Diamondback Energy Inc (FANG) — Q1 2021 Earnings Call Transcript

Thank you, Phyllis. Good morning and welcome to Diamondback Energy's First Quarter 2021 Conference Call. During our call today, we will reference an updated investor presentation, which can be found on Diamondback's website. Representing Diamondback today are Travis Stice, CEO; and Kaes Van't Hof, CFO. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Travis Stice.

Thank you, Adam, and welcome to Diamondback's first quarter earnings call. Diamondback had a successful first quarter, continuing to build off the momentum generated in the back half of 2020. Operationally, we are hitting on all cylinders. We were able to effectively navigate a once-in-a-generation winter storm while keeping well costs and cash operating costs near all-time lows. We closed both the Guidon and QEP acquisitions in the first quarter and are very pleased with how the integration efforts are progressing. We are achieving our synergy targets ahead of schedule and in excess of the $60 million to $80 million of annual cost savings we highlighted when the deals were announced. Yesterday, we also announced three noncore asset divestitures for gross expected proceeds of $832 million. By selling these noncore acreage positions in such a timely and opportunistic manner, we were able to take advantage of a strong A&D market and generate attractive cash returns for Diamondback shareholders. We anticipate using the combined proceeds from these noncore asset sales to accelerate debt reduction. As we discussed last quarter, even though oil demand has shown signs of recovery from the depths of the global pandemic, oil supply is still purposely being withheld from the market, primarily through the actions of OPEC+. As a result, we continue to believe we do not need production growth and will hold our pro forma fourth quarter 2020 oil production flat through 2021. Due to the complexity resulting from the timing of the QEP and Guidon acquisitions as well as the announced divestitures, we have instituted quarterly production and capital guidance for the first time. For the second quarter, we anticipate spending $350 million to $400 million in capital and producing 232,000 to 236,000 barrels of oil a day. This production range accounts for a full quarter of contribution from QEP's Williston asset and approximately two months of production from the announced noncore Permian asset sales. Looking at the full year of 2021, our free cash flow profile continues to improve. In the first quarter, we generated approximately $330 million of free cash flow, marking the third consecutive quarter of significant free cash generation. At current strip pricing and accounting for the Williston divestiture, we expect to generate approximately $1.4 billion in pre-dividend free cash flow this year at a reinvestment ratio of below 55%. In March, we executed a successful tender offer and refinancing of all of QEP's bonds and one of Diamondback's existing bonds. This refinancing equates to $40 million of annual interest expense savings and extended our average debt maturity by three years. Today, we have three debt maturities that are callable before the end of this year: $191 million due later this year, $650 million due in 2023 and $432 million due in 2025. We expect to use cash on hand from internally generated cash flow as well as proceeds from our asset sales to retire these three tranches of bonds, reducing our absolute debt load and further strengthening our balance sheet. Now turning to ESG. We recognize the importance of operating with the highest level of environmental responsibility and continue to make progress on our ESG initiatives. We flared 0.75% of our gross gas production in the first quarter, a decrease of over 85% from 2019. Flaring is the biggest driver of our CO2 emissions. And while we are happy with our progress on our legacy acreage, we still have significant work to do on our recently acquired positions as we move to reduce our Scope 1 GHG intensity by at least 50% from 2019 levels by 2024. We've also committed to reducing our methane intensity by 70% over the same time frame. In the first quarter, we continued spending capital to retrofit our older tank batteries with air pneumatic devices as gas pneumatics account for 50% of our methane emissions. We also signed a contract to conduct quarterly flyovers of all of our tank batteries to more frequently check for equipment leaks, improving our maintenance practices. Our Net Zero Now initiative is also underway, which means every hydrocarbon molecule produced by Diamondback is anticipated to have zero net Scope 1 carbon emissions from January 1, 2021 forward. While we recognize we still had a carbon footprint, we have already purchased carbon credits to offset remaining emissions and ultimately plan to be a fast follower in investing in income-generating projects here in the United States that will more directly offset these remaining Scope 1 emissions. To finish, the first quarter was busy and productive. We generated substantial free cash flow, kept our capital and operating costs down, extended debt maturities, added Tier 1 inventory and divested noncore assets. All the while, our strategy remains the same: operate in a prudent and sustainable manner, spend maintenance capital to hold production flat and use future free cash flow to return cash to shareholders and reduce debt. With these comments complete, operator, please open the line for questions.

Quite, you and the team, a bit emphatic about what I would call macro speaking that the world really does not need any more oil growth anytime soon. So my question is really pertaining to this. Do you all believe your operational program is as optimal at this lesser pace than if you had a more multi-rig larger frac plan in several of your areas and whether business have much impact on your cash cost?

Certainly. If you examine our cash costs for this quarter, it's clear that there hasn't been any leakage or cost pressure affecting our execution related to the lower activity rate. Prior to the pandemic in 2020, we were operating 23 drilling rigs and around 8 or 9 frac spreads, which was a rapid pace. I have been quite satisfied with how, despite a significant reduction in pace last year, we have managed to maintain efficiency this year with 11 rigs and 3 to 4 frac spreads. Monitoring our reported numbers will be a good gauge of our efficiency, and for both the first and fourth quarters, the results have appeared strong.

No, I agree. I agree. Okay. And then now that Guidon and QEP are in the books, I'm just wondering, could you or Kaes comment anything you all see that's different or surprised you from the assets? Maybe specifically, if you all still believe there's as many quality locations? And how do you sort of rank that inventory versus existing?

Yes. Certainly, that narrative hasn't changed at all. In fact, it's probably gotten a little bit better. And I'll tell you, I was very complimentary of the QEP team at acquisition announcement time and again, during our February call and our April update. Operationally, they were doing some really efficient things. And just looking at the drilling report this morning, QEP's always use water-based mud. And Diamondback now, we've adopted it and we're on our first or second well with water-based drilling fluids that, quite honestly, QEP is helping us with. And so far, really, really impressed with the improved efficiency using water-based mud. So that's been a nice add to what I thought was already a really efficient Diamondback legacy operations team. This looks to be a little bit of a stairstep in the right direction.

Travis, I guess the shoe is on the other foot this time with Diamondback on the other side of marketing assets. I wanted to get your thoughts. Obviously, you guys have the data room for the Bakken sale. You sold some noncore Permian assets as well. What is your sense of the A&D market today? We've seen a couple of very large Permian trades, DoublePoint and Vitol. And I guess I wanted to get your sense of, do you see more of these private-to-public trades occurring this year? And what criteria that Diamondback will use to evaluate A&D activity?

Certainly, we were really pleased with the interest in the Bakken divestiture process. Now granted, we were the beneficiaries of commodity price run-up and some previously announced deals in the Bakken that I think put some wind at our backs. So that – I think that piece of the A&D still seems to be pretty frothy, particularly on the PDP-focused type of divestitures, a lot of interest in that. But specific to what Diamondback is looking for on a go-forward basis, we still remain very resolute in our strategy that it's got to meet internal objectives like free cash flow, and it has to be return accretive on a per share basis. And when you look at the combination, we've got to accelerate return of free cash flow. The larger trades that – particularly the ones that you referenced, it's – the quality of assets that fit for capital in Diamondback's top quartile are probably fewer than greater. And the prices that were recently announced on some of those trades might have coiled some of the activity for a little while anyway. But I think as long as we can demonstrate that we're being accretive on a per share basis and that we're accelerating return of free cash flow, we're going to continue to look in the Permian Basin. But the opportunity set is pretty narrow right now.

But most importantly, there has to be inventory that competes for capital right away, right? We – while this industry has moved towards financial metrics, that can't be the only numbers that we look at when we think about what makes sense in terms of an acquisition, and sticking inventory in the bottom quartile or bottom half of our existing inventory just doesn't make sense to us from a returns perspective.

Makes sense. Kaes, I'd love to get your thoughts on the updated inventory disclosure, quite a few changes here. It looks like in terms of – focusing on the Midland Basin, you increased your inventory count by just over 150 net locations. I know that the lateral lengths increased a little bit and perhaps, the Delaware declines just reflect some of the A&D activity. But give us some thoughts on the updated inventory kind of snapshots, kind of the key takeaways. And I do sense that you perhaps are using a little bit wider spacing for some of the acquired assets from QEP and Guidon?

Yes. That's right. We hadn't posted a full inventory update since the beginning of 2020. So this was the first update post the two deals. I'd say, generally, we spend a lot of time looking at our development as well as offset development, particularly in the Midland Basin. And I mean, I think our focus is the best zones can still handle kind of 660-foot spacing, which is as tight as we've kind of ever gotten. But we kind of realized that maybe the secondary zone should be spaced a bit wider. And so that's reflected in that inventory numbers we've put out. So secondary zones that are getting codeveloped with the primary zone, which we still think is the right thing to do, are getting spaced at 5 to 7 wells a section rather than kind of 7 to 8, which is the best zones.

Taking a look at the slides here, you show at a $60 WTI price in reference to this driver in your script of north of $1.4 billion of free cash flow before the dividend this year. But this year, you are burdened by hedges. I was curious if you could provide some perspective around what open EBITDA would look like in that type of environment. And then also your perspective on use of proceeds of all this free cash flow and the asset sales, your framework around returning some of this excess capital to shareholders.

Yes. That's a good question, Neil. We're probably sitting on about $450 million or $500 million of hedge losses for the rest of the year at strip today for the balance sheet. So that's the drag on free cash this year. I think it's fortunate that we are losing money on hedges compared to where we were a year ago, but unfortunate that we do have to write the checks. But overall, I think if you add that number back to the free cash number, you can get a pretty clean look at what the future might hold on an unhedged basis.

That's great. And that ties into the follow-up around capital returns. Talk about how quickly you can get to the leverage levels that you're targeting. And then there are a lot of different options at that point, right? You could think about a buyback, you can think about a variable dividend. Recognizing it's too early to commit to that until you hit your debt target, just walk us through your framework about the different options that are at your disposal.

Yes, Neil. It's beneficial for our industry to focus on ensuring that investors see a return on their investments. Reaching certain debt targets, as we discussed yesterday, will help us achieve these goals more quickly. We anticipate reducing our callable debt by $1.2 billion or more by the end of this year, which will position us well for next steps. There's considerable interest in establishing a clear approach to capital allocation and returning profits to shareholders. While it would be ideal to have a straightforward formula for this, our industry is influenced by changing market conditions. Thus, I am cautious about guaranteeing results based on fixed models. However, our strategy regarding variable dividends and share buybacks will be part of future Board discussions, along with our ongoing commitment to maintain our base dividend. We are pleased to expedite our debt reduction targets through a strong divestiture outcome and will continue to focus on performance without making overt commitments too far in advance.

Travis, after the QEP deal, you suggested that your breakeven to sustain your production would potentially move lower. Just wonder if you could give an update in light of your comments around synergies last night as to where you see that settling out.

Well, certainly, the synergies that were in excess of what we promised stem from the refinancing of the locked QEP's debt. I think we talked $40 million. We didn't even describe that as a synergy at acquisition announcement time. The specifics around lowering the breakeven cost has to do with our capital allocation of moving rigs into this newly acquired acreage, both Guidon and QEP. And while I can't formulaically give you dollars and cents how much our breakeven cost has come down, we do know that doing higher cash flow-generating projects at higher rate of return is going to translate to a lower breakeven cost.

Okay. It seems to us you've won by about $1 or $2, but we'll take that off-line. My follow-up is also related to I guess some of the comments at the time of the QEP deal related to infrastructure and maybe the opportunity to drop or look at dropping down some assets to Rattler and maybe some royalty opportunities for Viper. I'm just wondering if you got any update you can share as to how you're thinking about that.

Yes, Doug, there isn't much to transfer from Viper to Diamondback today. QEP and Guidon operate differently; QEP is involved with numerous large landowners in the Permian who have been established for a long time and aren't looking to sell their minerals, while Guidon had a sister company similar to Viper that was acquiring minerals. We are definitely looking for minerals at the Viper level on QEP and Guidon land, but there won't be any transfer at this time. Regarding Rattler, we've mentioned that QEP has done an excellent job with infrastructure. We've gained valuable insights from them, particularly on recycling, which will enhance our Midland Basin recycling initiatives significantly. Eventually, those assets will likely be better suited for Rattler, but it may take a few more quarters to finalize everything before we can transfer them.

Every quarter, efficiency gains are achieved. Where do you think you are in that learning curve? And are you trying any new technologies that could prove to be beneficial for future improvements?

Yes. Gail, I mean, I think Travis kind of said it earlier in the call, but bringing the QEP team in the fold, just like when we brought Energen in the fold, we don't need to be the best, we just want to learn from the people that we add to the team. And we learned a lot from Energen, and then we recently just learned a lot from QEP. So as Travis was mentioning, water-based mud on the drilling side, some drill-out techniques on larger pads that are saving us some time. On the cementing side, I think we've learned that we can batch drill and batch cement, which saves us time, and this all reduces time on location and increases the efficiencies, which is why Danny's team on the drilling side is getting kind of ahead of the 2021 program early in the year, which I think is positive.

Gail, during the Energen announcement, I mentioned that we set aside our egos when we brought the Energen team on board. This serves as another example of putting egos aside to determine the best approach for our shareholders. I’m really proud of the operations organization; they've consistently shown this commitment. Although we haven't had the QEP team for long, they are already making a positive impact.

And then circling back to the inventory. With the improvement in oil prices, do the secondary zone see a potential uptick in capital allocation in '22 forward? Or should we still be assuming that the primary zones are the target for the foreseeable future?

I think just generally, we're very focused on co-development between zones, particularly in the Midland Basin, and the secondary zones get spaced a little wider. I think, Gail, we did a lot of work at various oil prices on inventory and spacing and EUR per foot. And we kind of found that the benefit to IRR outweighs any benefit to NPV from going tighter. So no one got mad at you for drilling wells that were too good. And so I think we're going to stick with that strategy, particularly with how much undeveloped acreage we got with the QEP and Guidon deals.

Just curious, the deal with QEP only closed, I guess, about seven weeks ago now. As we think about your development plans on those assets, when would be like a decision point where we might see a shift of activity either more towards county line or some other areas that you're learning from that might have surprised you with what you're seeing today versus pre-deal so we could start thinking about how '22 looks?

Yes. David, I think you start to see that in terms of the wells that we're going to be drilling now, but you won't see it in terms of production until kind of Q4 '21, early '22. I think we're trying to get as many rigs as we can in the Robertson Ranch/Sale Ranch area in South Central, Martin County, some big pads and efficient development going to be headed that direction. Rigs are there right now. I think when it comes to kind of county line in the northern part of Martin County, we've done a lot of technical review with the QEP team and our team, and they've done some things in the shallower zones that we like, some targets that we like in the county line area. So I think you'll see more of the Wolfcamp A, Middle Spraberry, Dean, LS work in the county line area and then more of the deeper Wolfcamp and Lower Spraberry in the Robertson Ranch area.

Appreciate that. And if I could just ask one on just the capital program this year. Just curious, like relative to your guidance on footage cost of $520 to $580 in the Midland and $720 to $800 in the Del, where you guys are today? Because as I look at the rest of the year, it seems to certainly be implying like a back half-weighted program. Does that stairstep up each quarter now going into the end of the year? Because I guess we're thinking about sort of like the sustaining quarterly run rate that we should expect going into next year.

Yes. That's a good question as well. I think I'll take the well costs first. We put a lot of look at well costs in the deck. Midland Basin was around $530 a foot, and Delaware was actually below the low end of the guide, which I think was just a really good quarter operationally, a little lower sample size as well. But as you think, we did put out Q1 CapEx of $300 million in Q2, implying $375 million at the midpoint. So that would imply we're going to spend $1 billion in the back half of the year. And I would say there's certainly some conservatism on our side. We've been very vocal that we will cut CapEx to keep production flat rather than grow production and spend more dollars. But the ancillary stuff, environmental, infrastructure, midstream, non-op is going to pick up a bit in the middle of the second half of the year, and that, on top of the couple of quarters of true pro forma QEP and Guidon and Diamondback activity, will result in capital coming up slightly throughout the year. But yes, we're off to a pretty good start in the first half.

Congrats on your transactions. Perhaps for Travis or Kaes, following up on the earlier A&D question, but taking it a slightly different direction. In your view, did that larger transaction tilt the environment to a seller's market? And if so, would it make sense to pursue smaller divestitures to further improve your balance sheet?

That's a good question. The market has improved significantly, which is why we initiated the Upton County and non-op New Mexico processes that we had considered selling for years. However, the previous 12 months were not favorable for selling cash flow. The trend has been that many private investors are focusing on acquiring PDP-heavy assets to distribute cash flow to their investors or shareholders. With many participants pursuing the same assets, there has been increased competition, allowing us to receive strong bids on all three assets, which we are pleased with. However, for us, any additional assets in the Permian that we consider selling have significant undeveloped value, and we aren't looking to sell those right now since the market for them is less competitive compared to the PDP-heavy market.

Yes. Specifically, for Diamondback, we discussed CCUS technology and its emerging trends. A good analogy for our Diamondback shareholders would be to see how Rattler has worked with experts in long-haul pipelines. We don't plan to become experts in income-generating or CCUS projects, but we do intend to align with those specialists and explore those technologies. These emerging technologies are not just months away; they are several quarters out. New technology is continually emerging, and we're focused on staying informed. When I speak with my industry peers, they are taking a similar approach, trying to be quick adopters and figuring out which emerging technologies to embrace first. This is definitely a trend within the industry.

Any thoughts on a drop-down of your QEP Midstream assets or formerly QEP assets into Rattler and timing of that?

Yes. David, it's certainly on the schedule. The other activity is getting Bakken sold and getting the refinancing done took priority, but the team is doing their work. I think as you think about the drop-down, we're going to have a very large block across half of Martin County, and so we want to get the engineering right and also build out recycling infrastructure across that block to be able to store, produce water and reuse it in the Midland Basin. So I think it's a couple of quarters away, but certainly, it's on the docket.

I wanted to follow up a little bit on your comments around synergies. You guys talked about that you're ahead of expectations of the $60 million to $80 million. Clearly, you pointed out the debt refinance split. Perhaps maybe you could talk a little bit more to kind of the G&A and the operational synergies. Are we going to start to see those numbers show up as soon as second quarter earnings when you report? Do these come more in the second half of the year? And can you maybe provide a little bit of color just on the operational synergies and specifically, where those will come from?

Yes, Leo, we based the deal mainly on G&A and interest. QEP operated at a low cost similar to Diamondback. Unlike Energen, we didn’t claim we would drill 2,000 wells significantly cheaper. However, the G&A improvements should become evident in the third and fourth quarters, and the interest has already been addressed. There may also be potential gains on the operational side if a drop-down occurs at Rattler, allowing us to link all our midstream systems without incurring additional capital costs for that capacity, which could be an unexpected advantage.

And also, Leo, operationally, what we discussed earlier on this call regarding the water-based mud, the use of big rigs for drill-out, and some of the cementing practices that Diamondback is now adopting from QEP learnings, all contribute directly to lower costs per foot, which are significant synergies as well.

That's helpful. I noticed that your first quarter LOE was below your full year guidance even with the severe weather we experienced. It seems you're doing a great job in the field. Do you anticipate coming in under that LOE guidance for the year, or should we expect an increase once the QEP and Guidon assets fully come into play in the second quarter?

Leo, it's Danny. The LOE in the first quarter, we certainly saw some surprising benefits throughout the year during first quarter from some electrical contracts and other things throughout the storm. We do expect that we'll see a little bit of increase from that number from the Guidon and QEP assets. Mostly the Guidon assets have a little bit higher lifting cost than what we've traditionally seen at Diamondback. But we like the low end of that guide right now. And as we learn kind of more about the assets and where their lifting cost is going to settle as we get them integrated, we'll update the market.

Just one question for me, kind of following up on the earlier ESG discussion. And you mentioned, Travis, in your opening comments about being the fast follower in the investment side. So you generated strong free cash flow, and it certainly looks like that continue given where commodity prices are. How large of a part of the FANG story could investment in renewables or CCUS type projects or entities develop into, say, over the next 2, 3 years?

That's a fair question, Richard. However, I don't know what that number will look like yet. There's still too much uncertainty with new technology development. I understand its importance, but I'm not comfortable discussing what percentage of our capital will be allocated to that because, honestly, we just don't have an answer at this time.

Yes. I mean I think what's most important, Richard, is if our Scope 1 emissions go down, you have less incentive or need to invest on the other side to offset it, right? So today, $15 million a year is going into the tank battery side. And I think we put out some new numbers that we're going to replace 200 generators in the field this year and move that to line power. We're then moving towards a Scope 2 emissions number and how we're going to get that down through sourcing electricity through renewable sources. So while Travis says we're going to be a fast follower on the investment side, we're certainly going to be a leader in terms of spending dollars in the field to clean up and reduce our intensity on what we can control.

I have a quick question followed by a more open-ended one. You've sold or agreed to sell nearly $1 billion worth of assets, but your CapEx guidance remains the same. Does this indicate that your CapEx on those divested assets was minimal, or is there some reallocation taking place?

No. It just means they were noncore, Charles. The key to an asset sale is does that asset compete for capital with the rest of your assets, and these three assets did not. I'd say some of the New Mexico acreage was really good acreage. But we're not a non-op producer. So we sold stuff that sits lower in the inventory ranking, and we're going to reinvest it at this time to pay down debt and generate free cash to return to shareholders.

Yes. I wish many of the decisions I have to make were simply yes or no questions, but this isn't one of them. From a broader perspective, OPEC+ is currently controlling the market, which has resulted in reduced inventories. Amid a still developing oil demand recovery, which may be negatively affected by the unfortunate situation in India, it's too early for us to discuss growth. There's no clear indication at this time. While we may need to reach a certain level, with OPEC+ still in place, I'm not sure that's the right approach. We also need to factor in that we are likely to see 1 million to 1.5 million barrels a day of production returning. It's a question that continues to evolve. For Diamondback, we see no clear signs to increase volumes, and it's unlikely that you'll see any of those signs this year.

Travis, just curious that you talked about the near-term debt reduction for this year, $1.2 billion. Longer term, what will be the right capital structure or the debt level for Diamondback?

Yes, that's definitely an evolving question. We aimed to reduce our debt to the levels we had before the QEP and Guidon acquisitions, and we're nearly there. Regarding our leverage target, leverage depends on EBITDA and oil prices. The Board's mandate has kept us below 2x since our IPO, and we will reach that soon. In the long term, I believe our leverage should ideally be around 1 or lower, which will require several quarters to achieve. However, I am encouraged by our forward outlook and our strategy for debt retirement.

I am curious about that because I believe that in a volatile sector like oil and gas, the best hedge is not necessarily a paper market hedging program, but rather maintaining a strong balance sheet. With that in mind, will Diamondback consider reducing its net debt to a very low level so it can completely avoid the hedging program and position itself to be much stronger, with greater flexibility and opportunities when facing the next downturn?

Yes. Paul, I mean, I don't know if that's an either/or answer, right? I think it's an and answer. And like Travis was saying, I think something like a turn of permanent leverage at high 40s WTI is a pretty good hedge, natural hedge for the next downturn, but I think you also need some sort of put protection or big insurance policy that if things go really south like they did in 2020, you're still protected. So I think it's a combination. I think hedges will still be a part of our story, particularly with a growing dividend and investors demanding capital be returned to them. You have to protect that cash flow. The only way you can in the paper market, you might do a wire collar or buy puts that are pretty cheap. But I think, again, it's kind of an and discussion. We sold everything we had in that business for 29% of it. For Diamondback shareholders, the IPO of Rattler was definitely a win. We need to view the subsidiaries through the lens of what is best for both Diamondback shareholders and the subsidiaries' shareholders. Fortunately, we've established these vehicles without major conflicts of interest, and they have typically traded at higher multiples than the parent company. Overall, they have been successful investments. However, we need to consider the value they add. In a market with acquisitions, they have added value, but if we are acquiring less, we will need to reassess their value. Right now, they still hold strategic importance, and there is significant value for Diamondback shareholders tied up in the stock of those two companies.

Okay. All right. Final question for me. Can you discuss the process when you sell the Bakken asset? Maybe we are wrong, but when we're looking at the future strip, that for the next 12 months, the Bakken asset that you sold should be able to generate EBITDA of about $250 million to $300 million. So it looked like you sell for 2.5 to 3x turn. That seems a bit low. So just trying to understand the process.

I think the process was very competitive. This was an asset that wasn't going to be getting capital from us. So I think, Paul, we were very vocal that the Bakken was going to be held for sale. I'm personally very pleased with the price we received. It seems like in the fall, everyone was saying, 'Oh, you can't sell anything for better than PDP, PV-15.' And like I said earlier in the call, I think this industry can't move towards only looking at financial metrics. NPV and NAV still matter. They probably play a lower role than they did in the past. But financial metrics alone isn't going to be the reason why we sell an asset we deem noncore when we did an acquisition a couple of months ago.

Thank you again, everyone, for participating in today's call. If you have any questions, please contact us using the information provided.