Good morning, and welcome to Centennial Resource Development's Conference Call to discuss its Fourth Quarter and Full Year 2018 Earnings. Today’s call is being recorded. A replay of the call will be accessible until March 5, 2019, by dialing 855-859-2056 and entering the conference ID number, 6886106, 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.

Thanks, Josh. And thank you all for joining us on the Company's fourth quarter and full year 2018 earnings call. Presenting on the call today are Mark Papa, our Chairman and Chief Executive Officer; George Glyphis, our Chief Financial Officer; and Sean Smith, our Chief Operating Officer. Yesterday, February 25, we filed a Form 8-K with an earnings release reporting full year 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 statement section of our filings with the Securities and Exchange Commission, including our annual report on Form 10-K for the year-ended December 2018, 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 measures we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release available on our website. And with that, I'd like to turn the call over to Mark Papa, Chairman and CEO.

Thanks, Hays. Good morning and welcome to Centennial's fourth quarter 2018 earnings call. Our presentation sequence on this call will be as follows: George will first discuss our quarterly and full year financial results and 2019 guidance. Sean will then provide an operational update, including recent inventory additions and well results and then I'll follow with a review of our 2018 performance, macro view, our current strategy emanating from the macro and closing items. Now I'll ask George to review our financial results.

Thank you, Mark. As you can reference on Slide 15 of the earnings presentation, Centennial's daily oil production for Q4 averaged approximately 40,000 barrels per day, which was up 11% from Q3 and 46% over the prior year period. Oil as a percentage of total production was 57%, which was consistent with Q3. Average oil equivalent production totaled approximately 69,600 barrels per day, also up 11% for the quarter over the prior quarter. Revenues for the fourth quarter totaled approximately $223 million, which was 5% lower than Q3, despite higher production volumes. This was attributable to a lower WTI NYMEX oil price of $58.80, which suffered a 15% decline compared to Q3 inclusive of the impact of our basis hedges. Centennial's realized oil price for the quarter was $49.36 per barrel, or approximately 84% of NYMEX. Turning to costs. LOE per barrel declined 8% quarter-to-quarter, as higher production volumes more than offset an increase in workover expense. Cash G&A per barrel was essentially flat quarter-to-quarter at $2. GP&T expense declined significantly to $1.94 from $2.78 in Q3. This resulted from a short-term monetization of a portion of our natural gas firm transportation agreements, which had the effect of lowering our expense. DD&A costs increased 10.6% from Q3 to $15.94 per BOE in part because of the higher capital spending on important facilities and infrastructure expenditures and increased capital that don't contribute to additional reserves. Adjusted EBITDAX totaled approximately $166 million for Q4. This was 7% lower than the prior quarter as our production volume growth was more than offset by the decline in the realized oil price. GAAP net income attributable to our Class A common stock totaled approximately $31 million, or $0.12 per diluted share, compared to $0.15 and $0.12 per share in Q3 2018 and Q4 2017 respectively.…

Thank you, George. Before I go into this quarter's operational update, I'd like to provide a review of our inventory replacement efforts from last year. 2018 was very successful in terms of inventory additions and this will continue to be key for Centennial going forward. In Reeves County, we delivered five successful tests from the Third Bone Spring Sand interval, which we believe spans across the majority of our acreage. This resulted in the addition of over 200 gross locations. In 2019, we will continue to explore the uphold section on our existing acreage in Reeves County. Additionally, we continue to post successful delineation results in Lea County, New Mexico. Our recent confirmation tests in the Avalon and First Bone Spring intervals represent upside to our current inventory count. In just 18 months, we've reported robust results from the Avalon First Bone Spring, Second Bone Spring, Third Bone Spring and Wolfcamp A reservoirs in Lea County, and we expect additional zones later this year. During 2018, we also closed on four strategic bolt-on acquisitions in and around our positions in Reeves and Lea counties. Combined with our ongoing leasing program, these efforts resulted in the addition of over 9,000 high-quality net acres for a purchase price of under $23,000 per acre adjusted for current production. Importantly, these transactions added approximately 100 gross operated locations and we're predominantly funded with the $141 million of proceeds from our largely non-operated divestiture early last year. To put all this into perspective, in 2018, we added over 300 gross operated locations through organic inventory additions, small bolt-ons and organic leasing. These new inventory locations replace the 82 wells drilled in 2018 four times over. Notably, we were able to accomplish this without raising equity or issuing additional shares in a large-scale transaction. This accomplishment…

Thanks Sean. I'll now provide some thoughts regarding the oil macro and relate them to Centennial strategy. However, first let me say a few words regarding CDEV's 2018 performance. In my opinion, I think the Company executed very well throughout 2018, which sets us on a firm footing for 2019. We're one of the few Permian peers who stayed within our original CapEx budget, while essentially hitting our original volume targets, and we substantially beat all unit cost targets. Equally important, we increased our location inventory by four x, staying within our capital budget and not expanding our share count. This is something that no one else in the Permian peer group accomplished. We're also one of the few Permian midcaps protected from forced gas and NGL flaring issues. Additionally, I believe our well quality was some of the best in both Reeves and Lea counties proving CDEV to be an efficient competent Permian mid-cap company. I'll also note that the majority of our Reeves County locations are based on 880 foot spacing, which is quite conservative. Now I'll turn my focus to 2019 and start with the oil macro. The October 2018 on/off signal regarding our Iranian sanctions has clearly upended the oil market. We think the January 1 Saudi production cuts will take nine months to bring global inventories back into balance and we expect stronger oil prices by Iran. Because of the fourth quarter rapid oil price drop, we've drastically changed our 2019 CapEx and production growth plan. Our original plan was to grow from seven rigs at year end 2018 to nine rigs in January 2019, and then possibly jump to 10 rigs in July and grow oil production from 34,700 barrels a day to roughly 50,000 barrels a day in 2019. Our new plan is to drop one rig, which we did in January, run six rigs flat and monitor the oil macro during the course of the year, which should generate 12% year-over-year oil volume growth per share. Note that I am quoting volume growth per share metrics, which is a rare statistic among the Permian peers. Depending on our macro view, we might adjust our rig count either up or down this year. For modeling purposes, our numbers assume a six-rig program throughout the year. Our logic is simple. We don't intend to pursue significant production growth in a $55 oil world. Volume growth is secondary to balance sheet protection. We're fortunate to have a 17% debt-to-cap and don't intend to become a high debt company in this price environment. Thanks for listening and now we'll go to Q&A.

[Operator Instructions] Your first question comes from the line of Scott Hanold from RBC Capital Markets. Your line is open.

Scott? This is Hays. Give your mute button on.

Yeah. Can you hear me now?

Yes, sir.

Sorry about that. Mark, if we can kind of dive in a little bit to your last comment on oil production growth, you're not really looking to do it into $55 oil environment. So the question with that is, is that sort of the trigger point where if you see a sustainability above $55 or you would look to potentially add rigs, and also as you think about your 2020, prior 2020 expectations more focused on free cash flow neutrality by the end of the year. Is that going to be a challenge with this relative reduction that we've seen this year?

Yeah. First and let me just make it clear that, the original plan was to grow to 65,000 barrels of oil a day in 2020 and to have free cash flow neutrality by year end 2020. That was assuming a $70 WTI world. And clearly that plan is out the window. So that plan is just gone. So, what we're looking at now is that my macro view is that I think there's a reasonable chance that we may reach $70 WTI by year-end and then hopefully we see a stable $70 dollar WTI price for next year, which would be 2020. Under that scenario, we can approach 65,000 barrels of oil a day by 2022. So, a two year delay in the game plan, and the cash flow neutrality would slide by a couple of years. So, there is a path to reach the cash flow neutrality and to reach 65,000 barrels of oil a day, but it would be delayed by 24 months assuming that we get to a $70 WTI world. Now again in September we had $70 WTI. So, that's not a crazy scenario. So that's the path that I'm hoping would happen. But it's entirely a function of oil price. But in the current world where we're sit today, $55, simply put we're just not going to bang our heads against the wall and attempt to grow production in that kind of world. And so that's our logic. We would probably just continue to have a scenario, where we would just attempt to maintain flat production, which is really pretty much what we're doing. We've got momentum coming into the year, that's going to carry us and show us with 12% production growth. But that's not that much production growth and simply put, to be honest with you, I don't care about production growth in $55 oil world. I care about balance sheet protection. So that's my priority. So, hopefully that gives you a bit of an answer into kind of what my thinking is, Scott.

Yeah. I know that that's actually extremely helpful. I appreciate that. It's my follow-up question and maybe this is for Sean. When I step back and look at where kind of consensus expectations were for 2019 on obviously a little bit of a reduced outlook from when you guys obviously put out the 8-K, I think it was late last year. It seemed like there's still a bit of a delta, where production expectations were for 2019 versus where they came in, but CapEx was very similar. And Sean, could you give some color on the productivity of the wells that are expected to come on 2019, and just help us kind of reset the bar on our production modeling?

Yes. Let me fill that question Scott. I'm aware just looking at some of the first call notes that there's some consternation out there relating to the expectations for production growth even at this six-rig program apparently were higher. Let me just make a simple statement here. All those expectations for production growth emanated from Wall Street expectations. None of those expectations came from Centennial guidance. If you analyze Centennial guidance for the calendar year 2017 and the calendar year 2018, you'll find that the guidance we gave on both production guidance and cost guidance was remarkably accurate. And so the guidance we've provided, I would suggest was very accurate and we're just simply not responsible for guidance that's created by Wall Street. So if the production input that we're giving you now is not what the Wall Street expectations were that's simply not anything we can control. We'll provide the guidance as we just did of the 12% production growth and if that doesn't comport with Wall Street's calculation of what they thought production might be, that's just not our problem, frankly. So that's it. If there's an issue there, I'll relate you back to the comment I made on last quarter's earnings call in November. The issue for the entire Permian Basin relates to parent-child wells. Every year, every company is drilling a higher percentage of child wells and those wells are simply not as powerful as the parent wells. And the reason that you analysts may not have picked that up from the people who have reported earnings so far from the pure Permian companies is that most of the pure Permian companies have engaged in M&A activity, and so the results that come out are really difficult to analyze, because you've got M&As mixed up in all those companies. And you really don't have an apples-and-apples comparison. But I – we have some of the best acreage in the Delaware Basin and what we are seeing is the increasing impact of the child wells. And we are typical of what every single Permian company is seeing and that impact is clouded by M&As that most companies have engaged in, but that is just what I have been talking about really for a couple of years is that although the whole shale revolution appears to be quite powerful. If you look just under the hood, you see that every company has to run faster and faster to achieve growth because you're seeing the effect of geology and well interference that is taking a toll.

So based on your – the data that you all see, which we can appreciate conservatively better than obviously, what we have available. What would you suggest that when we model kind of child wells, how much – what is sort of that productivity delta between sort of a parent and a child well that kind of help us with this modeling?

Yes. I think last quarter, I gave a number just on reserves of about 80% – reserves are about 80% child well versus a parent well. I mean, 80% to 85% is approximate ratio there, so that's just a rule of thumb number that we've seen. And again, we're in the heart of the Southern Delaware Basin. So I think, we are typical, I believe we've got some of the better acreage, so that would be a good ratio to use.

Thank you, Scott.

Your next question comes from the line of Neal Dingmann from SunTrust. Your line is open.

Good morning, guys. So maybe a question for George, or maybe, even Sean. Given the demand that you all talked about by keeping that net debt around 20% or better, you mentioned pretty in detail how this might impact the rig count up or down depending on what prices do. Could you talk about the impact potentially on the infrastructure spend? Will that continue sort of on the current pace? Or will that too have some variance to it?

Hi, Neal, it's George. I think, what we've forecasted for this coming year at the midpoint is a $140 million spend, which is about 30% less on facilities and infrastructure relative to what we spent last year. So you're seeing some slowdown relative to just activity levels. I think Q4 was little heavy because of some timing considerations versus wells that were coming on in 2019, and we spent on facilities at the back half of last year so you will see that moderate a little bit.

Okay. And then just one follow-up, just a bit on cadence. You talked about sort of the rig count that you have – potentially have and again, obviously – understanding that's sort of price dependent. Can you talk about specifically, I guess, looking at Slide 6 and around the success you've had in New Mexico, is there a thought to test a little bit north of that Airstream state? Or will you try to stay in that same block for the remainder of the year? I'm just trying to get a sense of that.

No, from a cadence point of view – this is Sean speaking. I think you can expect some kind of even completion cadence essentially quarter-to-quarter for the year assuming six rigs flat for the year. So that is the cadence part of that. Second part of that is distribution what we mentioned in the earlier comments was that it's four to five wells in Texas. And if we have six rigs running that means so one to two wells in New Mexico. Currently, we have one rig running in New Mexico. I think, there will be a point in the year that we'll likely move one of those rigs from Texas to New Mexico. Timing will be dependent on various things. But so that's likely to happen sometime during the year. Going north of the Airstream, we've already drilled wells north of the Airstream successfully. So that's certainly not our northernmost well and we do expand to develop that acreage to the north as well.

Very good, thanks Sean. George, appreciate the details.

Thanks Neal.

Your next question comes from the line of Subhasish Chandra from Guggenheim. Your line is open.

Hi, good morning everybody. Just wanted to clarify something, I think in the prepared remarks, you talked about what would have been in 2019, 50,000 barrels of oil. And would that have equated to a capital budget of around $1.3 billion, because I think you talked about it being down $400 million versus prior expectations?

Yes, the derivation of the $385 million is really simplistic in the sense that we used our D&C cost for 2018 and extrapolated that against the seven rig program and then took the 3.5 rigs that are implied by the drop-in capital to come up with that $385 million, so it's really that simple, Subash.

Got it. Okay. So that's the math of what would have been. Could you hazard a guess on what your base decline rates are?

Subash, we don't disclose decline rates. That's kind of one of those things, a kind of an entrapment question. So that's just, obviously, really don't want to talk about.

Yes, Mark, I mean, that wasn't the intent. It's – I guess, among your peers, it's a broadly disclosed number, probably more than it ever has been. So that wasn't the intent. And I guess, your views on hedging are the same?

Yes, for better or worse. Right now, like I said – the macro view is and again, maybe right, maybe wrong is that we're kind of hoping these Saudi oil cuts will bite. And so we're likely to stay unhedged at least for the next six months or so regarding oil.

Okay, thank you.

Your next question comes from the line of Asit Sen from Bank of America. Your line is open.

Thanks. Good morning all. Mark, two quick ones for you. You've alluded to capital program being flexible. And can you talk a little bit about your – some thought process of price points, where you might choose to change activity. You kind of emphasize $70 view, but is that the price point that you're thinking about?

Asit, to give you the little bit of directional thought on there. Around mid-year this year, we're going to kind of assess our view of the oil market. Specifically, what the situation is vis-à-vis global inventories. In other words, our global inventories drawing down as we would hope they would and then also what's the position of OPEC specifically Saudi's. Are they showing an intent to continue to kind of hold the one million barrels of oil a day off the market or they showing an intent to put more oil on the market in the second half of the year. And if both of those things appear to be trending in the bullish direction, we'll at least – and if we're seeing some signs of oil prices firming from the current $55 level by midyear, then we will consider adding one or two rigs.

Got it.

Conversely, if for some reason, we see barrier signs or if prices have softened from $55 by midyear, we may consider dropping one rig and going from six to five. So that's – those are the signals that we're looking for around mid-year either pro or con.

Okay. Thanks Mark. And then just a big picture question, Mark, given your unique perspective having running a large company successfully as well as now a smaller company, as you listen to emerging investor debate on the right balance between growth rate and the need to return cash to shareholders. Just wanted to see what your thoughts are and any updated views on consolidation in this environment?

Yes. And that's a good question, Asit. I think that the mid-cap space is, particularly in this price environment is particularly challenged. The large caps have a bit of an advantage, I think and that they may have a bit of a more mature production profile. But I think if we stay in a $55 oil environment for an additional six to 12 months, I think it's going to be a very stressful time for the entire mid-cap space. And I think that you would likely see an increased level of consolidation or some sort of corporate activity in the mid-cap space.

Okay. Thanks Mark.

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

Hi, guys. Wanted to follow up a little bit on kind of some of the M&A thought there, obviously you guys did some bolt-ons in the fourth quarter here of 2018, which you all talked about. With the appetite for CDEV to do incremental bolt-ons in 2019 and you see available deals out there in the market kind of like what you saw in 2018?

Yes. Our goal again is not necessarily to do big M&As, Leo. As you know, that's really not my style, but our goal is to replace our drilling inventory, at least, by one – between 1x and 3x again this year, I mean, last year we did 4x, I think that was an exceptional year either by organic leasing or by doing bolt-on acquisitions and – or farm ends. And so I expect by the end of the year, if we fast forward it to our earnings call next year at this time that we'll be able to report that we've done somewhere between a 1x and a 3x in terms of our inventory replacement by a combination of organic leasing bolt-ons or farm-ins. So we've got good progress so far, two months into the year in accomplishing that goal.

Okay. That's helpful. And I guess just with respect to kind of developing the different zones in the Permian, if I look at, I guess 2018, obviously you guys had some success with incremental zones, a little bit more back half weighted in the year. Just trying to get a sense and in 2019, is the plan to kind of move more toward cube development and attack a lot of these different zones simultaneously as you develop or will it be more of a focus on the Upper Wolfcamp where there are little bit more established economics?

Sean, you want to fill that question?

Sure. I think it's a little bit of both. I think we've done a good job of delineating a lot of different zones both from a spacing perspective as well as from a productivity perspective. And I think you'll still see some of that in 2019 particularly in the fact that we don't – we have less rigs running this year than we did last year and certainly are ramping up to what we had planned on doing. So we'll still see a little bit of that, but the focus will be more so on the Wolfcamp A zones that being commingled with either the zone above or below, I think as what you'll see a fair amount of this year.

Thank you.

You are clear.

Your next question comes from the line of Irene Haas from Imperial Capital. Your line is open.

Yes, hi. I have two questions for Mark, sort of big picture stuff. At current crude price environment, when do you think Delaware production would peak? That's question number one. Number two, you mentioned earlier that around mid-year you're going to take a look at the world market and see if the Saudi’s choose to keep production off the market on. And Mark your thoughts as to what would be the drivers and considerations for the Saudi to either continue to hold production tight or increase production?

Well, I mean, on your second question, Irene. I can just go on kind of published data where for their annual budget from what I've read, the Saudi’s need equivalent of a WTI oil price of between $70 and $80 a barrel for their annual budget to be a break-even situation. So one would think that would be a desirable price for them just for break-even point on their annual budget that they would like to see. So that might be a point where they would like to guide the market toward. On the Delaware Basin is to what point it will peak, I think you'll see Delaware Basin continue to grow well past 2025, it will be one of the last areas to peak among the shale plays. I think my overall logic is that we will continue to see year-over-year growth, but what will happen is that the companies are going to have to pedal harder every year to get the kind of growth that perhaps they've been promising as you just have a higher percentage every year of child wells versus parent wells. And then you kind of go to child of child wells as you go to even denser spacing in the future. And you've seen this every earnings, every quarterly earnings you see, at least, one or two additional companies report that the spacing that they had previously articulated was too dense. And now they have to go to a wider spacing than they previously talked about. So you're getting data points every quarter from companies where they talk about the wells. I thought I could drill 1,000 wells on my acreage, and it turns out I can only drill 600 wells on my acreage because of essentially parent/child issues. So the data is coming out, it's just coming out, kind of dribbling out quarter-by-quarter.

Great. Thank you very much.

Thanks.

Your next question comes from the line of Derrick Whitfield from Stifel. Your line is open.

Thanks and good morning all.

Hi, Derrick.

Hey, Mark, and I agree with your parent/child industry comments as we certainly see the data as well. Perhaps for yourself or Sean regarding your 2019 guidance, did your percentage of parent wells in 2019 materially decrease relative to 2018?

Well, I wouldn't say materially, but – yes, the percentage of – yes, either way you look at the percentage of child wells every year goes up. So the percentage of parent wells every year goes down, it's not a material change, but it's kind of a – erosional change, if you want to think of it that way. So it's not a dramatic change, but every year it just the percentage does go up of child wells.

Understood.

Yes. What you would expect really. Yes.

Makes complete sense. And then as my follow up perhaps for Sean. Would it be fair to say that your drill-bit F&D cost should remain relatively flat from here given the depth of inventory maturity of ops and the current cost environment?

Yes. I would think so, ish. Obviously, if we are drilling more child wells, you have a little bit less efficient use of capital there. But as Mark just said, it's not meaningful the percentage that goes up on an annual basis. So I think if you're using that ish number going forward, you're probably in the right ballpark.

Great. Thanks guys, very helpful.

Yes. Derrick, I'd just add one other point. If we don't – again we don't like to talk about inventory years too much because that's kind of get valued at too much, but if we stayed at six rigs our inventories is in a range of about 20 years in terms of location inventory. So it's a pretty robust inventory.

Your next question comes from the line of Paul Grigel from Macquarie. Your line is open.

Hi. Good morning. It was a bit of a point in the release as well as the presentation about 2018 making sure the numbers were hit from a CapEx perspective, without a raise, how should we think about 2019? Is there some conservatism built in there? There are details on potential service cost either inflation or deflation just within the confidence of the budget that's been laid out this morning?

Yes. I'll answer that. Paul, I would say if we elect to stay at six rigs for the full year, I would say that at this juncture I've got a reasonably high degree of confidence that we won't be coming back at any point during the year and saying, oh my gosh, we've got to raise the capital budget even though we're only running six rigs. We misestimated back in February. I'd say, there's a pretty good chance that it'll be kind of like last year that we'll be able to say, we're able to make it through the whole year and not have to adjust the capital budget. As we see it today, particularly if we – if you stay in a $55 oil environment, there is probably not a lot of inflationary pressure that's going to be coming throughout the year in the cost side, but I will say that we are going to reassess at midyear the number of rigs we're going to run. So and if we decide to run a different number of rigs, whether we go up or go down on the rigs, there would be a change in the CapEx budget for the second half of the year. But assuming six rigs, I would say it maybe a higher than usual confidence factor that we won't have – we wouldn't come back and change the CapEx budget.

Okay. That makes sense. Yes. And then, I guess, turning to flaring, you guys are somewhat uniquely positioned. Is there any discussion or talk with any other either the, call the government agency or out in the field just on any sort of concerns that may come up from regulatory scrutiny or anything along those lines from increased flaring that we're seeing in the basin?

Sean, George, you want to fill that one?

Well, as I said in the earlier comments, I think we've done a fantastic job of getting in front of that. We have not come across any regulatory agencies wanting to discuss with us the amount that we flare. What we are trying to do is make sure that we don't have those conversations. And I think that securing our FT for all of our volumes and as we showed on the slide deck, we're one of the lowest flaring companies out there, certainly among our peers but maybe even among the E&Ps in the basin. So I think we just want to stay in front of that to make sure that that we don't ever receive that call from any of the regulatory agencies.

Thank you very much.

Your next question comes from the line of Josh Silverstein from Wolfe Research. Your line is open.

Thanks, good morning guys. Just going back to some of the comments on the longer term outlook for 2020 previously, I appreciate that the 65,000 barrel a day number was made for a $70 world, but it was still made 2017, where you guys had bumped the 50,000 barrel a day target for 2020 to 60,000. And oil was at $50 then, so I appreciate that wanting to preserve some of the inventory but what's changed over the course of the last kind of 18 months to 24 months that is really starting to bring this down?

Yes, back in 2017 my view of the macro was that we had a quite a high likelihood that we were going towards $70 oil. Everything from my view look pretty constructive and indeed that's where we were just back in September. So we were pretty bullish as to where we were heading on the oil price, but and again I think what happened was the on/off on the Iranian sanctions and the fact that the Saudi’s were asked to, if you will, overproduce early in 2018 to kind of make up for the assumed loss of Iranian oil that's what has kind of messed up the oil market, now we're trying to get it cleaned up again. But once we got off that growth trend and lost the momentum, it's really – it will now take us two years to regain that momentum even if we decided in some time late this year, oh my gosh, we want to get back on that production growth trend. The fact that we've gotten off that growth trend and you lose that growth momentum, it's not like it only takes you six months to regain that momentum. So our issue really is, is that it would probably take us two years to regain that momentum. And frankly, we've got to regain the confidence in the oil market again before we'd ever turn our on switch on a growth momentum again. And right now, our confidence in oil market like I think everybody is shaken. So we had a game plan, but now that game plan has changed considerably and I've just got to be honest and say the original game plan is just flat out the window. And we're in a process of a much more conservative game plan until we get a clearer picture of what is going to happen with oil prices not so much for the first half of this year. I expect they're going to be pretty bad for the first half of this year, but really what are they going to look like in 2020 and 2021. And that's what we're hoping to figure out by sometime late this year.

Got you.

Josh, that's the most honest answer I can give you.

Got you. Okay. And I do appreciate that given some of the comments that were made before. The other question I had was – let's just say, you're right in thinking that potentially maybe at the midpoint of this year we do see a – or by year-end, we do see a spike toward that $65, $70 level. The previous plan was to add two or three rigs at that price point. Any reason why you wouldn't just add one rig and then start to generate a lot more free cash flow and get there a lot sooner? Could that be in the works as well?

You mean get to free cash flow a lot sooner, is that what you're saying?

Right. Like why not just add one rig or why add a rig at all instead of the original game plan was maybe adding two or three rigs at $70? I'm trying to work through some of the scenarios that you guys may want to outline.

Yes. I mean that – you're right, I mean, that possibility is on the table. The 65,000 barrels a day is not – that's not a number that's casting concrete anymore. So frankly, that number is pretty much out the window too, to be honest with you. So yes, it could easily be a plan where we would just say, we'd add one rig and just to – just slowly grow in the new target is some number less than 65,000 barrels a day. And we're targeting a company that's a bit smaller than previously, but we're going to reach free cash flow – maybe in 2021 or 2022 at just a lower level. So that the ultimate goal is to get to free cash flow. But I got to be honest with you, its $55 oil. That's a real stretch for any midcap to get to free cash flow, who's a pure shale producer and to have any kind of production growth concomitant with that. So that's the real trick.

Right. Got it. Thanks. I appreciate that Mark.

Yes.

All right. Thank you for all your questions. I'd now like to turn the call back over to Mark Papa.

Okay. Thank you very much. Obviously this has been a trying time, these last three months. And the point I would just like to leave everyone with is that trying to balance production growth and capital constraint and balance sheet protection for a mid-cap entity even one that is well positioned is Centennial is a very tenuous balancing situation. And in the conclusion that we've come to at Centennial is, is that when you try and balance those two things, the one where we are going to put the most weight on is balance sheet protection and not production growth. And so that's the conclusion that we have reached and so that's the way we think we're best protecting shareholder interests. So thank you very much.

Thanks to all our participants for joining us today. We hope you found this presentation informative. This concludes our presentation. You may now disconnect and have a great day.