Permian Resources Corp (PR) 2017 Q2 法說會逐字稿

Good morning, and welcome to Centennial Resource Development's Conference Call to discuss the Second Quarter 2017 Earnings. Today's call is being recorded. (Operator Instructions) At this time, I will turn the call over to Hays Mabry, Centennial's Director of Investor Relations for opening remarks. Please go ahead.

Thanks [Kaylah], and thank you all for joining us on the company's second 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 August 7, we filed a Form 8-K with an earnings release reporting second quarter 2017 earnings results for the company and second 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 Home page or under Presentations at www.cdevinc.com.

I would like to note that many of the comments during this earnings call are forward-looking statements that involve risks and uncertainties that could affect our actual results and plans. Many of these risks are beyond our control and are discussed in more detail in the risk factors and forward-looking statements 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 aren't 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.

Thanks Hays. Good morning, and welcome to Centennial's Second Quarter 2017 Earnings Call. Our presentation sequence on this call will be as follows. George will first discuss our second quarter financial results, capital structure, and revised 2017 guidance. Sean will then provide an operational update, and then I'll follow with my views regarding the oil macro, our strategy as a function of the macro and closing comments. Now I'll ask George to review our second quarter financial results.

Thank you, Mark. As you can reference on Page 9 of the earnings presentation, average oil production for the second quarter was 17,435 barrels per day, a 66% increase compared to approximately 10,500 barrels per day during the first quarter. Average oil equivalent production for the quarter totaled approximately 29,665 barrels per day, a 61% increase compared to the first quarter.

Oil volumes for the second quarter increased to approximately 59% of total production, compared to 57% in Q1 as our second quarter completions were more heavily weighted towards lower GOR acreage where we saw some outstanding well results.

These excellent production results were driven by 3 factors: first, overall well performance continued to exceed our expectations; second, drilling and completion efficiencies allowed us to bring more wells online than we anticipated; and finally, we had more rigs running in Q2 on average compared to the first quarter.

Because of the strong production and operational efficiencies gained to date, we have deferred adding our previously planned seventh rig this year, and will instead move one of our 6 rigs from Reeves County to Lea County in early September to begin developing on our Northern Delaware acreage.

Revenues for the second quarter were $91 million compared to $61 million in the first quarter. This 49% increase was driven by higher sales volumes. Our average realized oil price, excluding the impact of commodity derivative transactions, declined by approximately 10% quarter-over-quarter to $44.58 per barrel as a result of lower oil prices during the period.

Lease operating expenses, including work over costs totaled approximately $8.3 million in the second quarter or $3.06 per BOE. This 30% per unit decline compared to Q1 was primarily driven by flush production from the 20 wells we completed during the quarter.

Total cash G&A declined by 13% to approximately $8.3 million in Q2 compared to $9.5 million for the first quarter, which was burdened by several non-recurring items. Cash G&A per BOE was $3.08 and is trending toward the low end of our guidance of $3.

Transportation gathering and processing expenses totaled $7.4 million for the quarter or $2.74 per BOE, which compares to $3.16 for Q1.

DD&A totaled $34.3 million or $12.70 per BOE compared to $15.74 in the first quarter. This significant per unit decline resulted from the sizable proved developed reserve additions during the quarter and lower capitalized DNC cost. This had the effect of driving down the DNC per barrel component of our DD&A rate.

EBITDAX totaled $63 million for the quarter compared to $36.4 million for Q1, this represents a 73% increase as our higher production volumes were only partially offset by the 10% decline in the realized oil price.

GAAP net income totaled approximately $20.8 million, essentially doubling the $9.8 million we generated in Q1.

Centennial?incurred approximately $170 million of total capital expenditures during the quarter, of which approximately $146 million was related to drilling and completions. DNC costs per well for the quarter were in line with the guidance we provided earlier in the year. Our drilling and completion teams were able to increase field efficiencies to offset some degree of service costs inflation and higher proppant loading on our completions.

On June 8, we closed on the previously announced acquisition of undeveloped leasehold and producing oil and gas properties in Lea County, New Mexico from GMT Exploration Company for $350 million. Since we only include 23 days of production from GMT and had no completions during the quarter, the average daily contribution from GMT for the quarter was approximately 300 barrels per day or about 2% of our quarterly oil production.

As you will recall, we raised approximately $340 million of gross equity proceeds to fund the acquisition, resulting in the issuance of 23.5 million shares of Class A common stock in a private placement.

Turning to Page 11 of the presentation, which summarizes our share count. On May 25, Centennial shareholders voted to approve the conversion of our Series B preferred shares to common stock, resulting in the issuance of $26.1 million Class A common shares to Riverstone and certain affiliates. The preferreds were originally issued to fund a portion of the December 2016 Silverback acquisition.

Taking the Series B preferred conversion and the GMT private placement into account, total outstanding shares, including Class A and Class C common stock were approximately 275.8 million.

Turning again to Page 9 of the presentation, you can reference Centennial's?balance sheet items and liquidity position. At June 30, we had approximately $35 million of debt on the balance sheet resulting in total liquidity of approximately $315 million. We look forward to our fall borrowing base redetermination process, which will incorporate recent drilling activity as well as production associated with the GMT assets, which is not included in the current $350 million borrowing base.

Turning to guidance, which is summarized on Page 12. Due to our strong results during the first half of the year, we are updating full year guidance as follows.

First, we are raising our midpoint oil and oil equivalent production estimates by 14% and 15%, respectively. This places our mid-point oil production guidance at 18,000 barrels per day, and our total equivalent mid-point at 29,500 BOE per day.

Additionally, we're reducing the midpoint of our costs guidance ranges for lease operating expenses, gathering, transportation and processing costs, severance and ad valorem taxes and cash G&A, all of which are declining at a more rapid rate than we anticipated.

Notably, we are also significantly reducing our DD&A guidance by $4 to $14 to $16 per BOE from $18 to $20. This reduction takes into account the previously mentioned impact of significant proved developed reserve additions during the quarter relative to capitalized D&C CapEx, which is driving lower F&D costs.

Finally, as mentioned, we are holding flat at 6 rigs for the balance of the year, and are maintaining previous guidance for D&C CapEx, and 65 to 75 wells drilled and completed for the year.

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

Thank you, George. Centennial added 6 rigs during the second quarter of 2017 and spud 20 wells. Centennial?also completed 20 wells during the quarter with the majority of these being drilled in the Wolfcamp Upper and Lower A. On average, these wells exceeded our internal expectations and continue to prove the high quality nature of Centennial's acreage position.

As you will see on Slide 5, we've delivered tremendous results that are second to none in Reeves County during the last few quarters. I will address a few of these standout wells completed during the second quarter.

Turning to Slide 7, the first 2 wells are located on Centennial's legacy acreage and have the highest IP30 per lateral foot drilled to date by Centennial. The Stephens 2H was completed in the Wolfcamp Upper A with an effective lateral length of approximately 4,190 feet. The well had an IP30 of 1,503 barrels of oil per day and 1,953 barrels of oil equivalent per day, 78% oil. This well generated an IP60 of 1,365 barrels of oil per day and 1,758 barrels of oil equivalent per day, again 78% oil.

Another high-performing well on our legacy acreage was the Russell 6H. This well was also drilled in a Wolfcamp Upper A with 4,185 feet of effective lateral length. The IP30 was 1,503 barrels of oil per day and 1,750 barrels of oil equivalent per day, 86% oil. The IP60 was 1,272 barrels of oil per day and 1,487 barrels of oil equivalent per day, again, 86% oil.

As you may remember during the first quarter, we announced the Big Fundamental 4-52 1H, which at the time ranked as one of the best wells drilled in Southern Delaware and the Southern Reeves County on a normalized cumulative production basis.

As you can see on the left-hand side of Slide 7, our recently drilled Russell and Stephens wells are outperforming the Big Fundamental by over 30% on a cumulative oil basis. This not only points to the quality and repeatability of our acreage, but also to the hard work our technical team has done with regard to our completion techniques.

Flipping to Slide 8, the third notable well on the legacy acreage was the Hightower 2H. It was drilled in the Wolfcamp Upper A, and represents our longest lateral drilled to date, with an effective lateral length of 9,515 feet. The IP30 was 1,566 barrels of oil per day and 1,951 barrels of oil equivalent per day, 80% oil.

Note that our long laterals have the same initial flowback procedure compared to our single mile laterals, hence a similar IP30. The major difference is the shallower decline for the longer laterals allowing for a greater ultimate recovery and rate of return.

On the Silverback recovery, we will discuss 2 outstanding wells, the Ninja 1H and the Samurai 1H. Both of these wells were drilled in the Wolfcamp Upper A reservoir with an effective lateral length of 8,775 feet and 8,990 feet, respectively.

The Ninja well had an IP30 of 1,704 barrels of oil per day and 3,140 barrels of oil equivalent per day for 54% oil, an IP60 of 1,552 barrels of oil per day and 2,942 barrels of oil equivalent per day, and an IP90 of 1,440 barrels of oil per day and 2,725 barrels of oil equivalent per day.

The Samurai well achieved an IP30 of 1,391 barrels of oil per day and 2,672 barrels of oil equivalent per day, 52% oil, and an IP60 of 1,292 barrels of oil per day and 2,575 barrels of oil equivalent per day.

Most notably, as you can see on Slide 5, all 5 of these wells show the geographic diversity of outstanding results across our Reeves County position. For the quarter of we averaged 4,843 feet of effective lateral length. For the remainder of 2017, we plan to focus on extended laterals and pad drilling due to their increased economic returns and expect to average over 6,000 feet of effective lateral length for the full year.

Centennial's technical team is focused on the continuous evolution of our completion design. All wells completed during the quarter had 15 clusters per stage, 100% slickwater and averaged greater than 2,300 pounds of proppant per lateral foot. This represents a significant design change from wells completed in the previous quarters. This improved completion technique has helped to drive better results and is part of the reason that we are raising our annual production guidance.

Our drilling team also continues to drive improved efficiencies. The most recent single mile laterals are averaging 15 days from spud to total depth, which represents an almost 30% reduction compared to the fourth quarter of 2016.

During the second quarter, we drilled a single mile lateral in 13.2 days and that was a record well for us. Perhaps more important than drill time, this well was drilled 100% within the target interval. Year-to-date since bringing geo-steering in-house, our wells have averaged 94% within the 30 foot target zone. For reference, anything greater than 90% is an excellent result. Full credit and praise go to our drilling and geo-steering teams.

As mentioned in previous quarters, we plan to commence drilling on our first Reeves County Bone Spring Well later this month. This well will target a third Bone Spring carbonate interval, which will actually target a shale and is similar in nature to the Wolfcamp A. This reservoir is a different target than other recently released results from offset operators and distinctly separate from the more traditional targeted third Bone Spring sand. We expect to have initial production results by year-end.

Looking at our newly acquired asset in Lea County, New Mexico, we participated in a non-operated well called the [Wicked 17 301H] for our 41% working interest that targeted the first Bone Spring. This single mile lateral generated an impressive IP30 of 1,910 barrels of oil per day and 2,470 barrels of oil equivalent per day, or 77% oil.

This is outstanding news as no credit had been given to the first Bone Spring in our acquisition evaluation and it has the potential to add tremendous value and incremental inventory to our position as we develop the reservoir.

We're also beginning some operated activities in Lea County. When the New Mexico asset was acquired, it came with 1 drilled but uncompleted well. This second Bone Spring well will be completed within a few weeks. A drilling rig will be moving in shortly, and we expect to have our first well spud by beginning of September. The plan is to continue drilling with a single rig in Lea County for the remainder of the year for a total of approximately 5 wells.

Turning towards mid-stream. We've updated our proved gathering contract in Reeves County to allow for up to 85,000 barrels of oil per day transportation to Midland or Crane. This will ensure that all of our future crude production needs are met on the existing Reeves County asset.

We also recently entered into a firm transportation agreement for 40 million cubic feet a day of gas to Waha. Together these contracts will give us assurance that our products will be able to reach market at a competitive price.

With that said, I will hand it back over to Mark.

Thanks, Sean. Now I'll provide some thoughts regarding the oil macro picture and relate them to Centennial's?strategy. We expect total U.S. production to grow 425,000 barrels a day in 2017. And we see both U.S. and global inventories returning to normal levels by March 2018.

Like many others, we're surprised that current oil prices haven't yet responded more strongly to falling inventory levels, but we think prices will inevitably have to respond to tightening physical supply/demand signals.

We think the big surprise will come in the 2019 and 2020 period when total U.S. oil growth will be less than many people are currently predicting because of a deterioration in the remaining number of Tier 1 locations in the Eagle Ford and Bakken and declines in the Gulf of Mexico.

Even in a robust oil price environment, I'd expect 2019 and 2020 total U.S. oil production growth to be 700,000 to 800,000 barrels per day per year, which is much, much less than the 1.5 million barrels per day many people are predicting. Given likely 2018 through 2020 global demand growth of 1.4 million barrels per day per year, this sets up a tight supply demand picture.

I would also caution people to be wary of extrapolating well level economics that almost all E&Ps advertise into assumptions regarding ever-expanding U.S. supply. Ask yourselves a simple question, if these advertised economics are so great, why has the industry destroyed so much capital and generated negligible GAAP income over the past 3 years?

Centennial's base plan is to grow to 60,000 barrels of oil a day by 2020. However, if the short term oil price disappoints, we'll consider lowering our 2018 oil and CapEx target on the path towards 60,000 barrels a day in 2020. We don't intend to waste CapEx in a flat $49 oil environment. We'll revisit our 2018 production target in December when we refresh our perspective regarding the global oil macro.

Let me make one other comment regarding a possibility of future acquisitions. While we always keep our eyes open for future accretive Delaware basin opportunities, I feel that at our current size and growth capability, we have enough assets in gravitas that we don't need to do additional acquisitions to achieve a critical mass. Therefore, it's not obvious that we'll be doing any large future additional acquisitions.

Our objective is to have the best E&P equity performance over the next 4 years, not to be the biggest Delaware basin acreage holder. We're fortunate in that the 2 acquisitions that we've made to date, Silverback and GMT, both look like winners based on drilling results to date. But that doesn't mean we're going to become a serial acquirer.

In closing, there are 5 things we'd like you to take away from this Earnings Call. First, we've upped our expected 2017 production target without changing our expected CapEx. Second, we've reduced our full year estimate of every category of expected 2017 units cost. Third, we've completed 5 impressive second quarter wells, and are beginning to see tangible results from our technical staff that was recently put in place.

Pages 5 through 8 of the IR slides we released yesterday afternoon show proof that we're well on our way to becoming the mid-cap technical leader in shale oil exploitation, which was one of the goals we articulated 8 months ago when we organized this company. We think some of our recent wells are likely the best in Reeves County by any operator during at least the past 6 months.

Additionally, we'll spud our first well on our Northern Delaware GMT acreage?in early September. Fourth, we expect our year-end net debt to cap to be below 10%. And fifth, we intend to begin to generate attractive GAAP ROEs and ROCEs when oil prices reach $55 WTI.

Thanks for listening, and now we'll go to Q&A. Kaylah, you want to queue up for Q&A?

(Operator Instructions) Our first question comes from Will Green from Stephens.

I appreciate the color that you just gave us on a long-term guide. Just to kind of clarify, it does sound like you guys are expecting that prices do improve still. But in your remarks, if crude prices disappoint, and we should think about that as kind of a closer to $40 level, that's where you guys would start to think about ratcheting back to that long-term goal? Is that fair?

Yes. You should consider our 2020 goal of 60,000 barrels a day intact. I mean, there is no change to that whatsoever. The path -- and that's really based on our macro view that by 2020, we expect a WTI price in range of $60 to $65.

The path between today and 60,000 barrels a day is going to be a function of how oil prices proceed. And so we're going to just look at the -- our view of what the oil macro is at year-end this year. And then we'll put out a number as to what that path is going to be in 2018 to 60,000 barrels a day.

And yes, frankly, if the oil price happens to be $40 at year-end this year, that will be a disappointing oil price for us. And it's likely that we would scale back our trajectory towards 60,000 barrels a day in 2018 than what it otherwise would be.

I appreciate that. And then, I wanted to ask on the Northern Delaware, sizable position but not near as blocky as you guys have down in the Southern Delaware. But realizing that that is a great zip code, and obviously, you guys wouldn't be there if you didn't think so as well.

What do you guys see is the limiting factors to ramping rig count ultimately in that area? Is it infrastructure? Is it just scalability of that asset? Where do you see that area -- how do you guys see that area evolving in terms of the position in your portfolio 2 to 3 years down the road?

Yes, I mean, frankly, if I would grade our acreage, I'd break our acreage into 3 tranches. The GMT, which is in Northern Delaware, the Silverback position, which was the first acquisition we made, and then, our legacy Centennial position, which is how we started out.

And if I would grade it on the quality of our acreage, number 1, I'd say all 3 are high quality. But if I put it on a relative scale, I would say the GMT is probably the highest quality, the Silverback second highest and the legacy Centennial was probably -- I would grade it third in priority.

We've made good wells on -- certainly on the Silverback and on the legacy acreage, as you can see from the slides we released yesterday afternoon. Haven't drilled any wells on our own so far in GMT, but I expect that's going to turn out fine.

So we're blessed with having 3 tranches of high-quality acreage. But I would say that, if we can add acreage in Northern New Mexico at reasonable prices, reasonable would be in the $20,000 an acre range as we added for GMT and for the Silverback, we will do it.

But I'd also say that adding to our position in Northern New Mexico or in the Northern Delaware is not our highest priority, right now. I feel like we're at a big enough size, where if we can only add small increments in the Northern Delaware, I'm still happy with the size of the company.

So don't look for us to be aggressively chasing acreage?in the Northern Delaware. When I say aggressively, going to $30,000, $40,000 an acre, just to say we've accreted a significant position. That's not going to be our game plan. So hopefully, gives -- that gives you some clarification, Will.

Our next question comes from the line of Brian Corales from Howard Weil.

Just -- you aren't adding the seventh rig but the drilling and completion number of wells isn't changing. Can you maybe try to quantify -- can you -- used to be able to ? did you all estimate 10 wells per rig a year, is it now 12? Can you maybe try to quantify that a bit?

Yes, Sean, do you want to field that question?

Yes, we were thinking it was about 12 wells per rig. And we're upping that based on the efficiencies we've seen. Right now, we completed -- or spud 20 wells during the quarter. And we also completed wells -- 20 wells during the quarter, and I would expect that cadence to continue for the remainder of the year.

Okay. And then one, you all did a heck of a job on the unit cost, I think you had a clean sweep across the board. Was that -- is that more efficiency driven or was a big portion just production a lot higher than you originally thought?

Yes. Brian, what the -- I'd like to say, it's just brilliant levels of efficiency. But I would have to say that a significant portion of that is just the denominator, the production volumes. We're increasing efficiency but it's production volumes.

This is the same phenomena that we saw at EOG. It's really growing the production volumes at a much higher rate than -- that really just dilutes the costs. And I think what we're going to see in 2018 and 2019, and really through 2020 is that pretty much all those unit costs are going to get driven down considerably more just again because the denominator, the volumes are going to go up so disproportionally fast.

So what I would say is, what you're going to see, what you saw this quarter and what you're going to see in subsequent third and fourth quarters is really just the start of how those unit costs are going to get driven down. Expect to see that get amplified in 2018, '19 and '20.

Our next question comes from the line of Michael Glick from JP Morgan.

A question for Mark. And not to distract from an exceptional quarter, but there's been a lot of focus in our view, irrational fear or outright panic in the market about gas/oil ratios in the Permian.

Just given your experience drilling perhaps more unconventional oil wells than anyone, could you give us some high-level observations on your experience regarding how unconventional wells behave over time as it relates to GOR?

Yes. Sure, Michael, I'll be glad to. Yes, this whole issue of "bubble point death" is -- my view of it is that -- and in my previous life at my previous company, we did a fair amount of research on this, particularly as it relates to the Eagle Ford.

And I would say that when you're dealing with a reservoir that has not been previously depleted by vertical wells. And that certainly would apply to the Eagle Ford, it would apply to the Bakken, it would apply to the Delaware Basin, just with the Big 3 shale plays. I'd say this whole bubble point death issue is not relevant. It just simply is just not applicable.

And so my feeling -- I'm talking really as a reservoir engineer here. I don't think it's a factor at all. The only place where it might be a factor would be in the Midland Basin where you've got 70 years of Sprayberry depletion and also some Wolfcamp depletion.

And I would just say, it's something that needs to be watched in the Midland Basin. And it's just something that needs some further time and observation to see, if indeed, it is a factor there. And that's where I would just leave it at this point in time. But is it something that is undermining all shale plays in the United States. I would say, definitely no. That would be my overview statement to you.

Got it. I appreciate the color there. And then, just given these -- the gains you guys have seen on the productivity side, obviously you changed your completion design. But just curious, how important is geo-steering to productivity in the scheme of things?

Again, going back to my previous life there. I would say, it's surprisingly important in there -- in that, one would think that, gee whiz, if you missed the optimum target by not being in zone for say 75% of a well as opposed to say 95% of a well, what does it matter because you're just going to frac the heck out of it anyway.

That would be just -- you'd think just as an overview statement, you'll overcome that with a frac, but the experience I had in my previous company would contradict that strongly.

And I'd say that, probably in order of priority, the frac optimization is clearly the single most important thing. Picking the target zone to make sure you have the right target zone is probably the second most important thing. And then, the third most important thing to making a good well is then making sure that you get the thing geo-steered where somewhere between 90% and 95% of your well -- of a lateral is in that target zone.

And generally that target zone is maybe a 20 foot target zone. So geo-steering is, I'd say 1 of the 3 primary things. And I'd say it's very important. You got to get those 3 things right, the frac, picking the right target interval and then getting the lateral to actually be in that target interval. So those will be the top 3 things to making an effective successful oil exploitation -- shale oil exploitation kind of a strategy, if you will.

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

Following up on the ranking of the 3 operating areas. Can you speak to the difference in the oil cut, say between the company's legacy leasehold and what was acquired in the Silverback transaction? And how does the cumulative oil production differ between the 2 areas over time? And maybe related to that, if you could just touch on the GOR difference between the company's Northern and Southern Delaware leasehold?

Yes. As far as the oil cut, yes, I'll answer part of that. And then Sean, you may want to chime in on part of it. But there, if you break again our assets into the 3 separate groupings, if you will, the -- our legacy acreage, which is kind of I'll say our Southern portion of our Reeves County holdings, and then, the Northern Delaware holdings, those are both pretty analogous in that those are what I'll call in the phase window or the oil window in that both those areas would have an oil gravity of roughly about 45 degrees and -- 45-degree API.

And both of those have relatively low GORs, between 1,000 and 2,000 GORs. So those are, I guess, to describe it in layman's terms, pretty non-gassy in there. So -- and relatively high oil contents. Then our other area, which is the Silverback area, is in what we used to call kind of at EOG, it is tending more towards the combo phase window in that the oil gravities on our Silverback are higher, they're about 49-degrees API.

So they're -- you're moving a bit towards the condensate window. You're still in the oil window, but you're moving towards the condensate window and moving toward -- directionally toward a combo play. You're not in a combo play, but you're moving directionally towards that. And your GORs, your gas/oil ratios, instead of being 1,000 and 2,000, they're closer to about 7,000. So it's a distinct -- you're in a different regime, if you will.

So the reason that our oil mix was up a little bit relative to the first quarter, oil mix versus the gas, was simply that we had a little bit of tilting toward our legacy drilling versus Silverback on the second quarter. And we expect that's going to continue -- the proportion will continue about the same with a little bit of GMT contribution through the rest of the year.

But I would say, as confused with -- as separate from some of these bubble point issues that are going out in the Midland basin, what could happen, for example, if we get into 2018, if we decide to drill disproportionally on the Silverback acreage, we could end up with higher gas/oil ratios in 2018 in our mix.

But that's got nothing to do with a bubble point. It's just that we're drilling more in a combo portion of our anchorage, if you will. So I don't -- does that give you some explanation, Dan, because we do have 2 separate phase windows on our acreage, if you will?

It really does. And I'm thankful for it Mark, I am. And maybe just as a follow-up to that. You speak about the strength of your technical team and that strength certainly shows in the reported results. What is it that's different or even proprietary about the team's process that makes for better wells? And how many of those folks have EOG in their pedigree?

Yes. I would say that the technical team we've assembled, you probably are looking at -- probably 50% maybe 60% of that technical team has EOG in their pedigree, either EOG directly or EOG once removed. And the system we put in place is very heavily influenced by the system I put in place at EOG. So it's very much a clone of that.

And so obviously, at EOG, I still consider them to be probably the technical -- definitely, the technical leader in shale oil exploitation. And our aspiration at Centennial is to be the mid-cap technical leader in shale oil exploitation, not the overall industry technical leader.

And what we're really doing is just using that template that I put in place at EOG. And just replicating that template here at Centennial. And you're seeing the results of that template. And it's really a bottoms up focus on technical underpinnings of every part of the business. And that's probably the simplest explanation I can give you there, Dan.

Our next question comes from the line of Jeanine Wai from Citigroup.

Maybe just trying to get a little more detail around your comments on $49 flat oil and activity, focusing more on the near term. On the production guidance raise, Centennial is already ? is now growing 250% year-over-year versus 205% previously and that's already top-tier.

Can you talk about how you think about balancing activity with the wide cash flow outspend this year, given that you're already ahead of your original production forecast? Based on our estimates, you guys don't come close to any of your financial governors and liquidity is fine.

But do you -- what do you consider sufficient growth to achieve your corporate objective of having the best equity performance in the mid-cap base, especially since currently growth is coming at a cost with a budget -- above average outspend this year and potentially again next year?

Yes. That's -- I mean, that's a very -- that's a good question. It's also kind of subjective question. I guess, I'd go back to saying, when we designed Centennial we were able to start with a blank sheet of paper and one of the parameters that I put on that blank sheet of paper to design Centennial was I wanted to start the company out with essentially 0 debt. And we've effectively, we started out with mildly negative net debt.

And the reason I did that was, I said, I feel very strongly that a $40 or $50 WTI oil price is not a steady-state long-term global oil price and that is just too low. And I still believe that, and all you have to do is look at the fact that nobody is making any GAAP net income essentially at current oil prices, or look at -- nobody is really making a full cycle positive IRRs of any consequence at current oil prices.

And so it's my belief that the more stable long-term global oil price is $60, $65. And so I said, I want to design a company that we can withstand several years of low oil prices until we get to a more rational long-term oil price. And to do that, we have to have a company that's not over-levered to start with.

So we have an advantage over most every other company in that we have essentially no current leverage. And so we are capable of outspending our cash flow for several years. In fact, one model would show that if oil prices were just flatlined at $49 through 2020, and we decided to continue to go to 60,000 barrels a day and outspend cash flow through 2020, we get to a debt-to-EBITDA of somewhere like a 1.4x ratio roughly.

So it's still not that high of a debt level. So our -- we're continuing to go on the basis that ultimately oil prices will increase, and we will just govern our path to 60,000 barrels a day, depending on what we view the macro on a year-to-year basis is.

So that -- it all goes back to us designing the company to start with 0 debt. So hopefully, that gives you a little bit of an overriding thinking. But the overriding thinking is, is that ultimately oil prices will go up. And we want to be positioned when they go up.

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

Really tremendous quarter. And my question has to do with the third Bone carbonate and the shale width in the third Bone. Kind of curious how extensive this zone is and roughly where it is located, the new well you're going to drill. And then, potentially how many more new locations this could lead to.

And if I might, a second question is on your 13 day well that you've done 1 mile lateral in Reeves County. How much is that in terms of total drilling completion costs at this drilling rate?

Yes. Sean, do you want to field that?

Sure. So first addressing the Bone Spring. The Bone Spring is present across our entire Reeves County position. So if we find that it's productive, it's going to add significant inventory to our current inventory, which is already at greater than 10-plus years.

So I think that we're excited about that, we will be drilling a well here later this month and have that online hopefully by the end of the year. And then we've identified multiple zones within the Bone Spring, so not just the third Bone carbonate looks productive, but some of the second Bone looks interesting as well.

And we've done a fair amount of work looking at the lithology from doing petrophysics and doing certain pressure tests to feel pretty confident that we're going to get some kind of production out of the Bone Spring. And hope that we can make it a commercial reservoir.

The second part of your question was about the drill time and efficiencies driven by that. We've seen about a 10% reduction in costs on drilling. So that's late 2016 to current. I think that we're doing great in that regard. And we continue to push that. If we -- as I said on -- in the initial part of the call, our last several wells are averaging 15 days. And if we can continue to drive those down, we're going to continue to see increased cost efficiencies there.

Great. Would you be able to tell me where your new third Bone well will be located roughly on your acreage?

I don't think we're ready to disclose that yet.

Our final question comes from the line of Derrick Whitfield from Stifel.

Mark, bigger picture question for you. If you were to think about your 2020 game plan, how many rigs would you need to accomplish it in light of your efficiencies and current well performance? And the point being, you're clearly doing more with less, but how much less to reach that objective?

Yes. That's a good question. Yes, the original plan was we would need to get up to somewhere around 12 or so rigs by 2020. But my guess is -- I mean, my guess is that with the drilling efficiencies and then the better wells that we're almost certain to be building, that we're probably going to end up, can achieve that goal with somewhere in the range of probably 10 rigs.

That's just a guess at this time Derrick, so don't hold me to that. But it's probably going to be less rigs than we had articulated a year ago. A year ago we'd articulated a schedule that is -- probably was an overstatement of how many rigs would be required to get to 60,000 barrels a day.

And I'd just say on the 60,000 barrels a day, we could flex that higher, we could flex that lower. That's a number that we can move either direction, but we've got the well capability to go any which way there, but I would say for modeling purposes, you ought use 60,000 barrels a day in 2020.

Got it. And then, one last question. In light of what you know today on the Russell 6H and Stephens 2H, relative to the Big Fundamental, are you confident that 2,600 pounds per flow is the upper boundary on proppant intensity?

We are kind of leveling off at that point. So don't look for us to be going massively to 3,000 and 3,500 or so. The way I'd view where we stand on kind of frac technology at this particular point in time is we've made great strides, we were probably at the fourth grade level 6 months ago, and today, we're kind of at the 11th grade level. And I'd say that the best company out there is maybe at the 12th grade level today.

So we're pretty much where we need to be in turning the big dials and now we're turning just the little dials on our optimization. So don't look for us to massively increase the proppant loading in terms of -- we're now at pretty close to 100% slickwater usage, which is pretty much where we'll be. I don't think we're going to change that too much.

We may tweak some things on cluster spacing, we may tweak some things on types of perforating, but the way to view us is in the first 6 ? in most recent 6 months, we've done a lot of changing on the big dials on frac optimization and most of that has been done. And now we're going to be tweaking some of the smaller dials.

This is the end of Q&A for today. I will now hand the call back over to Mark Papa for any closing remarks.

Okay. Thank you very much for taking the time to listen to us. And the last thing I would just leave with you is that Centennial closed the Silverback acquisition at year-end, so effectively, we got that thing closed on December 28.

So what I would say is we've effectively been a company for about 7 months. And if you view us in the context of the continuum of time, we have made tremendous progress as a company in 7 months. And I now feel that we're coming together as a company, we're beginning to gel. We have our team in place.

And I think this particular earnings call was a manifestation of -- it's the first call when you can view us as a company where we've got a team in place. And you're now seeing results of that team. So thank you for taking the time to listen to us.

This is the end of today's call. You may now disconnect, and have a great day.