Good morning, and welcome to Centennial Resource Development's conference call to discuss its first quarter 2020 earnings. Today's call is being recorded. A replay of the call will be accessible until May 19, 2020, by dialing 855-859-2056 and entering the conference ID number 6939844 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. And thank you all for joining us on the company's first 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, May 4, we filed a Form 8-K with an earnings release reporting first 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 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 March 31, 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. I'd like to start by extending our thoughts and prayers to all those who have been impacted by the coronavirus, as well as thank all the first responders, healthcare workers, and other essential service personnel. We are truly indebted to these individuals who are on the front lines fighting this pandemic. In response to COVID-19, even before state and local officials in Colorado and Texas issued mandatory stay-at-home orders, Centennial had already instituted a work-from-home policy for all our employees in the Denver and Midland offices. While our office employees are still working from home, the organization has been able to continue to perform all our field operations as well as back and front office functions without any material disruption to our business. This is a direct result of our team's resiliency, positive attitude, and teamwork. Keeping our employees, business partners, and all their families healthy will remain a top priority. I think everyone listening in on the call is aware of COVID-19's impact on global oil demand, which has resulted in a steep decline in crude oil prices. Now more than ever, we will remain focused on our balance sheet and liquidity. We acted quickly to suspend our drilling and completions activity in response to low oil prices, and going forward, we'll be keenly focused on reducing costs, protecting the balance sheet, and managing our liquidity. Given the potential for near-term shut-in volumes and declining drilling activity by both U.S. and international producers, we believe there is a good chance that oil prices will be higher towards the end of this year. Therefore, our capital budget allows us the flexibility to resume a modest amount of activity during the second half of the year depending on prices. As many of you saw in today's earnings release, we plan to voluntarily curtail up to 40% of our production in May. This is a prudent financial decision given projected netback prices during the month of May. Future curtailment decisions, both voluntarily due to price or involuntarily due to midstream congestion or storage constraints, will be made on a month-to-month basis depending on commodity prices and other contractual agreements. In addition to the announced capital reductions, we've taken several steps to significantly reduce our cost structure. Given the current commodity price environment, we recently made the difficult decision to reduce the size of our workforce. While we are extremely proud of the organization that we've built over the past three years, this reduction will position us to navigate the uncertain macro environment and better align the company organizationally to anticipated activity levels. Additionally, we made reductions to employee salaries across the board, with the largest reductions being taken at the senior management level. Specifically, the Vice Presidents, George and I have reduced our salaries by 10%, 15%, and 25%, respectively. The Board of Directors has also elected to reduce their cash retainer by 25%. These are unprecedented and challenging times for our industry, including Centennial, but as you can see from the actions outlined today, we are acting swiftly and decisively to protect the business. With that, I will turn the call over to George to review the financial results.

Thank you, Sean. I will first go over our financial results for Q1 and then summarize some financial considerations regarding our response to the current oil price situation. Looking at our financials on Slide 12 of the earnings presentation, our net oil production for the first quarter averaged around 41,500 barrels per day, representing a 2% increase compared to the same period last year but an 8% decline from a strong Q4. Our average net oil equivalent production was about 71,800 barrels per day, which remained relatively unchanged versus the prior year but was a 10% drop from Q4. It's important to note that our main natural gas processor operated under ethane rejection for the entirety of Q1, which affected our NGL volumes during the quarter. Despite solid well results, production volumes were influenced by the timing of completions and shut-ins of offset fracking operations. Of the 22 wells that came online during this quarter, about 20% fewer than in Q4, nearly half were completed in March and thus had limited impact on overall production. Revenues reached approximately $193 million, marking a 25% decrease from Q4, primarily driven by lower production and diminished commodity price realizations across all product streams. Excluding basis hedge impacts, Centennial's realizations were 98% of WTI, or $45.14 per barrel for the quarter, down from $53.25 in Q4. In terms of unit costs, we maintained positive momentum from the previous quarter. LOE per barrel fell by 6% from Q4 to $4.99 per barrel, mainly due to reductions in equipment rentals, ESP expenses, water disposal, chemical costs, and lower workover expenses. Matt will cover more details on our LOE soon. Cash G&A for Q1 was $1.99 per barrel, down 6% from the previous quarter. DD&A decreased by 8% to $15.49 per barrel because of reserve additions during the quarter. GP&T expense also declined by 8% to $2.59 per barrel. Collectively, these unit cost metrics were down nearly $2 per barrel compared to last quarter, even though total equivalent production dropped by 10%. In Q1, we reported a GAAP net loss attributable to our Class A common stock of $548 million, stemming from a non-cash impairment charge of $611 million, primarily related to proved oil and gas properties. This impairment was a result of lower commodity price futures for both oil and natural gas as of the end of Q1. Adjusted EBITDAX was around $114 million, down from $160 million in Q4 due to reduced commodity prices and volumes, partially offset by decreased operating costs. Regarding CapEx, we operated 5 rigs for most of the quarter before responding to the significant drop in crude oil prices. In context, we entered March with a 5-rig plan and, by early April, had already reduced the number of rigs and dedicated frac crews to zero. We incurred about $1.5 million in rig termination fees in Q1. For the quarter, we spud 17 gross wells and completed 22, compared to 22 and 27 gross wells, respectively, in the previous quarter. As a result of reduced activity and ongoing well cost declines, Q1 drilling and completion CapEx fell to $147 million or 10% lower than Q4. Capital for facilities and infrastructure reached about $25 million, down nearly 20% from Q4 due to decreased completion activity in Q1. We also spent around $3 million on land capital. Overall, Centennial's total capital expenditures in the first quarter were about $175 million, a decline of 11% from $197 million in Q4, marking our fifth consecutive quarterly CapEx reduction. On Slide 8, we outlined our capital structure and liquidity status. Following our spring redetermination process, our borrowing base was adjusted from $1.2 billion to $700 million. By the end of the quarter, we held $4 million in cash and $235 million in borrowings on our credit facility. As of March 31, and adjusting for our updated borrowing base, Centennial had total liquidity of $468 million. Finally, Centennial's net debt to LTM EBITDAX ratio at March 31 was 2x, and net debt to book capitalization was 29%. Now, regarding our response to the lower commodity price environment, there are several key points to discuss. First, concerning CapEx, as noted on Slide 10, we have halted activities for the foreseeable future and currently have no drilling rigs or completion crews active. You may remember that in mid-March, we reduced our rig count from 5 to 1 and suspended our initial annual guidance. We have since announced a revised 2020 annual capital budget of $240 million to $290 million, reflecting the suspension of all near-term activity but leaving room for the potential resumption of modest completion and rig activity in the second half of the year, depending on price improvements. This new CapEx guidance represents a 60% reduction from our original plan for approximately 4 rigs for the year. However, it is a more significant drop considering that around two-thirds of our total forecasted capital expenditures for the year were incurred in Q1. About 85% of our revised annual capital budget is expected to pertain to drilling and completion capital. For Q2, it's worth mentioning that we completed 4 wells in early April. Thus, while we plan to run no rigs for most of the second quarter, we will still incur related CapEx from that activity. It is also important to note that even in the absence of drilling or completion activity in a quarter, we will still incur a small amount of fixed or recurring capital for capitalized workovers, infrastructure, and land. For instance, if we do not spud or complete any wells during a quarter, we might still expect to spend $10 million to $15 million on these items. Given the ongoing uncertainty from COVID-19, oil market volatility, and potential future curtailments, we are maintaining our previous suspension of annual guidance on production and unit costs as we cannot reasonably estimate these elements at this point. In terms of expenses, we have significantly reduced our cost structure through the difficult choice to implement a reduction in force. We anticipate these reductions, combined with other non-payroll initiatives, will lower Centennial's original 2020 cash G&A budget by around 30%, or about $18 million to $20 million annually going forward. Due to the timing of the cuts and associated one-time costs of approximately $3 million to $4 million, we forecast that our full-year 2020 cash G&A budget will be roughly 15% lower than the original guidance. We will continue to examine costs throughout the organization, both in the field and in our corporate offices, to ensure we are operating as efficiently as possible. As for hedging, starting in March, we implemented significant fixed-price oil hedges, primarily for Q2 and Q3, to guard against further declines in WTI prices, which are regrettably occurring right now. Slide 11 summarizes our hedge positions. In total, we have hedged approximately 19,400 barrels of oil per day for the rest of the year, primarily in Q2 and Q3, at a weighted average price of just under $27 per barrel. We have started hedging our Q4 volumes and will actively expand our oil hedge position for Q4 2020 and into 2021 in the upcoming quarters. Regarding our credit facility, as previously mentioned, our borrowing base was revised to $700 million, providing the company with substantial liquidity. Additionally, we have amended our credit facility to remove the total debt leverage covenant through the end of 2021. This covenant will be replaced by a first lien debt to EBITDAX leverage ratio starting at 2.75x and decreasing to 2.5x in Q1 2022. We believe these adjustments offer further flexibility in a challenging environment, and we appreciate the support of our banking partners. Lastly, on April 22, we announced the initiation of a debt exchange offer where current bondholders can swap their senior unsecured notes for new senior secured notes. Depending on how many holders exchange their existing senior unsecured notes, this transaction could significantly lower total outstanding debt and reduce annual interest expenses. The early tender date for this exchange is today at 5:00 p.m. Eastern Time, while the final expiration date is May 19. We will keep the market updated when results are available, but we will not address any questions regarding the exchange during the Q&A session today. Before I hand this off to Matt Garrison, I would like to welcome him to the executive management team. Matt was promoted to Chief Operating Officer last month and has been leading our Geosciences Department since 2016. He played a key role in our initial growth and entry into the northern Delaware. Before joining Centennial, Matt spent 9 years at EOG, mainly in their Midland office, concentrating on exploration and development in the Delaware Basin. Sean and I congratulate Matt on his well-deserved promotion. Now, I will turn it over to Matt to discuss operations.

Thank you, George. This was another solid quarter for the operations team, highlighted by continued reductions in D&C and unit costs. Overall, well results during the quarter were in line with our expectations. But as George alluded to earlier, first quarter oil volumes were impacted by our March weighted completion schedule as well as higher-than-expected offset shut-ins during February. Thus, despite solid well results, the majority of our Q1 completions had a limited impact on first quarter production due to timing. Turning to the cost side. During the quarter, we continued to build upon our recent drilling and completions efficiencies, which have been highlighted in the past two earnings calls. Slide 6 details our ongoing improvement in spud to rig release and completion stages pumped per day. Overall, these efforts resulted in a 9% reduction to our drilling cost per foot and a 13% reduction to our completed lateral cost per foot in the first quarter compared to the second half of last year. Most importantly, I believe we will continue to see improvements in both our cost and efficiency metrics when activity resumes. During downturns such as this, it is important to manage our controllable costs. Sean mentioned our recent G&A reductions, and we've also worked to find ways to lower our LOE costs. As you can see on Slide 5, first quarter LOE of $4.99 per Boe represents a 6% reduction from Q4 and a 17% reduction from Q3 levels. This decrease is the result of numerous projects undertaken by our team, dating back to around this time last year. First, we've been able to save a significant amount in electricity costs throughout our operating base. We've been gradually transitioning more facilities off of generators and onto electrical grid power, which saves money on equipment rentals. Additionally, Phase 1 of our company-owned electric substation will be operational this month, allowing us to shift further away from generator-provided power. Second, we've had an ongoing effort to transition more of our artificial lift methods from ESPs to gas lift, which has benefits from both a cost and production standpoint. The increased reliability associated with gas lift results in fewer overall workovers, which directly impacts the bottom line by providing stability to the base production. Third, we've taken a hard look at our chemical providers and our overall usage needs. In doing so, we found that we can cut costs and optimize our usage in the field. Lastly, as an overall improvement in our operating efficiencies at the field level, several LOE categories have seen quarter-over-quarter declines driven by our Pecos and Hobbs production operations staff. These smaller categories are starting to show up in a significant way, and we expect for these trends to continue going forward. I'd note that none of these projects are one-and-done in nature. These are ongoing cost-saving initiatives that we'll be focused on throughout the year. Going forward, our team will continue to analyze every dollar spent, looking for additional ways to cut costs. Before I pass it back to Sean, I'll provide a quick update on our pending SWD divestiture. As previously announced, in February, we entered into a purchase and sale agreement with WaterBridge to divest our SWD and associated water infrastructure in Texas for $225 million, consisting of cash and incentive payments. That transaction remains pending, and either party may terminate the transaction if closing does not occur on or before May 15, 2020. And with that, I'll turn it over to Sean for closing remarks.

Thanks, Matt. As you heard from our comments this morning, protecting the balance sheet will remain our number one priority during these times. Before we go to Q&A, I'd like to quickly recap the steps we've taken to achieve this goal. We've shut down all our drilling and completion activity in the near term, resulting in an approximate 60% reduction to our original CapEx guidance. We significantly reduced our G&A in response to lower activity levels. We secured a $700 million borrowing base and amended our credit facility to provide leverage covenant relief. And finally, we hedged a substantial portion of our 2020 production to protect against downside commodity risk. In closing, we are fortunate to be entering this low commodity price environment with a solid balance sheet and good liquidity. This, along with our proactive steps in reducing activity and costs, should ensure Centennial prospers once again when commodity prices improve. Thanks for listening, and now we'll go to Q&A.

The first question is from Josh Silverstein.

It's Josh Silverstein. So just a question on the hedging profile here. You guys have mentioned that you're going to start to try to layer in some hedges for next year and the coming quarters. Why don't you just do that today with prices that are higher in 2021 than where you've hedged in 2020? Is there a price point that you're waiting for or something just to trigger that?

Sure. I'll take that, Josh. I appreciate you mentioning that. Hedging has not been part of our repertoire in the past, sometimes to our benefit and sometimes not. Recently, we've made some substantial hedges for both Q2 and Q3, as you've seen. We've also started layering on Q4. I think what you'll see from us going forward is a much more systematic approach to hedging our production. You asked why not hedge out next year. I think prices are going to continue to improve as we go throughout this year and into 2021. So I don't think there's a particular price point that we're going to talk about on this call, but we will continue to add hedges on a quarterly basis going forward.

Got it. And then just a question on the volumes. You guys have held this kind of 40,000 to 45,000 level for, it seems about 6 quarters now and spending anywhere from the $175 million to $200 million plus in that range. If you guys were to add the $75 million of capital in the back half of this year, can you stabilize volumes at a lower level? Or do volumes continue to decline into 2021?

I think production is something we've always focused on certainly in the past. And with production curtailments, that's a hard thing to forecast. So I'm not going to give you some specifics around that. It's just too hard to look at right now, from a curtailment point of view, on how we're going to end the year. Q4 last year was a very strong quarter, and we knew that coming into Q1, it was going to be a little bit lower than Q4, even with the 5 rigs that we had running in the first part of the quarter. So I think the production was in line with our expectations, even though we had a few more shut-ins due to offset completions. I'm going to hesitate or back off the maintenance CapEx question a bit, but know that we are certainly managing production to the best of our ability. And without giving any forward-looking forecast on what our volumes are going to be this year, I'm going to shy away from the back half of that question.

Your next response is from Dun McIntosh.

Sean, I sort of had a quick question, maybe a little more color around the curtailments, up to 40%. How do you kind of think about a true shut-in versus maybe choking wells back? And then to break that down further between maybe some older legacy, kind of lower rate wells versus your more flush production? And then kind of coming out on the back side of that, bringing those back on, any color around costs that might be associated with bringing those volumes back?

Sure. I'll just take a first pass at that, and then maybe I'll pass it over to Matt Garrison to talk about some specifics. But the up to 40% curtailment is what we were very specific in our language there, and that we have the flexibility should we want to shut in up to 40%. We know which wells and how we would roll that out across the field. And so what we do is it's a very detailed look on a well-by-well basis on how we're going to manage that, whether that's a full shut-in or a reduction in production on various wells, it varies across the field. And with that, maybe I'll turn it over to Matt to talk about some specifics on how that process works.

Sure. Yes. As it pertains to the shut-ins of the field, we've been monitoring pretty closely through our production department, our cash flow statements on the wells, and we've been able to model what we think the realized prices might be in the coming weeks and months. The decisions about curtailing or not curtailing production is really driven primarily by the cash flow of the well and then secondarily to that, any sort of volume nominations that we've got maybe for that particular month. As far as old production versus new production, yes, Centennial has quite a few older wells associated with acquisitions made throughout the course of this company's history. And yes, those wells tend to be a little bit higher on the operating costs. And so we do watch those closely. And those are most likely the ones that are in the near-term targets for any sort of curtailments. With regard to the costs associated with bringing wells back online, I would offer that shut-ins are a part of our day-to-day business in normal operating conditions with drilling rigs and completion spreads. So we have a pretty good line of sight on what it costs to shut in wells in the case of offsetting frac jobs. Since this does not involve offset frac jobs, we feel even more confident in our conviction with regard to the costs and we do not anticipate costs that are outside the normal operating procedure for shutting in wells and turning them back on.

Great. And then for a follow-up, I was wondering if you could provide a little color on your current marketing arrangements because I know you've got firm sales with BP, but one of the things that I've kind of been educated on recently, and I think maybe the same for other sell-side analysts, is the exposure to the roll and the contract. And I didn't know if that was a part of what you're doing with BP? Just trying to get a little better idea on pricing in the second quarter.

I think that we haven't disclosed what all of our contracts and terms are with our various providers. But the roll is certainly part of some contracts, and it's certainly part of our netbacks, and so you definitely need to think about whatever pricing index you are using, whether it's Brent, MEH, or WTI, minus whatever roll is in your contract, minus transportation costs. And that's the netback for crude, which is what the majority of contracts have involved, not just us, but across the business. But specifics around that will not be provided.

Your next response is from Christian Renaud.

I guess just looking at the workforce reduction here, where across the organization were these reductions made? And what level of activity are you kind of staffed for right now? Could you go back to a 5-rig program tomorrow if you needed to?

Well, it's a very sensitive topic. Anytime you have a workforce reduction, it affects everybody, both those folks who are no longer here as well as those folks who are at the company. So I'm not going to comment on across which divisions they were mainly focused in. I will talk about, once we do get back to operating, we have retained some staff who are capable of ramping back up to some modest level of operations should we be ready to do so in the back half of the year. And so we're prepared to do that as commodity prices improve toward the end of 2020.

Okay. Great. And then I guess just kind of on that signaling for additional activity, you've mentioned that price is probably the predominant signal that you'd look for. But are there any other things that might govern how quickly you return to activity? And I guess, like what level of activity you'd be looking to get back to?

Sure. So I don't have a specific price that we're going to reference today, but I think the back half of the year and going into 2021 looks a lot more promising than it does today. With that in mind, that's what we're looking forward to. As those prices start to realize, we will consider getting back to operations. So I'm not going to specifically say what price we're going to trigger to start up activity. If you look at strip pricing now, the back half of the year looks a lot stronger than it is today, and we have the ability within the budget that we provided to do some modest level. The number of rigs and the number of completion crews, we haven't specified for a reason because I don't know exactly what commodity prices are going to be. So we've given ourselves some financial flexibility to put some activity in place, and the level of activity will be purely related to the commodity price.

Your next response is from William Thompson.

Sean, maybe just a follow-up on that. I mean, I know oil price is a big factor in determining reactivation activity in the second half of the year. But is there a certain guidepost, like a return, that you're looking to, to justify bringing activity back?

Sure. We are a rate-of-return driven company. And we've talked about that many times. Corporate rate of return is kind of how we judge ourselves. It's difficult in this commodity price environment to say that that's a number today that we're focused on. But overall, for the year, that is what drives our business. And as Matt alluded to, we've been continuing to drive down the cost and increase our efficiencies across the field, both from an operating point of view and also from a capital point of view. As those costs have come down, and I expect service costs to continue to feel pressure throughout the rest of the year, that will continue to lower the commodity price needed to generate a decent rate of return.

And then a follow-up to that. How much do leasehold obligations have on further curtailment decisions and an ability to continue to maintain no development activity? The last I remember, Centennial had significantly increased its percentage of acreage held by production during 2019, but I assume there are some continuous drilling obligations. So just to get your thoughts there.

There are. And I think for any operator that operates in Texas, you tend to have those more so than in other parts of the basin, i.e., in New Mexico, where you tend to hold all depths, all rights. In Texas, you have a little bit more shorter terms on your leases. And so there will always be some kind of need for activity level to hold all positions. That being said, we've done a very good job of HBPing our position and holding our most attractive rate-of-return pieces of property and zones of interest. The amount of acreage that is exposed is minimal in 2020. We had 5 rigs running in the first quarter, which held a significant portion of potential properties that might be expiring. If we ramp up activity towards the end of the year and into next year, I think we're going to have very little problem keeping our acreage position mostly intact.

Your next response is from Neal Dingmann.

Sean, my first question is whether you expect to see much impact at either the field or well level given the significant number of shut-ins you've mentioned. Are you anticipating any issues at those levels? I haven't seen any indications of problems in this regard for you or others so far. Additionally, regarding shut-ins, I've heard that some service companies believe that a considerable amount of stimulation may be required to bring these wells back. What is your perspective on that?

Yes. I'll take the first part of that question, then I'll pass the second part over to Matt to talk about stimulation. But as Matt referenced in both his portion of the script and a previous question, we've done a fair amount of shut-ins across the field throughout our operation, and those shut-ins due to offset fracs, whether they are our own fracs or offset operators, can last anywhere from days to a month. We've got a fair amount of experience, both with the shut-in process and on what that recovery looks like post shut-in. We've seen very little negative effects from shutting in wells for that kind of duration, whether they're older or newer wells. I think we've got a pretty good feeling of what the response will be once we bring the wells back online. Matt, maybe you can comment on if there's any thought about restimulating wells? That was the second part of Neal's question.

Yes. Neal, I was actually going to ask if you could repeat that second part of the question so I can make sure I answer it to the best of my ability.

I've heard differing opinions on the approach to bringing shut-in wells back online. Some service companies say that significant stimulation might be necessary, while others believe it won't be required and that we can simply manage the flow to restart them. I'm curious about your perspective on this issue.

Sure. That's a good question. I'll start by saying we currently do not believe that turning the field back online would require additional refracs or stimulations of any of the laterals that we're proposing to be curtailed. That being said, there is an ongoing initiative within our group to evaluate potential refrac candidates based on a variety of different criteria internally. So that is a project that we are looking at doing in environments like this, where you could potentially realize some cost associated with a refrac or a stimulation, but not all the costs associated with drilling and casing and cementing and everything else. We are actively looking at that, but we have no plans at this time.

Very good. Great details. Sean, I was curious about your drilling approach from earlier days when you were known for having more significant declines. Could you share some insights on how you anticipate the production decline profile or the overall corporate decline as we move towards the end of this year and into 2021?

Sure, Neal. Yes. I think it's pretty well documented, even though we haven't released official numbers on what our corporate decline is. It's widely known that it's in the 45% to 50% range going into the quarter. And we still had 5 rigs running in the first quarter if you recall, right? So coming into this quarter, I would say it's in that same kind of category. But also, as you mentioned, as we have now shut down our activity, you're going to see a material decrease in that corporate decline as we get towards the end of the year and into next year. From that perspective, it will help our PDP decline rates and our production decline rates significantly by not having continued activity. So the one benefit, if you will, of shutting all capital activity down is your corporate decline rate lowers materially.

Your next question is from Kashy Harrison.

Apologies if this was covered in the prepared remarks. I have a quick question about the balance sheet. If, theoretically, the WaterBridge transaction doesn’t go through and you can’t reduce what's drawn on the revolver, are there any alternative methods to decrease the balance on the revolver? Specifically, could asset sales or other transactions be pursued to reduce that balance? Additionally, if you happen to exceed the new leverage covenant at any point in 2021 or 2022, are there opportunities for obtaining waivers? I'm trying to understand the potential risks if you exceed that leverage covenant at any time.

Kashy, it's George. Thanks for the questions. On the first one, in terms of reducing the credit facility balance, the first order of business, obviously, in addressing this situation is getting the borrowing base reaffirmed, which we did, or getting a new borrowing base set, which we did at $700 million. We believe at this time that provides us with ample liquidity and a decent runway from a liquidity standpoint. In terms of lowering those balances, obviously, the original intent of the SWD transaction was to raise proceeds to do that. If that transaction doesn't close, I think the focus is more on what we're doing on the capital side and what we might be doing from a hedging standpoint to protect our cash flow and liquidity going forward. It’s difficult to point to any one thing that suggests you'll take the outstandings down, any kind of catalyst to do that. So it's really more about maintaining liquidity, obviously looking at hedges to preserve the borrowing base moving forward. With respect to the second part of your question on exceeding leverage covenants, the near-term focus was obviously evaluating how we can address the current situation with the total leverage covenant, and that's why we switched to the first lien leverage covenant. We feel like we've addressed our near-term and medium-term considerations with respect to those leverage covenants. Your question really gets into forecasts around what prices are and what kind of levels of cash flow we have when we trip a covenant. The thing I would highlight is we've done this to avoid tripping a covenant in the future, and we’ll have to see how prices shake out, what our spending levels are, what cash flows look like moving forward before needing to address that situation. I would say that banks are used to dealing with waivers on certain covenants. We certainly hope that we're not faced with that in the future. The initiative we've just closed on was very much focused on that.

That's very helpful information, thank you. I have a second question that's fairly straightforward. Do you have any insights on what you're observing regarding leading-edge cost deflation? I'm curious about the type of relief you might be experiencing today compared to your initial budget.

Yes. What we saw, and talked about in our earnings presentation, was a pretty material decrease in our capital costs associated with D&C that's driven both by efficiencies within the company and service costs coming down. I think there will continue to be some downward pressure on some service costs. Obviously, the fact that we've got no drilling rigs or completion crews running, we don't have much baked into those through the remainder of the year. But I do think there will be some continued downward pressure on service costs.

Your next response is from Matt Portillo.

Just a quick follow-up question on the commentary around May. You mentioned up to 40% of your production curtailed. Any color on where that might be at spot? And then the follow-up question would just be around June. We've seen the forward curve improve to about $24, $25 a barrel over the next couple of months. Should we expect generally the vast majority of your shut-in volumes to come back on stream to maximize cash flow given the improvement in the forward curve, obviously, volatility aside?

Yes. I think that it's a good question, Matt. And we, again, selected that terminology specifically, up to 40% because it's a very dynamic market. Crude prices fluctuate materially on a day-to-day basis now. Your realized price for both May, June, and July are very much in flux. Depending on how those shake out, we have the ability to adjust up or down based on what our netbacks are at the wellhead. So I'd love to say that it's going to be this specific amount for May and then this specific amount for June. That's just not the world we live in when crude fluctuates 10% to 15% on any given day. So that's how we're managing it. As Matt outlined, we've got a very specific tool that we use internally to manage a well-by-well look back on what our costs are. Until those wells are positively cash flowing, we're going to consider them as potential curtailment wells. That being said, as you mentioned, June prices look a lot better than May prices, which look better than April prices. Everything is going in the right direction. I would expect, if that continues, you'll have less production shut-in in June than you did in May.

Okay. Maybe just to clarify there. So if we look at kind of a $24, $25 crude price, is it fair to assume the vast majority of your production is in the money in terms of cash costs, and that's a pretty healthy level if it were to hold for you guys to start working back off of the curtailments?

I think that is definitely going in the right direction. And without being specific about what the costs are, because it's a well-by-well decision, yes, the vast majority of them look a lot more profitable at $24, $25 than they do today.

You have a question from the line of Jeffrey Campbell.

My first question was just to ask, what is your current DUC inventory and assuming there is some resumption of activity in the second half of '20, are the DUCs the most likely first target for spending?

Yes. Thanks, Jeff. Appreciate the question. We do have some DUCs built up because, obviously, as we shut down our completion crews, we still had rigs running, and so we've got a few DUCs built up, which is not our traditional MO, as we like to build as few DUCs as possible. Currently, we have 5 uncompleted wells that are ready to be fracked. Those, as you pointed out, will be the first level of activity that we would spend capital dollars on as we get towards later in the year. Obviously, your costs associated with that are just the C side of the D&C cost. It’s much more minimal than both the drilling and completion costs.

Right. And I was wondering what your current nat gas flaring looks like? And what do you anticipate for that in the future?

I don't think we've disclosed a percent flaring number. But I think we do a good job of managing that. Any Mcf flared is a wasted molecule in my book. So we do our best to not have any. That being said, there are areas where they're more isolated. Sometimes, it's harder to get midstream pipelines to those locations in a timely manner. That said, it's continued to come down over time and is a process that we manage very carefully.

And if I ask one last quick one. Going back to services, just wondering, is there any concern about obtaining the necessary services when you're ready to get going again, bearing in mind the drastic shutdown of E&P activity currently?

Yes, I'll pass it over to our COO, who's a little closer to services. But I don't think we're going to see an issue coming out of this. But Matt, do you have any commentary on that?

The conversations I've had with folks suggest that somewhere in the approximately 1 month of lead time is kind of a good rule of thumb for coming back out and picking up rigs or picking up frac spreads, so we're trying to, to the best of our ability, lead that appropriately.

Thank you. There are no further questions in the queue at this time. And I'd like to turn the call back over to Sean Smith.

Great. Thank you. These are certainly challenging times for the industry and Centennial as well. Hopefully, what you saw from our release is that we are clearly prioritizing the balance sheet, and it's a bit of a shift away from the growth company that we had originally positioned this to be. So focusing on balance sheet and liquidity is what we're going to be doing going forward. Hopefully, that's what you'll see coming in the next earnings call and beyond. So appreciate everybody's participation on the call and look forward to future conversations. Thank you.

Thank you. This concludes today's conference call. You may now disconnect and have a good day.