Good morning and welcome to Centennial Resource Development's Conference Call to discuss its Third Quarter 2017 Earnings. Today's call is being recorded. A replay of the call will be accessible until November 21, 2017, by dialing 855-859-2056 and entering the conference ID number of 96043152 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, Ali, and thank you all for joining us on the Company's third quarter 2017 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 November 6, we filed a Form 8-K with an earnings release reporting third quarter 2017 earnings results for the company and third quarter 2017 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 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, 2016 filed with the SEC on March 23, 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. And with that, I'd like to turn the call over to Mr. Mark Papa, Chairman and CEO..

Thanks, Hays. Good morning and welcome to Centennial's third quarter 2017 earnings call.

Our presentation sequence on this call will be as follows; George will first discuss our third quarter financial results, liquidity and revised 2017 guidance, Sean will then provide an operational update from the quarter, and then, I will follow with my views regarding the oil macro, our strategy as a function of the macro and closing comments.

Now, I will ask George to review our third quarter financial results..

Thank you, Mark. As you can reference on Page 9 of the earnings presentation, average oil production for the third quarter was approximately 21,100 barrels per day, a 21% increase compared to the second quarter.

Average oil equivalent production for the quarter totaled approximately 34,700 barrels per day, a 17% increase, compared to the previous quarter.

Oil production volumes for the quarter increased approximately 61% of total equivalent volumes, compared to 59% in Q2, as our third quarter completions were more heavily weighted towards lower GOR acreage, and we had a full quarter contribution from Lea County production that has a higher oil component.

Production results were in line with our expectations and resulted from approximately 13 completions during the quarter. We continued to run six rigs and shifted one rig from Reeves County to our Lea County acreage in early September. Revenues for the third quarter were approximately $112 million, compared to $91 million in the second quarter.

This 23% increase was driven primarily by higher sales volumes. Our average realized oil price, excluding the impact of commodity derivative transactions was $44.95 per barrel, compared to $44.57 in the previous quarter. Lease operating expenses including workover costs totaled $11.4 million for the third quarter or $3.06 per BOE.

This was a 16% increase on a per unit basis compared to Q2 primarily because of higher workover expense and water handling costs. Despite the quarter-over-quarter unit cost increase we are maintaining current full year LOE guidance.

Gathering, processing and transportation expenses totaled $9.9 million for the quarter or $3.11 per BOE, which compares to $2.74 for Q2. The increase resulted primarily from firm transportation payments that were initiated during the summer.

We view these FT payments as a prudent measure to ensure that our gas gets to markets, so that oil production can proceed unabated. Cash G&A of $3.12 per BOE for the third quarter was essentially flat on a sequential basis, compared to $3.08 in the second quarter. DD&A totaled $42.4 million or $13.28 per BOE compared to $12.70 in the second quarter.

This was a 4.6% increase relative to Q2, but it’s still below the low-end of our previous guidance range. Our DD&A rate continues to benefit from the results of our successful drilling program. EBITDAX totaled approximately $74 million for the quarter, compared to $63 million for Q2.

This represents an 18% increase resulting primarily from higher production volumes. GAAP net income totaled $14.4 million, compared to $20.8 million in Q2 which included a $7 million gain on sale related to a non-core acreage divestment.

Centennial incurred approximately $180 million of total capital expenditures during the quarter, of which, approximately $163 million was related to drilling and completions. As Sean will discuss in more detail, we had a number of wells come online in October, in which a majority of the associated D&C costs were realized during the third quarter.

Overall, D&C cost per well continue to be in line with our guidance issued at the start of the year. On Page 11 of the presentation, you can reference Centennial’s balance sheet items and liquidity position. At September 30, we had $165 million of debt and approximately $3 million of cash.

Our fall borrowing base redetermination which was recently finalized resulted in a $225 million increase to $575 million. Pro forma for the new borrowing base liquidity at September 30 was approximately $412 million.

Turning to guidance, which is summarized on Page 12, we are modestly raising the midpoint, oil and oil equivalent production estimates by 200 barrels per day, and 500 BOE per day respectively to reflect our latest viewing of anticipated full year results and better than expected well performance displaces our midpoint oil production guidance at 18,200 barrels per day and our total equivalent midpoint at 30,000 BOE per day.

Additionally, we are reducing the midpoint of our cost guidance range for DD&A to $14 per BOE compared to $15 previously, which is reflective of lower F&D costs. Severance and ad valorem taxes are now estimated at 6% of revenue compared to 6.5% previously.

Lease operating expense guidance is unchanged at $3.25 to $3.55 per BOE and the midpoint of cash G&A per BOE is being increased by a modest 1.5% to $3.30 compared to $3.25 previously.

Finally, as mentioned, we will continue to hold flat at six rigs for the balance of the year and are maintaining previous guidance for full year D&C CapEx in 65 to 75 wells completed, while slightly increasing our expected spud count due to drilling efficiencies gained to-date.

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

Thank you. The third quarter represented another quarter of continued execution for Centennial. We brought forward another round of solid well results in multiple intervals across both the Northern and Southern Delaware Basin. During the quarter, Centennial operated six rigs which spud 22 wells and completed 13 wells.

At the end of the third quarter, we had separate multi-well pads that were being stimulated. The three well pad and four well pad came online in early October and thus we expect to complete ten wells in October and a total of approximately 25 wells in the fourth quarter, which is in line with our full year guidance.

Extended laterals are an important driver for Centennials future. Our average lateral length for wells completed during the quarter was approximately 5800 feet and represents a 20% increase from the previous quarter. As an example, we drilled the Brooks two well pad with an effective lateral length average of 9100 feet.

These wells were spaced on 440 foot spacing in the upper and lower A with an IP-30 of 1375 barrels oil per day and 1350 barrels of oil per day respectively. This again shows the viability of two targets in the Wolfcamp A, as well as 440 foot spacing.

We will continue to pursue extend laterals and multi-well pad development as both generate significant value. Turning to our well results, we brought online a number of admirable wells during the quarter including our best well drill to-date.

The Matador 3H well was drilled with an effective lateral length of 4300 feet and achieved an IP-30 of 2150 BOE per day, consisting of 74% oil. On a per thousand foot basis, this equates to 375 barrels of oil per day. Additionally, this well produced over 100,000 barrels of oil during its first 90 days online.

As you can see on Slide 5, the Matador well is more productive than our previously released record wells the Russell 6H and Stephens 2H. Additionally, the C.H. Knight 6H reported a IP-30 of 1620 barrels of oil equivalent per day, consisting of 73% oil and had a lateral length of approximately 4400 feet.

This well achieved 271 barrels of oil per day on a per thousand foot lateral basis and has cumulative production of over 80,000 barrels of oil in its first 90 days online.

In September, we moved one of our six operated rigs from Reeves County, Texas to our recently acquired acreage in New Mexico and look forward to results from this development in the fourth quarter. We did complete one well in New Mexico that was drilled by the predecessor operator.

The Romeo 1H targeted the second Bone Spring Sand and had an effective lateral length of approximately 4200 feet and an IP-30 of 1300 BOE per day with 84% oil.

We expect to continue to operate one rig in this area throughout 2018 and look forward to completing wells in several proven – in several different proven zones throughout this acreage position. During the third quarter, we also began drilling our first Reeves County Bone Spring well, targeting the third Bone Spring Carbonate interval.

As previously discussed, we expect to have production results during our fourth quarter call. As you can see on Slide 8, we recently entered into a long-term proppant supply agreement with a local sand mine. The mine operator will provide Centennial with high quality in-basin proppant over the next several years.

We have entered into a contract that will supply approximately half of our expected proppant needs over the next three years. In-basin sand sourcing will provide significant savings of 5% to 10% of the total well cost. Along with the cost savings, we are having optionality on sand supply reduces the risk of any potential sand disruption.

Our completions team has done significant due diligence to ensure that the size and crush strength is sufficient to effectively stimulate the reservoirs. The proppant efficacy was evidenced by the ED2 well pad. These 440 foot stack staggered wells target at the Wolfcamp upper A and lower A intervals.

They had an average effective lateral length of 6800 feet and an average IP-30 of 2040 barrels of oil equivalent 58% oil. We are pleased with these results as they are in line with our offset production while realizing significant cost savings.

With continued success, we expect to utilize in-basin sand on approximately half of our operated wells in 2018. In addition to our enhanced completion design, we continue to focus on lateral placement.

Year-to-date, Centennial’s in-house geo-steering department has steered approximately 60 wells and has remained in our 30 foot target window of approximately 95% of the total lateral length. Not only are we staying in a target interval, but we continue to realize drilling efficiencies.

During the third quarter, we drilled our record well in 12.6 days, spud to total depth. This was a single mile lateral. Turning to Slide 7, we show continued success with our latest completion techniques and I believe we are entering the later stages in terms of stimulation optimization. Centennial has come a long way in a relatively short timeframe.

During the quarter, we averaged approximately 2500 pounds of proppant for lateral foot and 15 clusters first stage. This represents an approximate 30% increase in proppant per foot and 70% increase in clusters per stage over our vintage completion design used during the end of the last year.

We will continue to refine our design depending on area and reservoir in order to maximize the return on our investment. As many of you have heard Mark say in previous calls, our goal is to become the best mid-cap E&P with regards to geosciences and well stimulation.

We believe that over the long-term, the best technical team will recover the most hydrocarbons per lateral foot. On the left-hand side of Slide 7, you can see that our team has already accomplished year-over-year productivity increases.

Overall, the improved completion design, target identification and accurate drilling has helped to drive higher and more consistent results, and as part of the reason, we are raising our annual production guidance for the second consecutive quarter.

I would be remised if I did not give credit to our field staff and logistics and marketing teams for navigating any potential production disruptions due to Hurricane Harvey. Due to their rigorous effort in planning, we saw no material impact to our production during the events. With that, I will turn the call back over to Mark..

first, we are remaining unhedged regarding oil, we may hedge some gas and may add to our gas FT commitments to ensure that our products move out of the Permian Basin, but we like the supply and demand picture on oil and with our low debt see no reason to hedge oil.

Second, we will continue on a path towards 60,000 barrels of oil a day in 2020, which is a highest four year oil growth CAGR of any E&P. And third, we will look for tactical means to cautiously term up service company agreements. In closing, there are four things we like you take away from this call.

First, we began to increase our 2017 production target, albeit slightly this time without increasing CapEx. Second, we began to reduce our full year 2017 DD&A estimate. This represents the financial effect of the top quality technical team we now have in place as exhibited by the good wells we noted in our press release and on this call.

Third, we are exhibiting a very high multi-year oil growth rate, while maintaining negligible debt with an expected year-end debt to cap below 10%. And fourth, we expect to begin to generate reasonable GAAP ROEs and ROCEs beginning at oil prices just about where WTI is today. Thanks for listening and now we’ll go to Q&A.

Ali, if you want to queue up the - that’s appreciated.

[Operator Instructions] Our first question is going to come from the line of Irene Haas with Imperial Capital..

Morning, Irene..

Irene, your line is open..

Yes, and my question is, the in-basin sand, have you tried out sort of the crushing strength.

Are you worried about it being too deep in Delaware Basin?.

Yes, Irene. Let me introduce, Dan Robinson, our completion manager. He is also on this call and let you get that answer from the horse’s mouth.

Dan, would you field that question please?.

Sure, hi, Irene. We’ve done our due diligence there and third-party testing, as well as evaluating the Wolfcamp with defits and we feel that closer strengths and crushers at thin and strengths of the proppant there is sufficient for used in the Wolfcamp..

How far into the Wolfcamp, you are trying and then A, how does it look for B & C?.

We believe it’s fine for the B & C intervals as well..

Great. Thank you very much..

Our next question will come from the line of Brian Corales with Howard Weil..

Hey, good morning guys. Mark, your original plan, the kind of five year plan, I think you are adding one or two rigs per year.

Is that still kind of hold true? Or is efficiencies maybe reduced that?.

Good morning, Brian.

Yes, if you go back a year ago, we had a - I guess, a fairly aggressive ramp up in a number of drilling rigs, by the time we got to 2019 and 2020, and it is fair to say that the drilling rig efficiencies have allowed us to project that we are going to get to 60,000 barrels a day, with less rigs than we would have projected a year ago.

So, clearly, we are drilling the wells faster than we would have projected a year ago and so we are going to get to 60,000 barrels a day with less rigs. We are not yet prepared to give you a forecast for where are going to be in 2018 on number of rigs, but it is – I’d say, reasonably certain that we will be adding rigs over the number six in 2018.

And again, it’s a general guide, if you take our production forecast for this year, and just scale it out between where we are going to be at this year and 60,000 barrels a day in 2020, it’s pretty much a straight-line forecast for the production growth.

You are not going to be just wildly off, if you just took a straight edge and just took a straight-line forecast for where we are going to be in 2018, 2019 and 2020. That would give you a pretty good estimate..

Thank you. And one more, just with oil prices moving higher, a great move on the in-basin sand, it sounds like it’s going to be a good cost saver.

What other areas are you – I guess, concerned with inflation or service tightness?.

Well, my macro view, first, a couple comments on the oil pricing. I think that, if I am right on the oil macro, what we will see next year is, less growth in U.S., total U.S. oil production than most people are expecting. And that will be a – it would cause a further upward response in WTI prices.

And, then you will see, obviously more activity in the U.S. and more demand for service companies. And I think we are going to see kind of across the board uptick in pressure – pricing pressure. And probably the last place we are going to see it in terms of availability is rigs.

So I think that the efficiency of rigs is still going to put us in a – we are not going to see a huge tightness on rigs in terms of accessibility of rigs. So, I think the pressure I guess on the E&Ps is going to be on completion related activities, pretty much everything related to completion activities is where we are going to see tightness.

And so, we are going to be focusing, primarily on those activities, although we may look at terming up some drilling rig contracts. Right now, we got really – essentially a whole lot of short-term drilling rig contracts of six months to nine months is probably our average term on our rig contracts.

So we may look at terming those up, but I think, frac crews, flow back crews, everything related to well completions is what I expect to see a lot more tightness as we get into and through 2018..

Thank you..

And our next question is going to come from the line of Jeanine Wai..

If we have some fun with excel, again as crude prices are kind of in that $60 to $65 range in 2019, and 2020, I think you’ve talked about in the past, there is some significant free cash flow if we just want Centennial’s activity to hit anything close to that 60,000 barrel a day target in 2020.

Can you talk about the sensitivity of and the optionality around that 60,000 a day targets and by 2020, you’ll have more than paid down your debt and you’ve told us in the past not to consider you a serial acquirer?.

Yes, Jeanine, yes, at this juncture, we would not intend to be a serial acquirer. So, it’s not – even in a – let’s say a constructive oil price environment, don’t look for us to be going out and adding massive amounts of acreage or doing M&As or issuing equity to do M&As.

I kind of like our position where we are today is kind of a self-contained company. So, from this point forward, the likely path for us is more internally generated growth from our own acreage. So, that’s the likely path and I would not – I am not going to 100% rule out M&A, but, I would say, that is a less likely path.

In terms of our – we will likely continue to outspend our cash flow, for the next several years, as we march towards 60,000 barrels a day and I know that scares some people. But, remember, we’ve designed this company rolling out of private equity with – we came out with negative net debt and we will exit this year with less than 10% net debt to cap.

So, we are a relatively lightly levered company and as we move forward, we would expect that we will never be in a situation where net debt-to-cap ratio exceeds the low 20% range. So, we are always going to run the company at a very little net debt-to-cap ratio as we go forward.

And probably, depending on the oil price, we will probably get to a net neutrality on cash flow CapEx in the range of 2019 as we would see it. So hopefully, that gives you some color, Jeanine..

Oh, yes. That’s really helpful. Thank you.

So, I guess, beyond that in 2020 and 2021, when we see significant free cash flow, should we be thinking about a dividend?.

I mean, if you project past that point, I mean, you could look at – we would establish likely a dividend and start considering things like buybacks.

So, again, that’s – you are getting a little bit to a speculative position because you are trying to forecast out three or four years, but that’s the direction we would look at moving at that point in time and then, one of our goals.

And this is, as oil prices have moved up recently, this is becoming more of a shorter-term goal is to start showing some GAAP ROEs and ROCEs that would not be embarrassing numbers. And the break over point for us is about a $60 WTI, when we get to $60 WTI, our GAAP ROEs and ROCEs, based on our projections are beginning to look respectable.

And so, we want to be a company that we don’t talk non-GAAP. So we’ll be dealing GAAP numbers. And so, those numbers are very important to us prospectively..

Okay, thank you for taking my questions..

Okay..

Our next question will come from the line of Jeffery Campbell with Tuohy Brothers..

Good morning and congratulations on the quarter. Mark, your first Lea County well is in the second Bone Spring Sand.

I am just wondering, is this going to continue to be the primary zone, now that Lea is attracting a rig or do you have some others in mind?.

Sean, do you want to field that, please?.

You bet. Jeff, on the first well we drill in the second Bone Spring Sand target interval that is definitely a primary producer across our entire acreage position. Although, I think we have announced before that, we’ve got first bone production on our acreage as well as several other zones in and around our acreage.

So, I think it will be a mix of First, Second, Avalon and possibly some Third and even Wolfcamp into the first part of next year. So, multiple zones in New Mexico..

Okay, good. That’s very helpful. Thank you.

I thought, I heard you mentioned higher water cost in your earlier remarks, I was just wondering is that another thing that you can sort of try to attack and improve upon similar to the way that you’ve improved your local sourcing of proppant?.

Mark, I’ll take that one, as well. So, water is certainly something we deal with on a daily basis and it is a major component of LOE and we are certainly focused on that. In New Mexico, we have yet to build out fully our infrastructure and I think, as we do that, that will help bring down our water handling costs..

Okay, all right. If I could ask one more, wanted to return to Mark’s macro commentary and I want to preface it by saying in no way trying to be argumented for – but there had been several large Bakken operators that have announced improved wells results in the quarter. That is to say, they have upwardly revised their EURs.

So, how do you think we should view those improved results in the contexts of the Bakken running low on Tier-1 locations.

If you were to think, maybe the sort of the end result of high grading or how should we look at it?.

Yes, I think, in both the Bakken and Eagle Ford, you are going to continue to hear of individual successes and individual well results by individual companies. And, in no way, shape or form am I saying that you won’t still have individual successes in the Bakken and Eagle Ford.

But I think if you look from the 30,000 foot level, at the Bakken and Eagle Ford overall, I would say that they are no longer the growth engines that they were four, five years ago.

And that, the majority of the Tier-1 quality locations have been drilled and they are just not that many to go and if you suddenly got to an oil price environment that, let’s just say, turns out to be $70 WTI, and you pump a lot of capital into the Bakken and the Eagle Ford, the resulting production growth that you are going to see from current levels in those assets, I predict is going to be disappointingly low.

But, clearly, you’ll have individual wells, from time-to-time that will be successful. So, yes, to look at it from a macro view and not from an individual well view..

Well, I think that’s fair. I thought that’s worth asking. So, I appreciate the answer..

Thanks, Jeff..

Thank you..

And our next question will come from the line of Derrick Whitfield with Stifel..

Mark, we’ve heard from industry that cycle terms are deteriorating due to overall service quality and less experienced crews.

Given the strength of your operations, could you comment on what you guys are doing to counter some of these forces?.

Yes, Sean or Dan, you guys are closer to the tranches.

Why don’t field those questions?.

Sure, I think that is certainly something we are focused on and keeping your crews happy out there getting experienced folks, getting them to the job site safely and treating them properly keeps them motivated and I think we’ve done a good job of engaging and retaining top-tier talent in the field and I think that we haven’t seen any real loss either on our rigs or on our dedicated frac crews.

So, happy with the crews and their performance and continue to see good things come from them..

Derrick, let me just add one thing to that. One of the items that may come is as companies find that volumes are disappointing is that, you can expect, I believe to hear in more future calls that the culprit is laid upon the service companies.

And you’ll hear us from that service company quality deteriorates unavailability of service company crews, you’ll hear stories about the midstream bottlenecks and my advice to you is, if you filter through that, well, yes, there is certainly an element that’s through in all that, but I think it maybe masking the underlying culprit and the underlying culprit is likely lack of Tier-1 geologic quality drilling locations and fundamental, lesser quality drilling results.

And so, it’s going to be up to you people to fair it out, is it really the service industry that’s causing the bottlenecks for disappointing production or is it that the reservoirs themselves are not yielding the aggregate production that people had expected. And is that why the overall monthly EIA numbers are showing less than expected results.

And again, one more comment, going back to the macro, I am in no way saying that I expect future production growth in the U.S. to be flat lining. I expect to see production growth in the U.S. continue to increase, but I just expect that increase to be more tepid than many people are predicting.

So, it’s just something that I would suggest, you just keep an eye on over the next six to 12 months and monitor for yourself as the monthly EIA numbers come out and I would suggest you don’t pay much attention to the weekly EIA monthly production numbers, because they are not that accurate. Thank you..

Thanks, Mark. That’s definitely a fair point.

For my follow-up, perhaps Sean, regarding your comments on the sequential increase in average lateral links, how do you see that projecting over the next couple of years, as you look out to your development?.

It’s good question.

Certainly, it’s something we are pushing on and I’ll give a tip of the hat to our land crew, because they are working feverishly to trade us out of small non-op positions and trade us into larger not operated positions, such that we can, A, increase our working interest and B, drill more long laterals and so that’s something that we are certainly concentrating on.

We have – we are showing in our current plan the way our acreage sits today that we will increase next year again in our lateral length. So, certainly north of 6000 feet is our target in 2018 and depending on how our land group can do, putting together acreage positions, we hope to continue to grow that in the coming years..

Thanks for taking my questions..

Yes, thanks, Derrick..

[Operator Instructions] And currently we have no further questions in the queue. I’ll turn the conference over to Mark Papa for closing comments..

Okay. I’d like to thank everyone for paying attention to the call and we’ll talk to you again in three more months. Thank you. Operator Once again, we’d like to thank you for participating on today’s conference call. You may now disconnect..