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Centennial Resource Development, Inc. (NASDAQ:CDEV)
Q4 2019 Earnings Call
Feb 25, 2020, 10:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Good morning, and welcome to Centennial Resource Development's Conference Call to discuss its Fourth Quarter and Full Year 2019 Earnings. Today's call is being recorded. A replay of the call will be accessible until March 10th 2020 by dialing 855-859-2056 and entering the conference ID number 7679910 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 -- Director of Investor Relations

Thank you, Rebecca. And thank you all for joining us on the Company's fourth quarter and full year 2019 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 24th, 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 risk 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 in the forward-looking statement section of our filings with the SEC, including our annual report on Form 10-K for the year ended 2019, 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 the earnings release or presentation which are both available on our website.

And with that, I'll now turn the call over to Mr. Mark Papa, Chairman and CEO.

Mark G. Papa -- Chairman & Chief Executive Officer

Thanks Hays. Good morning and welcome to Centennial's fourth quarter earnings call. Our presentation sequence on this call will be as follows. George will first discuss our quarterly and full-year financial results, the monetization of our saltwater disposal assets and 2020 guidance; Sean will then provide an operational update, including recent efficiencies, well results and year-end reserves; and then I'll follow with my macro view, our current strategy emanating from the macro and management's succession plans.

Now I'll ask George to review our financial results.

George S. Glyphis -- Vice President & Chief Financial Officer

Thank you, Mark. Centennial finished 2019 with strong fourth quarter results. As you can reference on Slide 19 of the earnings presentation net oil production for the fourth quarter averaged approximately 45,000 barrels per day, which was up 13% over the prior year period and 7% over Q3. Average net oil equivalent production totaled 79,734 barrels per day, which was up approximately 15% and 4% above the prior year period and Q3 respectively.

Revenues totaled approximately $256 million, which was a 12% increase compared to Q3, primarily as a result of higher production and price realizations. Excluding the impact of basis hedges, Centennial's realized oil price was $53.25 per barrel for the quarter compared to $51.71 in Q3.

Shifting to unit costs, on the last earnings call, we identified several initiatives to mitigate the increase in lease operating expense incurred during Q3. The preliminary results of those initiatives have been positive.

LOE per barrel decreased by 12% from Q3 to $5.30 per barrel, primarily as a result of reductions in equipment rental, electricity, chemical and labor costs.

Cash G&A for Q4 was $2.12 per barrel, which was up quarter-over-quarter, primarily as a result of a non-recurring contract settlement charge. Without this one-time charge, cash G&A per barrel would have been a $1.88. DD&A increased by 4% to $16.75 per barrel. And lastly, GP&T expense decreased 5% to $2.82 per barrel.

For the quarter, we recorded GAAP net income attributable to our Class A common stock of $9.6 million. Adjusted EBITDAX totaled $160 million, up approximately 20% from Q3 due to higher revenues and lower LOE.

Shifting to capex, during Q4, we ran five rigs compared to six rigs for most of Q3. For the quarter, we spud 22 gross wells and completed 27 compared to 21 gross wells and 17 respectively during the prior quarter. Despite completing 10 more wells during Q4, D&C capex of approximately $163 million increased only 1.5% compared to Q3.

Facilities and infrastructure capital totaled approximately $31 million, which was down 23% from Q3, because of a significant decline on the infrastructure side. This trend will continue as we expect to see significantly lower facilities and infrastructure spending during 2020. In Q4, we incurred approximately $3 million in land capital, which was down from $11 million in Q3, keeping us within our original guidance range.

Overall, Centennial incurred approximately $197 million of total capital expenditures during the fourth quarter compared to $212 million in Q3, which represents a 7% reduction and marked our 4th consecutive decline in quarterly capex.

On February 24th, we signed a purchase and sale agreement with WaterBridge to divest our saltwater disposal assets in Texas for a total purchase price of $225 million. The consideration comprises $150 million in cash up front and up to $75 million of additional incentive payments that, if achieved, would primarily be paid out over a two-year period.

We believe the incentive payments are reasonable to achieve based on our current Reeves County activity levels. The divested assets, which are detailed on Slides 10 and 11 consist of Centennial's operated SWD wells, interest in four non-operated wells, approved and pending permits and associated water infrastructure located essentially all in Reeves County.

These assets currently dispose of nearly half of Centennial's gross water volumes in Texas. Upon closing, which is expected at the end of Q1, after-tax cash proceeds of approximately $150 million will be used to repay borrowings under our revolving credit facility, further reducing our already solid leverage metrics.

Additionally, these proceeds will plug any funding gap associated with our development program, making us essentially cash flow neutral for 2020. WaterBridge is a long-standing partner of Centennial's and has historically disposed of nearly half of our produced water volumes in Reeves County. The divested assets combined with WaterBridge's broader Southern Delaware system will provide significant flexibility and additional capacity to service Centennial's water disposal needs.

After closing, Centennial will pay a market disposal rate on the incremental volumes that the Company doesn't already send to WaterBridge which is incorporated into our 2020 LOE guidance.

On Slide 14, we summarize our capital structure and liquidity position. At December 31st, we had $175 million of borrowings on our credit facility and approximately $635 million of total liquidity based upon an $800 million of elected commitments. It is important to note that the elected commitment has a $400 million cushion relative to our $1.2 billion borrowing base. In that regard, we view our liquidity position as somewhat insulated to the biannual borrowing base redetermination process.

Turning to leverage statistics, Centennial's net debt-to-book capitalization at December 31st was 25% and net debt to last 12 months EBITDAX was 1.8 times. Also, as illustrated on Slide 15, I'd like to remind everyone that our first bond maturity is in the first quarter of 2026, providing us with significant financial flexibility.

Before moving on to 2020 guidance, I'd like to spend a moment to put fiscal year 2019 into context, which is detailed on Slide six. You will recall a year ago that we had forecast 2019 oil production volumes at 39,000 barrels per day at the midpoint of our guidance with the 6-rig program. At the time, that represented 12% oil growth at the midpoint, predicated upon a $625 million to $725 million D&C capital spending range.

In fact, we ran a 6-rig program through early September when we dropped to 5 rigs as a result of increased efficiencies. We completed 84 gross wells versus 70 at the original midpoint and raised production guidance twice during the year. Ultimately, we generated 23% oil production growth instead of the initial 12% guide. And all of that occurred with $691 million of D&C capital, which is approximately 2% over the midpoint of our original guidance.

Essentially we got much more efficient operationally, particularly in the second half of the year. This in turn, allowed us to deliver a much higher degree of capital efficiency and a more attractive production growth profile in 2019 than most had expected, which is also a function of our well and acreage quality.

I'll now turn to 2020 guidance, which you can reference on Slides 17 and 18. Given the recent weakness in oil prices, we have decided to reduce our rig count beginning in April to four from five rigs in order to preserve capital and drilling locations until oil demand recovers. For a majority of the year, we plan to run three rigs in Reeves County and one rig in Lea County.

This allocation will allow for the build out of infrastructure in New Mexico, while meeting all of our leasehold requirements in Texas. This program will allow us to spud and complete 70 gross wells at the midpoint and is expected to drive 3% annual oil production growth. D&C capex for 2020 is estimated at $520 million at the midpoint, which represents a 25% reduction from 2019 levels.

Notably, as a result of the higher rig activity earlier in the year, it should come as no surprise that Q1 will be our heaviest quarter from a capex standpoint. In total, we expect this D&C program to generate midpoint oil production of 43,800 barrels per day. Finally, oil as a percentage of total production is expected to be 57%, which is consistent with what we saw during 2019.

Facilities Infrastructure & Other capital is estimated at $105 million at the midpoint, which is $57 million lower or a 35% reduction compared to 2019 levels. Finally, our Land capex budget is $10 million to $20 million, which is down from the $38 million we spent in 2020.

Turning to unit costs, at the midpoint, LOE is estimated to be $6.20 per barrel, which is partially reflective of higher water disposal fees from the portion of our water volumes in Texas that are impacted by our SWD sale. Additionally, midpoint DD&A is estimated at $16; GP&T at $3.20 and cash G&A at $2.15. You can reference how that compares to our 2019 actual results in the summary table on Slide 19.

With that, I'll turn the call over to Sean to review operations.

Sean R. Smith -- Vice President & Chief Operating Officer

Thank you, George. This was another consistent quarter of strong execution for Centennial. As we highlighted last quarter, our operations team continues to do a tremendous job driving down well costs as a result of efficiencies gained in the field.

As seen on Slide 7, we've been able to reduce our spud to rig release in the fourth quarter by almost 40% to 19 days on average, compared to last year. Importantly, we were able to achieve this while remaining inside of our 30 foot target window 95% of the time during the entirety of 2019. Similarly, on the completion side, we've increased our average stages pumped per day during the quarter by 30% year-over-year to 6.4 stages per day.

Overall, these efforts resulted in an over 20% reduction in fourth quarter well costs for our 7,500 foot laterals compared to the prior year period. Combined with longer laterals and larger pad size, this has translated into a material improvement in our overall capital efficiency. Importantly, we believe there are additional efficiencies to be gained and this would be a primary point of focus for CDEV in 2020.

Now turning to results for the quarter on slide 8. In Reeves County, the Bodacious 2-well pad was drilled using approximately 6,200 foot laterals in a stacked-staggered pattern targeting the Third Bone Spring Sand and Wolfcamp Upper A intervals. The pad delivered an average IP30 of approximately 1,800 barrels of oil equivalent per day or 210 barrels of oil per 1,000 foot of lateral per well. Overall, Centennial completed 10 Third Bone Spring Sand wells in Texas during 2019, with the majority of them being paired with a Wolfcamp Upper A.

We have not only proven the viability of co-developing these two zones, but most importantly, our Third Bone Spring Sand results to date have been on par with our Wolfcamp Upper As. This highlights the quality of our inventory additions with the Third Bone Spring Sand. As a reminder, it wasn't too long ago when we were one of the few companies in this area of the Southern Delaware Basin to develop the Third Bone Spring Sand with modern completion techniques.

Approximately two years later, we've developed this zone into a top tier reservoir for Centennial with essentially zero entry cost. Also in Texas, the Lucy Prewit and Nicholas pads each consisted of three wells in the Wolfcamp Upper A spaced at our usual 800 to 900 foot spacing.

The Lucy Prewits were drilled with approximate 7,000 foot laterals and reported an average IP30 of 1700 barrels of oil equivalent per day or 214 barrels of oil per day per 1,000 foot of lateral per well. Drilled with approximately 10,000-foot laterals, the Nicholas wells achieved an average IP30 of almost 1900 barrels of oil equivalent per day.

Now turning to New Mexico on Slide 9, the Airstream 24 State Com pad was co-developed with four wells targeting the upper and lower portions of the Second Bone Spring Sand. These approximately 10,000-foot laterals delivered an average IP30 of over 1,800 barrels of oil equivalent per day or 1,500 barrels per day of oil. This is another important test as previous operators in this area have historically targeted this interval with four wells per section.

Notably, the Airstream were drilled at 900-foot spacing, representing approximately six wells per section. We believe this co-development pattern will allow us to accommodate more wells per section on a portion of our acreage, while draining the reservoir more effectively.

The Duck Hunt pad consisted of four 7,000 foot wells targeting the First, Second and Third Bone Spring Sand and Second Bone Spring shale intervals. Combined, these wells delivered average IP30s of approximately 1,700 barrels of oil equivalent per day or almost 200 barrels oil per day per 1,000 foot of lateral per well.

Shifting to Slide 13, total proved reserves increased 15% to approximately 300 million barrels of oil equivalent at year-end 2019. We organically replaced approximately 243% of our 2019 production at a drill bit F&D cost of just over $13 per BOE. At year-end, our proved reserve value on a PV-10 basis was approximately $2.2 billion, which represents a reduction from year-end 2018, primarily as a result of lower commodity prices across all three streams.

Now before I turn it back over to Mark, there are a few important items I'd like to note. Our 2020 plan represents an almost 30% reduction in our overall capital budget year-over-year, while still displaying positive oil growth. On the D&C front, this is partially a function of the decline in rig count, but also driven by a material reduction in well cost. Infrastructure, facilities, and other capex is down 35% year-over-year and is the outcome of several initiatives.

As a result of our SWD divestiture, we'll no longer be responsible for that system's associated capex, whether it'd be the drilling of incremental SWD wells or the construction of small gathering lines or large diameter pipe. In 2020, we also expect to tie into existing tank batteries and reuse existing pads, saving further dollars on facilities capex. Combined, these cost savings make us much more capital efficient. Our 2020 plan also has many other advantages that might be less obvious, but arguably just as important.

First, we're not going to grow production just for growth sake. By dropping a rig at the end of the first quarter, this will not only preserve capital but also high-quality inventory that would otherwise be produced in a sub-optimal oil price environment, not to mention growing incremental volumes in a market that currently does not value growth. Centennial also continues to focus on replacing over 1 times our drilled inventory each year, whether it'd be from organic inventory additions, swaps or trades.

2019 was no different as we organically replaced approximately 1.5 times our drilled inventory last year as shown on Slide 12. While this might not be rewarded in the market currently, it will continue to be key for Centennial going forward.

If you go back and look through our presentations as early as 2016, Centennial's goal has not changed a bit. We are determined to reach the point where our development program is entirely funded through cash flow from operations, while providing moderate oil growth on an annual basis. And our asset base certainly has the ability to deliver on these goals. I don't think there's any question with regards to our asset quality, which is evidenced by our well results and consistent execution of our annual guidance.

And I'd like to wrap up by saying how truly honored I am to succeed Mark as CEO and would like to personally thank the Board for this opportunity. I'm excited to lead such a great organization and I look forward to continued execution while driving long-term value for the stakeholders.

With that I'll turn the call back over to Mark.

Mark G. Papa -- Chairman & Chief Executive Officer

Thanks, Sean. Now, I'll provide some thoughts regarding the oil macro picture and relate them to Centennial's 2020 strategy. I'll also discuss our management succession. Two things are apparent regarding the 2020 global oil supply demand picture. First, U.S. oil year-over-year growth will be less than past years; and second, global demand will likely be less than 1 million barrels per day this year.

CDEV's 2020 business plan response to the current coronavirus induced low oil price is simple, we're prioritizing balance sheet preservation over production growth. Our capex budget is approximately 30% lower than last year, yet we still expect to achieve a small amount of production growth. We believe the slowdown in overall U.S. production growth will allow the global market to rebalance within a reasonable timeframe and we plan to preserve our balance sheet until that occurs.

By monetizing our saltwater disposal system and reducing from a five to a four rig drilling program, we expect to be essentially cash flow neutral this year based on the current forward strip, I'll remind everyone that we have 80,000 reasonably contiguous acres in the heart of, arguably, the best U.S. shale oil basin; that we're one of the few companies with a multi-year track record of exceeding our production target while staying within our original capex estimate each year.

I'll also note that unlike many other shale companies CDEV has not had any spacing or well pattern debacles. From the get-go, we've spaced our Texas wells at a conservative 880 feet. When you aggregate acreage quality, operational execution, a clean balance sheet and good management; that's a strong combination.

Speaking of management, I think all of you have seen our press release announcing our management changes that will take place June 1st. I'll be retiring and Steve Shapiro will replace me as non-Executive Chairman, Sean Smith will be promoted to CEO and Matt Garrison will be promoted from VP Geosciences to COO.

I'm retiring simply because I've reached an age where I need to step off the stage. I'm 73-years old and when I started this company as a spec in 2016, I told everyone I'd likely stay for four years until 2020. Clearly, the oil market and E&P equity valuations didn't develop as I expected but I'm staying consistent with my original career plan. We're fortunate to have a competent team to come in behind me.

Some of you may remember Steve Shapiro from his days as CFO and Board Member of Burlington Resources where he was very well regarded by the investment community. He was with Burlington until the buyout by ConocoPhillips in March of 2006. He joined the CDEV Board in October of 2019. Sean Smith has been with Centennial since 2014 and has been functionally running much of the Company since 2018. I believe he'll do a great job in the CEO role. Matt Garrison is an EOG alumni, who has been with CDEV since 2016 has been one of the drivers of the significant production growth we've achieved since inception. I'll be working closely with this team over the next three months to assure that this is a seamless transition.

Thanks for listening and now we'll go to Q&A.

Questions and Answers:

Operator

Thank you. [Operator Instructions] And your first question comes from the line of Matt Portillo with TPH

Matthew Portillo -- Tudor, Pickering, Holt & Co. -- Analyst

Good morning, guys.

Mark G. Papa -- Chairman & Chief Executive Officer

Good morning, Matt.

Matthew Portillo -- Tudor, Pickering, Holt & Co. -- Analyst

Just a strategic question from a capital allocation perspective. Investors are looking for industry participants to move toward capital allocation strategies that are able to generate free cash flow under strip pricing. For 2020, you backstopped the outspend with the saltwater disposal, but as we look out into 2021 and beyond, if crude remains depressed at these $50 levels, should we expect to further paring back of capital toward a cash flow neutral program.

Mark G. Papa -- Chairman & Chief Executive Officer

Yeah. In '21, if crude remains at $50, I think it's pretty well certain it will prioritize the balance sheet again over production growth and that I think is very, very likely. It'd would be really, really odd to say in that kind of environment that CDEV would say we're going to grow production in, in a $50 or $52 oil environment.

Again, that would go back to the macro picture that have articulated. I think that we're going to see a significant slowdown in U.S. production growth this year. I'd say that's certain to happen. If you play that out in '21 and you say you're at the $50 or $52 oil price environment, I'd go so far to say that the U.S. year-over-year production growth in '21 would probably be zero, under that price environment.

So one would expect a significant tightening in global supply/demand. So I don't think you could go too many years with U.S. year-over-year production growth of zero before you see a rise in oil prices. So that would be the thesis that we would work under that we would preserve the balance sheet as CDEV and that -- with a significant slowing in U.S. year-over-year production growth that they wouldn't be too many years before you would see an increase in global oil prices.

Matthew Portillo -- Tudor, Pickering, Holt & Co. -- Analyst

Thank you, that's very helpful. As my second question, just curious if you could dig a little bit into the facility spend as it relates to 2020? Any incremental color you could provide on where that capital, the $105 million of capital is going toward?

And then just a bigger picture question over time, how should we think about that facility spend as the asset starts to mature and as you start to spend more and more capital at the drill bit.

Mark G. Papa -- Chairman & Chief Executive Officer

Yes. Sean, do you want to field that?

Sean R. Smith -- Vice President & Chief Operating Officer

You bet. Thanks for asking the question, Matt. So as we talked about, it's pretty material decrease in facilities and infrastructure spend year-over-year. So we're certainly seeing the benefit of maturing the asset. On the facility side, those allocated costs are really at the wellhead, so that includes tank batteries and things like that, what's needed to hook up to the well.

We do think we're seeing some incremental savings there by going back in to reexisting facilities and utilizing what was there from last year and years prior. So we're seeing some nice efficiencies gains there. On the infrastructure side as -- we're still a young asset, if you will, but as we develop this over the previous several years, we've been able to spend enough infrastructure to where the position is pretty well set up. So on an annual basis, there is a nice reduction in infrastructure spend from 2019 to 2020.

We do have a few items that are outstanding that include, as we've talked about in previous calls, our electrical substation still needs to go live. A portion of that was spent last year, but the remaining portion will be spent in 2020. And then the second part of that is there is a little bit of infrastructure that needs to be spent in New Mexico to bring that up to where we needed to be before full development. So that's where the lion's share of the infrastructure spend is for 2020.

Matthew Portillo -- Tudor, Pickering, Holt & Co. -- Analyst

Thank you.

Operator

And your next question comes from the line of Scott Hanold with RBC Capital Markets.

Scott Hanold -- RBC Capital Markets -- Analyst

Yeah, thank. And first, congrats Mark on your long and successful career. Your leadership, I think bar none, has been an asset to the industry and hope you well in your future endeavors?

Mark G. Papa -- Chairman & Chief Executive Officer

Thank you Scott.

Scott Hanold -- RBC Capital Markets -- Analyst

My first question is, and maybe Mark, you want to start out with Sean [Phonetic] or George you want to fill in late on the management. But you talked about your view on the macro and how CDEV would potentially look to develop its assets moving forward in this environment, and you did talk about maybe a point at which the market gets more balanced. Can you give us a view on when do you think that occurs? And bigger picture, has your view on hedging oil changed given what's happened over the last couple of years?

Mark G. Papa -- Chairman & Chief Executive Officer

Yeah, on the macro situation there, Scott, it would -- it would seems like to me that absent the coronavirus, we were on the verge of being balanced sometime in the second half of this year where we were -- we were likely to see $65 WTI in the second half of this year.

Now you lay the coronavirus on there, and I think it's probably pushed the balance situation into likely '21, in my view. And so, what I think we're going to see happen is U.S. year-over-year production growth is going to slow down considerably from the 1.2 million barrels a day that we saw in 2019 to probably 400,000 may be 500,000, 600,000 barrels a day this year. And then likely, considerably less than that in '21 and '22.

And so I think we're going to see a balancing in '21 or no later than '22 as we see a structural change in the ability of total U.S. production to grow short of oil going to $80 and stabilizing there, which I don't think any of us believe is likely. So playing into CDEV strategy, the strategy is pretty simple, it's preserve the balance sheet as we watch U.S. production growth year-over-year frankly weaken over the next 12 to 36 months, permanently weaken, let me say, and have CDEV in a position where we have significant inventory at that time and a strong balance sheet at that time.

And we're located in arguably the best U.S. oil shale basin where we can then grow significantly and have the ability to add some additional acreage during this weak period and being a small company, but a small high growth company when we see the pricing signals go that way. So that's simply put, is our strategy.

And whether that period is 12 months or 24 months, I can't tell you, but I don't think it's going to be much longer than 24 months of a period of these low oil prices. So hopefully, that answers your question.

Scott Hanold -- RBC Capital Markets -- Analyst

Yeah, it does, good. And just about the hedging then, has your hedging views changed?

Mark G. Papa -- Chairman & Chief Executive Officer

The hedging, you know since we can't tell exactly when this -- when this is going to turnaround, it's not -- I'd say at least at this period in time, it's probably not a good time to hedge oil. So I don't think we'll be hedging any oil at least during my tenure, which is not that long. So you can -- you can see how Sean wants to play out.

I mean that strategy may change after I leave. I've been a notorious anti-hedger. Maybe that's been a good move. Maybe that's not been a good move. But that's one philosophy that might well change as I transition away from the organization.

Scott Hanold -- RBC Capital Markets -- Analyst

Right. Is it too early to put Sean [Phonetic] on the spot? And I wonder if he'll say that one for the second quarter conference call.

Sean R. Smith -- Vice President & Chief Operating Officer

I'd probably save that for the May conference calls Scott. [Speech Overlap] Okay.

Scott Hanold -- RBC Capital Markets -- Analyst

Alright, fair enough. As my follow-up question, your 24 completions in the quarter was extremely robust relative to what -- I think you have only even modeled and what we expecting. But what played a role in that? Was it DUCs you had? Was it the size of well pads that you had coming online or timing of those? Can you give a little color on the -- what caused such a high completion comp in 4Q?

Mark G. Papa -- Chairman & Chief Executive Officer

Yes, Sean?

Sean R. Smith -- Vice President & Chief Operating Officer

Sure. Yeah, thanks for the question. It certainly wasn't DUCs. We don't have a practice of building up DUC inventory haven't in the past and that's certainly not something that we look to. Obviously when you're doing Pad development there is just some lumpiness that comes along with that. So we had a fewer completions in Q3 versus Q4 really related to just the pad timing of when wells were being completed and brought online. So nothing strategically positioned there. It was really just a timing thing.

Scott Hanold -- RBC Capital Markets -- Analyst

Understood, thanks.

Operator

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

Asit Sen -- Bank of America Merrill Lynch. -- Analyst

Thanks, good morning. Mark, all the best on your retirement. Your views will be missed. And Sean, congrats on the new role. Sean, on Slide 6, you talk about D,C&F capex per completed foot that was down nicely in 2019. What does the 2020 budget imply? Because in your prepared remarks, you talked about long lateral and larger pad size. Any thoughts on 2020 lateral length or pad size would be appreciated.

Sean R. Smith -- Vice President & Chief Operating Officer

Sure. Yeah, thanks for the question, and then, pointing that out again. I think Slide 6 is a great representation of a pride, if you will, from the operation side of things where we reduced well cost pretty significantly from what we thought we were going to accomplish beginning of the year to where we ended up at the end of the year.

I think if you roll that forward, that's a good view of how we have guided our 2020 look forward of D&C cost on a per foot basis. Maybe just kind of split the difference there, I think it's a decent way of looking at what we've got going forward. That's driven by a combination of things, obviously pad size, reuse of existing facilities, and then really the operations team continuing to drive efficiencies in the field and the majority of that drive is really working with our technical team.

Obviously, we've done some things with bottom-hole assemblies and mud systems and whatnot. I think that's been effective. But really working with the technical teams; geology, reservoir engineering etc. has really helped us to identify any drilling hazards and avoid those as we're going and I think that we've shown that we've been able to drive efficiencies pretty materially year-over-year.

Going forward, I do think there is some more opportunity to lower those costs throughout 2020. But until we execute on those, none of that's baked into our 2020 guidance.

Asit Sen -- Bank of America Merrill Lynch. -- Analyst

Got it Sean, thanks. And George, a quick one for you. Thanks for the update on infrastructure spend. Can you discuss a good rule of thumb to estimate recurring infrastructure spend beyond 2020 post water disposal and post the electric substation spin?

George S. Glyphis -- Vice President & Chief Financial Officer

Yeah, the challenging thing there is, there does tend to be a little bit more lumpiness on the infrastructure side relative to facilities. So, I said it's frankly difficult to give you a good number on that. I think I had referenced on last quarter's call that the relative split of facilities and infrastructure was approximately 75%, 25% historically and I think that's generally a good rule of thumb going forward.

Although I would say, monetizing the SWD system will obviously lower that requirement on a go-forward basis. In 2020, we have the power substation which is adding some incremental capex costs. So it's really tough to predict, but I do think over time, those costs are going to continue to come down.

Asit Sen -- Bank of America Merrill Lynch. -- Analyst

Appreciate the color. Thank you.

Operator

Your next question comes from the line of Kashy Harrison with Simmons Energy.

Kashy Harrison -- Simmons Energy -- Analyst

Good morning, and thank you for taking my questions. So my first one, just looking through -- looking through the K, it looks like there was a section where you talked about acquiring about 24,000 net acres in the Permian Basin. I was just wondering if you could share any additional color on what that pertains to.

And then also, it looks like there was about $84 million of proved -- unproved property acquisitions. Was just wondering what all that was related to? Thank you.

Mark G. Papa -- Chairman & Chief Executive Officer

Yeah, on the first -- I'll field the first part of that and I don't know, George or someone you might want to check on the second part of that while I'm fielding the first part of that question. So you did your homework, looking at the K on there Kashy. Good job.

Yeah, the, acreage that's mentioned in the K is something that, if you know my track record at EOG, we don't like to stand still on our existing plays and what I'll just answer in a circuitous manner is that we're consistently looking for exploration plays that acreage relates to a new exploration play somewhere in the Permian Basin. And for confidentiality reasons, we're still working on acquiring acreage in that particular play.

We'll be drilling it and testing it sometime in the first half of this year and that's all the information I'm prepared to disclose at this time relating to that. So for the second half of it. George, you want to field the -- see if you can field that particular question?

George S. Glyphis -- Vice President & Chief Financial Officer

Sure. Kashy, I don't have the K in front of me, but I think part of what you're describing will include some of the activities Mark just mentioned, but also some small-ish organic leasing and acquisitions we've done throughout the course of last year. So nothing -- no one driver that kind of drove the number, but a compilation of different things.

Kashy Harrison -- Simmons Energy -- Analyst

Got it. That's helpful. Thanks for the comments on both fronts. And then there is a comment I think in the release that most of the spending -- most of the D&C spending in 2020 would be on operated as opposed to non-op.

I was just -- I was just curious, in 2019, what percentage of D&C was allocated to non-op and how does that track entering 2020?

George S. Glyphis -- Vice President & Chief Financial Officer

I think Kashy, for 2019, it was less than 5% and I think we're taking a consistent view with that for 2020.

Kashy Harrison -- Simmons Energy -- Analyst

Awesome. Thanks for that. And Mark, best of luck in retirement.

Mark G. Papa -- Chairman & Chief Executive Officer

Thanks Kashy

Operator

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

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Hey guys, and congrats, Sean, on the new position. My first question centers on your Slide 9, on the Southern Delaware results. I'm just wondering here, do you all envision doing more of these multi-zone pads such as the Bodacious or will sort of more of the focus on this year target a multiple of some of the pads, such as the Lucy Prewit where you're just targeting multiple wells in one formation.

Sean R. Smith -- Vice President & Chief Operating Officer

Sure, yeah. Thanks for the question. I think that going forward, it will be a combination of both of those. But I think that what we've shown is that doing multiple reservoirs in New Mexico, off of a single pad is definitely successful and it allows us to develop the asset in the most efficient way. So certainly that will be a large portion of our development going forward.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Okay. My second question is just follow up on what you all were just talking about little bit on acreage. Given the slowing activity, is there any issues on holding existing acreage or is that maybe part of what the $10 million to $20 million in land capex is directed toward or is it most of that HBP?

Sean R. Smith -- Vice President & Chief Operating Officer

Mark, I'll take that one. So, we do have a small portion of our land budget that goes to making sure that we can retain our position together. But the majority of our acreage is held with the rigs and so I think that the combination of the two will allow us to keep our position together in 2020 and beyond.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Great, thanks Sean.

Sean R. Smith -- Vice President & Chief Operating Officer

Thank you.

Operator

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

William S. Thompson -- Barclays -- Analyst

Hey, good morning. Mark, congrats on your reretirement and congrats to Sean for promotions. May for Sean or George, maybe you can help us understand the potential production cadence through 2020. You're coming off a strong 4Q with 27 completions, you'll be carrying a fifth rig through April, how does that set up for one half versus second half? And then, it was mentioned in the prepared comments that TDEV still targets a moderate oil growth. At four rigs, what would that reasonably can be for oil growth in 2021? I know it's a tough question, but maybe any color you can provide would be helpful?

Sean R. Smith -- Vice President & Chief Operating Officer

Sure. Yeah, I think it is a tough question. But I think we're dropping a rig at the end of the first quarter. And so, the balance of the year, we'll be running a four-rig program. So, and there will be a little bit of lumpiness. Obviously, we don't give quarterly guidance, we give the annual guidance.

But first quarter, I think you can assume is going to be our highest capital quarter because we have an extra rig running. And I think from a production point of view, you'll see the effects of that in Q2. But then you also see what we were forecasting for the midpoint of our production for the year. So I think you can make some generalized assumptions from that statement.

William S. Thompson -- Barclays -- Analyst

Okay. Thank you. And then the 10-K shows about $1.6 billion or about $20,000 per flowing barrel PDP, PV-10 at $52 -- around $52 WTI. With that, my math indicates your current enterprise value implies less than $3,000 per net acre. Would you consider selling some acreage that's in the back part of your inventory stack to further offset outspend? Just curious on any thoughts there?

Mark G. Papa -- Chairman & Chief Executive Officer

Yeah. Will, I'll field that question. Likely, no. I mean, we -- not any significant acreage to cover any outspend at this point. We've got our acreage pretty well caught up [Phonetic] and we sold a little bit of acreage that was on our Western fringe during 2019.

And so right now, I'd say that the acreage we have, which is just a tad less than 80,000 acres is pretty much a 100% core. So at this juncture, it's unlikely we'll be selling any acreage in either Lea County or Reeves County of any consequence. And we're not looking at the option of using acreage sales to try and equilibrate to cash flow neutrality.

William S. Thompson -- Barclays -- Analyst

Okay. Thanks for taking my questions.

Mark G. Papa -- Chairman & Chief Executive Officer

Okay.

Operator

Our next question comes from the line of Leo Mariani with KeyBanc.

Leo Mariani -- KeyBanc Capital Markets -- Analyst

Yeah, hey, guys. Wanted to kind of follow-up a little bit on some of the macro thoughts and comments Mark that you articulated a hopeful rise in oil prices in 2021. Just wanted to get a sense of whether or not there's flexibility in 2020 if we were to get an oil price recovery say in the second half of 2020, might CDEV considering -- consider adding another rig or would you just kind of stay put with the existing four rigs here?

Mark G. Papa -- Chairman & Chief Executive Officer

Well, we've -- I mean, we certainly have the flexibility. I mean, there's certainly going to be rigs available to be picked up. And if you look at some of the third-party forecasts, there are forecasts out there that are forecasting by the fourth quarter WTI will be $65 a barrel. So were that to occur, were that tightening to occur, I'd say that we would certainly consider adding back a rig.

But at this -- and so, I'd say, at this juncture, we expect to see the tightening in '21 and probably the most likely scenario would be that we would continue with the program we've articulated through '20. And then, if indeed we see the tightening and oil prices firming that it's possible we consider adding back that rig in '21 as opposed to making a change to our capital program in '20. That's the most likely scenario kind of -- even if oil prices firmed up in late '20 we'd probably stand pat until '21 and then make a change in 2021.

Leo Mariani -- KeyBanc Capital Markets -- Analyst

Okay. That's helpful color in terms of the thinking over there, for sure. Just a question on the cash G&A guidance. I think you guys came in, just over $1.80 per Boe in 2019. I think you guys are saying that could go up, to say, $2.00 to $2.30, in 2020 here. So you're kind of moving up a little bit, on a per-barrel basis. Just wanted to get a sense of what might be driving that? I guess I would have thought maybe with less rigs that G&A really wouldn't be going up here in '20?

Mark G. Papa -- Chairman & Chief Executive Officer

Yeah, George?

George S. Glyphis -- Vice President & Chief Financial Officer

Sure. I think we did a very modest amount of hiring during the course of 2019, so I think there's a little bit of increased cost associated with that. But we are very well staffed for current levels.

And I think if you factor in, at least for Q4, that there was roughly a $2 million contract settlement charge in our G&A. There's a bit of an offset to Q4 there. But if you step back and look at our dollar per Boe, which at the midpoint we're saying for 2020 is $2.15 that still rates very well relative to the small and mid-cap peers out there on a dollar per Boe basis.

We are very much toward the lower end of that metric. I think philosophically we tend to run very lean and efficiently. So while we are seeing a little bit of increases relative to where we've been historically, I think overall the Company is very well placed, from a cost standpoint, on G&A.

Leo Mariani -- KeyBanc Capital Markets -- Analyst

Okay, that's helpful color. And I guess maybe just on the D&C and F well cost per lateral foot, what were the main drivers that caused the big reduction, which I think you guys said was primarily in the second half of 2019 to get that big year-over-year reduction?

Sean R. Smith -- Vice President & Chief Operating Officer

Sure. I'll field that one. I think that it was kind of a couple of things. Obviously, service costs came down a little bit at -- in the middle half of last year, but that was a portion of it.

The greater portion of it was really the efficiencies that we're seeing in the field. I think, we've just had that much more experience and reputation now out in our portion of the Delaware Basin to where we understand what it takes to get these wells down. That in combination, as I said earlier, with our technical teams identifying any potential drilling hazards. When you can avoid those, you reduce your days of drilling and completions. And so, the combination of all that has allowed us to be that much more efficient in our D&C cost.

Leo Mariani -- KeyBanc Capital Markets -- Analyst

Thank you.

Hays Mabry -- Director of Investor Relations

Great, thanks, Leo. Rebecca, do we have any more questions in the Q&A?

Operator

There are no further questions.

Hays Mabry -- Director of Investor Relations

Well, great. Well, at this time, everybody can disconnect. I'd like to thank everybody for their interest in Centennial. And feel free to reach out with any questions. Thanks a lot. Have a great day.

Operator

[Operator Closing Remarks]

Duration: 51 minutes

Call participants:

Hays Mabry -- Director of Investor Relations

Mark G. Papa -- Chairman & Chief Executive Officer

George S. Glyphis -- Vice President & Chief Financial Officer

Sean R. Smith -- Vice President & Chief Operating Officer

Matthew Portillo -- Tudor, Pickering, Holt & Co. -- Analyst

Scott Hanold -- RBC Capital Markets -- Analyst

Asit Sen -- Bank of America Merrill Lynch. -- Analyst

Kashy Harrison -- Simmons Energy -- Analyst

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

William S. Thompson -- Barclays -- Analyst

Leo Mariani -- KeyBanc Capital Markets -- Analyst

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