and particularly, can I presume with your permission, giving us details around the financials of the Total deal. I'm curious whether someone getting 9x EBITDA for what is purely a financial instrument, can you carry volume risk, but you're not giving up any operational control or any operational impact whatsoever. Has that changed the way you view some of that more core infrastructure? And I'm also curious just whether there's any change in timeline expectations on the infrastructure with the Oil Search transaction? Or are you still full steam ahead?

Well, Mark, as you would know, my CFO doesn't show a lot of emotion, but gets very excited to talk about infrastructure. So I'm going to throw that 1 over to him because he likes talking about it. So Anthony?

Yes. Thanks, Mark. Look, that's a look through like-for-like that we've sort of had to back calculate from the Total Energies transaction, but it's a pretty close proxy to the value that they got, which was $95 million of EBITDA per annum. So I think you're right. It shows that there is appetite out there for a sort of 9 to 10x transaction that is largely a synthetic financial instrument like you said. So it was a very good value point for us to be able to sort of show what we've been talking about now for the past year because, as you said, I think it was in your note that the rest -- that EBITDA in our portfolio is trading at 4x to 5x. So if we can unleash that incremental multiple of an extra 5x on a $500 million EBITDA business, including GLNG, then you're potentially looking at a quite a significant value uplift of over $2 billion, if you just apply that multiple. So I think it does show that there's appetite out there. It shows that there's money out there. It gives us the flexibility and the options as another source of capital as well. And in terms of the last part of your question, look, I think it's something that when merger goes ahead that we need to look at in the tools that we have around all balancing out all of the capital management we have across all the different projects. And as Kevin said, looking at the alignment across the projects as well. So I think this is still on the agenda for us. It's just going to be in part of a bigger portfolio.

And I guess my next couple of questions actually kind of tie into that last point as well. And I'm just curious with the Dorado sell-down. Is there logic to finding out how much of Alaska you're able to keep and end up keeping? Just from a kind of portfolio balance perspective, how much liquids you want in the portfolio? Or should...

Well, look, I mean, I think that's a good question. I mean, sometimes the timing of these events are going to take care of themselves. But look, ultimately, we're looking to have a balanced portfolio. We've always said that we like the idea of having a certain share of our portfolio that's fixed price domestic gas contracts. We want a certain share or exposure to the LNG markets. And of course, then you've got your liquids markets that we like to have an exposure to as well. And so having a balance in the portfolio, not too dominated by any one, is important to us, and we've seen the benefits of that through the cycle when oil price has crashed in recent years. Those fixed price domestic gas contracts come to the fore. And obviously, when oil price goes up, our LNG and our oil or liquids products then sort of carry the weight of the revenue stream. So we do want a good balance, and we don't want to be too exposed to anyone. But yes, to answer your question specifically, yes, looking at what you may end up being left with in Alaska following Oil Search's sell-down process would be an important consideration.

Okay. And then just last quick one in terms of the bit of a kind of wonky big picture one. And it is putting the cart before the horse because [indiscernible] asset sell-downs. But I guess there's a world where you do sell-down a reasonable size stake in PNG LNG and all of a sudden, the businesses -- I mean, [indiscernible] with the ability these companies need to be able to fund themselves. But do you have a view on what you think is an optimal balance sheet for an E&P in the go-forward world and no debt's inefficient? Do you have in your mind where you would ideally like to see the balance sheet look in 12, 24 months post completion?

Well, look, I mean, I think we've said historically that, that 20 to 30 range is a great place to be through the cycle from a gearing perspective and probably targeting around 25%. Going forward, that might be more in the 20% to 25% range as a much healthier place to be because you're right. You don't want to get too lazy and have a lazy balance sheet. But I think what we want as an organization has got enough cash flow generation that we're effectively funding or able to fund our growth projects, pay a dividend and self-fund all of our sustaining CapEx within that and not be too leveraged when inevitably the commodity cycles turn against you.

Your next question comes from Tom Allen from UBS.

Question on CCS. So given the Moomba gas plant is currently emitting 2.3 million tonnes per annum, and Beach have indicated their intention to opt in for their share of the project, how come the scope is still only for a 1.7 million tonne project rather than all the emissions from the plant? And can you just confirm which specific reservoir will be first targeted for CCS?

Yes. Look, I mean, the emissions that we're capturing are reservoir emissions. So the reservoir -- the emissions that get separated out at Moomba, but they come from the reservoir. We still have what we call combustion emissions. So the emissions that come from running the power plants at Moomba, we're not capturing those yet. So we'd have to have economic post-combustion carbon capture technology available to that, which I might talk a bit later. But -- so it's the 1.7 million that come from the reservoirs that we're capturing and then we're injecting them into the upstream reservoirs. And the first one, I can't actually remember the specific deal, but as we've said before, we have something like 20 million tonnes per annum of Cooper capacity for the next 50 years. It's available to us across all of those reservoirs, across the Cooper Basin. So it's just come back to me, stress lecky. So it's a stress lecky field that we're injecting into initially, and that's Phase 1. And I think that gives us the first 7 to 10 years, I think, before we have to move to an adjacent reservoir. So we've got a lot of reservoirs, all set and depleted over the years, great inventory. And I believe it won't be too long until we start to share that capacity with you just the same way we book reserves today. We're working through the PRMS to start to credit storage capacity, and that will be booked in the not-too-distant future and be part of our annual reserves and I suppose capacity statements that we'll put out. There also another project in the Cooper Basin, our upstream nodal optimization project, which we're just going through the final stages of approving internally over the course of the next 2 to 3 years, where we'll be electrifying, as part of a larger Cooper electrification project by electrifying some of our compression in power gen and the upstream satellites. What that does is that allows us to bring more CO2 than back to Moomba that is currently -- where the gas is currently being consumed to drive the compression in the power gen at the upstream satellites to date. And by bringing that back to up to Darwin -- sorry, bring that back to Moomba -- Darwin would be one heck of a pipeline -- bring that back to Moomba, we'll then add to that 1.7 million tonnes over time. And so that's something we'll be doing over the next few years. And not only will that bring us more CO2 to inject and generate more carbon credits, what it will also do, and this is very important, is it will produce more sales gas because we'll burn less gas for power gen and essentially be running poles and wires from the Moomba power facilities to operate those upstream facilities.

Sure. And then based on your read of the draft legislation from the clean energy regulator, do you think you'd still be eligible for Australian carbon credit units, if you saw a little bit of incremental production from injecting CO2 underground via enhanced store recovery?

Well, look, I mean, the regs and the legislation is focused on CCS, not CCUS. If that happens in the future, that will be the case. But our project is built to only inject and store and permanently store the CO2. So that's what we are focused on. We're not focused on enhanced recovery of any fields. And so our focus here on this project is purely as a carbon capture and storage project.

Sure, sure. And then just lastly, on your plans to build out the scale midstream business, can you describe -- so you're pointing to potentially beefing up the EV with the synthetic toll from, GLNG. But can you describe how you might bring the CCS project into the scope of the midstream EV and how we should think about open-access tolling on carbon sequestration and how the value of ACCUs might be shared?

Well, look, in the Cooper Basin, that's going to be a bit more restrictive, right, because it's not close to other industries. It's not close to a lot of other fields other than the Cooper Basin operators that we have today. So I don't anticipate a lot of third-party CO2 being transported into the Cooper Basin. That said, Santos is investing in direct air capture technology, both post combustion and direct air capture, and looking to get a target price there below AUD 50 per tonne to capture. And if we're able to achieve that in the years ahead, depending on carbon price, then that opens up the opportunity to offset other people's emissions in the Cooper Basin. And given we have such a large capacity of up to 20 million tonnes per annum capacity, that creates future offsetting or tolling opportunities for us in the Cooper. And we'd be very -- well, we are very excited about our opportunity for the longer term. But the carbon price isn't there yet. It's not there to make that economic yet, but we do believe that will happen in the years ahead, not too far into the future. DLNG, however, is a bit different. So when we look at the Bayu-Undan CCS opportunity that we're pursuing, that would be looking to take around 2.3 million tonnes from Barossa and Darwin every year. But it has a capacity of up to 10 million tonnes per annum. And so we're looking at other projects in the region there and third-party access there is an opportunity. And that can become a very lucrative opportunity, not only for oil and gas projects, but for other industries in the Darwin area that could or would be emitters. And so we see that as a real exciting opportunity. There's a bit of work to do in that, but all the studies so far are very encouraging. We have a number of MOUs with our partners, both at Darwin and Bayu-Undan. We're working with Australian and Timor-Leste regulators on this project. I believe it's a very exciting project, but a water to go under the bridge on that one. But if we're able to get that up, I think that is a very exciting opportunity.

Your next question comes from Adam Martin from Morgan Stanley.

Just first question, just on Van Gogh. You disclosed a pretty good flow rate, 23,000 barrels a day. You've got reserves there of 10 million barrels back in 2020. Are there any reserve implications here?

No, we wouldn't have thought so at this stage. Obviously, if there's an outperformance, that would change it. But at this point, it's pretty much in line with...

The 2P numbers are in the presentation, Adam, in Page 16, which was -- VG was 10 million barrels gross at year-end.

That's right.

Yes. Okay. And production costs in Northern Australia about $70 million a quarter, obviously coming down nicely. Is that the sort of new run rate from here? Or are you expecting to lower that again?

From an OpEx perspective, you're saying?

Yes.

Yes. So look, we're definitely in the bottom end of the range. So I think that's obviously the place we'd like to be. The range is 790 to 830. The reason it's got a bit of flex in the range, obviously, FX, as I said in the presentation and has sort of been pushing us a little bit higher, particularly in the onshore assets in Cooper Basin, although FX seems to have eased off a bit in the second half, which is good news. So the lower U.S. FX rate helps us from that sense. So that will hopefully -- the easing of the FX helps us keep towards the bottom end of that range. And the other thing that hit us hard in the first half, and obviously, it's hard to see the impacts of it, in the second half would be, is COVID costs such as quarantining in particular,and extra sort of security and sanitization costs, et cetera, across the organization so...

Those particularly for Northern Australia.

Yes, particularly in Northern Australia with the Bayu-Undan field because it's offshore, and we've got Timor-Leste people as well coming on to the platform. So those 2 things aside, yes, that is the trajectory on a normalized basis. So taking those things out is in the bottom end and coming down.

Okay. And final question just on the merger just in due diligence. I mean if you have to describe the sort of 1 or 2 key focus areas there, what would that be?