Murphy Oil Corporation (MUR) Q2 2020 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Second Quarter 2020 Earnings Conference Call. [Operator Instructions] I'd now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

Good morning, everyone, and thank you for joining us on our second quarter earnings call today. Joining us is Roger Jenkins, President and Chief Executive Officer; David Looney, Executive Vice President and Chief Financial Officer; and Eric Hambly, Executive Vice President, Operations Please refer to the information on slides we have placed on the Investor Relations section of our website as you follow along with our webcast today. Throughout today's call, production numbers, reserves and financial amounts are adjusted to exclude noncontrolling interest in the Gulf of Mexico. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors may exist that cause these results to differ. For further discussions of risk factors, see Murphy's 2019 annual report on Form 10-K on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I will now turn the call over to Roger Jenkins.

Thank you, Kelly. Good morning, everyone, and thanks for listening to our call today. On Slide 2, we look at where Murphy stands after the second quarter, and what a quarter it was. I'm sure we can all agree that it was not typical, but our company swiftly took multiple actions to ensure that when we emerge from the downturn, we'll be a more resilient company. We rapidly reduced our capital spending for 2020 and in our long-range plan. As we look to the longer term, we will deliver a flatter oil-weighted production profile with the goal of reducing debt, so we maintain our low leverage to future price cycles. Secondly, we work to rightsize and realign our workforce and corporate structure to drive further organizational efficiencies. Operations teams continue to lower operating expenses as well as drilling in completion wells faster and more efficiently, thereby achieving lower per well cost. Most of these savings are durable, which translate to enhanced margins, along with free cash flow generation. Exploration programs in various stages in focused areas, providing significant upside to our existing resource base and optionality for future development. We continue to effectively manage COVID-19 risks by implementing work-from-home processes, along with operational protocol. These processes and protocol have been highly effective in the office and field as we have safely delivered production within the current environment with 0 impacts. I have to say to the organization that I could not be more proud of your resiliency and accomplishments over the last few months as we, like our peers, had to live with incredible uncertainty and stress that COVID-19 has created. We believe that an important tenet of Murphy's strategy is to maintain a multi-basin portfolio to provide flexibility and in the long run, reduce risk. Although we will not be providing formal guidance today, as we look toward next year, the flexibility we've built into our future business planning scenarios and our ongoing process of reducing costs allow us to deliver on our goal of maintaining a conservative balance sheet with flatter production, paying our dividend and paying down debt in an oil price recovery. On Slide 3, Murphy's second quarter production is 168,000 barrel equivalents per day, consisting of 58% oil and 65% liquids and a near even division between our onshore and offshore assets. As previously disclosed on our first quarter earnings call, our production was negatively impacted primarily at 16,000 barrels equivalent today that were shut in in the Gulf of Mexico due, as we know, extraordinary extreme low pricing. We spent a total of $174 million in CapEx for the quarter, including $33 million for King's Quay with CapEx totaling $542 million for the first half of the year as planned. Please keep in mind that we do not expect -- that we do expect rather, to be reimbursed $177 million at the closing of King's Quay transit -- transaction, which includes $52 million spent in the first half of 2020. While oil prices experienced a black swan event, briefly falling to unimaginably negative levels, our realized price for the quarter was at $23 per barrel. Currently, we're seeing our various oil pricing points trade closer to WTI parity on a realized basis, which is our norm. Overall natural gas price remained in line with previous quarters realizations at $1.54 per McF. I'll now turn the call over to our CFO, David Looney, to give a financial update. David?

Thank you, Roger, and good morning, everyone. On Slide 4. Like our peers, Murphy was substantially impacted by the historic low prices in the quarter. The result was a net loss of 130 -- I'm sorry, $317 million or negative $2.06 per diluted share for the quarter. Earnings were affected by several noncash charges, all of which I am quoting here on an after-tax basis: an impairment of $16 million related to an expired offshore lease, restructuring expenses of $32 million related to our office closures in El Dorado and Calgary and noncash mark-to-market loss on crude oil derivatives and contingent consideration totaling $158 million. After backing out all of these items, Murphy had an adjusted net loss of $110 million or negative $0.71 per diluted share. Slide 5. Due largely to the lower prices, our net cash provided by continuing operations was actually a negative $23 million for the quarter. Included within this number was a $106 million cash outflow due to a working capital increase, which relates to our decreased level of activity. Combined with property additions and dry hole costs of $213 million, we had negative cash flow of $236 million in the quarter. For the first 6 months of the year, Murphy generated $369 million of cash from continuing operations with a $220 million free cash flow deficit after $589 million of property additions and dry hole costs. Given that our capital spending was heavily weighted towards the first half of the year with over 75% of total CapEx being spent in the first 6 months, the combination of positive free cash flow for the rest of the year, along with proceeds from the closing of the King's Quay transaction should leave us in approximately the same liquidity position we had at the beginning of the year, which is a truly remarkable accomplishment given these difficult times for the industry. Through the team's efforts to reduce costs earlier this year, our LOE has improved to less than $9 per BOE. Excluding the $20 million Gulf of Mexico expense workover in the quarter, this falls even further to approximately $7 per BOE. Lastly, Murphy has taken additional action to protect its 2021 cash flow with the addition of crude oil hedges of 15,000 barrels of oil per day for the year at an average price of $42.93 per barrel. Slide 6. Murphy maintains a strong balance sheet with $1.4 billion available under our $1.6 billion senior unsecured credit facility, in addition to $146 million of cash and equivalents. Our next debt maturity isn't until mid-2022 with approximately 80% of our senior notes due in 2024 and thereafter. With the market shift earlier in the year, we opportunistically repurchased $19 million of senior notes with $12 million of cash in the first half of the year. Again, as Roger stated, Murphy's long-term goal is to reduce our total debt profile in an oil price recovery, so that we have an even stronger balance sheet going forward. Slide 7. Construction of the King's Quay floating production system, or FPS, continues to progress very well, along with our negotiations on the complex, multiparty transaction documentation with ArcLight Capital Partners. The logistical effects of COVID-19 and extended stay-at-home mandates have caused delays in closing the transaction. However, significant progress has been made on substantially all key agreements of late. And we're targeting closing in the third quarter of this year. As planned, the agreements include reimbursement of our previous capital outlays for the FPS, including $125 million in 2019 and approximately $52 million for the first half of this year. With that, I'll turn it back over to Roger.

Thank you, David. On Slide 9 with the revised capital program reduced onshore drilling schedule, Murphy delivered free cash flow above our dividend this year based on current prices. We prepared the company the past several years through oil-weighted development, accretive transactions and appropriate balance sheet management. Our streamlined yet diversified portfolio provides flexibility through multiple avenues with additional value to our shareholders through exploration upside. On Slide 10, we've reduced our CapEx by more than 50% from our original budget with the midpoint of 2020 budget now at $700 million. As previously disclosed, reductions were made across our portfolio. We closed our corporate offices in El Dorado and have now relocated our headquarters to our existing Houston office. Additionally, we shut down our office in Calgary. Both of these office closures, along with lowering staff levels in Houston, resulted in an overall staff reduction headcount of 30%. While a difficult decision, this flatter organization is better aligned with our business priorities going forward and results in ongoing cost savings beginning in the third quarter of 2020. As we enter the back half of the year, our greatly reduced capital plans layered on with planned reimbursement from Kings Quay and lower G&A expenses will again result in cash flow in excess of CapEx with the quarterly dividend at current prices. We move now to Slide 12 in the Eagle Ford Shale. We produced 38,000 equivalent in the second quarter, consisting of 74% oil volumes. We brought on 11 wells as planned in our Karnes acreage. Murphy does not have any operating activity planned in the Eagle Ford Shale for the second half of the year. In Kaybob Duvernay, on Slide 13, we produced nearly 11,000 barrels equivalent per day in the second quarter, with 66% oil and 74% liquids. We continue to be very impressed with our Duvernay results in drilling and completion costs. Slide 14. Murphy produced 237 million a day and no activity occurred in this -- after the first quarter. The asset will generate approximately $35 million free cash flow for the year supported by fixed price forward sales contracts at the AECO hub for the remainder of 2020 and full year 2021. Slide 16, in our Gulf of Mexico business. We produced 72,000 barrels equivalent per day, comprised of 78% oil. As previously disclosed and discussed here, we were negatively impacted by shut-ins during the quarter primarily at one facility, with workovers completed at Dalmatian DC 134 and Cascade 4 that we completed during the quarter for a total expense of some $20 million. In addition, the second well in our Front Runner campaign was brought online. The third well was deferred as part of our capital reduction plan announced and discussed here. Several nonoperated projects continue to advance, including the drilling of Kodiak #3 in the second quarter, which is complete and is now awaiting a decision we made on the timing of the completion. On Slide 17 in our major projects, we have Khaleesi/Mormont and Samurai remain on track for first oil in mid-'22. Our team has been executing well over the project thus far and has remained within budget with significant contract awards for key execution elements behind us. Further, we're pleased to announce we signed a rig contract for a 10-well operation in this project, starting in early 2021, which will allow us to progress our final permitting on the project. Our operating partner spud the first producer well in the campaign with the St. Malo waterflood project as well this quarter. Capital over the next 3 years for these major projects will average $260 million annually, ahead of achieving significant production in 2023, which is a key understanding of our projects and capital going forward as we continue to support these major offshore projects through this down cycle this year. On Slide 18, we're making progress on Block 15-01/05 in the Cuu Long Basin in Vietnam. We received final approval for the retainment area of the LDV field in the second quarter. We continue to mature remaining block prospectivity here and are waiting submission for the field development plan for approval in the third quarter of this year. On exploration, Slide 20. As a non-op partner, Murphy participated in the Mt. Ouray exploration well in the second quarter at a cost to us of $8 million. The well was a dry hole, unfortunately. In the third quarter, Murphy as a non-op partner will spud another opportunity called Highgarden in the Gulf of Mexico targeting Upper and Middle Miocene targets. Total well cost, again, is estimated to be $8 million net our company. On Slide 21 on other exploration, we maintained a significant optionality with diversified exploration portfolio, mainly focused in the Gulf of Mexico and the U.S., Mexico, Brazil and Vietnam, all in various stages of valuation. And our offshore Mexico block's a 3-year discretionary Cholula appraisal program received regulatory approval, allowing us to drill up to 3 appraisal wells and complete all needed geologic and engineering studies. Murphy's 2 non-operated positions in Brazil are moving forward with partners agreeing to drilling prospects in the Sergipe-Alagoas Basin and seismic evaluation well underway in the Potiguar basin. In Vietnam, our team has secured seismic data on 15-2, which is adjacent to our 15-1 block, as shown here, with the joint operating agreement nearing partner finalization. We're excited for the long-range plans we have in these areas and opportunities they may bring us in offshore international developments ahead. On Slide 23 and our future plans. Now looking at the quarter, third quarter, we expect production in the range of 153,000 to 163,000 equivalents per day. Guidance is impacted by 2 major events. We and our planning have an assumed storm downtime of nearly 5,000 barrel equivalent per day for the quarter, and we have repairs at our Delta House facility, leading to an additional 8,000 barrels equivalent per day downtime there. We recently had a natural gas hydrate blockage in an export pipeline that occurred exiting our Delta House facility, which halted production. That has been remediated. However, we need to make some additional necessary repairs in the system, which will lead to further downtime this quarter. Further planned maintenance at a non-operated Habanero facility resulted in an additional 1,200 barrels a day of downtime. For the year, we plan to spend a range of $680 million to $720 million as we discussed earlier this morning. Should oil prices move materially higher in the back half of the year, we have no intention to add to our capital and we intend to build cash on the balance sheet and in turn, allocate the free cash to reducing debt. As we begin the budgeting process for 2021, we plan to spend within cash flow producing oil-weighted high margin barrels, focusing on continued cost reduction and delivering our long-standing dividend. We plan to give official guidance in early '21. With that in mind, we believe that our capital program in line with 2020 spending, Murphy could deliver production volumes of approximately 150,000 to 160,000 equivalents per day on current pricing with our normal percentages of oil and liquids. Last, Slide 24. I'll take a few minutes to leave you where we are at this time. We're building a plan that emphasizes our flatter production profile going forward to support debt reduction in a price recovery. We continue to be laser-focused on costs in our company across all levels to improve our margins. We have a lineup of meaningful exploration opportunities over the next year, and we will build upside to our current restore space through targeted exploration. As always, we believe in protecting the health and safety of our workforce during the COVID-19 crisis. Maintaining a multi-basin portfolio for additional risk reduction and flexibility is key for our company. On behalf of our executive team, I want to give my sincere appreciation to our employees whose the driving force behind our company and culture despite the incredible uncertainty and stress of this time. Although we may not know the timing, one thing we can count on is the recovery in oil demand, people around the globe rely on our products to make everyday life better, and Murphy intends to be there for that recovery. I'll now take your questions and awaiting that now. Thank you.

[Operator Instructions] Your first question comes from Roger Read with Wells Fargo.

Quick question for you on the debt side. I appreciate you want to get debt down. I think that is a critical thing for the whole industry here. What would you describe as the right debt metrics for us to think about? Or at what point you would feel comfortable saying you could go to maybe 50% cash flow to CapEx, 50% to debt reduction, that sort of thing. Just to maybe put a tighter framework on expectations there?

Well, I mean, it's true at pricing, like most companies, it will take a few years to make advancements in our debt. What we're trying to do now is the first thing you have to do is stop borrowing and putting money on your revolver, that's the first step. And that's what led to our -- we had priorities to lower our capital and lower our cost structure and get that solidified around this mid-range of $700 million, and that allows us to make it through the year. Even with our dividend and with all these planned recovery from the King's Quay to allow us not to have any borrowing this year at these prices we have, which is positive. And you got to maintain that going forward as the first step at strip prices from us, say, a week ago, is a key part of our strategy. And then we're looking and planning on a long-range plan now at this same range that I disclosed this morning, 150,000, 160,000. I mean we're still working this, Roger, and we want to take prices that are currently there. And any advancement above that look to lowering down debt. So if you're a person who believes in a recovery, we're going to keep this same level of spending and capital, probably the midpoint of our capital, quite honestly, now at $700 million is probably the one of the highest end of our capital that we see in the next 2 to 3 years. And any kind of price recovery like that once we get through these big projects, we have significant capital as opposed to this new, much lower capital as part of these projects, Roger. As you know, they flow in 2023, but our significant long-term profiles of very high EBITDA per BOE at $23,000 a day for several years of plateau as shown in these slides. And when we get beyond that period, we will have significant reductions in debt. And we want to take this debt in a recovery down pretty low in the company. We haven't established those goals that you asked for yet, but we're trying to lower it way down and get into a situation wherein volatility like we had this year and these one-off events that we get to keep our capital maintained with our liquidity and everything that we have, and not have to helter skelter our capital budget like that all the time. So that's something we've been working with our Board on a lot of meetings and a lot of discussion over the last 4 months.

Okay. So within a program like that, would it be reasonable to presume you'll continue to hedge. As we look at -- obviously, this year, there were some opportunities on the hedging front. But I'm just curious, '21, you think about the strip where it is -- would you want to hedge much of '21 as it comes in? Or would you prefer to, let's see a market recovery, which, I mean, I think after the depths we've seen, better than strip would be, I think, most people's expectations for '21 and '22 on the crude price?

Well, we're in pretty decent shape because in a recovery, we make so much EBITDA per barrel. If you look at any kind of data, we're going to be a leader in EBITDA and cash flow from operations for BOE. We do have a hedging plan. We're not going to disclose that plan this morning, but we have tranches. As David discussed a few minutes ago, we've marched our way up on that to 15,000, at around $44, $43. So that -- we're kind of done at that level. And where we're looking to in a price recovery to hedge more, I wouldn't see Murphy over a 50,000 barrel-a-day kind of hedged company. We've not been a leader in that regard because we have the balance sheet and liquidity not to be a leader in that. But we have a game plan that's going up pretty aggressively from here. So I wouldn't anticipate a lot more hedging at the $43 level, Roger. But we're walking our way up in stair steps, and they use a collar device as things get higher, which we haven't done before, and we're in the middle of planning out what to do about that. So our CFO team and our treasury team, of course, working on a hedging game plan. So we have a plan right now, and it's going to need to walk up some more before we take any more off the table on that.

Your next question comes from Gail Nicholson with Stephens.

Looking at LOE, it was very impressive this quarter. Can you just talk about how we should think about LOE trending in the second half of '20 as well in '21? And what has been the biggest improvement that you have done on the LOE side to date?

Well, I look forward to not being higher than this. We did have a real good quarter. Keep in mind that you have variable and fixed costs, as you know, and we delivered these costs here even with the big fields shut in for a good bit of production. So I'm quite proud of that. We -- you are seeing through the supply chain improvements and all types of services and rebidding and reevaluation of vendors. That's quite common. Of course, the vendors are doing that. We did -- one thing unique about our OpEx, what we call OpEx or LOE here, is we have had some very serious offshore completion -- recompletion work that our operating expenses that are kind of one-off, but these are well over 100% rate of return projects at strip. So when you turn a well on from 0 to 5,000 to 7,000 barrels a day in this environment, you make a lot of money still. So at that 7,000 level, pretty low. We did real well on OpEx in Canada, bringing that down. Eagle Ford through the years has had a lot of focus on chemicals and uptime and ride pumps and various levels of artificial lift. So it's a goal of ours to keep this. You got to be below 9,000 and it's our goal to do that. And I think we're going to be able to do that outside the workover situation.

Great. And then looking kind of at the upcoming activity in the Gulf of Mexico. There's Calliope, Kodiak and Lucius that's going to be coming online kind of 4Q '21 -- for a path of '21 time frame. Can you talk about volume expectations for those wells?

Those wells -- I'll let Eric talk about -- let me frame this. So we have -- he's going to tell you the volume expectations as well. Calliope is a well that's already drilled and completed and is tied back to a BP facility and we've laid the umbilical and about to work on the pipeline. So that's going to happen in the fourth quarter. Of course, with the risk of COVID, when can we get that tied up? Of course, we have that coming on late in the year. And then the other 2 projects are being, of course, non-op, and they're being planned to be executed by our partners at Oxy. And we're partnering with Kosmos and others at Kodiak. I'll let Eric speak to the expectation there.

Yes. So the Calliope project is expected to come online in the middle of the fourth quarter and the initial rate contribution for the fourth quarter is in the 500, 600 net BOE per day range.

But the IP would be what, Eric?

Quite a bit higher than that, like about 1,200 net BOE per day.

Okay. Great. And then I have to squeeze another one in, if you don't mind. When you guys look at the major project spend that remain, you guys talked about like $260 million of the annualized run rate. Can you just talk about how that major project spend has come in to date versus the original expectations? It seems to me that we're trending better than originally expected, but I just wanted to verify that.

Yes. It's early days in that, and you hate to say go out ahead of schedule. We've had some elements of the equipment and procurement that is below budget. We're happy with our rig rate, it was below budget. There's some gives and takes, and the subsea is down and the rig rate is down to the original plan. Of course, we inherited a project in a capital that was ongoing. We -- the facility, which is part of this King's Quay, we don't own it, but we're supervising the direction of the building. It's going very well. They have to mobilize that on a ship from Korea to the Gulf and bringing it over here and take it offshore and set it up. But I'd say now that we're cautiously optimistic on being below sanction here with a couple of years to go, we find ourselves very well positioned in that regard. And then, Gail, another key understanding about all the stuff about maintenance CapEx and what's your CapEx going to be. I think it's quite phenomenal, actually, about the -- we're laying out high levels of framing here this morning. Of course we have 2 to 3 months to work with our budget with our Board. But if you start looking at a capital level, on the lower end of our guidance we have this year, keeping production in the mid 150s like that, you have to keep in mind that $270 million of that, let's say, $700 million is for projects that will not flow until 2023. And these are very, very high range projects that are way better than drilling, the equivalent of $270 million of pads and onshore, I assure you that. So you got to keep in mind, our maintenance CapEx to maintain production is really quite low and quite impressive. But we're in our market cap compared a lot of times with peers that are just putting all their capital into onshore drill bit. We, of course, are not doing that. But it's a pretty low maintenance CapEx for the rest of the business, if you pull out something that doesn't flow for 3 years. I think that's a key point to make this morning.

Absolutely. And then just on the kind of that 150,000 to 160,000 kind of potential range in '21. Should we assume roughly oil composition is like 56%? Is that a good bogey?

That will be a little higher than that. Our goal is not to make it lower. So it'd be in that range for sure.

Our next question comes from Steve Dechert with KeyBanc.

Just wanted to see if the 2021 -- The 2021 outlook, is that based on a certain oil price?

All the work we're doing now is strip from a couple of weeks ago and looking to use oil price recovery to help our balance sheet.

Okay. Great. And then I just wanted to ask about Eagle Ford next year. Is there a plan in place to add activity currently or not really?

I'm sorry, I missed the first part of your question. Add what? Eagle...

Is there a plan to add?

No. You're breaking up a little bit. That's okay. No, we're maintaining our capital. We do have some DUCs in the Eagle Ford. We're not a big DUC outfit here at Murphy. We probably have about 12, 14 DUCs in the Eagle Ford. So we'll be able to start the year off pretty well positioned. I mean past years, we didn't really leave the year with many DUCs. So that would be our first big completion project. We'll start right after the holidays and early next year, but we are not looking to add rigs or anything the rest of the year. We're going to ride out this CapEx range that we have in our disclosure this morning.

Okay. So nothing in 2021, though?

No, no, no, 2021, we're getting back in the Eagle Ford again, for sure. Yes. We're going to have -- we're going to be slowly maintaining that Eagle Ford production. And then we have a certain capital to maintain it. No, sir. I thought you're asking this year, we don't have any more activity this year. 2021, part of that capital that we're disclosing this morning is, of course, related to Eagle Ford Shale. The Eagle Ford Shale and our big projects is a big hunk of that CapEx.

Our next question comes from Betty Zhang with Scotiabank.

So my question is on the Gulf of Mexico JV. It looked like the unit DD&A was quite a bit lower this quarter. Could you please explain the factors there? And if this is a good baseline going forward?

I'm sorry, what was that, ma'am, on the -- did you say G&A?

The DD&A.

DD&A. Well, we had some impairments in the first quarter, you might recall. It's something not too favorable here at Murphy, but we did have some impairments, which many of our peers did as well, and that lowered that DD&A there, Betty.

Okay. Got it. And my follow-up is on the Eagle Ford. So on a longer-term basis, how are you thinking about running in the Eagle Ford?

We're really in the middle of our plans here now and just had the last couple of weeks of looking at that and not disclosing that long term. But we're trying to work in a 30k to 35k a day range in there for $250 million a year of CapEx kind of maintenance there. And I think that's going to do pretty well and will lead to a lot of EBITDA in an oil price recovery if we flatten out our production there. That's what we're thinking on that, Betty.

[Operator Instructions] Our next question comes from Pavel Molchanov with Raymond James.

So we talked a lot about, kind of, context of the oil market. Wanted to approach this from a slightly different angle. With 6 months into the pandemic, can you talk about how you have adapted on your offshore assets? Specific kind of social distancing measures that you've taken in the Gulf to protect the workforce?

Really, thank you for asking. That's rarely asked. I can't tell you how pleased I am and how proud I am of my offshore team. We were way ahead of this game with a really good crisis management team real early in January or kind of around January 28. And we were optimistic there. We bought about 4,000 test kits and started -- and got these things procured and started testing every single person that goes offshore. Today, there's near 350 cases of COVID in the offshore Gulf of Mexico off of facilities platform to rigs, and Murphy, knock on wood, has had one. This is unbelievable performance. We were ahead of the game. We didn't do just fever tests. We do these prick tests where you can get your blood and test it very quickly, screened a lot of people, really into all the distancing, all the cleaning. And now this can change on you quickly. But so far, we feel that we're a leader in the industry on it as we know we are. And we've done really, really well in that regard, and I'm super pleased about it. So our big thing is screening on the beach, and then, of course, the distancing and working offshore situation as well. Thank you for asking that.

Okay. A question about '21. So total CapEx flat, how would you [Indiscernible] the kind of resumption of exploration in Vietnam, the Mexican portion of the Gulf or anywhere else? Where would that be funded out of?

Well, that's in that capital that we're disclosing. It will probably next year, in the high 60s to do the wells that we want. We're planning for a couple of wells in Brazil, 2 wells in Mexico at this time and a well in the Gulf.

Okay. So 10% of the budget, roughly?

Yes, it happens equally. That's fair. Yes, a good point. Yes, I don't think of it that way, but yes.

Mr. Jenkins, there are no further questions at this time. Please proceed.

Okay. Thanks, everyone, for calling in today. Appreciate it, and we look forward to seeing you at our next quarterly results meeting later this fall. 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.