Good morning, and welcome to Centennial Resource Development's Conference Call to discuss its Second Quarter 2020 Earnings. Today's call is being recorded. A replay of the call will be accessible until August 18, 2020, by dialing 855-859-2056 and entering the conference ID number 7031059 or by visiting Centennial's website at www.cdevinc.com. At this time, I will turn the call over to Hays Mabry, Centennial's Director of Investor Relations, for some opening remarks. Please go ahead.

Thank you, Rebecca. And thank you all for joining us on the company's second quarter earnings 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, August 3, we filed a Form 8-K with an earnings release reporting second quarter earnings results for the company and 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 homepage or 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 SEC, including our Form 10-Q for the quarter ended June 30, 2020, which was also filed with the SEC yesterday. 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. With that, I will turn the call over to Sean Smith, our CEO.

Thank you, Hays. The past six months have certainly been a challenging time for the entire E&P industry, including Centennial. In March, we witnessed an unprecedented increase in global supply from OPEC plus members amid a global pandemic, which had already significantly weakened near-term demand. These events, in part, have caused oil prices to move significantly lower and caused widespread shut-ins by the industry during the second quarter. With this in mind, I'd like to start off today's call by quickly reviewing Centennial's response to recent global events that have transpired over the past several months, as outlined on Slide 4 of today's presentation. We reacted decisively in order to protect the balance sheet and manage liquidity. In May, we announced plans to temporarily suspend all drilling and completion activity while materially reducing our full-year capital budget by 60%. As a result of low realized prices, we voluntarily curtailed approximately 20% of our May production in order to protect field-level cash flow and economics. The production team used our in-house data analytics tool to quickly evaluate well economics to determine which wells should be shut-in based on actual net backs and operating costs for each individual well. In early June, as oil prices increased, we brought back essentially all of our shut-in volumes with virtually no incremental costs or associated work-over expense. As discussed on the previous earnings call, we also took several steps to significantly reduce our cost structure and operational inefficiencies. During the second quarter, we made the tough but necessary decision to reduce the size of our workforce to better align the company's organizational structure given the current commodity price environment and subsequent activity levels. This also included reductions in salaries across all company employees, with the largest reductions being taken at the senior management and board levels. Additionally, we executed a successful debt exchange offer, which reduced our total debt outstanding by $127 million and lowered future interest expense. It is important to note, we have not been standing idle during this lower commodity price environment. We've taken this opportunity to completely review our operational procedures and practices, searching for any incremental cost savings or efficiencies. While George and Matt will provide more details on this shortly, I am confident that Centennial will emerge from this downturn with expanded operating margins and structurally lower well costs, which will continue to benefit the company going forward. With that, I will turn the call over to George to review the financials before providing some closing remarks.

Thank you, Sean. I'll first review our Q2 financial results and then discuss the debt exchange, capital structure, liquidity hedge position and 2020 guidance. Turning to our financials on Slide 11 of the earnings presentation. Net oil production for the second quarter averaged approximately 37,400 barrels per day, which was down 13% over the prior year period and represents a 10% decrease from Q1. Production was impacted by the voluntary curtailment of approximately 20% of May volumes and the significant reduction in completion activity during Q2. Average net oil equivalent production totaled 68,245 barrels per day, which was down 10% from the prior year period and represents a 5% reduction from Q1. Total equivalent production declined less than oil production because we have less flush contributions from new wells, which typically yield a higher oil cut, and we flared fewer volumes in Q2 compared to Q1. Revenues totaled approximately $90 million, which was a 53% decrease compared to Q1, primarily as a result of the significant decline in oil and NGL price realizations and lower production. Excluding the impact of basis hedges, Centennial's Q2 realizations were 77% of WTI or $21.47 per barrel compared to $45.14 in Q1. Lower oil realizations as a percentage of WTI, primarily driven by a negative CMA roll adjustment, particularly during the month of May. Lastly, NGL prices were down 46% to $7.72 per barrel compared to $14.30 in Q1. Turning to costs. Despite the decline in production volumes, unit costs continue to look good relative to our expectations. LOE per barrel decreased by 17% from Q1 to $4.16 primarily as a result of lower workover expense as well as continued reductions in equipment rentals and electricity. Cash G&A for Q2 was $2.21 per barrel overall, that was $1.75 when adjusted for severance costs primarily associated with our recent workforce reduction. DD&A decreased by 3% to $14.98 per barrel. Lastly, GP&T expense increased 7% to $2.78 per barrel, in part because of a significant reduction in FT monetization relative to prior quarters. In Q2, we recorded GAAP net income attributable to our class A common stock of approximately $5 million. Adjusted EBITDAX totaled $24 million, down from approximately $113 million in Q1, due to lower commodity prices and production volumes, which were partially offset by reduced operating costs. Shifting to CapEx, during Q2 we ran essentially zero drilling rigs and did not spot any wells. In April, we completed four gross wells, compared to 22 completions during the prior quarter. As a result of lower activity and continued cost reductions, Q2 D&C CapEx was $21 million, compared to approximately $147 million in Q1. As Matt will describe shortly, our D&C cost per well declined quite significantly as a result of internal initiatives to improve efficiencies, as well as overall service market conditions. Facilities and infrastructure capital totaled approximately $6.5 million compared to $25 million during Q1 due to the lower level completion activity in Q2 and fewer infrastructure needs. We also incurred approximately $100,000 in land capital. Despite the diminished land spend, we anticipate maintaining our acreage position as a result of recent swaps and trades executed by our land team. Overall, Centennial incurred approximately $28 million of total capital expenditures during the second quarter, compared to $175 million in Q1. Turning to Slide 8. As we addressed briefly on the last quarterly call, in April we launched the debt exchange that provided all bondholders the opportunity to exchange their senior unsecured notes into second lien notes at a significant premium to the prevailing market price. The objective of the exchange was to reduce our total senior unsecured debt amounts and lower interest expenses. On May 22, we completed the exchange in which holders of $254 million of senior unsecured notes across both the 2026 and 2027 tranches tendered and exchanged their bonds for 127 of new 8% second lien notes due in 2025. The net effect of the exchange was a reduction to our senior notes of $127 million, and we were pleased to have closed the transaction during a very turbulent period in the markets. On Slide 9, we summarize our capital structure and liquidity position. At the end of the quarter, we had $370 million of borrowings on our revolving credit facility. During the quarter, we borrowed $135 million on the facility, which was an unusually high amount relative to previous quarters, particularly in light of the minimal capital spend during the second quarter. The increased level of borrowings was primarily related to working capital changes, including a significant reduction of our accounts payables and accrued capital expenditure line items. This occurred because second quarter working capital needs were still reflective of higher levels of activity from Q1 and because incoming cash for the quarter was lower due to deteriorating commodity prices coupled with lower production. I would note that we do not anticipate anything remotely near this level of borrowings in subsequent quarters. In fact, based on anticipated capital spending levels for the second half of the year, which you can reference on Slide 10 of the presentation, we expect that expenditures will be funded through operating cash flow based upon current strip pricing and our hedge position. As of June 30, Centennial had total liquidity of approximately $300 million, which is based upon the $700 million borrowing base, adjusted for the $32 million availability blocker, $370 million of outstanding borrowings, $8 million of letters of credit outstanding, and approximately $7 million of cash. Given that we don't anticipate significant level of borrowing going forward, we expect that our liquidity position will remain quite sufficient for future activity. Finally, at June 30, Centennial's first lien debt to LTM EBITDAX was 0.9 times, net debt to LTM EBITDAX was 2.6 times, and net debt to book capitalization was 29%. I'll remind you that the leverage covenant currently applicable in our credit agreement is first lien debt to LTM EBITDAX, which currently has a maximum threshold of 2.75 times, providing plenty of cushion. The amendment to our leverage covenant, which was completed concurrently with the debt exchange, significantly enhances our financial flexibility going forward. Turning to hedging on Slide 13. As a result of the Q2 hedges that we established in March as oil markets were rapidly deteriorating, we incurred a hedging loss of approximately $7 million during Q2. At the time, we also entered into similar hedges in Q3 and will likely incur even more significant hedge losses during the third quarter. At the time, we made the prudent decision to implement these hedges in order to protect the company against further downside risk in the event that oil prices remained at severely depressed levels for a prolonged period. Subsequently, we have initiated a more systematic hedging program to protect future cash flows, which is more representative of what you'll see in the future. Going forward, we plan to hedge a portion of our production with the goal of covering certain corporate costs such as G&A, interest, and exploration expenses, while also retaining exposure to potential upside in prices. With this philosophy in mind, we recently entered into fixed price WTI swaps for the fourth quarter of this year, covering 13,000 barrels per day at an average price of $38.89. Additionally, we have costless collars in place for Q4, covering 2,000 barrels per day with a floor of $39 and a cap of $44.50. We anticipate continuing to add to our oil hedge program for future volumes with a primary focus on 2021. I'd now like to touch on our updated 2020 corporate guidance on Slide 12. As you'll recall, we have largely suspended guidance, with the exception of CapEx back in late March as a result of the precipitous decline in oil prices and our concomitant reduction in activity. We are now able to reissue full-year guidance given that prices have stabilized to some degree and the potential for future shut-ins has been drastically reduced. As oil prices have recovered from record lows, we have commenced the completion of five ducks in New Mexico and assuming strip pricing, we plan to add one operated rig in the fourth quarter. Currently, we expect this rig will commence drilling in Reeves County before moving to New Mexico late in the year where it is likely to remain. We expect the completion activity to generate midpoint oil production of 35,500 barrels per day for the year. You'll also note that oil as a percentage of total production is expected to be approximately 54%, which is not surprising given the lack of flush production from new wells compared to prior periods. Given these planned activity levels, we estimate total capital expenditures for the year of $240 million to $270 million, which represents a $10 million reduction at the midpoint compared to our previous guidance. As you can see back on Slide 10, total CapEx incurred during the first half of 2020 represents approximately 80% of our updated full year budget and was largely driven by our five-rig drilling program at the beginning of the year. This implies a much lower spend in the second half of the year compared to the first, which will, as I mentioned, be expected to result in cash flow neutrality for the balance of the year. To wrap up, I hope you've come away with a sense of the tangible progress we've made on a number of fronts during the quarter. We materially reduce our cost structure, particularly with regards to G&A and LOE costs. We were able to reduce our total principal amount of debt outstanding by $127 million while lowering future interest expense. And finally, we've instituted a hedging program providing protection from downside commodity risks. Ultimately, all of these actions have better positioned the company for the future. And with that, I'll turn the call over to Matt to review operations.

Thank you, George. During challenging times such as present, we have been more focused than ever on reducing what costs we can control across every single discipline in the company. As many of you know from last quarter's call, Centennial has implemented a number of projects in the field focused on reducing LOE costs. And I'm pleased to share with you the progress we've made, as well as detail the positive financial impacts that they've had. As you can see on Slide 5, we reduced second quarter LOE per unit by 17% compared to last quarter, representing our third consecutive quarter of declining LOE per unit. Even more impressive is the fact that we've been able to continue to reduce our LOE in a declining production environment. Viewed from a slightly different perspective, total LOE decreased $16.5 million from the third quarter of 2019, even though we added over 50 wells since that time. This considerable savings has been driven by the execution from our operations staff on a number of different fronts. Earlier this year, we completed Phase 1 of our company-owned electric substation in Reeves County; upon initial startup, we were immediately able to reduce the number of generators from approximately 135 to 50 as seen on Slide 6. The savings on rentals from this is obvious, but the more reliable and consistent form of power manifests itself in significant reductions in downtime, which directly impacts the bottom line. Additionally, we expect Phases II and III of our electric substation to be operational during the fourth quarter of this year, further reducing our reliance on generators and having a direct impact on our go-forward LOE cost. Staying on Slide 6, you can see our transition to gas lift has been a significant effort by our production and field teams. At this time last year, roughly half of our wells were reliant on ESP as the primary form of artificial lift, and only 20% utilized gas lift. By Q2 of 2020, we had added roughly 100 incremental wells to the field, and only a third of the total wells remained on ESP, while 40% utilized gas lift. This is key because gas lift is inherently more reliable when compared to ESPs. The increased reliability of our artificial lift program has resulted in a more stable production base with lower downtime. We've also seen our failure rates for the artificial lifts drop by 34% this year compared to 2019, resulting in less workover expense. We will continue to utilize gas lift across our assets wherever possible. Our team has also continued to optimize our saltwater disposal system in Reeves County. Year-to-date, we've realized significant reductions in disposal costs through the removal of generators at our SWT sites. In addition, costly trucking of produced water has virtually stopped as 97% of our water is now via pipelines. Combined, these efforts have reduced our per-barrel disposal costs on our operated system by 35% compared to last year, adding continued downward pressure to LOE and further increasing the value of our SWT system to Centennial. While this is just an update of a few of our larger cost savings initiatives, we've continued to pursue smaller items such as equipment purchases that are at historically low prices. With prices as low as they are, in many cases, purchasing equipment rather than renting just makes good business sense. Additionally, we continue to scrutinize and bid out all of our service providers for better pricing. Turning to well costs, I'd like to detail some of the continued improvements that we're seeing in D&C costs, which are seen on Slide 7. We've seen a material steady decline in our D&C costs, which have been driven by both higher efficiencies as well as structural cost reductions. Beginning with drilling, year-to-date, we've reduced our spud-to-rig release cycle times by 25% to just over 18 days on average compared to last year. And while we are proud of these improvements overall, we believe there is still plenty of room to realize lower costs and greater efficiencies. We have taken full advantage of our drilling hiatus to focus on every single aspect of our drilling program from pad construction through the rig release, carefully evaluating every aspect of the operation. When we resume activity, it will be a very different look for us. Since much of these changes are attributable to our new Centennial 2.0 culture and a much more streamlined approach to our cost structure, we believe the majority of these lower costs will be permanent and not necessarily tied to potential service cost inflation in a rising oil price environment. On the completion side, we continue to be impressed by what our team is accomplishing. Compared to last year, we've increased our average stages pumped per day, year-to-date, by roughly 35% to over eight stages per day. Put another way, we have increased the total lateral footage completed per day from 1,350 feet in 2019 to 1,700 feet per day in 2020. With this team's track record of success, we feel confident about maintaining that high level of performance when activity resumes. But we've also benefited from overall service cost reductions. Our water recycling efforts are starting to play a bigger role this year in our completion cost reduction. For quick background, in 2019, we implemented a water recycling program with an initial focus on our New Mexico operations. Last year, we recycled and reused over 3 million barrels of flowback and produced water in New Mexico. After successful implementation in the Northern Delaware, earlier this year, Centennial initiated those same solutions for our Texas operations. Water recycling reduces both freshwater consumption and produced water disposal volumes, which not only lowers our overall completion costs and positively impacts LOE, but also is important from an ESG perspective. Year-to-date, we have recycled 72% and 31% of flowback volumes in New Mexico and Texas, respectively, and plan to continue to increase our use of recycled water with the goal of utilizing recycled water whenever practical. To sum it up, Centennial is not the same company we have been in the past. The hard times that we've endured have forced us to look at every single piece of our business and consider ways that we could do it better. The fruits of this labor can be seen in the graph at the top of Slide 7, where overall, we've reduced our year-to-date total well costs by approximately 25% compared to early 2019. As a reminder, since operators report these figures several different ways, I would point out that the well costs we provide are fully burdened, inclusive of drilling, completions, facilities, and flowback costs. More importantly, we believe a large portion of these savings are more structural in nature. Set another way, based on current strip prices, along with the expected oilfield service environment, we believe that we will be able to further reduce all-in D&C costs to approximately $900 per lateral foot, assuming our average of 7,500-foot lateral lengths, when activity resumes later this year. With the goal of even further reductions to the sub-$900 per foot range in 2021. Before I pass it back to Sean, I want to touch on our exposure to federal leasehold, as I know this is a topic of recent concern. Out of our roughly 80,000 net-acre position spanning both the Northern and Southern Delaware Basins, Centennial only has 4,000 net acres, or approximately 5%, located on federal lands, all in Lea County, New Mexico. Though our federal land leases only represent a small portion of our total land position, we continue to be proactive about building permit inventory, such that we always have multiple years of permitted drilling locations. And with that, I'll turn it over to Sean for closing remarks.

Thanks, Matt. Having made some significant cost improvements in the business over the past several months, I trust you can understand why we're excited to resume activity during the second half of the year. This is an important first step in order to moderate current declines and provide momentum heading into 2021. I'm confident that we'll be able to carry forward the cost reductions you've heard highlighted on today's call. Therefore, it is key to understand that our future growth as a company will be supported by expanding margins, specifically pertaining to future LOE and G&A costs, and materially lower well costs. Finally, one positive outcome which has resulted from our reduction in activity is the significant reduction of our corporate decline rate. As I mentioned during last quarter's call, our corporate oil decline rate was 45% to 50% at the end of March. Including our planned activity during the second half of this year, we expect this metric to improve to the low 30% range by the end of this year. This represents a significant reduction and will have multiple benefits. The resetting of our corporate decline rate will provide a stronger production base for us to restart activity, helping us eventually return to modest production growth in the future. Before we go to Q&A, I'd like to leave you with five key takeaways from this morning's call: One, we've significantly lowered our D&C costs, thus driving capital efficiency, and there's still more room for improvement as Matt mentioned. Two, we've enhanced our margins as a result of recent cost initiatives and optimization of our asset base, particularly to LOE and G&A. Three, our corporate decline rates will be materially lower than previous years providing us with solid footing headed into 2021. Four, we've reduced the total principal amount of debt outstanding and lowered future interest expense, as a result of the debt exchange. And five, finally, we expect to be essentially cash flow neutral for the remainder of this year, helping us to manage liquidity while resuming activity. In closing, all the above will provide a solid base for Centennial underpinned by a materially lower cost structure. And let's not lose sight of the fact that we have very high-quality assets and an outstanding technical team to sustain and drive the future value of the company. With these tailwinds in our back, we're excited to return to a modest level of activity as we close out 2020 and head into 2021. Thanks for listening, and now we'll head to Q&A.

Thank you. The question-and-answer session will be conducted electronically. Our first question comes from Scott Hanold with RBC Capital Markets.

Thank you. I guess my first question would be, what is the plan going forward? I mean, obviously, you guys had taken off all activity when prices got low and are starting to resume now. But as you look forward, what strategically do you want to do? Is the goal to reduce gross debt and leverage metrics to a certain point, or maintain production? If you can give us some line of sight on how you think about that? And when you do start activity on a more consistent basis going forward, is it going to be more weighted to the New Mexico area or to Texas?

Sure, Scott. I appreciate the question there. And I certainly understand the desire for everybody to get a look at 2021. As we all know, that the back half of this year is going to bring a lot of changes, and a lot can happen between now and when we start talking about our full guidance for next year. With elections coming up, we've got the vaccines relative to the pandemic, we'll see how that affects our global economy and then ultimately, supply-demand dynamics. And so all of that weighs into how we're looking at it next year. We have never given forward-looking guidance this early in the prior year, so that's not something we're going to do today. But from a management perspective, take into account that we've totally reset the company from our corporate decline rate, cost structure, and balance sheet, and we really positioned ourselves to respond to however commodity prices look going into next year. I think we've done a very good job of that. And the fact that we're cash flow neutral in the back half of the year really just shows how we've restructured the business. So while we don't give forward-looking guidance, what can be said is that we are going to balance both the capital spend returning to some level of activity while at the same time managing our leverage profile. So it'll be a combination of the two as we manage our business going forward. I know that's not the maintenance CapEx number that people are looking for, but that's how we are going to manage our business for the back half of the year and how we look into 2021.

I understand the challenges. I appreciate that color. And my follow-up.

Let me just address that before you even ask one more follow-up. Texas and New Mexico—I think that George mentioned that maybe the rig is going to start off in Texas and then move into New Mexico. That is the plan we've got. It just—we've got some very attractive leases there that we'd like to get to in Texas that can provide very favorable returns. So we're going to hit a two-well pad there, assuming we have a rig stand up in the fourth quarter. And then that rig will immediately move to New Mexico, where it will be in development mode on our New Mexico assets. So that's kind of our plan of activity and how we plan to attack it at the end of this year going into the first part next year.

And then my follow-up question is obviously the big transaction of Chevron on Noble. You could have implications on your acreage, and Noble's very intermingled with your acreage profile. Could you remind us how much of your acreage development strategy is somewhat continuous with Noble, or are you planning just to kind of go your separate ways? Or is there some push and pull now with Chevron taking control of that land?

I would say, there is not going to be any material push and pull with Noble and Chevron going forward. We operate the majority, I mean nearly all of our position, so we control our own destiny and we won't get pulled into any material non-operational positions with the new operator down there. I think we're in a very favorable position. They are more adjacent to us and intermixed with us, so I look forward to seeing what kind of development plan Chevron has for that area, but I don't think that it will impact any of our operations.

Your next question comes from the line of Neal Dingmann, Wunderlich Securities.

I know you mentioned a two-well pad. My next question is about the cost comparison for two-well versus three-well pads. Can you provide some insight on that?

You were breaking up during that question. But I think I got it all. You were really talking about pad size and capital efficiency associated with our average pad size. And can we continue that going forward? I think that's what you're getting to. So that's what I'm going to answer now. If that doesn't sound right, we can try it again.

That's it. That's it.

Going forward, we do plan on two, three, and four-well pad sizes. I think that's consistent with what we've done in the past. I think the efficiencies that we've seen in Q1 and even into late last year will continue those efficiencies plus the continued improvement as Matt had mentioned. So I don't think we'll have anything lost from going from five rigs to now ramping back to one rig and then eventually more as we go into the future. Maybe Matt, I'll let our COO address anything that I may have missed there. But go ahead, Matt.

I think fundamentally what Sean said is correct with regard to our desire to drill more wells on a pad. Our sweet spot is somewhere around two and three wells per pad on average. That being said, anytime you're standing up a rig and starting over, there will be just some level of efficiency lost from when you were running multiple rigs for months on end. So, I wouldn't expect right off the pad that we hit our stride on the very first well out of the gate. I think it's going to take some familiarity with the people in the field and some communication and oversight from our guys in the office. And then I think we'll hit our stride pretty quickly because we do have lofty expectations for efficiencies on a go-forward basis.

Okay. On the hedges situation. Earlier this year, I thought your outlook for 2021 would put you in a much better position, both in terms of cash and operations. So, would it be more about taking opportunities with the hedges? How are you considering this?

Yes, I think Neal, the way we're thinking about the hedges, as I said in my remarks, we think about it in terms of covering a big chunk of our corporate costs, whether they be G&A or interest. And we're going to do that primarily through swaps and, to some extent, costless collars. In addition to that, in a more normalized operating environment, part of the philosophy is to hedge some volumes to protect your cash flow so that you can support your capital program with your overall activity levels. The other thing to think about is how those hedges might impact your borrowing base. There is a thought to optimize and enhance our borrowing base levels going forward. We also want to recognize that we're in the depths of the world here with the global economy, and as the economy improves, oil prices will go up. So we do want to give our investors some upside exposure as well. So there's a bit of a balance there. But I'd say as our strategy is evolving, it's obviously something that's new to the company. I think you can differentiate between what we did in Q2 and Q3 versus what we've done in Q4, and what we plan to do going forward. We don't have specific targets or timing for hedging a certain percentage of volumes, but that's something that we're working on internally as we go. Bottom line is we will be much more active from a hedging standpoint and mitigate the risks associated with the oil price environment.

Your next question comes from the line of Leo Mariani from KeyBanc.

Just wanted to get a little bit more color on actually restarting here. You certainly go into the one rig case just kind of wanted to get a sense is that a level of activity you feel pretty comfortable at? It's sort of $40, you guys have mentioned potentially adding some other rigs in the future. Is it really just kind of governed by cash flow? Is the plan going forward just to do your best to kind of spend within cash flows? Just trying to kind of get a sense of what the governors are for future activity changes?

Sure, thanks Leo for the question. Yes, I do feel comfortable that we will be likely adding a rig in the fourth quarter, obviously depending on what commodity prices are doing. I think it's still a volatile market. It has stabilized a bit, as we've all seen; it seems like $40 is now a bit of a floor at least recently. That's a good sign that there is support for that price and above. I think as we mentioned in the prepared remarks, assuming strip pricing, which is essentially $40 slightly increasing in the outward years, that supports at least a modest level of activity. Should prices change one way or the other dramatically, we may pivot from that, but I feel very comfortable that is where we're heading towards the back half of the year. We haven't given what a rig case would look like for next year, but assuming prices continue to improve and we think over time they will, as those prices continue to see upward momentum and support, look for us to add additional activity. That being said, we'll all be balanced with our leverage being forefront in our mind. We want to position the company such that we don't get too far overextended from a leverage perspective. Balancing between the two will be what we are doing going forward.

I guess, just following up on the leverage. Obviously, you guys had a successful debt exchange here recently. Just trying to get clearer on other future initiatives at the company to reduce debt. You're talking about spending within cash flow in the second half of the year, which maintains that debt. Are there other things you guys might be looking at, whether it's future debt exchanges or other initiatives to potentially reduce debt over the next couple of years?

We'll always be looking for opportunities to lower our leverage profile if there are options to do so that are accretive to our metrics. You recall we were looking at an asset sale earlier in the year, which would have materially changed our balance sheet. That did not go through, as we all know, but the benefits of that is that keeping that asset helped push our LOE costs further down. So there are good things to that. So we are always looking at strategic sales of non-core assets, and we'll continue to do that. If we're able to put a package together again of non-core assets that we think we can get fair value for that will be accretive to our metrics that will help de-lever the company, then we'll consider that going forward.

Your next question comes from the line of Will Thompson from Barclays.

I appreciate the detailed look under the hood and all the cost initiatives. It clearly seems like you there's more structural nature. But I want to ask—one of the slides indicates that Centennial is in active negotiation with service providers. Can you just give us a little sense on how those conversations are going and whether price concessions would be expected for 2021 cost impact versus what you're kind of taking in the second half of 2020?

Sure. Yes, this is Matt. I'll go ahead and start trying to field that question. We provided on Slide 7 a bit of a historical look at our performance since 2018, really from the spud-to-rig release as well as our completion stages per day, really kind of deliberately to show a bit of a track record of the structural efficiency gains with regard to our overall costs. If you think about this company's activity, the majority of our activity was in fact almost all in Q1. It stopped abruptly in Q2, as George alluded to in his portion of the script. And so with the exception of some minor spillover with regard to a few completions that were done in the first couple of weeks in Q2, dominantly, the costs that were reflected on Slide 7 were indicative of more structural changes. The negotiations with service company providers obviously without tipping too much, we feel very good about there being some additional upside potential there to realize some cost savings on top of that. We, of course, consider those kinds of things in a go-forward look at our business. But for the purposes of planning and for the purposes of just sticking to the fundamentals of blocking and tackling, we really like to focus on the things that we can control and the things that we can change with our teams. Does that help you?

That does. Thank you, Matt. And then I guess my follow-up just to clarify on the base decline. The improvement from to low 30s, is that on a BOE basis? And if it is, I mean how much Delta would it be for oil? And then maybe to manage expectations and context before your production guidance, is it fair to assume 4Q will be below 3Q levels? Just want to understand sort of the cadence and why the fact that's being completed this quarter.

Yes, I appreciate the question, Will. Thank you for acknowledging that we've given some increased level of detail. That's intentional; we're trying to be more helpful for folks to get a better look at the company and how we operate structurally going forward. Relative to the corporate decline, those numbers are quoted on a BOE basis, and we feel good about that being the controlling metric for the company. And so that's how we kind of think about things. We don't give quarterly guidance, and so that's not something I think I'm going to weigh in on. I think if you draw a line from where we stand today to the midpoint of our guidance, it'll give you a good feel for how we're thinking about things. That's the level of detail we can kind of provide from a quarterly basis.

Our next question comes from the line of Duncan McIntosh with Johnson Rice.

Quick question on the OpEx side. You guys have mentioned pretty impressive improvements. And like you said, despite volumes kind of coming down. That being said, it does look like based on the full-year guidance LOE comes up a little bit in the back half of the year. What's the driver there? And then to kind of get the midpoint looks like levels are around five dollars? Is that kind of a good number to think about going forward as well?

Sure, I'll touch on that, and if I'm missing anything, Matt can jump in. I think if you look at the back half of the year, obviously our activity level has slowed. And so our production will then also continue to decline a little bit. We've added a little bit of activity in the fact that we've got some ducks that we are currently completing, and we plan to start up a rig in the fourth quarter. But that's not going to be fully enough activity to offset the decline. So from a unit cost perspective, you may see some increase in LOE, but from a total dollar number, we're still working on decreases.

At this time, we have no further questions. This does conclude today's conference call. You may disconnect at this time.