Good day, and welcome to Centennial Resource Development's Conference Call to discuss its Second Quarter 2018 Earnings. Today's call is being recorded. A replay of the call will be accessible until August 21st, 2018, by dialing 855-859-2056 and entering the conference ID number 7818579, or by visiting Centennial's website at www.cdevinc.com.

At this time, I will turn the call over to Hays Mabry, Centennial's Director of Investor Relations for some opening remarks. Please go ahead..

Thanks, Erwin, and thank you all for joining us on the company's second quarter 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 August 6, we filed a Form 8-K with an earnings release, reporting second quarter earnings results for the company and operational results for our subsidiary, Centennial Resource Production, LLC. We also posted an earnings presentation to our website that we will reference during today's call.

You can find the presentation on our website homepage or under Presentations at www.cdevinc.com. I would like to note that many of the comments during this earnings call are forward-looking statements that involve 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 and the Forward-Looking Statement sections of our filings with the Securities and Exchange Commission, including our Annual Report on Form 10-K for the year ended December 31, 2017.

Although we believe the expectations expressed are based on reasonable assumptions, they are not guaranteed of future performance and actual results or developments may differ materially. We may also refer to non-GAAP financial measures that help facilitate comparisons across periods and with our peers.

For any non-GAAP measures we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release available on our website. With that, I'll turn the call over to Mark Papa, Chairman and CEO..

Thanks Hays. Good morning and welcome to Centennial's second quarter 2018 earnings call. Our presentation sequence on this call will be as follows; George will first discuss our quarterly financial results, updated hedge position and liquidity.

Sean will then provide an operational update from the quarter as well as give an overview of our new midstream agreements. And then I will follow with my views regarding our oil macro, our strategy as a function of the macro and closing comments. Now, I will ask George Glyphis to review our financial results..

Thank you, Mark. As you can reference on Page 10 of the earnings presentation, oil production for Q2 averaged approximately 31,270 barrels per day, which was essentially flat with Q1. Q2 oil volumes were impacted by completions being heavily weighted in the month of June and offset frac shut-ins.

Of the 20 wells that were brought online during the quarter, approximately half of the wells were completed in June, and therefore had a minimal impact on production for the quarter. Average oil equivalent production increased 6% quarter-over-quarter and totaled approximately 57,525 barrels per day.

The oil equivalent volumes increased because of the shift to ethane recovery at our primary gas processing plant. Ethane recovery currently provides better economics for NGL production and slightly increases overall revenues. While oil volumes are not impacted by ethane recovery, NGL production for the quarter surged by 50% compared to Q1.

As a result, total liquids production, including both oil and NGLs as a percentage of total production, increased to 76% from 74% in Q1, and oil as a percentage of total production was 54% compared to 58% in Q1.

Given the increase of NGL volumes, we adjusted our full year total equivalent production by 750 barrels per day to a new midpoint of 60,000 barrels per day, and expect our percentage oil mixed to end the year in the high 50% area.

I want to underscore the point that this mix change was entirely due to the ethane recovery and was not caused by any fundamental change in the GOR from any of our wells. Revenues for the quarter totaled approximately $218 million which was essentially flat with the prior quarter.

The company's average realized oil price before basis hedges was $61.21 and represents a 90% realization versus the average NYMEX price for the quarter. This compares to $61.53 per barrel in Q1, as higher NYMEX prices in Q2 were offset by higher differential.

Inclusive of the impact of our basis hedges, our realized price for the quarter was 92% of NYMEX. Turning to the costs side. Unit costs for the quarter continue to highlight our field efficiencies.

LOE came in at 366 per Boe, which was slightly above the low end of our original guidance range despite rising 10% quarter-over-quarter due to higher costs associated with contract labor and equipment rentals.

GP&T expense was 292 per Boe, a 3% increase quarter-over-quarter, cash G&A declined from 213 per BOE in Q1 to 184, as a result of lower legal and professional fees. DD&A costs were1,432 per BOE which was up 1,357 in Q1, but still near the lower end of our annual guidance range.

As noted in our updated annual guidance, which is illustrated on Page 13, our year-to-date results gave us the confidence to reduce nearly all of our annual unit cost guidance ranges. Adjusted EBITDAX totaled approximately $165 million for Q2, slightly above $162 million in the prior quarter.

Net income attributable to our Class A Common Stock totaled approximately $64 million or $0.24 per diluted share compared to $0.25 and $0.09 per share in Q1 2018 and Q2 2017, respectively. Centennial incurred approximately $203 million of total capital expenditures during the quarter compared to $238 million in Q1.

This was a 15% decline, primarily because of lower drilling and completions CapEx and facilities CapEx, D&C CapEx was $163 million, down for 10% from Q1, which was mainly due to drilling lower working interest wells.

Well level facilities, infrastructure, seismic acquisitions, land and other capital totaled approximately $40 million, down from $56 million during Q1. During the quarter, Centennial also entered into its second agreement with an in-basin sand provider.

This contract coupled with our original contract will allow Centennial to secure approximately 80% of our future profit means under regional contracts for the next several years.

As a reminder, in-basin sand is a significantly lower cost than traditional northern white, and we believe this will help mitigate any future service cost inflation in other areas of our operations. Turning to oil basis hedging -- excuse me, turning to oil hedging, Centennial continues to be completely unhedged on fixed price oil.

Regarding basis hedging, like many in the industry, we were surprised by the severity and timing of the Mid-Cush basis blowout that's started in Q2.

As you can see on Page 9 of the presentation, for the second half of 2018, we have hedges in place for approximately 23% of our midpoint oil production guidance, at the Mid-Cush differential of $2.38 per barrel. We also have hedged approximately 8,000 barrels per day of oil production in 2019 at an average differential of $6.88 per barrel.

We continue to monitor the market and may add to our 2019 hedge position. Later on Sean will review agreements that we've entered into to secure flow assurance for both oil and natural gas takeaway. On Page 11 of the presentation, we summarize our capital structure and liquidity position.

At June 30, we had approximately $43 million of cash, $400 million of senior unsecured notes and $30 million of borrowings under revolving credit facility. At quarter's end pro forma for our $600 million elected commitment on the credit facility, we had $612 million of liquidity.

Centennial's net debt to book capitalization was 11% and net debt to Q2 annualized EBITDAX was 0.6%. With that, I'll turn the call over to Sean Smith to review operations..

Thank you, George. During the second quarter, we made significant progress towards our goal of operating and full-field manufacturing mode beginning in 2019.

As you can reference on Slide 4, we achieved strong well results across multiple intervals announced a solid co-development test in the 3rd Bone Spring Sand and made a tremendous progress on securing flow assurance for both oil and natural gas.

Importantly, our operations team was able to achieve the following, while driving down full year unit cost and keeping D&C CapEx below the anticipated quarterly estimate.

Over the past 18 months, Centennial has made great strides shifting from a primarily one-well single-section development program to our current focus on extended lateral multi-well pad development.

For example, 90% of our completed wells during the quarter were on multi-well pads and our average completed lateral length increased approximately 50% year-over-year. There is no delay in the enhanced economic returns that come from our current programs and we will continue to focus on these types of projects going forward.

During the quarter Centennial spud 22 wells and completed 20 wells. As George alluded to earlier, second quarter oil volumes were impacted by our backend waited completion schedule and higher than expected offset shut-ins during May.

Approximately half of our second quarter completions were brought online during the month of June or more specifically 25% of our completions occurred during the last week of the quarter. As a result, these wells contributed little production during the second quarter and resulted in flat quarter-over-quarter oil growth.

Importantly, due to the quality of wells recently brought online, we remain on track to achieve our full year oil target articulated at the beginning of the year. Turning to Slide 6, The Red Rock A Unit 9H and 4H represent a successful co-development test targeting the 3rd Bone Spring Sand and Upper Wolfcamp A intervals respectively.

With approximately 11,000 foot laterals, these wells were drilled using a stack-staggered pattern with 440 foot lateral spacing and 200 foot vertical spacing between the wells.

The Red Rock A in 9H Bone Spring test had an IP30 of 1,578 barrels of oil equivalent per day, which 72% oil, and the Wolfcamp A 4H had an IP30 of 1,268 barrels of oil equivalent per day, 74% oil.

Not only does this provide our second successful 3rd Bone Spring Sand test result following the previously announced Weaver well, but also proves the viability of co-developing the 3rd Bone Spring Sand with the Upper Wolfcamp A. We believe this confirms the addition of a new zone on a portion of our Reeves County acreage.

Most importantly, future inventory from this zone represents organically added inventory, which is much more economic than pricy M&A. We plan to drill additional 3rd Bone Spring Sand test throughout the remainder of this year and expect this zone to be a meaningful contributor to our development program next year.

Also during the quarter, Centennial brought online the best wells we've drilled ever, which is illustrated on Slide 5.

Drilled in our legacy Arroyo Area and targeting the Upper Wolfcamp A, the CWI long 31H, 40H and 40H were drilled with approximately 9,800 foot laterals and achieved IP30s of 1,685 barrels of oil per day 2,269 barrels of oil per day and 1,766 barrels of oil per day prospectively.

Combined, the pad produced over 200,000 barrels of oil during its first 40 days online. The three- well pad is still averaging greater than 1,600 barrels of oil per day after 40 days of production.

Further highlighting our shift to extended lateral pad drilling, the Ninja 2H, 3H, 4H and 5H were drilled on a four-well pad in our Miramar area containing two Upper As, one Lower A and at Wolfcamp C.

With average lateral lengths of approximately 9,800 feet, these four wells delivered an IP30 of approximately 1,900 barrels of oil equivalent per day, 58% oil. During its first 60 days online, pad produced over 225,000 barrels of oil. Turning to midstream and marketing.

During our last earnings call, we emphasized that our primary point of focus was flow assurance. In the past few months, we've made tremendous strides securing flow assurance for both oil and natural gas.

Capacity out of the basin for both products is certainly been a hot topic as of late, and these agreements announced yesterday, will support Centennial's ability to meet our 2020 game plan.

Starting with natural gas, current Permian Basin dry gas production is approximately 8 BCF a day versus effective take away capacity of approximately 8.4 BCF a day. Given future expected production growth, we continue to expect that natural gas egress will become a serious issue for Permian Basin by early 2019, especially in the Delaware Basin.

This is why we've been working diligently over the past year to secure flow assurance for our gas. As you can see on Slide 7, through a series of firm transportation of firm sales agreements, we have contracted capacity on multiple pipelines for 100% of Centennial's gross residue gas.

Notably, these contracts cover Centennial's gas both to the WAHA Hub and out of the Permian Basin through the end of 2021.

As a result, we did not envision a scenario whereby Centennial will be required to flare or shut-in production, during the time period when we anticipate Permian Basin-wide production will be significantly exceed available take away capacity.

In turn, these agreements will also allow us to recognize the economic value of both natural gas and NGL's, which represent approximately 20% of our total revenue. Now turning to crude oil. We've recently entered into a 6-year firm sales agreement with a large diversified crude oil purchaser.

Beginning in January of 2019, this contract allows for firm gross sales of 20,000 barrels oil per day, increasing to 30,000 barrels of oil per day in 2020, and for the remainder of the agreement. By utilizing the buyers existing FT, this agreement will provide Centennial with firm physical take away capacity out of the Permian Basin.

The agreement will initially be based of Midland pricing and switch to Brent-based pricing beginning in 2020. Due to confidentiality agreements as well as for competitive reasons, we cannot discuss the specific pricing terms of this contract, but believe the commercial terms are attractive in today's market.

In addition to providing flow assurance, this agreement diversifies our crude oil pricing portfolio to include Brent exposure, which we believe is prudent in today's environment. To put into context, Gulf Coast refining capacity currently totals approximately 6 million barrels oil per day.

Due to current configurations, these refiners can accommodate less than 2 million barrels of oil a day of light sweet crude with the majority of the remaining demand being satisfied through imports of heavier gray crudes.

With Gulf Coast refinery reaching a maximum capacity of higher gravity in shale oil that can be blended into feedstock's, we expect the future Brent and WTI differential will continue to encourage the export of Permian light sweet crude.

This is why we believe a diversified approach to pricing exposure will prove advantageous for Centennial longer-term. While this recently executed contract secures flow assurance for a large portion of Centennials crude, our ultimate goal is to have essentially all of our future crude oil production subject to similar firm sales agreements.

Therefore, we are currently working with several large marketers and expect to enter into additional contracts in the very near future. With these agreements in place, we have taken the necessary steps to secure flow assurance for both our crude oil and natural gas allowing us to execute on our game plan through 2020 and beyond.

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

Thanks Sean. Now I’ll provide some thoughts regarding the oil macro picture and relates into Centennial's strategy. The global oil macro picture continues to develop as expected, and prices have developed in a manner analogous to my commentary on previous calls.

The overall themes supply concerns is similar, but the focus of those concerns is shifted from U.S. shale's to Venezuela and Iran. Regardless CBS response is consistent. We will continue to remain on hedge regarding oil. We have employed some tactical oil basis hedges for the next 18 months, but it's unlikely will hedge WTI anytime soon.

Given our bullish macro view, we see no need to change our targeted organic growth trajectory towards 65,000 barrels of oil a day in 2020. In summary, I’d like to note six key points.

First, within a few months we expect to be one of few Permian mid-caps to have both oil and gas exit transportation for all their volumes lockdown for the next several years. Second, we have recently completed our second high rate 3rd Bone Spring Sand oil well confirming we indeed have a viable new play on our Reeves County acreage.

Third, our oil un-hedge and it's one of the highest oil growth rates in the industry. Fourth, for this call, we reduced all of our full-year unit cost categories while keeping our CapEx unchanged and slightly raising volume guidance. Fifth, we have the lowest debt in the peer group at 11% debt to cap.

And finally, we continue to be focused on GAAP ROE and ROCE. Thanks for listening. And now we will go to Q&A..

[Operator Instructions] Your first question comes from the line of Michael Greg from J.P Morgan. Your line is now open..

You talked about this quite a bit, but I was wondering if you give us more thoughts on the gas situation in Delaware.

What’s your view about how things play out at a basin level if we bump into capacity? And would you expect to see something similar to the DJ where older low-pressure wells did not off first?.

Yeah. Good morning, Michael. Yes, our read is that indeed likely beginning in early 2019, there's going to be an issue where some gas in the Permian and likely first in the Delaware just isn't able to find a method of egress. And then the situation will be that gas either had to be flared or the gas has to be shut-in along with the corresponding oil.

So we do see that situation developing. Now the other complicating factor could be if there is corresponding oil shut-ins, which might mitigated.

But I would say there is a greater than 50% probability based on our assessment that there is going to be a gas takeaway problem that develops in probably starting in the first quarter '19, and it probably is one year duration.

And it'll probably be the smaller companies that are affected, I don't think, the large caps and I don't think the integrated will be the companies that are necessarily affected and that they have likely to secure gas FT.

So you can probably tell from the earnings call announcements on who have announced that they have gas FT and who have not as to where discrimination will be. And we've been pursuing this gas FT for about six months. And I believe we are likely one of the few mid-cap Permian pure plays that does have gas FT.

And so, I think, it is a discriminating factor for us. And it hasn't been talked about too much really, but I believe within four, five months the problem will be upon pretty much the whole Permian Basin..

And then if I could just ask one on offset that CWI pad, obviously one of the strongest pads we've seen in the Delaware to date.

Would do you think is driving the magnitude of the outperformance in those wells?.

Yes, I would just make an overarching statement and now as Sean to contributed there, I think if you look at Centennial's Reeves County well completions in the last 12 months, I believe, we would likely to have perhaps the best or one of the top two or three most effective well completions in really in -- of any company in the entire Southern Delaware Basin.

And we've seen several analyses where some shell-siders have done some analysis. And in some cases the Centennial data is colored by completions done when Centennial was a private equity company before we really became a public company. And that was done by a previous technical team, but now that we have got our technical team in place.

I think our completion efficacy is really pretty much second to none. And so my overarching answer to you Michael would be that we have pretty much the best technical team in the southern Delaware, and so the results aren’t particularly surprising to me. Sean, you can chine in if you want to add anything to that..

Thanks Mark. I’d really just concur with what you're saying there. We have been striving to land our wells properly, keep them in zone for a longer period of time within a tighter window, and then obviously our completions, we continue to push in a way where we can there.

There wasn’t anything magical on these particular wells except for small incremental changes that we continue to do to try to increase, as Mark said our efficacy and efficiency of our completions. And obviously the well results are bearing out.

I think we continue to see some improvement in certain areas both from the completion side and then obviously from the production side as well..

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

Mark, previously, I think you were fairly flexible about adjusting your activity levels with basis blowouts that might get your netbacks to below 50, somewhere around there.

And understanding we are not there, is it fair to say now that that is completely off the table considering these new flow assurance agreements?.

No, Subash. We are watching the basis differently, actually, I mean the BP agreement that we signed, the gas FT agreements that we've executed allow us flow assurance. They don’t protect us -- particularly oil agreement doesn't protect us against the basis blowout differential.

So what I would tell you about our target marching toward 65,000 barrels of oil a day and what may happen during 2019 or really in the second half of 2018, or the last few months of 2018, is if the oil basis just goes crazy, we will consider slowing down our completion activity.

And if you will temporarily hunting on our oil volume growth goals, now I’m not going to give you a specific number as to what the resulting netback is, you throughout the number of $50, that number is somewhere in the ballpark. But if the basis just goes crazy, we are not going to just chase the volumes regardless of what our basis netback is.

And in that circumstance, we can always purchase volumes to meet our FT commitments purchase third-party volumes. So we are not considering it. We have to grow volumes to meet these FT commitments at all. Does that give you a….

And then operationally, I guess in the 3rd Bone -- anything to read, your first 3rd Bone well was unbounded at a spectacular rate, this one was, obviously, in the pad design and co-develop lower rate.

But are you happy with that result in the spacing or what conclusion should we draw on the spacing vertically in-house and across?.

Yes, working in three dimensions here. First on the 3rd Bone's basing that we're anticipating -- the 3rd Bone Sand is more of a sand than a shale. So it is a plastic, if you will and so the spacing that we're anticipating is roughly 160 acre spacing.

So four wells per section is what we’re anticipating because it is not really a shale, it's more of a sand. So it's that the 164 wells per section is what we're kind of looking at for that on there. In terms of the well quality, you are right the first well the Weaver well was just -- it just was off of the charts.

I mean, in terms of what kind of well that turned out to be -- much better than the high side case that we had. This second well was a very strong well, but not as quite as strong as Weaver.

And there's a possibility that it's because we paired it with the Wolfcamp Upper A, but our development program is that we would -- we would end up tuning the wells as a development program with the 3rd Bone and Upper A.

So what I would tell you is that once we press released here are more likely what we would expect in an ongoing development program than the Weaver well. Weaver well maybe kind of an unbounded well.

And I would I would say for, if you are trying to model stuff for us will be go into a development program and use these wells that we just press released is something that would be a more accurate template than Weaver as we see it at this juncture..

Our next question comes from the line of Scott Hanold from RBC Capital Markets. Your line is open..

Could you talk about your strategy on looking to sign-up additional oil firm, you obviously said that your goal was to get pretty much all that lockup over the next several years.

Strategically can you discuss using firm sales versus going out and locking up FT on a pipeline?.

Yes, I can discuss it conceptually, number one, we are in very advanced negotiations with other entities, and the other entities are very, very big entities. So the transactions that we are contemplating are with major, major entities. So we’re not talking about doing deals with small oil marketers. They are big companies.

The transactions -- at the end of the day, our goal is to have transactions done that would allow us access for firm transportation to utilize other companies, these large entities, existing firm transportation agreements for the next four or five years.

The term of these would be generally between four to six years, so they are not 10-year deals; they are four to six-year deals.

And the ultimate pricing when you look over the all the terms of all the deals that were contemplating would be some mix of Brent and Midland base pricing, so that we end up with kind of a portfolio of pricing over the next four to six years.

So we’re not tied to 100% to Brent, we’re not tied to 100% to Gulf Coast, we're not tied 100% to Midland base pricing. So and we’re well on our way to getting this done and would expect in the next 60 days plus or minus to have this accomplished for essentially all of our volumes.

And let’s say, we're not going to view any specifics on either the BP contracts, and specific contract terms, or on these other ones, because as you can appreciate, right now we're in the middle of negotiations on some of these other contracts..

I appreciate that color. And just to clarify from understand, and so part of the strategy, do you use other people's FTs as your ability to get shorter duration versus locking-in longer term and giving you better flexibility over the end pricing.

Is that sort of a fair summary?.

Yes, at the end of the day, we don't know over the next four or five years is what would be more advantageous to be to have a Brent index or Midland index or Gulf Coast index, and what we're going to end up with is a portion price off of all those indices.

So at any given time we'll be partially right and partially wrong on which index is the optimal index, but hopefully the portfolio approach will give us a decent average overtime..

And then my follow-up question, you gave a little bit of color on the oil mix and I think you’re now targeting around upper 50s due to higher ethane recoveries kind of boosting your NGL volumes.

But could you also discuss if -- as you look in 2Q and then into 3Q, is there a mix shift in some of the wells you’re drilling, for example, less Miramar wells versus more the kind of the legacy Centennial stuff that's going to help that oil cut move from where it was in 2Q to something in the upper 50s?.

Sean, do you want to fill that question..

As we kind of stated in last quarter, I think our oil mix last quarter was 58% is what we said for the quarter, and this quarter you can see it's obviously affected by the ethane recovery. But what we have guided to and still expect to do is to shift a bit more towards our legacy position and just kind of how the scheduling has falling out.

Thus our percent oil will increase a bit towards the back half of 2018..

Through upgrade?.

Yes, I will say Scott. I mean that -- so the percent oil would increase, if we weren’t in this ethane recovery. But what you’re going to see at the end of the day is it's highly likely that we’re going to be in ethane recovery for the third and fourth quarters.

So you're going to see the mix with the whole bunch of NGLs, kind of like the second quarter, just to be clear..

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

Perhaps for you Mark, one of your large cap peers recently noted 440 such basing for the Wolfcamp for fulfill development, understanding that your inventory assumptions are based on 880 spacing for the upper and lower Wolfcamp A, and 1,320 for the Bone Spring Sand interval.

And I would note that we've seen considerable industry pellets at 660 interval spacing for the Wolfcamp.

What is your current view on optimal fulfill development for the Southern Delaware speaking to both spacing and co-development assumptions?.

Yes, you’re putting me in a bit of a tough situation now Derrick, I am aware there. What I would say in relation to Centennial is the -- our inventory is predicated on 880 foot spacing for the various Wolfcamp intervals whether it’s A the B the C.

And as you said for the 3rd Bone Spring Sand since that’s a bit more of a classic than a shale, it is the 1,320s. And so that's where we continue to be. We are doing a few spacing tests on slightly closer spacing, but nothing approaching 440s.

So at this juncture, I would just say that we're pretty happy with our spacing of the 880s, and I just won’t comment on the 440s..

Fair response Mark, I thought it would be worse discussion.

And then perhaps for Sean, regarding the ninja pad at Miramar, were there any noticeable differences in oil yields between the sea and the upper intervals?.

No. I would say the only difference that we’re seeing really between those different intervals is as you drill a little bit deeper you tend to get a bit more water. So we have a -- another 5% or so water cut increase as we drill the deeper interval. So that's the main difference we see between the A to B and the C..

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

My question is to do with sort of ethane recovery. So we’re increasingly seeing that over a number of companies. So kind of any worry on kind of capacity getting sold up or do you have alternative transportation.

And parallel to do this, could we end up with too much ethane flooding the market and depressing ethane price at some level?.

Sean?.

Sure. I’ll take a shot at that, Irene. Thanks for the color on the question. Obviously, this is our first quarter in ethane recovery, and I think the industry in general is going to star to start to shift more and more that because of residue gas prices where they are, and ethane prices where they are to date.

For us, it's obviously it’s a nice economic boost to us. I think our numbers were approximately $860,000 of increased revenue that we got by being an ethane recovery this quarter over just in a normal ethane rejection. So that was a good move by the gas plant that we work with, the EagleClaw gas plant.

So I’m glad that they did that from an economic perspective. As opposed to, on the topic of moving the NGLs, at the tail gate of that EagleClaw facility, we have got a direct line to the Lone Star and then Mont Belvieu NGL processing facility. So I think we are in a good position to move all of our NGLs down line.

We don’t have any issue or don’t see any foreseeable issues on that line or going into Mont Belvieu for the foreseeable future. We do expect to be in ethane recovery mode for the remainder of this year and then even probably throughout 2019 or at least that’s what we are planning on from a corporate level.

So as to the industry, in general I can't speak to them, but I think we are, Centennial is going to be very good position because our NGLs are on play..

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

Mark, thanks for the updated thoughts on natural gas egress. I just wanted to come back to the oil situation in Midland. Any thoughts on what you're seeing in terms of Midland dips peaking? And more importantly your thoughts on operator behavior with CapEx, generally inching up, U.S.

production keeps chugging along are you surprised?.

Well, let me talk about total U.S. production. It just taking it to the macro scale -- at the beginning of the year, I had predicted that total U.S. production this year was going to grow about 950,000 barrels a day year-over-year. I have had to revise that estimate; I now believe it's going to grow about 1.1 million barrels a day year-over-year.

Interesting to me is we have seen the Gulf of Mexico rollover. It had been growing about 70,000 barrels a day year-over-year over the last two to three years. And this year it looks like it's going to -- they have the first year of annual year-over-year declines for, probably the last four five years.

So we are finally seeing the effects of lack drilling in the Gulf of Mexico. And I think the Gulf of Mexico will be on a year-over-year decline for the next three or four years consecutively now.

The other thing, I think an overall trend that I have observed is we're seeing four five companies at least on this earnings cycle that are reallocating CapEx out of the Permian into EagleFord or Bakken or anywhere else, if they're a multi-basin company on there.

And I also expect that some of the private equity Permian companies are likely scaling back or will scale back in second half of the year although you don’t get public announcements from them.

So I think the impact will be that the Permian growth that maybe was predicted earlier in the year will end up being less, just due to not as much capital being channeled into the Permian. I don't know what to expect on how is that differential going to play out over the next 6 to 12 months in terms of the basis.

So you know the basis was, for July, was $8 or $9, and now I believe for August, it's roughly $12 or $13. And so, what I can tell you is Centennial is remaining kind of fluid in our plans. Our plans are to grow production as we projected for the next three or four months through the end of this year.

But if the basis goes crazy, we will probably react to it by keeping our drilling activity, but cutting back on a completion activity, and growing docks. And I think other big players in the industry will do that, if the basis just goes crazy. So the whole thing has been a bit of unknown to me.

It's cracked-up on the industry as a surprise, and it's been a kind of a very clouded issue is to what is exactly the situation. So I wish I could give you more specifics is to where they are going to go over the next 6 to 12 months, but I can't. It does appear that the issue will go away by the fourth quarter of 2019. That appears pretty clear to me.

So that's a best explanation I can give..

I have a quick one for George. George, the CapEx range -- our guidance range for 2018 is still relatively wide and light of kind of lower first half run rate.

Should we expect the CapEx ultimately to be at the low end of the range? And if not, what would make it to go at the higher end of the range?.

Thanks. I think the first thing to say is the lower CapEx that we saw in Q2, was really driven by lower working interest wells. And it was just the function of the drill schedule that we have some pads that have lower working interest and that depressed that number for Q2.

The operations team in the field is also doing a terrific job and trying to keep a lid on costs of driving efficiencies. So they're doing a terrific job. But I think, as we look at the range for the year, we obviously have not changed it. What we see in the second half of the year is drilling pads that are higher working interest and what we saw in Q2.

We had already anticipated this decline in terms of lower working interest for the quarter. But I think given some field inflation and things we're seeing out there, we felt comfortable with the ranges we've provided and we're seeing inflation cost on steel, wireline, coil tubing that will impact the second half of the year.

And that's offset by a pretty good pressure pumping market and in basin sand contracts. The other thing I would note on the lower working interest percentage is that did have a contributory effect on our production for the quarter in terms of being flat.

The big drivers as I pointed out were the completion timing in the cadence towards the back half of the quarter as well as frac shut-ins, but I think the working interest also had an impact there as well..

Our next question comes from the line of Brian Corales from Johnson Rice. Your line is now open..

Back to oil macro side, the extended differential is that a sign of the price now for coming out of the Permian on the oil side?.

Well, Brian, I will give you an answer, but it's kind of just as a second and third-hand answer. And this is just what we've distilled from talking with various marketers, and mainly it’s the markets that we’re negotiating these oil contracts with.

And will say that the two months ago they told us that there was maybe 300,000 barrels a day of surplus capacity on the lines. And even -- so two months ago, even when the differential was $8 to $9, there was still surplus capacity. What they're telling is today is that there's pretty much very, very small surplus capacity.

So if we believe what they seem to be telling us, it's that as of today the lines are approaching being completely full, but that -- over the past five or six months, when these differential started blowing out, they blew out when the lines were really not full. So it's kind of a surprising situation.

So trying to project from this point forward what's going to happen is with differentials is a bit problematic. That’s the best answer I can give you. But that is a second and third hand answer. We that's the best info we have..

That's helpful. Thank you. And just one -- I know you talked about the lower working interest on the CapEx side, but operating costs were lower almost across the board.

Are you all seeing much inflation? And can you maybe just comment about the service environment that you're seeing today?.

Yes Sean..

Sure. Brian, thanks for the question. We have seen some cost pressures in certain areas, obviously steel costs are up, rig rates are up because that market is a little bit tighter, and certain parts of the service industry are definitely seeing pressure, and therefore we are seeing some inflation across the board.

We see some softness in the market from pressure pumping perspective. And so some of that gets offset by that, but overall prices are our little higher. I'll have you note that we did book in our model and in our CapEx structure and expense structure that we assumed a 10% increase year-over-year in inflation and service costs.

So I think we're seeing that, but I think we’re also doing a decent job of mitigating that through efficiencies in the field..

Our next question comes from the line of Dan McSpirit from BMO Capital Markets. Your line is now open..

For what length of time do you need to see bases differentials go crazy as you put it -- that would move, I guess, move you to take your foot off the accelerator?.

What level of craziness would ….

Yes, what level and for what length of time?.

I don’t want to give specifics, Dan, on what level, but obviously if the differentials got $20 to $30, I think, then it would be a no-brainer decision for us on there. So, and in the timeframe, I think we know pretty much for sure that by the fourth quarter of '19, there’s going to be additional pipe capacity.

And if you just look at the future strip that the future is indicating that the differential goes back to three or four bucks by then. So I think the timeframe we’re looking at is maybe a maximum of 12 months period in there. So we’re just going to play at almost month-to-month here and take a look at it. That’s best answer I can give you.

But I would just tell you that we’ll just make a rational economic decision here, and we’re not going to just blindly say that our volume goals are going to be a number one priority, they're not, economic goals are the number one priority, not the volume goals..

And as a follow-up, I’ll avoid asking directly what you paid for the oil take away maybe instead ask what the going rate is in today’s market?.

I would just say, a deal that we didn’t pay anything for the old takeaway. It was just a mutual agreement what BP got was basically to capture our oil for the next five or six years and what we got was a fair price.

So it wasn’t that they extracted some premium they basically were able to capture our oil and know that our oil is going to show up during that period. And what we got was, I believe, a fair and reasonable price. So that’s the way I would presented them..

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

Mark question for you, as I am just looking at the slide for just selling some of those excellent multi-well pads you had. My question is like, relative to Ninja, were you able to bring in four wells there into that pad with some, obviously with that three different formations.

Do you anticipate now with the success you’ve had with the 3rd Bone been able to incorporate that into something similar?.

Sean?.

Yes, I think we’re, obviously we’re maturing as a company and we’re getting more and more into this co-development world. I mentioned in my portion of the discussion that we like to get into more of a manufacturing mode starting really in 2019, so we’re experimenting a bit with different formations and spacing and what not.

I think that you’ll see more and more of that from us. We will do more co-development of various different horizons depending on the area of that particular pad location, maybe 3rd Bone Upper A or maybe Upper A, B, C. And so we’ll continue to do a combination of that. But I think that that does make sense to do a fair amount of co-development..

And then just lastly Mark, just on bolt-ons or M&A, are you seeing more privates approaching you, I mean, obviously you guys being one of the better well-known operators, obviously, in the pure plays as you continue to stay, just wondering if you’re getting approached more often these days?.

I would say, no, we’re not getting approached more often. I mean there’s a modest and continuous kind of flow of deal opportunities, but I don’t think it’s increased -- haven’t increased or decreased over the last six months.

So we're still -- our preference is to do relatively modest sized tactical deals as opposed to large M&As kind of like the one energy deal that we did earlier this year. And that's what we're constantly looking for and hopefully we will be able to consummate one or two similar deals over the next 6 to 12 months. So that's our target size range..

Next question from the line of Gail Nicholson from KLR Group. Your line is open..

You guys have done a phenomenal job with efficiencies.

If we use kind of that base ball analogy what inning do you think you are in your efficiency gains? How much more improvement do you think you will have? And kind of, I guess, what's the incremental low-hanging-fruit that you can go attack?.

Well, in terms of well completion efficiencies, I would say, I continue to believe that the industry is in probably the seventh inning of well completion efficiencies.

And then what I mean by that is, I just don’t think that there is going to be any hydraulic fracture improvements or other well completion efficiencies where companies or the industry over the next two three years are going to say, wow.

The well completions we had in 2018 compared to 2021, we are getting twice as good of wells in 2021 or even 50% better wells in 2021 that we weren't getting in 2018. I think now we are into just incremental improvements and not things that are revolutionary improvements in the shale world.

And I think where we are with Centennial is, I believe that we've positioned ourselves in -- frankly in the Permian Basin to be one of the top tier companies in terms of well efficiencies of completions. So I would expect our completion efficiency up with one of the top two or three best companies in the industry, in the Permian basin.

But I'm not projecting that two to three years from now, we are going to be able to say that we're -- our wells are 30% or 40% better than they were two three years previously. So that's why I think we are there.

In terms of the cost efficiencies and what I think is going to be a gently rising oil price environment, I think it's going to tough for the industry to just hold their ground in terms of unit costs. And I’m just hoping that Centennial can keep itself positioned in the lower quartile of unit costs over the next two or three years.

And I think we have kind of exhibited that in this quarter and really for the full year. But I am not going to predict that we are going to have dramatically lower unit costs across the board in 2019 versus 2018, except for G&A, where we can drive that down just from volume growth.

So hopefully that gives you kind of my view on efficiencies and cost efficiencies..

Do you still think from a standpoint like the drilling side those incremental days that can be picked up?.

I think there is some advantage on drilling efficiency. But I'm not one that says that everybody is going to be able to drill their wells 20% faster in two or three years from now. I think there will be some efficiencies that I would say there will be relatively small..

Thank you. I will now hand the call back to Mr. Papa for the final remarks..

Okay. Thank you very much for taking the time. We chewed up an hour here on the fairly good questions. And we look forward to talking to you again three months from now..

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect..