Earnings Transcript for BPT.AX - Q2 Fiscal Year 2021

Matthew Kay: Hello, and welcome to the FY '21 Half Year Results Presentation from Beach Energy. My name is Matt Kay. I'm the Managing Director and Chief Executive Officer for Beach. Joining me on the call today is our Chief Financial Officer, Morné Engelbrecht. And we're also joined by the Beach Executive Team. For today's presentation, I'll first provide an introduction on the current state of play at Beach Energy. Then it will be over to Morné, who will run through the financials, and then I'll provide an update across our portfolio of assets. Following that, we will open the lines for Q&A. Before I begin, Slide 2 includes our disclaimer, price assumptions as well as information regarding our reserves disclosure. I'll leave this for you to read in your own time. So let's move on to the main presentation. There's a lot of information to get through today. So Slide 3 captures what we consider to be the key takeaways. My message to you today is that Beach is on track to deliver on its 5-year plan. Growth is happening and it's happening across the portfolio. The 6 takeaways which I'll explore in further detail today are as follows

Morné Engelbrecht: Good morning, everyone, and thank you for joining us today. As Matt has already touched on, the results from the Western Flank and the impact from the major planned maintenance at the Otway gas plant were not going to affect our sales volume and revenue during the half. This was further impacted by an almost 40% fall in the average realized oil price when compared to the first half of FY '20. Beach reported an NPAT of $129 million during the half; and an EBITDAX of $446 million, resulting in an impressive sales margin of 63%. In accordance with accounting standards, Beach continued to expense exploration items not within an established area of interest. This resulted in the company expensing $39 million of greenfields, frontier exploration expense during the first half of FY '21. This mainly relates to the unsuccessful Ironbark well and the relinquishment of the Wherry block in New Zealand and permits in the Bonaparte Basin. This resulted in EBITDA of $407 million. Beach continued to have an impressively strong balance sheet supported by stable revenue from our gas business, the backbone of the company. We've access to more than $400 million of total liquidity, including $114 million of cash. We have moved into a net debt position recently following the impact of the weaker commodity prices during the first half. However, at net gearing of 1.5%, we continue to have broad flexibility with our robust balance sheet. Our stable gas business continues to provide a platform for the company, with gas and ethane sales accounting for more than 40% of our total revenue. This is despite the Otway gas plant being offline for 22 days for planned maintenance. It should also be noted that more than 99% of our gas volumes were sold on the contract, providing downside protection. Oil prices have improved more recently. We are not taking our eyes off our cost base. Unit field operating costs were down 2% on the previous corresponding period. And positively, our operational team managed to deliver the Enterprise 1 campaign approximately $8 million below budget, a great achievement. Slide 15 provides more detail of our financial highlights. Production was steady when compared to the prior corresponding period. However, revenue was down 22% due to an almost 40% fall in average realized oil prices. The flow-through impact of [weaker] revenue resulted in an underlying EBITDAX of $446 million, down 28% from the prior corresponding period. As previously mentioned, EBITDA of $407 million was impacted by $39 million of exploration expense items. Also, as Matt mentioned, the Board has elected to pay an interim dividend of $0.01 per share fully franked. Moving to Slide 16, you can see the underlying NPAT movements over the first half when compared to the first half of FY '20. As previously mentioned, Beach delivered an underlying NPAT of $129 million, down 53% from the corresponding period. Revenue was the largest factor, falling by more than $220 million, including a $27 million reduction in other revenue mostly associated with the unwinding of the GSA liabilities and exploration expense, driving a softer NPAT. This was offset by lower operating costs, reduction in royalty payments and lower tax. Slide 17 shows the results on a segment basis and the key drivers of production during the period. It was again worth highlighting the impressive EBITDAX margin across all 3 segments, with a total group margin of 63%. Slide 18 reiterates our current financial position. Beach remains well capitalized to deliver on the FY '21 and '22 investment program. On the left, you can see the changes in the movement in our cash position, with operating cash flow of $296 million down 16%, impacted by low revenue and $128 million of income tax paid. Cash capital expenditure of $345 million was down 18%. This included drilling costs for Enterprise and Ironbark, offset by reduced Cooper Basin and Western Flank costs as activities reduced to single rig. It's also worth noting that -- when the contracted acquisitions for the Senex Cooper Basin assets and Mitsui's interest in the BassGas settles, that the amount of the net cash outflows will depend on the final cash flow adjustments from the effective date of 1 July 2020 to the settlement date. As previously highlighted, we maintained liquidity of more than $400 million, with the current cash and available undrawn loan facilities expected to support the delivery of our growth program. We're also currently assessing the federal government's stimulus initiatives that allow us for an instant tax write-off of qualifying capital assets. This measure is expected to have a positive impact on our operational cash flows over the next 3 years. Importantly, Beach remains a growth-orientated company with highly value-accretive organic growth opportunities which we are in the process of executing. Free cash flow will continue to be reinvested into our high-returning projects, the majority of which allow us IRRs in excess of 20% and short-term payback periods. With that, I will hand back to Matt. Matt?

Matthew Kay: Thank you, Morné. Before I go into a snapshot of our asset portfolio, I want to talk a little bit about the current dynamics of our markets. On Slide 20, you will see that Beach's geographical diversity and market distribution is across 3 gas markets

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

James Byrne: So yes, really interesting presentation in the context of the 5-year outlook. You've had obviously the acquisitions in the Cooper and the Bass Basins and you've described Enterprise as being a cracker, but I guess I've just noticed a subtle change in language in terms of the production outlook now being meeting 37 MMboe by FY '25 as opposed to the prior stated goal of 37 MMboe to 43 MMboe. It just feels like you're deemphasizing the top end of that range there, so it does feel like it's a bit of a softer outlook despite the fact that you've had those acquisitions. So is it are you just deemphasizing that because of the uncertainty around the Western Flank decline rate? Or is there anything else in the portfolio that maybe is performing below your expectations?

Matthew Kay: Thanks, James, for the question. No, look, there's nothing else in the portfolio that's delivering below expectation. We've fully disclosed today anything that's happening on the assets. And I think we've been very clear about the Western Flank, or as clear as we can be right now. All we're saying is that, that 37, we always said, was base target and then we had an upside target above that. We've got a slide there which pretty much shows you what those key assumptions were and what the track record is. And what we're seeing at the moment is a high degree of confidence in terms of delivering on the base because of Enterprise and because of Waitsia FID. And then you can see exactly what we need to happen to have the higher case come in. Now the fact that we're progressing Trefoil will absolutely help with that. The great thing about our portfolio right now is -- having 6 production hubs is we're going to have ups and downs and ins and outs from all of those assets, but we now have diversity where, if one of the assets has a downturn, then the other assets lift the game, all right? So we're very, very confident on the 37. A high-side case will depend on a few other things coming in. And what we've done has been pretty clear in that slide to flag what those items exactly are.

James Byrne: Yes, I got it. So if I look at -- I think it was Slide 23. I can't remember but -- the table with all of the growth projects. You've reiterated the very high IRRs from the Western Flank, 20% to 100%. If I think about those new wells you're drilling that are effectively cannibalizing production from other wells and yet you've still got very high IRRs, is it right to say that you're probably thinking about still committing to reach higher volumes consistent with that 5-year outlook but, I guess, it would come with a higher capital intensity? Like it's still NPV positive because of those IRRs, but you're having to spend more CapEx to achieve that same volume. Is that fair, or do you just not know yet?

Matthew Kay: No. Look, I think the way to think about it is the reason we've reduced the band on some of those rates of return in the Western Flank is, if you roll back 2 years, the vast majority of our production in the Western Flank was coming out of the Namur wells, which we were getting incredibly high rates of returns, over multiple hundreds at the same IRRs. A lot of our production is now coming out of the McKinlay. And we're also working obviously some of the other parts of the basin as well, well up Birkhead. And on some of those campaigns, we're seeing lower returns than the pure Namur play. So we're just showing the range at the moment. From our perspective, in terms of exactly what's going to happen here going forward, that's where we want to do the work before we come out and announce to the market. There's a range of options varying from accelerating drilling on wells, going to slowing down, going to targeting gas first, going to targeting more of the Senex acreage. The great thing about the Senex acreage is it's a good add for us that gives us some opportunity to work out which elements we want to move forward on first, but we need to do the technical work, frankly. That's why we're not being too explicit today.

James Byrne: Yes, got it. And then the last one for me

Matthew Kay: I think, what we've said in terms of this year, there is obviously 2 acquisitions that we've undertaken. Therefore, we've got higher equity at Trefoil. We've obviously got the Senex assets as well. So clearly, that will come with some additional CapEx but also additional production and additional value. The process is going in our planning cycle right now. This is where we start doing our 5-year planning recap, so we've got a chance to do that, and at the right time, we'll update the market on what the future looks like. I don't expect it to be substantially different from what's already out there, but I want to withhold being definitive on that until we can come out post our 5-year planning, replanning with that new portfolio.

Operator: Your next question comes from Mark Samter from MST Marquee.

Mark Samter: A couple of questions, if I can. Just to leave nothing to doubt. Can we be crystal clear on the 37 million barrels that you're still targeting in FY '25? Does that include now Trefoil and Senex assets? Because I mean, Trefoil, your production guidance would give you -- the acquisition gives you another 1.5 million barrels, and then Senex there's another 0.5 million barrels. Should we see this supposed reiteration of guidance actually being a 35 million barrel target for the original portfolio and we've added through acquisitions to that?

Matthew Kay: Not in relation to Trefoil, Mark. Trefoil would send us -- if it comes on in FY '25, which would be the plan, would send us well above 37, so I wouldn't count Trefoil in. In terms of our confidence, I think the main issue is the 2 key things we had to land was one FID on Waitsia-2 and exploration success in the Otway, which we now have. And then you have the ins and outs in basically what will happen on the Western Flank going forward. So we're very confident mainly because of what's happened in the west -- or what's happened in the Otway. And then the ins and outs will be what happens on the Western Flank going forward, but it doesn't rely on Trefoil.

Mark Samter: I mean, I guess, can you just help us contextualize that? You're talking about an increase in confidence, but if we go back and look 2 years ago what you were targeting for FY '20 and FY '21, you've had 10%-plus production misses versus those original targets. And you spent 50% more CapEx over those 2 years to achieve much lower production. I guess, what's different about the next 3, 4 years? And why we should, I guess, trust your enthusiasm for that outlook; and yes, what you've seen over these last couple of years that has made you reasonably materially miss your expectations on higher CapEx?

Matthew Kay: It's a fair question, Mark. I think, if you look back what's happened in the last 12 months, you have to take into account the decisions we made during the downturn. So decisions, one, to reduce some of our drilling in the Cooper; and more importantly, the fact we in effect delayed the entire Otway program by about a year predominantly because of COVID and the fact we were in a $20 oil scenario for a while there. So we've been very clear with the market on those moves we've made and the impact it's had, but a predominant issue, if you think back, the last 2 years has been the fact that we slowed down the Otway Basin drilling program by almost a year.

Mark Samter: Okay. And just one sort of around the Otway. I know you said in the answer to James that not less than some of the Western Flank have underperformed, but if we go back to your August result, the chart showed Otway doing about 30 PJs growth this year. And I mean, gosh, even if you did 100 [TJs] a day, which at the moment you're doing 50, you'd be like you'd hit 25 PJs for the year. Should we think about the existing wells potentially underperforming? Or is that all customer nomination?

Matthew Kay: That's customer nomination related. So what -- being obviously a gas business, what you see in terms of our fluctuation in the Otway particularly normally depends on customer nominations.

Mark Samter: Okay. And then just one quick last question, if I can. At the full year '20 results, you gave us oil production guidance of 9.2 million to 10.2 million barrels for FY '21. If we look at that underlying production guidance, to some excess, you've given us the group number, obviously, but can you tell us what the oil production assumption is within this, the new guidance?

Matthew Kay: Probably easier just to disclose to you what's happening at the moment on the Western Flank because that's really the change. So obviously what we said is we were expecting the Western Flank to be running by the 20,000 a day, and what we're seeing at the moment is we're now sitting at around 18,000. And that's purely really because predominantly the interference that we're seeing between those new wells from the FY '20 program across the existing producers. So that's been the key impact. I think that's the focus area for us.

Q - Mark Samter: Okay. And I guess that's -- mathematically filters through into FY '22, that by the time you've taken your decisions, I mean, even if the conclusion is to add a second rig and go hard, obviously you're going to be cycling much lighter production than thought. So I guess we should think there's a pretty material filter-through to FY '22, potentially in FY '23.

Matthew Kay: No, I'm definitely going to hold my response on that question. It's an appropriate one, but I'll hold my response until we've done the work because it will depend on what we come out with. It will also depend on what happens to those wells going forward over the next few months and how they settle down. Geoff, I don't know if you want to comment.

Geoffrey Barker: Yes. We've still got 8 wells to connect, 6 or so, from -- to drill and another 8 -- including 8 wells to connect. So there's a fair way to go yet and a couple of fracs we've got a chuck in as well. So a lot of the wells that are going to contribute to production. We haven't seen what their performance is like yet.

Matthew Kay: That's -- it's the right question, Mark, but it's too early for us to answer it accurately.

Operator: Your next question comes from Adam Martin from Morgan Stanley.

Adam Martin: Yes. Just on the Western Flank. Those decline rates, are they similar in both horizontal and vertical wells? Any difference there? And is this likely to have a reserve implication in August? How are you thinking about that at this point, please?

Matthew Kay: Yes, I'll have a go at that, Adam. And then I'm sure Geoff will add something. In terms of what we're talking about, really we're talking about Bauer. And we're really talking about some interference between the new wells and the historical producers both at Namur level and McKinlay. At the moment, it doesn't necessarily mean it will have an impact on reserves. There's a lot of data obviously that we're working through right now. There's 30 to 40 kilometers of laterals in McKinlay. There's course. There is production from about 150 wells, so there's a lot of data we're working through, but it does not necessarily mean that it will have a reserves impact. But Geoff is a reserves expert. He might want to comment.

Geoffrey Barker: No, I really don't have anything more to add. I think you covered it off pretty well, Matt. The reality is that we are assimilating a lot of information from a number of recently drilled wells. We've currently got about 40 horizontal laterals that have been drilled. 25 of those are in Bauer. As I said, we've got another 6 to 8 to go. We'll build 16 wells this year in the first half, this sort of first half. There's a lot of information that we need to assimilate before we come out and make a prediction on what the reserves will be.

Adam Martin: Okay. No, it's good. And next question, just on Enterprise. You've put in 63 TJs that it flowed at. Should we expect similar production rates when that's tied in first half '23, or lower? What should we expect from Waitsia?

Geoffrey Barker: Yes, look, the well potential is good. And we can expect those sort of initial rates.

Adam Martin: Okay, good. And that -- and final question, just on Waitsia. Can you just remind, is that joint marketing with Mitsui? And perhaps just a bit of color on sort of what countries, markets you're trying to market to there, please?

Matthew Kay: It's -- no, it's separate marketing, so we're marketing separately. We -- as I've mentioned previously, Adam, we've got a very experienced LNG marketing team in place that have been with us for a little while here, knowing where we were heading. Did we want to market heavily during the market downturn and COVID peaks? No, we didn't, so we held off. From our perspective, we're doing one-on-one engagements at the moment. We'll probably have a tender process running forward. We're getting very good interest because of the volume we're talking about and the reputation of North West Shelf, we're getting good interest not only from the longer-term customers but also getting interest from the traders. And so we've got all those options open to us. We haven't made any decisions on how much we're going to contract and how much we're going to hold back to spot. Because of the limited CapEx relative to greenfield and brownfield LNG projects that we have ahead of us, we've got that optionality. It's too early to speak exact countries and exact terms and what our price linkage will be. At the moment, the answer is all options are on the table as they should be at this point in time.

Operator: Your next question comes from Daniel Butcher from CLSA.

Daniel Butcher: Just one quick one, to start. Just I mean the result from Enterprise looks very good and well above what we assumed for that well. I'm just wondering. Does the size of that discovery and liquids contents change your views on the pre-drill expectations for Artisan or any of the development wells? And if possible, can you give us a rough feel for what you think they might come in at?

Jeffrey Schrull: No. Enterprise is in a separate previously undrilled basin, hence the -- we've never seen condensate rates of 25 barrels per million. So our size and enthusiasm for Artisan remains unchanged. And the -- of course, at Geographe and Thylacine, we've got well controlled. Those are infilled 2P undeveloped reserve wells, so...

Matthew Kay: I think the difference is, Daniel, that we have existing prospects and leads around Enterprise that we can drill off the same pad. So that gives us a lot more confidence for those, and we can mature those. And hopefully, we have the challenge going forward of how we're going to sequence these wells on these fields. That would be a nice challenge to have.

Jeffrey Schrull: There were a few bits of good news. One was the liquids rate, and the other was low condensate -- excuse me, the low CO2 percentage that we saw. So then that -- those 2 risk elements are much lower for any further drilling.

Daniel Butcher: Sure. And would you care to give us a rough estimate of your pre-drill estimate for Artisan then?

Jeffrey Schrull: No, can do.

Matthew Kay: We haven't...

Daniel Butcher: Well, it's worth a try.

Matthew Kay: Worth -- it was worth a shot, Daniel.

Daniel Butcher: Can we just go back to Adam's question maybe just to fill in a few things there? You gave the IRR for Waitsia this time. It's 20% roughly, and I'm just curious. I take that you mentioned you'll hold back for them to spot. You're not quite sure how much. Can you maybe give us a few more of those options that go into that number? We've got CapEx, so far. I mean, what sort of average LNG price are you assuming? Or you assume a certain oil price and slope in there. Or what do you think to get to 20%? I've got a lower number, so far.

Matthew Kay: Yes. No, look, I think we're well above 20% is what we're saying. So from our perspective, Daniel, I think we've given you the rates. We've given you the timing. We've given you the CapEx. You can use your own seriatim process on top of that, from our perspective, on what we see as prevailing forward curves, the type of returns we're looking at, hoping to get more, having to hit peak and get the marketing spot on. But what we can say is this is a highly economic project. You've got high deliverability from onshore wells already connected into the Dampier to Bunbury pipeline. You've got a tried-and-tested cookie-cutter, in effect, plant to go in as well. And then we go through North West Shelf with all the credibility of the North West Shelf facilities and offtakes, so we're very strong in terms of how that project sits and its returns.

Daniel Butcher: Okay. If you have time, one very quick last one

Matthew Kay: Guys, do you want to try that?

Morné Engelbrecht: I think it's -- I mean, on the number, it was pretty evenly split between the 2 halves. So we've given the range today on one of the slides in terms of the guidance in terms of what we see coming from the acquisitions, which I think was around 1 to 1.3 for the year.

Daniel Butcher: Yes, Slide 12, yes, right, but the bottom end of 1, less the 0.7 from the first half, would imply 0.3 at the low end for the second half. I'm just curious about that.

Morné Engelbrecht: Yes. Look, we can get back to you afterwards, both Mitsui and Senex acquisitions. So both of those.

Matthew Kay: We would be happy for you to dig into the detail with Chris, Daniel.

Morné Engelbrecht: Right, yes.

Operator: [Operator Instructions] Your next question comes from Gordon Ramsay at RBC.

Gordon Ramsay: Just on the Lattice negotiations. I know you said you didn't want to get into the details, but I just want to reconfirm the timing. You had previously stated third quarter FY '21, and then that's pushed out to second half. Is it still second half FY '21?

Matthew Kay: Yes, it's hard to predict timing, Gordon. It's now in the hands of the arbitrator. So it -- look, it could happen in the next month. It could happen in the next 6 weeks. It could happen in the next 8 weeks. So the process is well advanced is all I can say at the moment. And obviously, I can't give you any details, unfortunately.

Gordon Ramsay: Okay. And just on the Waitsia LNG contracts

Matthew Kay: It -- yes, it depends entirely on price and terms, right? If someone comes in with knockout price and terms and they're a high-quality buyer, then they'll do very well. I mean, as I said, this is still early days out of the gates. We're having one-on-one conversations with multiple buyers. We will almost certainly run a tender process for the volumes and what the competitive tension brings and we'll decide from that point. Obviously, it also depends, as you know, on the quality of buyer. I mean, if we have a premium, high-quality buyer with limited risk profile, then clearly we'd be happy to sell the vast majority of volumes to that buyer at the right price.

Operator: Your next question comes from Saul Kavonic from Credit Suisse.

Saul Kavonic: A few quick questions, I think. Sorry, and perhaps if I missed it, but are you perhaps able to outline more the instant write-off tax benefit that was announced in the budget last year? Have you got any further color on the degree to which you expect Beach to benefit over the next 2 years from that?

Morné Engelbrecht: Yes, no, thanks. So probably before -- I'll give you a very wide range in terms of the numbers we're sort of thinking about because obviously it's highly dependent on the strict criteria we need to meet, which is around the specifics of it being a qualifying asset. So it can't just be general CapEx. And it's obviously highly dependent on the commitment being made after the budget was announced and obviously being installed and ready for use by the 30th of June 2022. And obviously it's also very highly dependent on the work program and budgets for FY '22. As you would expect, it's probably more geared towards the short end in terms of onshore development in terms of committing and getting it ready for use. So I suppose, with of all those caveats, we're probably looking at about $100 million to $150 million of cash benefit over the next 3 years.

Saul Kavonic: Great. That great disclosure. My next question is on just talking about the work that's being done in Western Flank and as part of this assessing the situation before you determine the optimized production levels going forward. Do you have an ETA on when you expect to have, I guess, concluded that work and be able to announce what the plan for Western Flank production outlook might be?

Geoffrey Barker: Yes, look, I think this work is ongoing. We probably -- our plan would be to have that ready for obviously the FY '22 budget cycle. So the intention would be -- I would imagine, Matt, is to make disclosure as part of that cycle.

Matthew Kay: Yes, that's right, Geoff. And it depends partly as well on how material the impacts are that we see along the way and how definitive they are. I mean, as we mentioned earlier, if you look at the flank now, we've got 150 or thereabouts producing wells, 100 on pump. We've still got some more wells, as Geoff mentioned, to drill and connect over the coming months, so there's a lot of data to get through. My preference when we come out is to be definitive when we can, so that, if we see anything that is material and definitive and we have to disclose, we'll absolutely disclose, but obviously we've got reserve announcements coming up down the track. And then we've obviously got our guidance for next year as well, so there's obviously looming deadlines. The work has gone forever, clearly.

Jeffrey Schrull: And parallel to the work on developing the fields is developing the final portfolio of the [ENA] opportunities that we're going to be pursuing over the next couple years. We spoke a couple years ago about the [ENA] prospect inventory that still remains on the Western Flank. So a big part of the go-forward production forecast is going to be the new fields that we plan on finding in the next couple years.

Saul Kavonic: Got it. I guess a follow-on to that is can you just perhaps give us a bit more color on what are the potential targets that can be built around adjacent to Enterprise and potentially Artisan if it comes in?

Matthew Kay: Jeff, do you want to talk to the prospects around Enterprise?

Jeffrey Schrull: We -- I don't think -- we don't have any numbers for them. I can give you some names. They have names like [Rayville, Archer and Lindi] at the moment. And we're probably going to have some seismic acquisition to fill some of the gaps in the seismic database that we have. I mentioned earlier, one of the key risks we had to eliminate from that little mini basin was the CO2 content in the gas. And we were that's -- to be honest, that's why we had a risk. It's kind of 50-50 pre-drill. So they're probably a combination of some seismic acquisition and further studies, but obviously, once the pipeline is in back to the plant, the [MEPs] for anything drilled from an onshore location is going to be extremely low. So I guess, watch this space.

Saul Kavonic: Got it. And Matt, sorry to come back to just on the Western Flank. Under the long-term 2025 37 million barrel production target, are you able to just give us an indication of what the on the -- of that 37 was Western Flank when you provided that guidance last year? And can you just clarify again that Trefoil and the Senex acquisition is not included within that 37?

Matthew Kay: Yes, correct. So Trefoil was not included in the 37. The 37 was the base case. Obviously, Trefoil will be material. We haven't included obviously acquisitions in those targets either. In relation to Western Flank, obviously not dissimilar to our current production targets. We'd had them starting over 20 a day, but we did certainly have decline coming in over the 5-year period. We haven't released exact numbers on that, but naturally we had decline coming in. And really the dependency on that will be what we'll work through in the coming months around Western Flank going forward. Bottom line is, for me, this is the whole reason we did the Lattice acquisition, all right, to end up with 6 production hubs and multiple development options so that, if one is having a peak, fantastic. If one is having a down, it can be carried by the others and covered by the others, but don't be too quick to put a line through Western Flank would be my advice. It's still a very, very strong asset; still has great returns. And we've just got to get our heads around the current data that we're seeing which we didn't expect.

Jeffrey Schrull: Especially with the remaining exploration portfolio on the Western Flank.

Operator: Thank you. There are no further questions at this time. I'd now hand back to Mr. Kay for closing remarks.

Matthew Kay: I appreciate everyone's time and interest. And I thought we got a really good series of questions there, so thank you so much for the questions and your interest. If there's anything outstanding, of course, please feel free to call Chris anytime. If there's a need to have a follow-up conversation with management, that can happen, of course, as well. So thank you, everyone, and have a great day.

Operator: That does conclude our conference for today. Thank you for participating. You may now disconnect.