Good morning, and welcome to the Centennial Resource Development's conference call to discuss its third quarter 2020 earnings. Today's call is being recorded. A replay of the call will be accessible until November 17, 2020, by dialing 855-859-2056 and entering the conference ID number 3692456 or by visiting Centennial's website at www.cdevinc.com. At this time, I will turn the call over to Mr. Hays Mabry, Centennial's Director of Investor Relations, for some opening remarks. Please go ahead, sir.

Thank you, Rens. And thank you all for joining us on the company's third quarter call. Presenting on the call today are Sean Smith, our Chief Executive Officer; George Glyphis, our Chief Financial Officer; and Matt Garrison, our Chief Operating Officer. Yesterday, November 2, we filed a Form 8-K with an earnings release, reporting third quarter earnings results for the company and our operational results for our subsidiary, Centennial Resource Production, LLC. We also posted an earnings presentation to our website that we will reference during today's call. You can find the presentation on our website under presentations at www.cdevinc.com. I would like to note that many of the comments during this earnings call are forward-looking statements, that involve risks and uncertainties, that could affect our actual results and plans. Many of these risks are beyond our control and are discussed in more detail in the risk factors and the forward-looking statements sections of our filings with the Securities and Exchange Commission, including our quarterly report on Form 10-Q for the quarter ended 9/30, which will be filed with the SEC later this afternoon. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially. We may also refer to non-GAAP financial measures that help facilitate comparisons across periods and with our peers. For any non-GAAP measure we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release or presentation, which are both available on our website. And with that, I'll turn the call over to Sean Smith, our CEO.

Thanks, Hays. Good morning, and welcome to Centennial's third quarter earnings call. On today's call, George will first discuss our quarterly financial results, liquidity and updated guidance. Matt will then provide an operational update, including recent operational initiatives, well results and updated D&C costs. Then I'll follow up with a quick recap of the third quarter capital efficiency gains to date and provide a high-level overview of 2021. But before I hand the call over to George, I wanted to point out that what you will hear today stems from our new corporate slogan, Centennial 2.0, which centers around heightened capital efficiency and the goal of generating sustainable free cash flow. In the following discussion and within the presentation materials, you will see the significant progress we've made towards these goals in a very short period of time. With that said, I'll turn it over to George to review our financial results.

Thank you, Sean. Turning to our financials on Slide 17 of the earnings presentation. Net oil production for the third quarter averaged approximately 35,300 barrels per day, which was down 16% over the prior year period and represents a 6% decline from Q2. Supported by the 5 wells brought online during August and a reduction in production downtime, Q3 oil production volumes exceeded our expectations. Average net oil equivalent production totaled approximately 68,900 barrels per day, which was down 10% from the prior year period and represents a 1% increase from Q2. The relatively flat sequential equivalent production volumes were primarily driven by an increase in gas capture, a full quarter of ethane recovery and less flush oil production from new wells compared to previous periods. Revenues totaled approximately $149 million, which was a 65% increase compared to Q2, primarily as a result of higher price realizations across all 3 product streams as well as higher NGL and gas production. Excluding the impact of commodity hedges, Centennial's Q3 oil realizations were 90% of WTI or $36.95 per barrel compared to $21.47 in Q2. NGL prices were up 63% to $12.58 per barrel compared to Q2. Turning to costs. Unit costs continue to look very strong relative to our expectations. LOE per barrel decreased by 7% from Q2 to $3.87, primarily as a result of a continued reduction in equipment rentals and electricity costs. Matt will provide further details on LOE shortly, but we are seeing very tangible progress on our cost reduction initiatives. Cash G&A for Q3 was $1.94 per barrel, which was down from $2.21 during Q2. DD&A decreased by 6% to $14.10 per barrel relative to Q2 because of upward PDP revisions and lower D&C costs. Lastly, GP&T expense increased 9% quarter-over-quarter to $3.02 per barrel, in part because of higher natural gas and NGL pricing. In Q3, we recorded a GAAP net loss of $51.5 million, driven in large part by sustained low oil prices due to the COVID-19 pandemic. Adjusted EBITDAX totaled $51 million, up from approximately $24 million in Q2 due to higher commodity prices and reduced operating costs. Shifting to CapEx. As a result of continued muted activity levels and cost reductions, Q3 D&C CapEx was $20 million compared to approximately $21 million in Q2. In August, we completed 5 wells compared to 4 completions during the prior quarter. And in September, we stood up a single rig, which spud the first 2 wells of a 4-well pad. Once finished, this rig will move to our acreage in Lea County, where it will remain for the foreseeable future. As Matt will describe shortly, our D&C cost per well have declined as a result of well design changes and efficiency improvements as well as overall service market conditions. Facilities and infrastructure capital declined significantly for the second consecutive quarter, totaling approximately $1.5 million compared to $6.5 million in Q2 and $25 million in Q1, primarily because much of our needed infrastructure and facility spending has already been incurred for the year. In fact, given the pending completion of our substation project, we expect our infrastructure spending to remain modest relative to historical levels well into the future. We also incurred approximately $315,000 in land capital. Despite the de minimis land spend, we anticipate that our acreage position will grow year-over-year as a result of recent swaps and trades executed by our land team, and we expect to have an excess of 80,000 net acres at year-end. Overall, Centennial incurred approximately $22 million of total capital expenditures during the third quarter compared to $28 million in Q2. On the previous earnings call, we noted that capital expenditures for the second half of the year would be funded by operating cash flow. In the third quarter, we generated $10.5 million in free cash flow and now expect, despite the recent slide in oil prices, to generate free cash flow in the fourth quarter as well, assuming current strip prices. On Slide 10, we summarize our capital structure and liquidity position. As previously announced in October, during Q3, we repaid $15 million of credit facility borrowings and had our borrowing base reaffirmed at $700 million. As of September 30, Centennial had approximately $314 million of pro forma total liquidity, which was up 6% from June 30. Finally, at September 30, Centennial's first lien debt to LTM EBITDAX was 1x compared to a maximum covenant level of 2.75x. As a reminder, Centennial will not have a total debt leverage governor under the current credit facility until Q1 of 2022. Net debt to LTM EBITDAX was 3.2x at September 30. Turning to hedging. As a result of the Q3 hedge position that we established back in March, as oil markets were rapidly deteriorating, we incurred a hedging loss of $34.5 million during Q3. Looking to Q4, as you can reference on Slide 13, we have WTI swaps in place covering 13,000 barrels per day and costless collars totaling 3,000 barrels per day at an average WTI price of approximately $39 per barrel. Focusing on Cal '21, since our last earnings presentation, we have added significantly to our fixed price protection, particularly in the first half of the year. In Q1 of 2021, we have utilized fixed price swaps to hedge 9,000 barrels per day at an average WTI price of $41.81 and have swapped 3,000 barrels per day at an average Brent price of $46.85. For fiscal year 2021, we have hedged approximately 5,700 barrels per day on average with a blend of pricing at an average WTI price of $42.59 per barrel and a Brent price of $47.79 per barrel. I'd now like to turn our updated 2020 corporate guidance on Slide 12 of the presentation. Based upon Q3 results, we are increasing our daily oil and total equivalent production midpoints by 1% and 2%, respectively, while slightly lowering full-year capital expenditure guidance related to facilities and infrastructure. Due to strong results to date, we are reducing the midpoint of our LOE guidance by 9% to roughly $4.40 per BOE for the year. We are also lowering the midpoint of guidance for cash G&A, DD&A, severance, and ad valorem taxes and stock-based compensation, as highlighted on the slide. Finally, given ongoing efficiencies, we are adjusting our estimates for the number of spuds and completions during the full year. In closing, during our Q2 earnings call back in August, we identified the multiple steps we were taking to reposition the company in what we now describe as Centennial 2.0. I trust it is evident that we are making significant progress towards these goals with a material reduction in our cost structure, improvement in liquidity, and the generation of free cash flow during the second half of the year. We continue to be hyper-focused on these initiatives and expect that this momentum will carry into the future.

Thank you, George. Today, we are happy to report our fourth consecutive quarter of reduced LOE, the completion of 5 DUCs in New Mexico, and a return to drilling operations. As this challenging and transformative year enters its final months, it's truly amazing how far this team has come. Today, I'll cover several ongoing initiatives centered around improvements in LOE, D&C costs, and flaring. As noted on Slide 6, our focus on margin expansion can really be seen. Third quarter LOE came in at $3.87, representing a 36% year-over-year and 7% quarter-over-quarter decrease. This fourth consecutive quarterly drop is the result of ongoing initiatives in the field that we mentioned in the last earnings call. This quarter, we saw the electrification of Phase 2 of our substation in Reeves County. Effectively, our Reeves County substation, detailed on Slide 7, has reduced our generator count from around 125 in Q3 of 2019 to around 30 in Q3 2020. And by year-end, with the third phase of our field electrification completed, we hope to see that number of generators drop to roughly 10. This transition to line power impacts our business in several ways. We've seen significant reductions in rental costs, fuel costs, and downtime at the well site level. The line power source is much more reliable, and that directly impacts the bottom line by fundamentally changing our run rate assumptions on downtime. The profitability of this project can easily be understood, but we at Centennial are also compelled to be good stewards of the land on which we operate. The transition away from generator power means there will be over 100 fewer combustion engines running in the field. And while recently touring our field operations, the enthusiasm from our team members around this project, as well as additional opportunities to transition to electric motors wherever possible, was evident. We've also continued to evaluate our producing wells for opportunities to transition artificial lift to gas lift wherever possible. From Q3 2019 to Q3 2020, our utilization of gas lift as the primary artificial lift method increased from 25% to 40% of our wells. At the same time, we saw a significant drop in ESP usage. The increased reliability of gas lift is undeniable. The failure rates for artificial lift have fallen by around 40% when you compare the full year 2019 average to our year-to-date failure rate. This reduction in failure rate translates to overall lower workover expenses, driving our LOE down. Continuing with our operations in the field, I'm proud to share some additional work that we've really been focusing on, and that is our gas capture. As George mentioned earlier, we've put a tremendous emphasis internally on this subject. And as usual, our employees didn't disappoint. In Q3, we flared less than 2% of our produced gas volumes. Last month, that percentage was below 1%. Our ultimate goal is to minimize flaring to near zero. While on the subject, I wanted to provide a quick update on our overall ESG effort. Earlier this year, we've constructed an ESG committee, comprising both senior management as well as individual contributors from various departments within Centennial. This committee was designed to improve our overall ESG effort and disclosure. As such, we plan to publish a fulsome sustainability report in late Q1 of next year. This will expand on our current disclosures to include greenhouse gas emissions, flaring, water management, biodiversity impacts, and workplace safety, among other things. Turning to Slide 9. You can see the results of our 5 New Mexico DUCs, which were all targeted in the third Bone Spring sand and averaged around 9,000 feet of completable lateral length. Notably, all these wells reported strong results with average IP-30s and IP-60s of approximately 1,900 and 1,500 BOE per day, respectively, and consisted of 82% oil. Consistent with our message from last earnings call, we have continued to place a high level of emphasis on our water recycling efforts. For these wells, we utilized approximately 70% of recycled water during the completion. Our plan is to continue to utilize recycled water to the maximum extent we are able, positively impacting both the CapEx and the OpEx costs and remaining consistent with our overall ESG initiative. Speaking of costs, these wells averaged $858 per lateral foot. While impressive relative to our historical costs on Slide 8, we believe there is still room to improve as those wells included drilling costs that are higher when compared to our current drilling cost structure. With our current internal estimates, we believe we can achieve DC&F costs of $750 to $850 per foot going forward, which are inclusive of drilling, completions, facilities, and flowback costs. Lastly, we believe we are able to combat potential service cost inflation with the higher efficiencies being observed real-time, particularly on the drilling side. Today, you've heard some very impressive numbers for both LOE and DC&F costs. I'm pleased to share with you a portion of the road map that we are using to ensure that these goals become a reality. Over the last several months, we've scrutinized some of the challenges set before our company. To ensure we have better access to our field operations and to facilitate a more hands-on approach to our drilling and completions activity, we've made the decision to relocate our operations group, including the VP of Operations to Midland, Texas. We believe moving the operations team to Midland gives us the advantage and the oversight we've needed and believe that it sends a strong message to our stakeholders regarding our commitment to becoming a best-in-class, low-cost operator. With this being election day, I thought I'd take the time again to briefly review our limited exposure to federal acreage. Out of our over 80,000 net acre position spanning both the Northern and Southern Delaware Basin, only 4% of our total position falls on federal acreage. Additionally, we have 50 approved federal permits and 75 approved New Mexico state permits in hand. With the level of activity planned going forward, any concern relative to additional regulatory risks on federal lands will not impact the trajectory of our company. Before I hand it back to Sean, I'd like to wrap up by saying how proud I am of our team for truly changing the cost structure of the company. We've been able to significantly lower DC&F costs, LOE costs, and flaring. These initiatives, which have been the focus of 2020, will continue to be structural in nature for us as our operations group will now be able to oversee all aspects of their day-to-day work in person. That translates to sustainable progress and underpins our plans to be viewed as an even more capitally efficient company going forward.

Thanks, Matt. So let's quickly recap what we've achieved this quarter, which is outlined on Slide 14. On the left-hand side, you can see our key initiatives, which were taken verbatim from our Q2 slide deck published in August. On the right-hand side, we've listed our actual results from the quarter. And as you can see, we've either met or exceeded every goal that we've set out to accomplish. Starting with LOE, we reduced our per unit cost by 36% through the execution of field-level projects and, as a result, removed over $2 from our unit cost structure. Additionally, we lowered our all-in D&C well cost target by 11% as a result of higher efficiencies and structural design changes. In early October, we received affirmation of our borrowing base and organically increased our liquidity position by paying down debt during the quarter. Furthermore, to help protect cash flow from any deterioration in commodity prices, we added approximately 5,500 barrels a day of incremental oil hedges in 2021, primarily targeting the first and second quarters. Lastly, we were able to execute on all of these objectives while efficiently returning to operational activity during the quarter. Overall, this was a strong quarter for Centennial, and I'm very confident that the recent changes made to our cost structure are more permanent in nature, providing the company with a solid foundation going forward. To further build upon this statement and how it affects the underlying business, I'd like to shift to Slide 5, which shows the rate of change of Centennial's capital efficiency on certain key metrics. To start, our development program is now underpinned by significantly lower well costs as our current target represents a 40% reduction from last year. Next, we are resuming activity with a much shallower corporate decline rate. We expect this to be in the low 30% range at year-end compared to 40% to 50% seen at year-end 2019. This will provide us with a more stable production and cash flow base, effectively requiring less capital investment to maintain production targets. As Matt detailed, our electrification and artificial lift projects have removed a substantial amount of LOE from our cost structure, which, in turn, have significantly enhanced our margins in addition to improving downtime in the field. And let's not lose sight of the fact that we have a very high-quality asset and an extremely capable technical team, which is reinforced by our recent well results. Now with this higher capital efficiency in mind, as I outlined earlier in the year, our goal has always been to generate free cash flow, and there's been no change to this. For the remainder of 2020, we expect to continue operating a one rig program. And while we previously anticipated being cash flow neutral for the second half of the year, we now expect to generate incremental free cash flow during this period at current strip prices as a result of our recent reduction in costs and expanded margins. For 2021, we'll largely be targeting a maintenance program, essentially holding exit rate oil production flat. As it stands today, this will require approximately a 2-rig program for next year, depending upon drilling and completion efficiencies. Given that we expect to generate free cash flow in the second half of 2020, we believe we are well positioned heading into next year. As we have proven in the past, our high-quality assets are capable of growing production rapidly. That said, we are very mindful of global supply and demand dynamics and the recent pressure on crude prices. The substantial improvements in our cost structure do not give us carte blanche to drive significant oil growth into a depressed market. Thus, as we develop our formal 2021 plan, we are committed to executing a maintenance program while preserving our solid liquidity and cash flow profile. In closing, this was a very different Centennial than the company you saw at the beginning of the year, or as we now like to call it, Centennial 2.0, a company that is focused on capital efficiency, cost control, and operational execution, while ultimately generating sustainable free cash flow. And before we go to Q&A, I'd like to quickly leave you with several key takeaways from today's call, which are outlined on Slide 15. We significantly improved our capital efficiency versus previous years and now have line of sight on free cash flow. This is driven by lower D&C costs, which we believe are sustainable through 2021 and beyond, in addition to the material improvements made to our unit costs, particularly LOE. We've witnessed the resetting of our corporate decline rate and still have one of the highest quality assets within the basin. If you take all of these factors, combined with no near-term debt maturities and solid liquidity, you can see why we are so enthusiastic going into 2021.

You have your first question from Scott Hanold.

Sean, that was a helpful overview of what 2021 might look like, as many people are currently focused on that. If you were to implement a maintenance program based on the current market trends, could you share whether that would bring us close to a neutral free cash flow position? What is your willingness to allow us to overspend? Additionally, could you provide information on how many wells this maintenance program would involve bringing online?

Sure, Scott. Yes, I appreciate the question. I think as we think about the maintenance program next year, of course, we haven't given formal guidance as to what that looks like yet, but that's certainly what we are leaning towards right now. As we've all seen, the commodity prices are very volatile and the fact that we swung nearly $5 in the past 2 days. And so it's really interesting to think about how we look at next year, what it's going to look like. I think what you've seen from us, both from a hedging profile as well as how we've managed our debt and liquidity this year is that we're keenly focused on all of those metrics combined. And so yes, the maintenance program is our plan next year. We're certainly going to be aware of our liquidity and our leverage throughout the year. So depending on how commodity prices look, that will affect, of course, our outspend or if there is one next year at all. Depending on how you look at prices, strip prices today might suggest that there might be an outspend. But again, it's really difficult to forecast what that looks like. If there were a modest outspend next year, which we'll see how that looks, if you think about Q3 and Q4 of this year where we generated positive free cash flow, that positive free cash flow is enough to support a maintenance program next year, even if there were a slight outspend. So it's essentially a debt-neutral situation. So we feel very comfortable that we can attain a maintenance program from the exit rate of 2020. Does that make sense?

I appreciate that. I'm sorry, do you have an idea of the well count needed to keep production flat?

We haven't provided that yet, Scott. I think you can use about 18 wells per rig, and we set approximately 2 rigs next year. So I think that gives you some rounding numbers that, without giving some specifics on our 2020 guidance, that gets you pretty close.

No, I appreciate that. You mentioned discussions about making some swaps and trades to reach around 80,000 net acres. Can you provide more details about your position? Is it related to the Noble Chevron deal? How do you fit into the consolidation conversation? Part of it involves reducing your cost structure to improve your business, but there's also the aspect of achieving scale, which can be necessary for relevance beyond just corporate efficiencies.

Sure, Scott. You’ve asked several questions, all of which are important. As we mentioned in the call, we expect to end the year with over 80,000 acres. We'll provide more specific details in the next quarter when we can accurately assess our performance. This achievement reflects well on our land team, who remain active in making trades and swaps with neighboring operators, allowing us to increase our working interest in existing units and convert non-operated sections to operated ones. Often, these trades don’t equate to a straight one-to-one acreage exchange, so we’ve been able to add acres to our holdings without incurring costs throughout the year. This is evident in our modest land expenditures this quarter. Despite spending very little, we have managed to grow our position, which is encouraging. Regarding consolidation, the industry has indeed seen a trend, particularly among larger and some mid-cap companies. The advantages of size and scale are clear, and I anticipate this trend will eventually extend to smaller firms. Currently, we haven't witnessed much consolidation activity affecting us. It’s only a matter of time before we experience such dynamics, and we do consider any opportunities that could be beneficial to our shareholders and enhance our value. Looking forward, expanding our size seems to be a sensible goal for us. However, our current priority is managing costs and reducing our debt. Achieving free cash flow and continuing to organically lower our debt is our primary focus at the moment.

Just wanted to see with 3Q '20 well cost at $858 per lateral foot, what do you see as the drivers to get those costs down to that $750 to $850 range that you're looking for on a go-forward basis?

Yes. I'll let Matt take this. Go on and answer his question.

Yes. The figures we discussed regarding the DUCs were approximately $858 per lateral foot. What we mentioned earlier was that we benefited from recent completion activities and new facility constructions, but those costs were impacted by an older drilling design program used before we paused operations and revamped that department. We expect to move closer to the $800 mark, which falls within the range outlined in our presentation, primarily through the implementation of our drilling efficiency plan. So far, I’ve observed a significant focus on reducing flat-time on the drilling rig, including improvements in trip times and connection speeds that have decreased from hours to just minutes. These adjustments chip away at our daily costs and enhance our field efficiency. We’re also working on various wellbore designs, casing programs in Texas, and better drilling efficiencies in New Mexico. This is our strategy for reaching the $800 per foot target. Additionally, these structural changes highlight the importance of having engineers present in the field in Midland to ensure high oversight on all flat times. Does that address your question?

Yes. That's great. And then just as a follow-up, I just want to see if you think there's maybe an opportunity for CDEV to do another debt for equity swap sometime maybe next year.

Yes. This is George, Steven. I think right now, we're very focused on our cash flow profile and maintaining good liquidity. We wouldn't comment on any type of corporate initiatives, specifically like that. I mean we're very pleased with the outcome of the exchange we executed back in the springtime, which reduced our total debt by $127 million and reduced interest expense. But as I said right now we're very focused on reducing our cost structure, improving liquidity organically, and starting to pivot towards 2021 planning and guidance as we move into early next year.

I have a question about the improvements you've made regarding LOE and cost structure overall. You've provided updated full-year guidance, but as we approach the end of the year and consider 2021, it seems that many of these changes are likely to persist. As we look at next year's cost structure in comparison to this year, can we expect some additional improvements on an annual basis?

Thank you for your question, Don. As Matt mentioned, we take pride in our team's ability to significantly reduce costs, many of which, as you pointed out, are likely to remain consistent. The switch to electrification and the transition from ESPs to gas lift represent substantial advancements that will carry into next year and beyond. We are optimistic about these changes. We still need to complete some electrification work in Q4, which should help eliminate additional generators from our operations. There are ongoing projects that could further lower the lease operating expenses in a general sense. However, our guidance indicates that lease operating expenses are slightly higher than where we finished Q3 for the year. This is partly due to reduced production anticipated in Q4 as a result of limited activity in the second and third quarters of this year. We anticipate that if we maintain our current program, our operating expenses will stabilize at or around Q4's exit rate as we move forward. Therefore, it wouldn't be unreasonable to use our Q4 lease operating expenses as a benchmark until we provide guidance for 2021.

Okay. Great. And then I guess just a little more on that. We've talked about it, but you've got a rig back out there now, if we look at the updated guidance, at the midpoint, a couple more spuds, but the completions are maybe up by half a completion. So what would be some of the things that might push you to bring some wells on at the end of the year is kind of the plan for the next 2 months to really just put a couple more DUCs back on the books to kind of help you mitigate that decline and really get going on that maintenance program as we move into '21.

We currently have a rig in Texas drilling a 4-well pad. The timing for when these wells reach total depth and their readiness for completion can vary, which affects the total number of wells we expect to complete this year. We define completed wells as those that have had their first flowback. Several factors could influence the timeline, especially towards the end of December, which may determine whether some completions occur in 2020 or roll over into 2021. Despite this variability, we are pleased with the progress of the drilling so far and are eager to bring these wells online either at the end of this year or in the early part of next year.

A bit on decline rates. You touched on it earlier, but I just wanted to get a sense, do you kind of have an idea of what the incremental impact on reducing decline rates has on overall breakevens? And then kind of along with that, just what sort of a steady state 2021 maintenance program might do to that 30% to 35% decline rate that you guys were talking about moving into year-end?

Thank you for the question, Jordan. We haven't shared a breakeven number, and it's something we haven't released. I encourage you to analyze our costs and draw your own conclusions. I feel optimistic about our capital efficiency and operating costs, and I believe we are heading in the right direction, which will help to lower our breakeven costs. Regarding the corporate decline rate, we anticipate finishing the year in the range of 30% to 35%. If you maintain that number throughout 2021, it will likely be accurate. This is because we plan to increase some activity; we added a rig in September and are likely to have two rigs operational next year. With that activity level, I expect our corporate decline rate to remain stable through 2021.

I would like to follow up on the infrastructure spending. It's clear that this year, as well as last year, there has been a significant reduction. Are we now at a point where our infrastructure spending has stabilized? Are there any additional projects aimed at enhancing our level of effort that we could anticipate which might increase spending as we approach the end of the year and into 2021?

Yes. Jordan, it's George. The majority of our infrastructure spend in terms of major projects has been completed. A lot of that occurred in 2019. At the front end of this year, we had some spending, particularly in Q1. But as we look at major projects, we do see a significant decline in infrastructure spending, not only from the beginning of this year but year-over-year from 2020 into 2021. As we think about, obviously, we guide facilities and infrastructure capital together, so it's one bucket. And as we look towards next year, on the facility side, because we're going to be completing wells on a more normalized basis in terms of our resumption of activity, we will see some degree of increase in the facility spend. But on infrastructure, we're feeling very good about where we are in terms of not having much spend going forward.

Jordan, you might have cut out there. I'm not sure. Did that complete your questions? I apologize.

I believe so. Rens, do we have any more questions in the queue?

You have your next question from Nathan Rain.

You've got Sean Smith here.

I just wanted to get clarification because I know there's a little bit of confusion as far as compliance goes. My understanding is that we have an additional 180 days that we can apply for, is that correct?

Are you talking from a delisting point of view?

Yes, sir. Yes.

Yes. We received a delisting notice in August. We have until February for compliance in the first phase. There is a second phase that would extend that to August. So there is plenty of time to address the NASDAQ listing requirements. There are options to manage this, as many companies have done through stock splits and similar strategies. However, we are still in the early stages of this process and do not anticipate any issues.

There are no further questions at this time. Presenters, please continue. Thank you all for participating. This concludes today's web conference. You may now disconnect. Have a great day.