Permian Resources Corp

NYSE:PR

Earnings Call Transcript 2018-Q2

[Operator]

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 21, 2018, by dialing [phone] and entering the conference ID number, 781-8579, or by visiting Centennial's website at www.cdevinc.com.

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

[Hays Mabry, executive]

Thanks, 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'd like to note that many of the comments during this earnings call are forward-looking statements that involve risks and uncertainties that could affect our actual results and plans. Many of these risks are beyond our control and are discussed in more detail in the Risk Factors and the Forward-looking Statement section of our filing 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 guarantees of future performance, and actual results or developments may differ materially. We may also refer to non-GAAP financial measures that help facilitate comparisons across periods and with our peers. For any non-GAAP measures we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release available on our website.

With that, I'll turn the call over to Mark Papa, Chairman and CEO.

[Mark Papa, executive]

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 on the quarter as well as give an overview of our new Midstream agreements. And then I'll 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.

[George Glyphis, executive]

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 our 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 in 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 mix to end the year in the high 50% area.

I want to underscore the point that this mix change was entirely due to 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 (sic) [$61.37] barrel in Q1 as higher NYMEX prices in Q2 were offset by a higher differential.

Inclusive of the impact of our basis hedges, our realized price for the quarter was 92% of NYMEX. Turning to the cost side, unit cost for the quarter continue to highlight our field efficiencies. LOE came in at $3.66 per BOE, which was slightly below the low end of our original guidance range despite rising 10% quarter-over-quarter due to higher cost associated with contract labor and equipment rentals.

GP&T expense was $2.92 per BOE, a 3% increase quarter-over-quarter. Cash G&A declined from $2.13 per BOE in Q1 to $1.84 as a result of lower legal and professional fees. DD&A cost were $14.32 per BOE, which was up from $13.57 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 (sic) [ $161 ] 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 completion CapEx and facility CapEx.

D&C CapEx was $163 million, down 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 needs 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 -- 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 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 a Mid/Cush differential of $2.38 per barrel. We also 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 seniors unsecured notes and $30 million of borrowings under the 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.

[Sean Smith, executive]

Thank you, George. During the second quarter, we made significant progress towards our goal of operating in 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 1 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 denying the enhanced economic returns that come from our current program, 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 back-end weighted 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 9H Bone Spring test had an IP30 of 1,578 barrels of oil equivalent per day, with 72% oil; and the Wolfcamp (sic) [Red Rock] 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 codeveloping 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 pricey M&A.

We plan to drill additional 3rd Bone Spring Sand tests 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 49H 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, respectively.

Combined, the pad produced over 200,000 barrels of oil during its first 40 days online. The 3-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 4-well pad in our Miramar Area, containing 2 Upper As, 1 Lower A, and a Wolfcamp C. With average lateral lengths of approximately 9,800 feet, these 4 wells delivered an IP30 of approximately 1,900 barrels of oil equivalent per day, 58% oil. During its first 60 days online, the 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 has 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 takeaway 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 the 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 and 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 result, we do not envision a scenario whereby Centennial will be required to flare or shut-in production during the time period when we anticipate Permian Basin WAHA production will significantly exceed available takeaway capacity.

In turn, these agreements will also allow us to recognize the economic value of both natural gas and NGLs, 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 of oil per day, increasing to 30,000 barrels of oil per day in 2020 and for the remainder of the agreement.

By utilizing the buyer's existing FT, this agreement will provide Centennial with firm physical takeaway capacity out of the Permian Basin. The agreement will initially be based off Midland pricing and switched 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 of 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-grade crudes.

With Gulf Coast refiners reaching a maximum capacity of higher gravity, shale oil that can be blended into feedstocks, we expect that 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 disclosure will prove advantageous for Centennial longer-term. While this recently executed contract secures flow assurance for a large portion of Centennial's 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 will turn the call back to Mark.

[Mark Papa, executive]

Thanks, Sean. Now I'll provide some thoughts regarding the oil macro picture and relate them to 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 theme, supply concerns, is similar, but the focus of those concerns has shifted from U.S. shales to Venezuela and Iran.

Regardless, CDEV's response is consistent. We'll continue to remain unhedged regarding oil. We have employed some tactical oil basis hedges for the next 18 months, but it's unlikely we'll 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 6 key points: first, within a few months, we expect to be one of the few Permian midcaps to have both oil and gas exit transportation for all their volumes locked down for the next several years.

Second, we 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, we're oil unhedged, and have 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'll go to Q&A.

[Operator]

[Operator Instructions] Your first question comes from the line of Michael Glick from JPMorgan.

[Michael Glick, analyst]

You talked about this quite a bit, but I was wondering if you could give us more thoughts on the gas situation in Delaware. What's your view about how things play out at a basin level when we bump into capacity? And would you expect to see something similar to the DJ where older lower pressure wells get knocked off first?

[Mark Papa, executive]

Yes, Michael. Yes. Our read is that indeed likely beginning in early 2019, there is 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 has 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's corresponding oil shut-ins, which might mitigate it. But I would say there's 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 probably is a 1-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, in that they have likely secured the gas FT. So you can probably tell from the earnings call announcements on who has announced that they have gas FT and who has not as to where the discrimination will be. And we've been pursuing this gas FT for about 6 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 4, 5 months, the problem will be upon pretty much the whole Permian Basin.

[Michael Glick, analyst]

Got you. And then if I can just ask one on ops. That CWI pad, obviously one of the strongest pads we've seen in the Delaware to date. I mean, what do you think is driving the magnitude of the outperformance in those wells?

[Mark Papa, executive]

Yes. I would just make an overarching statement, and then I'll ask Sean to contribute there. I think if you look at Centennial's Reeves County well completions in the last 12 months, I believe we likely have perhaps the best or one of the top 2 or 3 most effective well completions in -- really in -- of any company in the entire Southern Delaware Basin. And we've seen several analyses where some sell 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've 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. So the results aren't particularly surprising to me. Sean, you can chime in if you want to add anything to that.

[Sean Smith, executive]

Thanks, Mark. I just really just concur with what you're saying there. We've been striving to land our wells properly, keep them in zone for longer periods of time within a tighter window. And then obviously, our completions we continue to push and innovate 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.

[Operator]

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

[Subash Chandra, analyst]

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're not there, is it fair to say now that, that is completely off the table considering these new flow assurance agreements?

[Mark Papa, executive]

No, Subash. We are watching the basis differentials. I mean, the BP agreement that was signed, the gas FT agreements that we've executed allow us flow assurance. They don't protect us, particularly the oil agreement, doesn't protect us against a basis blowout differential. So what I would tell you about our target, marching towards 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 pumping 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 threw out a number of $50. That number is somewhere in the ballpark. But -- if the basis just goes crazy, we're not going to just chase the volumes regardless of what our basis netback is. And in that circumstance, we will -- we can always purchase volumes to meet our FT commitments, purchase third-party volumes. So we're not considering it. We have to grow volumes to meet these FT commitments at all. Did that give you a pretty good...

[Subash Chandra, analyst]

Yes. Yes. It sure does. Yes. And then operationally, I guess, in the 3rd Bone, anything to read? Your 1st Bone -- 1st Bone well was unbounded and at spectacular rate. This one was obviously in a pad design and codeveloped, lower rate, but are you happy with that result in the spacing? Or what conclusion should we draw on the spacing vertically and across?

[Mark Papa, executive]

Yes. Working in 3 dimensions here. First, on the 3rd Bone spacing that we're anticipating, the 3rd Bone Sand is more of a sand than a shale. So it is a clastic if you will. And so the spacing that we're anticipating is roughly 160-acre spacing. So 4 wells per section is what we're anticipating, because it is not really a shale, it's more of a sand. So that's the -- 164 wells per section is what we're kind of looking at for that on there. In terms of the well quality, you're right, the first well, the Weaver well, was just a just -- it just was off the charts. I mean, in terms of what kind of well that turned out to be. It was much better than the high side case that we had. The second well was a very strong well, but not quite as strong as the 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 end up twinning the wells as a development program with the 3rd Bone and the Upper A. So what I would tell you is, that the ones we press released here are more likely what we would expect in an ongoing development program than the Weaver well. Weaver well may be kind of an unbounded well. And I would say, if you're trying to model stuff for us, we'll be going into a development program and use these wells that we just press released as something that would be a more accurate template than Weaver as we see it at this juncture.

[Operator]

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

[Scott Hanold, analyst]

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 locked up over the next several years. Strategically, can you discuss using firm sales versus going out and locking up FT on the pipeline?

[Mark Papa, executive]

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're 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 4 or 5 years. The term of these would be generally between 4 to 6 years. So they're not 10-year deals. They're 4- to 6-year deals. And the ultimate pricing, when you look over all the terms of all the deals that we're contemplating would be some mix of Brent and Midland-based pricing, so that we end up with kind of a portfolio of pricing over the next 4 to 6 years. So we're not tied 100% to Brent. We're not tied 100% to Gulf Coast. We're not tied 100% to Midland-based pricing. 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 oil volumes. Then let's say, we're not going to give you any specifics on either the BP contract and specific contract terms or on these other ones because as you can appreciate, I hope, right now, we're in the middle of negotiations on some of the other contracts.

[Scott Hanold, analyst]

No. I appreciate that color. And just to clarify for my understanding then, so part of the strategy to use other people's FT is 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?

[Mark Papa, executive]

Yes. At the end of the day, we don't know over the next 4, 5 years is -- would it be more advantageous to be -- to have a Brent index or a Midland index or a Gulf Coast index. And what we're going to end up with is a portion priced off of all those indices. And 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 over time.

[Scott Hanold, analyst]

Okay. Understood. Great. And my follow-up question. You gave a little bit of color on the oil mix, and I think you now are 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 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.

[Mark Papa, executive]

Sean, do you want to field that question?

[Sean Smith, executive]

You bet. As we kind of stated last quarter, I think our oil mix last quarter was 58% was 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, it's just kind of how the well scheduling has fallen out. Thus, our percent oil will increase a bit towards the back half of 2018.

[Mark Papa, executive]

Yes. I'll say, Scott, I mean -- 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 quarter. So you're going to see the mix with a whole bunch of NGLs, kind of like the second quarter, just to be clear.

[Operator]

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

[Derrick Whitfield, analyst]

Congrats on a strong operational update. Perhaps for you, Mark, one of your large-cap peers recently noted 440-foot spacing for the Wolfcamp for full field 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 pallets at 660 interval spacing for the Wolfcamp, what is your current view on optimal full field development for the Southern Delaware, speaking to both spacing and co-development assumptions?

[Mark Papa, executive]

Yes. You put me in a bit of a tough situation there, Derrick. I'm aware there. What I would say in relation to Centennial is, our inventory is predicated on 880-foot spacing for the various Wolfcamp intervals, whether it's the A, the B, the C. And as you said, for the 3rd Bone Spring Sand, that's a bit more of a clastic 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.

[Derrick Whitfield, analyst]

Fair response, Mark. I thought it would be worth the discussion. And then perhaps for Sean, regarding the Ninja pad at Miramar, were there any noticeable differences in oil yields between the C and the upper intervals?

[Sean Smith, executive]

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 another 5%-or-so water cut increase as we drill the deeper intervals. So that's the main difference between -- you see between the A, the B and the C.

[Operator]

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

[Irene Haas, analyst]

My question has 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 filled up? Or do you have alternative transportation? And then parallel to this, could we end up with too much ethane flooding the market and depressing ethane price at some level?

[Mark Papa, executive]

Sean?

[Sean Smith, executive]

Sure. I'll take a shot at that, Irene. Thanks for the call and the question. Obviously, yes, this is our first quarter in ethane recovery, and I think the industry in general is going to start to shift to more and more of 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 in ethane recovery this quarter over just in normal ethane rejection mode. 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 tailgate of that EagleClaw facility, we've got a direct line to the Lone Star and in Mont Belvieu NGL processing facilities. So I think we are in a good position to move all of our NGLs downline. 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 even probably throughout 2019, or at least that's what we're 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 in a very good position because our NGLs are on point.

[Operator]

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

[Asit Sen, analyst]

Mark, thanks for the updated thoughts on natural gas egress. Just wanted to come back to the oil situation in Midland. Any thoughts on what are you seeing in terms of Midland diffs peaking? And more importantly, your thoughts on operator behavior with CapEx, generally inching up. U.S. production keeps chugging along. Are you surprised?

[Mark Papa, executive]

Well, let me talk about total U.S. production, 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've 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've seen the Gulf of Mexico rollover. It had been growing about 70,000 barrels a day year-over-year the last 2 or 3 years. And this year, it looks like it's going to -- we have the first year of annual year-over-year declines for probably the last 4 or 5 years. So we're finally seeing the effects of the lack of drilling in the Gulf of Mexico. And I think the Gulf of Mexico will be on a year-over-year decline for the next 3 or 4 years consecutively now. The other thing, I think an overall trend that I've observed is, we're seeing 4 or 5 companies at least on this earnings cycle that are reallocating CapEx out of the Permian into Eagle Ford 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 may be 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 the basis was -- for July was $8 or $9. And now we 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 3 or 4 months through the end of this year. But if the basis goes crazy, we'll probably react to it by keeping our drilling activity, but cutting back on the completion activity and growing DUCs. 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 an unknown to me. It's crept up on the industry as a surprise. And it's been kind of a very clouded issue as to what is exactly the situation. So I wish I could give you more specifics as to where is it going to go over the next 6 to 12 months, but I can't. It does appear that it's -- the issue will go away by the fourth quarter of 2019. That appears pretty clear to me. So that's the best explanation I can give.

[Asit Sen, analyst]

That's very helpful, Mark. I appreciate the color. I have a quick one for George. George, the CapEx range for -- or guidance range for 2018 is still relatively wide in 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?

[George Glyphis, executive]

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 a function of the drill schedule that we had some pads that had 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 and 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 than 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 had provided. And we're seeing inflation cost on steel, wire line, 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'd note on the lower working interest percentage is that, that did have contributory effect on our production for the quarter in terms of being flat. The big drivers, as I pointed out, were the completion timing and 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.

[Operator]

Our next question comes from the line of Brian Corales from Johnson Rice.

[Brian Corales, analyst]

Mark, back to the oil macro side. The expanding differential, is that a sign of the pipes now full coming out of the Permian on the oil side?

[Mark Papa, executive]

Yes. Well, Brian, I'll give you an answer, but it's kind of just a second or third-hand answer. We -- and this is just what we've distilled from talking with various marketers, and mainly it's the marketers that we're negotiating these oil contracts with. And I would say that 2 months ago, they told us that there was maybe 300,000 barrels a day of surplus capacity on the lines. And even -- so 2 months ago, even when the differential was $8, $9, there was still surplus capacity. What they're telling us 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 5 or 6 months, when these differentials 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 the differentials is a bit problematic. That's the best answer I can give you, but that is a second and third-hand answer. That's the best info we have.

[Brian Corales, analyst]

No. That's helpful. And just 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?

[Mark Papa, executive]

Yes. Sean?

[Sean Smith, executive]

Sure. Brian, thanks for the question. Yes. 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 a pressure pumping perspective. And so some of that gets offset by that. But overall, prices are a 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 cost. 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.

[Operator]

Our next question comes from the line of Dan McSpirit from BMO Capital Markets.

[Dan McSpirit, analyst]

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

[Mark Papa, executive]

Yes. Are you asking what level of craziness would...

[Dan McSpirit, analyst]

Yes. What level and for what length of time?

[Mark Papa, executive]

Yes. Well, I don't want to get specific, Dan, on what level, but obviously if the differentials got $20, $30, I think then it would be a no-brainer decision for us on there. So -- and in the time frame, I think we know pretty much for sure that by the fourth quarter '19, there's going to be additional pipe capacity. And if you just look at the future strip, the future's indicating the differential goes back to $3 or $4 by then. So I think the time frame we're looking at is maybe a maximum of a 12-month period in there. So we're just going to play it almost month-to-month here and take a look at it. That's the 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 just going to blindly say that our volume goals are going to be the #1 priority there. They're not. The economic goals are the #1 priority, not the volume goals.

[Dan McSpirit, analyst]

I appreciate the answer. And as a follow-up, and I'll avoid asking directly what you paid for the oil takeaway, maybe instead ask what the going rate is in today's market?

[Mark Papa, executive]

I would just say, I'd view it that we didn't pay anything for the oil takeaway. It was just a mutual agreement. What BP got was basically to capture our oil for the next 5 or 6 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 present it, Dan.

[Operator]

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

[Neal Dingmann, analyst]

Mark, question for you or Sean, looking at that Slide 4, just showing some of those excellent multi-well pads you've had. My question is like, [ relative to Ninja ], were you able to bring in 4 wells there into that pad with some -- obviously, there was that 3 different formations. Do you anticipate now with the success you've had with the 3rd Bone being able to incorporate that into something similar?

[Mark Papa, executive]

Yes. Sean?

[Sean Smith, executive]

Sure. Thanks, Neal, for that question. Yes. I think we are -- 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'd 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 whatnot. I think 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 does make sense to do a fair amount of co-development.

[Neal Dingmann, analyst]

Okay. Really sounds encouraging. 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 play as you continue to say. Just wondering if you're getting approached more often these days.

[Mark Papa, executive]

I would say no, we're not getting approached more often. I mean, there is a modest and continuous kind of flow of deal opportunities. But I don't think it's -- hadn't increased or decreased over the last 6 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 1 energy deal that we did earlier this year. And that's what we're constantly looking for. And hopefully, we'll be able to consummate 1 or 2 similar deals over the next 6 to 12 months. So that's our target size range.

[Operator]

Next question from the line of Gail Nicholson from KLR Group.

[Gail Nicholson, analyst]

You guys have done a phenomenal job with efficiencies. If we use kind of that baseball analogy, what inning do you think you are in your efficiency gains? How much more improvement do you think you have? And kind of, I guess, what's the incremental low-hanging-fruit that you can still attack?

[Mark Papa, executive]

Well, in terms of well completion efficiencies, I would say, I continue to believe that the industry is in probably the 7th 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 2 or 3 years are going to say, wow, the well completions we had in 2018 compared to 2021, we're getting twice as good of wells in 2021 or even 50% better wells in 2021 than we're getting in 2018. I think now we're 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 frankly in the Permian Basin to be one of the top tier companies in terms of well efficiencies of completions. So I would stack our completion efficiency up with one of the top 2 or 3 best companies in the industry in the Permian Basin. But I'm not projecting that 2 or 3 years from now, we're going to be able to say that we're -- our wells are 30% or 40% better than they were 2 or 3 years previously. So that's where I think we are there. In terms of the cost efficiencies in what I think is going to be a gently rising oil pricing environment, I think it's going to be tough for the industry to just hold their ground in terms of unit cost. And I'm just hoping that Centennial can keep itself positioned in the lower quartile of unit cost over the next 2 or 3 years. And I think we've kind of exhibited that in this quarter, and really for the full year. But I'm not going to predict that we're going to have dramatically lower unit cost 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.

[Gail Nicholson, analyst]

Do you still think from a standpoint of like the drilling side, there's incremental days that can be picked up?

[Mark Papa, executive]

I think there's some advantage on drilling efficiencies, but I'm not one that says that everybody is going to be able to drill their wells 20% faster in 2 or 3 years from now. I think there'll be some efficiencies, but I would say they will be relatively small.

[Operator]

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

[Mark Papa, executive]

Okay. Thank you very much for taking the time. We chewed up an hour here on the good questions. And we look forward to talking you again 3 months from now.

[Operator]

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