Permian Resources Corp

NYSE:PR

Earnings Call Transcript 2018-Q4

[Operator]

Good morning, and welcome to Centennial Resource Development 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 [phone] 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.

[Hays Mabry, executive]

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 Forward-Looking Statements section of our filings with the Securities and Exchange Commission, including our annual report on Form 10-K for the year ended 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 measure 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.

[Mark Papa, executive]

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.

[George Glyphis, executive]

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 '18 and Q4 '17, respectively.

Net income for the quarter was impacted by lower revenue, higher DD&A costs and higher interest costs.

Turning to CapEx. D&C CapEx was approximately $199 million in Q4, a 10% decrease in Q3, while still completing the same amount of wells. Facilities, infrastructure and other capital totaled approximately $73 million. This was higher than anticipated as we spent more on D&C facilities to add vapor recovery units on a number of our historical tank batteries and increased our spending on incremental saltwater disposal facilities, such as water pipelines to enhance our company-owned SWD system.

Lastly, Centennial incurred roughly $10 million in land acquisitions during the quarter. Overall, Centennial incurred approximately $282 million of total capital expenditures during the quarter compared to $274 million in Q3. As previously announced in November, during the fourth quarter, Centennial spent approximately $88 million for 3 bolt-on acquisitions, which added approximately 2,900 high-quality net acres plus associated production. These properties are located in and around our existing position in Reeves and Lea counties, and will enhance both inventory and future development plans. Those activities are highlighted on Slide 9 of the presentation.

On Slide 11, we summarized our capital structure and liquidity position. At December 31, we had approximately $18 million of cash, $300 million of borrowings under the revolving credit facility and $400 million of senior unsecured notes. At year-end, based upon $800 million of elected commitments on our $1 billion borrowing base credit facility, the company had approximately $515 million (sic) [ $517 million ] of liquidity.

Centennial's net debt to book capitalization was 17%, and net debt was 1x 2018 EBITDAX. These credit metrics continue to represent one of the lowest leverage profiles of the Permian peers or indeed any E&P company.

On Slides 4 and 5 of the presentation, you can see for full year 2018, oil production was 34,737 barrels per day, which was up 81% compared to fiscal year 2017. Oil equivalent volumes were 61,082 barrels per day.

EBITDAX totaled approximately $670 million in a year that was significantly impacted by both the blowout in the Mid/Cush differential starting in April of last year and the oil price sell-off of Q4. Unit cost all came in below the midpoint of our guidance ranges. D&C capital spending of $766 million was right at the midpoint of the guidance we provided a year ago.

Total capital expenditures of $997 million was also within our original guidance range. Notably, we were one of only of a handful of companies that delivered on guided production volumes without having to increase our original CapEx budget.

In summary, we did an excellent job of executing on our business plan in 2018. We posted solid drilling results, improved our acreage position, created significantly more scale in production revenue and cash flow, and maintained a very solid balance sheet. We believe we're well positioned for 2019 and beyond.

Turning to 2019 guidance. In late September, as a result of the sudden decline in oil prices, we filed an 8-K announcing that we were forgoing our previous high-growth game plan, which targeted 65,000 barrels per day of oil production in 2020. In early January, we released one of our 7 operated rigs in order to reduce our deficit spend, protect our strong balance sheet and maintain a solid liquidity position.

Our 2019 operational guidance, which you can reference on Slide 13, assumes running 6 rigs flat, which will provide 12% year-over-year oil production growth at the midpoint and will keep our oil production levels relatively flat to Q4. In essence, we are prioritizing balance sheet strength and flexibility over production growth, while maintaining optionality to react as the oil price environment plays out. This flexibility could entail a further reduction in rig activity or an increase as oil prices dictate. It is important to note that compared to Centennial's previous high growth game plan, our current plan reflects a reduction of 3.5 rigs for 2019, which preserves approximately $385 million of D&C capital and defers the development of many locations that we plan to drill in a more attractive, future oil price environment.

As a result, D&C CapEx for 2019 is estimated at $675 million at the midpoint, which represents a 12% reduction from 2018 levels and is expected to generate midpoint oil production of 39,000 barrels per day. Facilities and infrastructure CapEx is estimated at $140 million at the midpoint, which is down 30% from 2018 levels.

Turning to unit cost. In 2018, we delivered full year unit cost at the low end of our previously lowered guidance ranges through field efficiences and a robust production profile compared to 2017. Because our 2019 growth profile has slowed considerably, we will experience an increase in unit cost, which is reflected in our forward guidance.

With that, I will turn the call over to Sean Smith to review operations.

[Sean Smith, executive]

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 5 successful tests from the 3rd 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 1st Bone Spring intervals represents upside to our current inventory count. In just 18 months, we reported robust results from the Avalon, 1st Bone Spring, 2nd Bone Spring, 3rd Bone Spring and Wolfcamp A reservoirs in Lea County, and we expect to test additional zones later this year.

During 2018, we also closed on 4 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 were predominately funded with the $141 million of proceeds from our largely nonoperated 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 replaced the 82 wells drilled in 2018 4x over. Notably, we were able to accomplish this without raising equity or issuing additional shares in a large scale transaction.

This accomplishment is a credit to our land, geo and reservoir teams for identifying and capturing opportunities to add core operated inventory.

Turning to operations. Centennial continued to bring on solid well results during the fourth quarter from 8 different intervals across our acreage position. During the quarter, Centennial operated 7 rigs, which spud 23 and completed 22 wells. Beginning with our northern Delaware results on Slide 6, the Radar Federal 301H and 101H were drilled with approximately 4,250-foot laterals, targeting the 1st Bone Spring and Avalon intervals, respectively. The 301H achieved an IP30 of approximately 1,700 barrels of oil equivalent per day or over 1,400 barrels of oil per day. While the 101H reported an initial 30-day production rate of approximately 1,300 barrels of oil equivalent per day consisting of 76% oil.

On a per lateral foot basis, the Raider Federal well has delivered an impressive 337 and 228 barrels of oil per 1,000 foot lateral, respectively. Importantly, these results represent successful follow-up tests and are outperforming the previously announced Pirate State wells, which at the time included the best 1st Bone Spring well ever drilled in Lea County. The Raider Federal results not only confirm additional zones on a portion of our northern Delaware acreage, but also provide us with the covenants that these types of results are repeatable on our Lea County acreage.

In early January, Centennial completed the Airstream 24 State Com 502H in the 2nd Bone Spring. Drilled with an approximately 10,000-foot lateral, this well achieved an IP30 of 2,400 barrels of oil equivalent per day, 83% oil or 198 barrels of oil per day per 1,000 foot of lateral. During its first 30 days online, the Airstream produced over 52,000 barrels of oil and represents our best well to date in Lea County.

Shifting to the Southern Delaware on Slide 7, we completed wells in 5 separate intervals during the quarter, including the 3rd Bone Spring Sand, Wolfcamp Upper A, Lower A, B and C intervals. In addition to our ongoing Upper A program, we generated positive delineation results in our lower Wolfcamp zones. On our Miramar acreage, the Wolfman C45H targeted the Wolfcamp C zone and was drilled with an approximately 8,000-foot lateral. The well achieved an IP30 of just over 2,000 barrels of oil equivalent per day with a 46% oil cuts.

On the southern portion of our acreage in Big Chief, we brought on the Mercedes L49H in the Wolfcamp B zone, which represents our southernmost well in this zone to date. Drilled with a single mile lateral of approximately 4,800 feet, the Mercedes reported an IP30 of over 1,000 barrels of oil equivalent per day consisting of 85% oil. On a per 1,000-foot lateral basis, this equates to 188 barrels of oil per day.

Lastly, in Reeves County, we brought online the Balmorhea State LT45H targeting the 3rd Bone Spring Sand with an approximately 6,200-foot lateral. This well had an IP30 of over 1,200 barrels of oil equivalent per day or approximately 1,000 barrels of oil per day, which was in line with our expectations. The Balmorhea State has displayed a very shallowed production decline reporting an IP60 of 917 barrels of oil per day. Notably, the Balmorhea State was drilled directly above 2 producing Wolfcamp A wells. This is important, as it gives us further confidence that the 3rd Bone Spring interval can be a meaningful value creator for Centennial.

As stated in my opening remarks, these types of ongoing delineation tests will be key for Centennial going forward. As George previously mentioned, our announced guidance plan for 2019 assumes 6 operated rigs. During the year, we expect to operate between 4 to 5 rigs in Reeves County with the remaining located in Lea County. With regards to activity, we expect the majority of our 2019 activity to be focused on Centennial's lower GOR Reeves County and New Mexico acreage, which should move our oil cut slightly higher on a year-over-year basis.

Before moving on to reserves, I want to provide a quick thought regarding our Permian takeaway and Centennial's marketing efforts. For well over a year, we have been quite vocal about the potential lack of natural gas takeaway out of the Permian Basin. With natural gas prices at WAHA recently turning briefly negative, it should come as no surprise that all available pipeline capacity is essentially full. As a result, this has caused increase of natural gas flaring throughout the basin. At Centennial, we are proud to be one of the few mid-cap operators to have secured the necessary takeaway for all of our expected natural gas production. Therefore, we have experienced no material amounts of flaring to date and expect this to continue in the future.

More specifically, as you can see on Slide 10 of the presentation, Centennial is one of the top operators in the basin in terms of minimizing natural gas flaring. Not only is gas capture important from an environmental standpoint, our secured takeaway capacity also allows us to process and capture NGLs, which represent a valuable portion of the hydrocarbon stream.

Now turning to crude oil. While the Mid/Cush differential has tightened considerably since our last earnings call in November, continued production growth in the basin still represents basis and takeaway risks for the next couple of quarters until large diameter pipes are brought online during the second half of the year. Similar to our natural gas situation, Centennial has secured physical takeaway capacity for essentially all of its crude oil out of the basin primarily through 2 firm sales contracts with major integrated oil companies.

Our primary contract, which provides us exposure to MEH pricing this year represents capacity of 20,000 barrels a day gross beginning in 2019 and gradually increases over the next 4 years.

Importantly, this agreement provides flexibility with our volume commitments. For example, if Centennial were to under-deliver, the purchaser would have the option to curtail our future capacity by an equal amount of the shortfall in any given period. Ultimately, we see this as posing very low risk to our operations, as pipeline capacity out of the basin will most likely be overbuilt for some time beginning early next year.

Our remaining firm sales contract represent gross volume commitments of approximately 20,000 barrels this year, or about 1/3 of our fourth quarter gross production. Overall, we're very pleased to have signed these contracts. And given the flexibility built into our marketing portfolio as a whole, we do not expect to incur any financial penalties in the future associated with these contracts.

Shifting to Slide 8. Centennial also delivered strong reserve growth during the year. Total proved reserve increased 40% to 262 million barrels of oil equivalent at year-end 2018. We organically replaced approximately 420% of our 2018 production at a drill-bit F&D cost of just under $10 per BOE.

Year-over-year our approved reserve value on a PV-10 basis increased more than 70% to approximately $3 billion. With that, I will turn the call back over to Mark.

[Mark Papa, executive]

Thanks, John. Now I'll 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 4x, 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 mid-caps protected from force 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 Iranian sanctions has clearly upended the oil market. We think the January 1 Saudi production cuts will take 9 months to bring global inventories back into balance. And we expect stronger oil prices by year-end. 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 7 rigs at year-end '18 to 9 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 1 rig, which we did in January, run 6 rigs flat and model the oil macro during the course of the year, which should generate 12% year-over-year oil volume growth per share. Note that I'm 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 6-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]

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

[Hays Mabry, executive]

Scott, this is Hays. Do you have your mute button on?

[Scott Hanold, analyst]

Yes, can you hear me now?

[Hays Mabry, executive]

Yes, sir.

[Scott Hanold, analyst]

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 in the $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?

[Mark Papa, executive]

Yes. Yes, first, 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 -- my macro view is that I think there is a reasonable chance that we may reach $70 WTI by year-end, and hopefully, we see a stable $70 WTI price for next year, which will be 2020. Under that scenario, we can approach 65,000 barrels of oil a day by 2022, so a 2-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 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'll just attempt to maintain flat production, which is really pretty much what we're doing. We've got momentum coming into the year. It'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 a $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.

[Scott Hanold, analyst]

Yes, no, that's actually extremely helpful. I appreciate that. And 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 '19 versus where they came in, but CapEx was very similar. And Sean, could you give us some color on the productivity of the wells that are expected to come on in '19? And just help us kind of reset the bar on -- serve our production modeling.

[Mark Papa, executive]

Yes, let me field that question, Scott. I'm aware just looking at some of the first call notes that there is some consternation out there relating to the expectations for production growth, even if this 6-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 '17 and the calendar year '18, 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 day thought production might be, that's just not our problem, frankly. So that's it. If there is 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 it -- 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-to-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.

[Scott Hanold, analyst]

So based on the 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?

[Mark Papa, executive]

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.

[Operator]

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

[Neal Dingmann, analyst]

So maybe a question for George, or maybe, even Sean. Given the mandate 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?

[George Glyphis, executive]

Neil, 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 a 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.

[Neal Dingmann, analyst]

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, I -- 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.

[Sean Smith, executive]

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 6 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 4 to 5 wells in Texas. And if we have 6 rigs running that means so 1 to 2 wells in New Mexico. Currently, we have 1 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 expect to develop that acreage to the north as well.

[Operator]

Your next question comes from the line of Subash Chandra from Guggenheim.

[Subash Chandra, analyst]

Just wanted to clarify something. I think in the prepared remarks, you talked about what would have been in '19, 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?

[George Glyphis, executive]

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 7-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.

[Subash Chandra, analyst]

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?

[Mark Papa, executive]

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.

[Subash Chandra, analyst]

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?

[Mark Papa, executive]

Yes, for better or worse. Right now, like I said, my -- 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 6 months or so regarding oil.

[Operator]

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

[Asit Sen, analyst]

Mark, 2 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?

[Mark Papa, executive]

Yes, 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 1 million barrels of oil a day off the market or are 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 mid-year, then we will consider adding 1 or 2 rigs. Conversely, if for some reason, we see barrier signs or if prices have softened from $55 by mid-year, we may consider dropping 1 rig and going from 6 to 5. So that's -- those are the signals that we're looking for around mid-year either pro or con.

[Asit Sen, analyst]

Okay. And then just a big picture question, Mark. Given your unique perspective having run a large company successfully, as well as now a smaller company, have you listened 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?

[Mark Papa, executive]

Yes. It'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, in that they may have a bit of a more mature production profile. But I think, if we stay in the $55 oil environment for an additional 6 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.

[Operator]

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

[Leo Mariani, analyst]

Wanted to follow up a little bit on kind of some of the M&A thoughts there. Obviously, you guys did some bolt-ons in the fourth quarter here of 2018, which I'll talk 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?

[Mark Papa, executive]

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 1 -- 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-ins. 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, via combination of organic leasing, bolt-ons or farm-ins. So we've got good progress so far 2 months into the year in accomplishing that goal.

[Leo Mariani, analyst]

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 in 2019, is the plan to kind of move more towards skewed 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? Or to a little bit more established economics?

[Mark Papa, executive]

Sean, do you want to field that question?

[Sean Smith, executive]

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 will 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 aren't ramping up to what we had planned on doing. So you still see a little bit of that, but the focus will be more so on the Wolfcamp A zones, that being co-mingled with either the zone above or below, I think, is what you'll see a fair amount of this year.

[Operator]

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

[Irene Haas, analyst]

I have 2 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 that -- you're going to take a look at the world market and see if the Saudis choose to keep production off the market or on. And Mark, your thoughts as to what would be the drivers in consideration for the Saudi to either continue to hold production tight or increase production?

[Mark Papa, executive]

Well, I mean, on your second question, Irene, I'm just going, kind of published data for their annual budget, from what I've read, the Saudis need a equivalent of a WTI oil price of between $70 and $80 a barrel for their annual budget to be a breakeven situation. So one would think that, 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 towards. On the Delaware Basin as 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 companies are going to have to peddle 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 1 or 2 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 had talked about. So you're getting data points every quarter from companies where they talk about, gee-whiz, I thought I could drill a 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.

[Operator]

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

[Derrick Whitfield, analyst]

Mark, 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?

[Mark Papa, executive]

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 is -- it's kind of an erosional change if you want to think of it that way. So it's not a dramatic change, but every year just the percentage does go up of child wells. Yes, what you would expect really.

[Derrick Whitfield, analyst]

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 the inventory, maturity of ops in the current cost environment?

[Sean Smith, executive]

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.

[Mark Papa, executive]

Yes, Derrick, I'll just add one other point if -- I mean, we don't -- again, we don't like to talk about inventory years too much because that's kind of get validated too much, but if we stayed at 6 rigs, our inventory is in range of about 20 years in terms of location inventory. So it's a pretty robust inventory.

[Operator]

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

[Paul Grigel, analyst]

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

[Mark Papa, executive]

Yes, I'll answer that, Paul. I would say, if we elect to stay at 6 rigs for the full year, I would say 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 say, oh my gosh, we got to raise the capital budget even though we're only running 6 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 stay in a $55 oil environment, there's 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 mid-year 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 6 rigs, I would say, maybe a higher than usual confidence factor that we won't have -- that we wouldn't come back and change the CapEx budget.

[Paul Grigel, analyst]

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

[Mark Papa, executive]

Sean, George, do you want to field that one?

[Sean Smith, executive]

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 F&D for all of our volumes, and that -- as we showed on the slide deck, we're one of the lowest flaring companies out there, certainly amongst our peers, but maybe even amongst the E&Ps in the basin. So I think, we just want to stay in front of that to make sure that we don't ever receive that call from any of the regulatory agencies.

[Operator]

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

[Joshua Silverstein, analyst]

Just going back to some of the comments on the longer-term outlook for 2020 previously, I appreciate that the 65,000 barrels a day number was made for a $70 world, but still -- May 2017 where you guys had bumped the 50,000 barrels a day target for 2020 to 60,000 and oil was at $50 then. So I appreciate 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 has really started to bring this down.

[Mark Papa, executive]

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 looked 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 with the on-off on the Iranian sanctions, and the fact that the Saudis were asked, if you will, overproduce early in 2018 to kind of makeup 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 train and lost the momentum, it's really -- it will now take us 2 years to regain that momentum even if we decided in -- sometime late this year, oh my gosh, we want to get back on that production growth train. The fact that we have gotten off that growth train and you lose that growth momentum, it's not like you only -- it only takes you 6 months to regain that momentum. So our issue really is, is that it would probably take us 2 years to regain that momentum. And frankly, we've got to regain the confidence in the oil market again, before we'd ever turn that on switch on the growth momentum again. And right now, our confidence in oil market, like I think everybody's, 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 ran out the window. And we're in a process of a much more conservative game plan until we get a clear 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 '21, and that's what we're hoping to figure out by sometime late this year.

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

[Joshua Silverstein, analyst]

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 towards that $65, $70 level. The previous plan was to add 2 or 3 rigs at that price point. Any reason why you wouldn't just add 1 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?

[Mark Papa, executive]

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

[Joshua Silverstein, analyst]

Right. Like why not just add 1 rig or why add a rig at all instead of the original game plan was, maybe, adding 2 or 3 rigs at $70. I'm just trying to work through some of the scenarios that you guys may want to outline.

[Mark Papa, executive]

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 cast in concrete anymore. So frankly, that number is pretty much out the window too, to be honest with you. So it could easily be a plan where we would just say, we'd add 1 rig and just slowly grow, and 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 may be in '21 or '22 at just a lower level. So the ultimate goal is to get to free cash flow, but I got to be honest with you, at $55 oil that's a real stretch for any mid-cap 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.

[Operator]

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

[Mark Papa, executive]

Okay. Thank you very much. Obviously, this has been a trying time, these last 3 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's as well positioned as Centennial is, is a very tenuous balancing situation. And the conclusion that we've come to at Centennial is that when you try and balance those 2 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 interest. So thank you very much.

[Operator]

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.