Permian Resources Corp (PR) 2017 Q3 法說會逐字稿

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, 96043152, or by visiting Centennial's website at www.cdevinc.com.

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

Thanks, Ally, 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 home page 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 Forward-looking Statements section of our filing 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 measure 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 for 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'll 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 with 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 of 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 continue to run 6 rigs and shifted 1 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 $11.3 million for the third quarter or [$3.56] 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 FTE payments as a prudent measure to ensure that our gas gets to market, 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% -- 4.6% increase relative to Q2, but is 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 with $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 costs 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 view of anticipated full-year results and better-than-expected well performance. This places 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 6 rigs for the balance of the year, and are maintaining our previous guidance for full-year D&C CapEx and 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, George. The third quarter represented another quarter of continued execution for Centennial. We brought forward another round of solid well results and multiple intervals across both the Northern and Southern Delaware Basin.

During the quarter, Centennial operated 6 rigs, which spud 22 wells and completed 13 wells. At the end of the third quarter, we had 2 separate multi-well pads that were being stimulated. The 3-well pad and 4-well pad came online at early October. And thus, we expect to complete 10 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 Centennial's future. Our average lateral length for wells completed during the quarter was approximately 5,800 feet and represents a 20% increase from the previous quarter. As an example, we drilled the Brooks 2-well pad with an effective lateral length average of 9,100 feet. These wells were spaced on a 440-foot spacing in the Upper and Lower A with an IP30 of 1,375 barrels of oil per day and 1,350 barrels of oil per day, respectively. This, again, shows the viability of 2 targets in the Wolfcamp A as well as 440-foot spacing.

We will continue to pursue extended 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 drilled to date. The Matador 3H well was drilled with an effective lateral length of 4,300 feet and achieved an IP30 of 2,150 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 re-leased record wells, the Russel 6H and Stephens 2H.

Additionally, the C.H. Knight 6H reported an IP30 of 1,620 barrels of oil equivalent per day, consisting of 73% oil and had a lateral length of approximately 4,400 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 1 of our 6 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 2nd Bone Spring sand and had an effective lateral length of approximately 4,200 feet and an IP30 of 1,300 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 3rd 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 profit 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 profit needs over the next 3 years. In-basin sand sourcing will provide significant savings of 5% to 10% of the total well cost.

Along with the cost savings, 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 in crush strength is sufficient to effectively stimulate the reservoirs.

The proppant efficacy was evidenced by the Eady 2-well pad. These 440-foot stack-staggered wells targeted the Wolfcamp Upper A and Lower A intervals. They had an average effective lateral length of 6,800 feet and an average IP30 of 2,040 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 the 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 is 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 2,500 pounds of proppant per lateral foot and 15 clusters per stage. This represents an approximately 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 geoscience 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 is part of the reason we are raising our annual production guidance for the second consecutive quarter.

I would be remiss 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 and planning, we saw no material impact to our production during the event.

With that, I will turn the call back over to Mark.

Thanks, Sean. Now I'll provide some thought regarding the oil macro picture and relate them to Centennial's strategy. Many of the macro comments are simply a repeat of the comments that I made on the earnings call 3 months ago. Events have moved even faster than I predicted and reinforced my conclusions.

Oil markets have recently responded to the combination of high global demand, rapidly reducing crude and product inventories and tepid U.S. production growth. The last of these items is the most controversial, and I'll elaborate a bit on the logic regarding the tepid U.S. growth.

Based on monthly EIA numbers, U.S. oil production has been essentially flat for the past 7 months, and I expect 2017 year-over-year production growth to be 330,000 barrels per day, much less than earlier consensus estimates of 700,000 to 800,000 barrels per day, even though the oil rig count is currently 900, an increase of 500 rigs compared to May 19, 2016.

Many people ascribe the reason for this tepid growth to be cash flow or service company limitations, but I think it's lack of remaining Tier 1 geologic quality drilling locations in 2 of the 3 major oil shale plays, the Eagle Ford and Bakken. Even in a constructive oil price environment, I expect that 2018 total U.S. oil growth will be considerably less than the 1.2 million to 1.4 million barrels per day that many people are predicting.

Centennial's strategic response to this tightening global oil supply demand picture is as follows. First, we'll remain on hedge regarding oil. We may hedge some gas and may add to our gas FTE commitments to ensure that our products move out of the Permian Basin. But we like this supply and demand picture on oil and, with our low debt, see no reason to hedge oil. Second, we'll continue on a path towards 60,000 barrels of oil a day in 2020, which is the highest 4-year oil growth CAGR of any E&P. And third, we'll look for tactical means to cautiously term up service company agreements.

In closing, there are 4 things we'd like you to take away from this call. First, we've again increased our 2017 production target, albeit slightly this time, without increasing CapEx. Second, we've again reduced 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've noted in our press release and on this call. Third, we're 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. Ally, if you want to queue up the -- that I appreciate it.

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

Yes. My question is the in-basin sand that you've 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's also on this call, and I'll let you get that answer from the horse's mouth. Dan, would you field that question, please?

Sure. Irene, we've done our due diligence there and third-party testing as well as evaluating the Wolfcamp with DFTs. And we feel that the closure strength and crush resistance and strength of the proppant there is sufficient for use in the Wolfcamp.

Yes. How far into the Wolfcamp? You've tried in A. How does it look for B and C?

We believe it's fine for the B and C intervals as well.

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

Mark, your original plan, the kind of 5-year plan, I think you all had adding 1 to 2 rigs per year. Does that still kind of hold true? Or have efficiencies maybe reduced that?

Brian, yes, if you go back a year ago, we had, I guess, a fairly aggressive ramp-up in a number of drilling rigs by the time we got to 2019 and 2020. And it's fair to say that the drilling rig efficiencies have allowed us to project that we're going to get to 60,000 barrels a day with less rigs than we would have projected a year ago. So clearly, we're drilling the wells faster than we would have projected a year ago. And so we're going to get to 60,000 barrels a day with less rigs. We're not yet prepared to give you a forecast for where we're going to be in 2018 on a number of rigs, but it is, I'd say, reasonably certain that we will be adding rigs over the number 6 in 2018. And again, as a general guide, if you take our production forecast for this year and just scale it out between where we're 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're not going to be just wildly off if you just took a straight edge and just took a straight-line forecast for where we're going to be in 2018, 2019 and 2020. That will give you a pretty good estimate.

And one more. Just with oil prices moving higher, 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, just a couple of comments on the oil price thing. I think that the -- if I'm 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 -- 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're going to see kind of across-the-board uptick in pressure, pricing pressure. And probably, the last place we're going to see it in terms of availability is rigs. I think that the efficiency of rigs is still going to put us in a -- we're not going to see a huge tightness on rigs in terms of access availability 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're going to see tightness. And so we're going to be focusing primarily on those activities, although we may look at terming up some drilling rig contracts. Right now, we've got really essentially a whole lot of short-term drilling rig contracts. 6 months to 9 months is probably our average term on our rig contracts, so we may look at terming those up. But I think, frac crews, flowback crews, everything related to well completions is where I expect to see a lot more tightness as we get into and through 2018.

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

If we have some fun with Excel, Mark, and if crude prices are kind of in that $60 to $65 range into '19 and '20 that I think you've talked about in the past, there's some significant free cash flow if we just limit 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 target? 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, we -- 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 as 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'm not going to 100% rule out M&A, but I would say that is the 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'll 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 our net debt to cap ratio exceeds the low 20% range. So we're always going to run the company at a very low net debt to cap ratio as we go forward. And probably, depending on the oil price, we'll 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.

Yes, that's really helpful. So I guess, beyond that, in 2020 and 2021, when we see -- as soon as we get 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're getting a little bit to a speculative position because you're trying to forecast out 3 or 4 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 breakover 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 only deal in GAAP numbers. And so those numbers are very important to us prospectively.

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

Mark, your first Lea County well is in the second Bone Spring Sand. I'm just wondering, is this going to continue to be the primary zone now that Lea is subtracting a rig? Or do you have some others in mind?

Sean, you want to field that, please?

You bet. Jeff, yes, the first well we drilled was a 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 is very helpful. I thought I heard you mention higher water costs in your earlier remarks. I'm 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. If I could ask one more. I wanted to return to Mark's macro commentary. And I want to preface by saying I'm in no way trying to be argumentative or pejorative, but there have been several large Bakken operators that have announced improved well results in the quarter. I mean, that is to say they have upwardly revised their EURs. So how do you think we should view those improved results in the context of the Bakken running low on Tier 1 locations? So if you think this may be the sort of the end result of high-grading? Or how should we look at it?

Yes. I think in both the Bakken and the Eagle Ford, you're 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 4 or 5 years ago, and that the majority of the Tier 1 quality locations have been drilled and there's not just 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 Eagle Ford, the resulting production growth that you're 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 you have to look at it from a macro view and not from an individual well view.

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

Mark, we've heard from industry that cycle times are deteriorating due to overall service quality and less experienced crew -- 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 trenches. Why don't you field those questions?

Sure. I think that is certainly something we focus 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 up, 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 it from -- that the 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's certainly an element of truth in all of that, but I think it may be 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 ferret 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 flatlined. 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 I would suggest you just keep an eye on over the next 6 to 12 months and monitor it 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're not that accurate.

Mark, that's definitely a fair point. For my follow-up, perhaps Sean, regarding your comment on the sequential increase in average lateral lengths, how do you see that projecting over the next couple of years as you look out into your development?

That's a good question. Certainly, it's something we are pushing on. And I'll give a tip of the hat to our land group because they are working feverishly to trade us out of small non-oppositions and trade us in to 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 6,000 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.

(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 3 more months.

Thank you.

Once again, we'd like to thank you for participating on today's conference call. You may now disconnect.