Permian Resources Corp

NYSE:PR

Earnings Call Transcript 2019-Q1

[Operator]

Good morning, and welcome to Centennial's Resource Development Conference Call to discuss First Quarter 2019.

[Audio Gap]

is being recorded. A replay of the call will be accessible until May 21, 2019, by dialing [phone] and entering the conference ID number 878-8490 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. Sir, please go ahead.

[Hays Mabry, executive]

Thanks, Mayra, and thank you all for joining us on the company's first quarter 2019 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, May 6, we filed a form 8-K, with an earnings release reporting quarterly earnings results for the company and operational results for our subsidiary, Centennial Resource Production, LLC. We also posted an earnings presentation to our website that we will reference during today's call. You can find the presentation on our website homepage, or under presentations at www.cdevinc.com.

I would like to note that many of the comments during this earnings call are forward-looking statements that involve risk and uncertainties that could affect our actual results and plans. Many of these risks are beyond our control, and are discussed in more detail in the Risk Factors and forward-looking statement section of our filings with the SEC, including our annual report on Form 10-K for the year ended December 31, 2018.

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.

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

[Mark Papa, executive]

Thanks, Hays, and good morning, and welcome to Centennial's first quarter earnings call. Our presentation sequence on this call will be as follows. George will first discuss our quarterly financial results and liquidity, Sean will then provide an operational update, including recent efficiencies, well results and our midstream status. And then I'll follow with my macro view, our current strategy emanating from the macro, comments regarding CDEV's inventory maintenance plans and closing items. Now I'll ask George to review our financial results.

[George Glyphis, executive]

Thank you, Mark. During the first quarter, Centennial ran 6 rigs, which is a reduction of 1 rig from our 2018 program. Our current operational plan is to continue to run 6 rigs for the balance of 2019, and we will closely monitor the oil markets to determine if any rig count changes are warranted. Capital spending in Q1 was in line with our budgeted forecast, while overall activity levels for completions and facilities were higher than anticipated due to operational efficiencies and proactive spending on facilities. During Q1, Centennial spud 17 wells and completed 20 compared to 23 and 22 wells, respectively, during Q4 of 2018. Notably, Centennial delivered sequential production growth during the quarter despite approximately half of the 20 completions occurring in March, which contributed minimal production during the quarter. Overall, we are pleased with the Q1 capital levels, well performance and unit costs and believe that our team is executing the 2019 plan very effectively.

As you can reference on Slide 15 of the earnings presentation, Centennial's daily oil production for Q1 averaged approximately 40,500 barrels per day, which was up slightly from Q4 and up 28% over the prior year period.

Average oil equivalent production totaled approximately 72,035 barrels per day, up 3.5% over the prior quarter, and 33% over the prior year period.

Oil as a percentage of total production was 56%, as a result of production from wells brought online in Q4, that are located in our higher GOR Miramar area. We still expect to average an approximately 59% oil mix for the full year.

Revenues for the quarter totaled approximately $215 million, which was 3.6% lower than Q4, primarily because of lower realized natural gas and NGL prices. Oil realizations before hedging were $48.15, which was essentially flat to Q4. Inclusive of the impact of our basis hedges, Centennial's realized oil price for the quarter was $47.93 per barrel, or approximately 87% of NYMEX.

Shifting to expenses, despite some cost increases relative to Q4, essentially all-unit costs were below the midpoint or low end of our annual guidance. LOE per barrel increased 22% quarter-to-quarter, primarily due to a significant but temporary increase in workover expense, associated with activities aimed at reducing production downtime. Cash G&A per barrel was down 5.5% to $1.89 as notional G&A declined by $600,000 compared to Q4. GP&T expense per barrel increased by 20% to $2.32, off an exceptionally low Q4 base. Despite the increase, GP&T was still the below the low end of our full year guidance range as a result of the continued monetization of excess FT capacity. DD&A expense declined by 6.6% from Q4 to $14.89 per Boe, given solid D&C expenditure levels and upward revisions to reserves during Q1 that resulted from good well performance.

Finally, severance and ad valorem taxes increased to 7.5% of revenue from 6.2% in Q4, primarily as a result of higher quantities and values of our PDP reserves.

Adjusted EBITDAX totaled approximately $141 million for Q1, this was 15% lower than the prior quarter, primarily because of the previously mentioned cost increases. We recorded a GAAP net loss attributable to our Class A common stock of $8.1 million, due to a noncash 31.3 million acreage impairment charge. The impairment was related to a Q1 divestiture of our remaining noncore leasehold in Ward County as well as the exploration of mostly non-op leasehold on the Southern portion of our Reeves County position.

Turning to capital spending. D&C CapEx was approximately $188.4 million in Q1, a 5.4% decrease from Q4. As you can reference on Slide 10, we completed approximately 29% of our annual budgeted midpoint completions during the first quarter and anticipate that D&C spending will have peaked in Q1 under the 6-rig program. Facilities infrastructure and other capital totaled $45.6 million, which was down from $73 million in Q4.

Facility spending was tracking higher than forecast as we took the opportunity to pre-build locations in preparation for future wells. Specifically, we pre-built facilities to accommodate approximately 30 wells relative to the 20 wells brought online in the quarter. We expect a portion of our future wells this year to tie into existing facilities, thereby reducing the need for incremental spending in construction.

As a result, we expect facility spending to moderate somewhat in subsequent quarters. Finally, we incurred roughly $11 million in land-related CapEx during the quarter, as we saw good opportunities to add high-quality acreage at attractive valuations. Overall, Centennial incurred approximately $245 million of total capital expenditures during the quarter compared to $282 million in Q4.

On Slide 12, we summarize our capital structure and liquidity position. In March, we issued $500 million of senior unsecured notes and used a portion of the proceeds to fully repay outstanding borrowings on our revolving credit facility. Effective in late April, our borrowing base increased by 20% to $1.2 billion as a result of the spring redetermination. At March 31, we had approximately $89 million of cash, 0 borrowings under the revolving credit facility and $900 million of senior unsecured notes. Based upon our $800 million elected commitment, the company had approximately $890 million of liquidity at quarter's end. Centennial's net debt to book capitalization was 20% and net debt to last 12 months EBITDAX was 1.3x.

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

[Sean Smith, executive]

Thank you, George. The first quarter represented another quarter of solid execution for Centennial, as overall well results continued to perform in line with our expectations. We operated 6 rigs for the majority of the quarter. As previously announced, we reduced our rig count from 7 to 6 rigs in early January, as a result of the sharp reduction in oil prices late last year.

During first quarter, Centennial spud 17 and completed 20 wells, which, as George noted, was more than expected as a result of operational efficiencies in the field. We have witnessed reduced cycle times from both drilling and completion activity. Just recently, for example, we drilled a 1.5-mile lateral into Mexico in just under 13 days, spud to total depth, which is a record for Centennial. In addition, we're completing more stages per fleet, per month compared to 2018. This has allowed our completion crews to bring wells online more quickly, further reducing spud to first production times. These are strong improvements, and are especially encouraging considering that we're producing some of the best wells in the basin.

The left-hand side of Slide #5 compares our well results on a barrels of oil per lateral foot basis with other operators in the northern and southern Delaware basin. As seen from the third-party source, our results are top tier and Centennial is certainly a technical leader among our mid-cap peers. Maybe more importantly, our well results continue to get better. The graph on the right-hand side depicts Centennial's average 2018 Wolfcamp results versus comparable wells placed online during the first quarter. The main point here is that we continue to increase well productivity as our year-to-date wells are outpacing 2018 results.

Now turning to our recent well results on Slide 6. In Reeves County, the Doc Martens comprised a 3-well pad targeting the Wolfcamp upper A with approximately 76-foot laterals. These wells delivered an average IP30 of almost 1,800 barrels of oil equivalent per day or approximately 1,450 barrels of oil per day. This equates to 190 barrels per day of oil per thousand foot of lateral per well. The Doc Martens are notable not only because they are performing well over average 2018 well, but also because these wells are spaced at 660-foot spacing, and are adjacent to existing producing wells within the same reservoir.

As you can see from the green shading in the map on Slide 6, the Doc Martens also directly offset our recent fourth quarter bolt-on transaction of 2,100 net acres and further justifies our strategy of making smaller tactical acquisitions adjacent to our existing acreage. The acreage is completely undrilled and thus allows for a more efficient co-development of the reservoirs. We believe that we can replicate the results of the Doc Martens wells, adding significant value to the newly acquired acreage.

In our Miramar position in Reeves County, we brought online a strong fundamental AAT-45H targeting the 3rd Bone Spring Sand with an approximate 9,000-foot lateral. This well had an IP30 of 2,400 barrels of oil equivalent per day. As expected for this portion of our acreage, the well had an oil cut of 59%, representing an IP30 of over 14,000 barrels of oil per day. As you can see on the map on Slide 7, this is an important test and successfully expands the fairway of the 3rd Bone Spring Sand, Northwest into our Miramar position. We have additional 3rd Bone Spring Sand tests scheduled throughout the year and plan to codevelop most of these tests with the Wolfcamp upper A.

Turning to the Northern Delaware on Slide 8. Centennial drilled the Airstream 24 state 502-H in the 2nd Bone Spring with an approximate 10,000-foot lateral. Completed in early January, the well continues to produce a strong rates. Over its first 90 days, the Airstream averaged almost 1,900 barrels of oil equivalent per day or over 1,500 barrels of oil per day, and has cumulative production of over 136,000 barrels of oil during this time. The airstream represents Centennial's best well drilled to date in Lea County, and is a strong follow-up to last year's Pirate State 301H, which was the best 1st Bone Spring well ever drilled in New Mexico.

Since adding a rig in New Mexico in late 2017, results in Lea County continue to exceed our expectations. Combined, these results over the past 1.5 year confirm the quality and repeatability of our position.

Before I pass it off to Mark, I'd like to touch quickly on our marketing and midstream efforts. Starting with natural gas, just last month, natural gas prices at WAHA traded as low as negative $9 per MMBtu and now trade close to 0. This sudden downtick was caused by the ongoing [ block ] of associated gas production in the basin, maintenance issues on long haul and interstate pipelines as well as reduced demand from the West Coast following the end of the winter heating season. Since all natural gas egress out of the Permian Basin has essentially been full since late last year, even relatively small disruptions can cause major swings in local prices.

Looking ahead, we believe WAHA can continue trade at 0 or even negative for the next month or so until demand increases from summer cooling loads in Texas. Overall, we remain bearish on WAHA prices for the remainder of the year until Kinder Morgan's Gulf Coast Express pipeline comes online in the fourth quarter. Fortunately, Centennial has limited exposure to WAHA prices. Beginning in the second quarter, as a result of our firm sales and firm transportation agreements, approximately 70% of our natural gas we'll receive midcontinent-based pricing. Year-to-date, midcontinent-based pricing has traded at approximately $1 to $2 premium to WAHA. As noted on Slide 11, our gas Takeaway agreements also mean we continue experience immaterial amounts of natural gas flaring due to pipeline takeaway constraints. Centennial's an industry leader in terms of minimizing natural gas flaring and we expect this to continue in the future.

Similar to our natural gas situation, Centennial has also secured physical takeaway capacity for all of its crude out of the basin. In 2019, essentially all of our crude will be priced off of MEH and Midland benchmarks. Based on current market differentials, gathering costs and associated transportation fees, Centennial expects to realize approximately 87% to 93% of WTI for the remainder of the year, excluding the effect of the existing basis hedges.

Beginning next year, our pricing shifts to a more diversified mix with even more greater exposure to international pricing. Therefore, in 2020, we expect realizations to improve towards 95% of WTI, which is inclusive of our in-basin transportation cost. Overall, we are pleased to have signed these agreements as our marketing portfolio as a whole is flexible in nature. And beginning next year, it provides us with an even more diversified portfolio with greater exposure to international pricing.

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

[Mark Papa, executive]

Thanks, Sean. Now I'll provide some thoughts regarding the oil macro picture and relate them to Centennial's strategy. Oil prices have obviously rebounded strongly relative to early this year, and we think the setup is positive for prices in the $65 to $75 WTI range by year-end 2019 and throughout 2020, as the impact of IMO 2020 provides a tailwind.

On our previous earnings call, we announced that we reduced our rig count at year-end from 7 to 6, but that we would monitor the oil macro during 2019 and we might adjust our rig count either up or down. We're currently in a monitoring mode and still running 6 rigs.

The other pieces of our business continue to perform at or slightly better than expectations. Our well results on average are performing slightly better than prognosed, as indicated on Slide 5 of our IR presentation. Our CapEx is in line and our unit costs are running a bit lower than we targeted. I would also refer you to Slide 4, which shows our acreage position relative to well productivity in the Delaware Basin. The ongoing APC situation points out the value of good quality Delaware Basin acreage, and Slide 4 indicates that all of our 81,000 acres is good-quality and relatively contiguous.

Additionally, I always keep a close eye on our location inventory replacement ratio. Last year, it was 4x, which was excellent. Although it's early in the year, I think we'll achieve 1.5x or 2x this year, which should be another very good year.

At this juncture, I'd say that CDEV performed well during the low oil price first quarter and should post solid results for the rest of the year.

Thanks for listening, and now we'll go to Q&A.

[Operator]

[Operator Instructions] First question comes from the line of Gabe Daoud from Cowen and Company.

[Gabriel Daoud, analyst]

Maybe just starting with your oil price realization guidance, definitely appreciate that. But could you maybe just give a little more clarity on the contract, I guess just given your Gulf exposure, narrowing Mid/Cush diff, I would have expected maybe a little bit of a tighter differential to WTI, even when accounting for your transport and gathering costs. So any clarity there that you can give would be helpful?

[Mark Papa, executive]

Well, yes, Gabe, I guess, the clarity I'd give, we got a contract this year is based -- a significant proportion is based on MEH pricing. Next year a component of the pricing is based on Brent pricing. And so when we gave that ratio of approximately 95% of WTI, it's really based on what the futures market would indicate, as you know, what's the ratio of Brent pricing to WTI pricing. And so as we go forward in 2021 and so on and so forth, what the percentage of WTI that we're going to actually receive is really going to be based on how Brent shakes out in relationship to WTI. And so, as you know, that's a little hard to forecast today. So we're giving you the best guess we have right now based on where we sit with the futures market, but what we wanted to get as we enter into this longer-term contracts, is a component of the international price index into the pricing formula and not be priced just 100% off WTI. And so that's why we may be a little bit different than some of the other mid-caps in terms of what we're forecasting as a percentage of WTI that we're going to expect in future years. So hopefully that gives you a little bit of color.

[Gabriel Daoud, analyst]

That's helpful. And I guess, just as a follow-up on a higher level, obviously M&A is pretty topical these days. We'd just love to hear your updated thoughts on how you see the mid-cap E&P space, and just, again, broadly how you view M&A?

[Mark Papa, executive]

Yes, I mean, I think it's obvious we're seeing 2 trends out there. I mean, the first trend is that the IOCs -- or well, the first overall trend that I'd point out, it's obvious that the Permian Basin is the coveted asset that pretty much everybody wants. So you're going to see a lot of focus and companies trying to get a larger position into the Permian Basin and perhaps more specifically into the Delaware side of the Permian Basin, as you've seen in the Anadarko transaction. And I think you're going to see that the IOCs are definitely going to get bigger in the Permian Basin. And whether -- whoever is ultimately successful in capturing Anadarko, I think you're going to see other transactions where the IOCs grow over the next year in the Permian Basin.

The second thing you're seeing is, you're seeing a lot of noise from hedge funds and others expressing unhappiness with some of the mid-caps. A lot of, we'll say, shareholder dissatisfaction pushing for M&As, pushing for mergers, and I think what you're going to see is, in the next couple of years is going to be probably less mid-caps than there are today. So I think there will definitely be more transactions in the space. And I think, what that means for CDEV is that our asset is going to be more valuable. Now I'm not saying that we're going to be an active participant in the M&A space, but clearly, the 81,000 acres we have is, I think, going to be indicated to be a lot more valuable than what that acreage is shown to be, if you do an NAV on us today. Thank you, Gabe.

[Operator]

Our next question comes from the line of Neal Dingmann.

[Neal Dingmann, analyst]

My question, can you talk a little bit, you've got a nice stable program running now, I'm just wondering, can you talk a bit about maybe the pop cadence that you see through the remainder of the year and kind of starting next year. Looks like you've got a pretty good ramp, just want to make sure I'm thinking about it the right way?

[Mark Papa, executive]

Yes. In terms of the rig cadence, you know, as you heard on the prepared remarks on the call, we said that we may move the rig count up or down, or just stay kind of constant at the 6 rigs. My view on the macro is, I'd like to say I'm pragmatically bullish at this point in time. I do expect that we will end the year at the higher price, perhaps a $5 higher WTI than we're sitting at today. And if we see continued bullish signs over the next multiple months, we expect to see inventories, both the U.S. inventories and international inventories tighten over the next 3 or 4 months. If we see that happen, if we see continued EIA monthly reports that show that U.S. supply, crude oil supply is not growing wildly, as we have seen at least the last 2 months, and if we see continued, shall we say, turbulence on the global oil supply front, then weighing those indicators, it is possible we might step up our cadence sometime in the second half of the year by 1 or 2 rigs. But at this point, we're not at the point of making that decision yet. So that's kind of where we are at right now and we're cautiously optimistic, but not sufficiently optimistic to pull the trigger on adding any rigs. On the other hand, if things get really, really ugly out there, I mean, we can pull in our horns more, too. So that's the most honest answer I can give you, as of today, on kind of where we stand.

[Neal Dingmann, analyst]

I like that flexibility. Just lastly, with the -- certainly the notable 3rd Bone Spring success, just wondered how you all think about maybe potential change of plans for the D&C, specifically, in your area in the Northwest?

[Mark Papa, executive]

Yes. As indicated on the map that's attached to the slides that we put out today, that expands the area the 3rd Bone Springs to the Northwest. That was a pleasant surprise. What we intend to do, between now and year end, is really see if we can further expand the 3rd Bone Spring to the south, pretty much to the due south, you get into a little bit different rock type as you go to the south there. But that's our plan for the 3rd Bone Spring. The key with the 3rd Bone Spring though is really, seeing if we can make sure that we can codevelop the 3rd Bone Spring with the Upper Wolfcamp A, without having a negative effect on either one of those intervals. But I'd say that, that was a very pleasant surprise in a strong fundamental well, because we didn't expect a well that good. So the 3rd Bone Spring continues to just give us better-than-expected results on our acreage and hopefully that will continue. And over earnings calls for the rest of this year, we'll continue to give you news, either -- hopefully good news, but we'll give you news on how the 3rd Bone Spring development continues over the rest of our Reeves County acreage spread.

[Operator]

Our next question comes from the line of Subhasish Chandra from Guggenheim Partners.

[Subash Chandra, analyst]

Just on GP&T costs. I suppose the being below trend line, or being below guidance there was subletting gas capacity as sort of the oil dynamics that are captured in the differential. And if that's correct, sort of how do you see that, the ability to keep those costs low, progress through the rest of the year with capacity as tight as it is in the basin?

[Mark Papa, executive]

George, do you want to field that?

[George Glyphis, executive]

Sure. There's a note, if you read the 10-Q, we actually disclosed the amount of the credit which was $7.5 million that we experienced in Q1 that was up from the Q4 level. It's not something that's easy to forecast, in terms of what those level of monetizations will be quarter-to-quarter. So what I'd say is, we've factored that into our GP&T guidance to some degree for the year. But I think Q1 was a little bit better than expected and I think for the balance of the year we expect GP&T to kind of increase over time. But hope to continue to see those monetizations occur.

[Subash Chandra, analyst]

I guess, on the oil side, if I understood correctly how you've described these contracts in the past. And I'm going to probably goof up the -- my definition of it, but it seems like sort of use or lose, you don't have a committed capacity, necessarily that you have to pay for. But if you don't use it, the counterparty can find other users of that capacity. And a, if that's correct; and secondly, is there an ability there too to sort of hold on to what you have and sublet the oil capacity as well?

[Sean Smith, executive]

So the first part of that question, Subash -- this is Sean, is correct. There's no monetary penalties if we don't fill our commitments there. It is kind of a use it or lose it, to put it in your terms, scenario. We have not explored the opportunity to try and monetize that. I don't think that's something that we're looking to at this point of time.

[Subash Chandra, analyst]

Okay. So at this point in time, you expect to fully use the capacity that you've announced?

[Sean Smith, executive]

Yes, that's correct.

[Subash Chandra, analyst]

Okay. And just a final one, and Mark maybe for you. So on inventory, I think you mentioned 4x last year. So when you look at the inventory this year especially net of the Ward sale, is that going to be through the land or do you see it organic?

[Mark Papa, executive]

Yes, I mean to explain the inventory thing. I mean, we're saying we're going to drill 65 to 75 wells this year. So in round numbers, if we replace 1.5x of that, very, very rough numbers, that means if we drill 70 wells, we need to find new locations of, let's just say, round number, 100 new locations this year. And it looks like the way we're going to find those is primarily through a combination of organic leasing, where we've had better success this year than I expected. And that's probably due to the first quarter oil price downturn, where competition for organic leases is a little bit less than what normally would have occurred. And then through some successful testing of some uphole zones, the different zone in the 3rd Bone Springs that we've had that we'll probably talk about later on in the year as we get some confirmation tests. So those 2 items will likely give us that 1.5x and 2x this year.

[Operator]

Our next question comes from the line of William Thompson from Barclays.

[William Thompson, analyst]

Mark, you've been quite candid about the fact that 80% plus of your wells this year will be child wells, but I believe your definition of a child well is quite a bit conservative compared to some of your peers, as it includes all half-bounded wells, so any well in a multi-well pad. I believe there's some misconception that maybe CDEV has a lot of legacy parent wells that has resulted in that high child mix. Maybe it'll be helpful to understand roughly how much of your child well mix actually fits the traditional child well definition of being bounded by a legacy parent well, not simply as a result of a multipad development?

[Mark Papa, executive]

Yes, I mean, I don't want to get into a big discussion on this, since we've beat this subject to death on the last couple of earnings calls. But we've basically have defined a child well as any second well drilled in a section. So we've had a very liberal definition of child wells. But that's probably all I need to say about it, since we had a long discussion on child wells in the Q&A section last quarter. Thank you, Will.

[William Thompson, analyst]

Okay. And just maybe a follow-up on Slide 6 and 8, it looks like the Doc Martens and Airstream wells fit the more traditional child well definition, yet results appear to be exceeding the legacy type curves. Can you maybe talk about the strong performance there and what you attribute that to?

[Mark Papa, executive]

Yes, again, our model for the wells is maybe a little bit conservative as what we're finding here is that on average, we're beating our model. I would say, yes, we're very pleased with those wells because it does offset the acquisition we made last year. So that's why we highlighted it there, but the overall point I would make is, I believe it was on Slide 4, I don't have it in front of me, but the average well that we drilled during the quarter is beating our average type curve by about 5%. And that's the one that I'd like everybody to really focus on, which is our averages are doing well. So that's the key point, the key takeaway for the quarter.

[William Thompson, analyst]

Is that a function of any sort of completion design changes or what would you attribute that to?

[Mark Papa, executive]

I would continue to believe that among the mid-cap space, Will, that we've got the best technical team in terms of shale exploitation, G&G and completion technology. And that's something that the people I've hired to staff it, I think are some of the best in the industry. And I'd stack them up against any other mid-cap team just in quality and we've placed a lot of emphasis on that. And I think, it's just shining through really. And I think really, since we started this company there's really not been a question of the technical competency of our well completion efficacy and it's -- if you look last year, you look the year before, you look this year, of our relative well quality, it's always been the best among mid-caps and really second best in the area only to the previous company I ran. And that's a pretty high bar to have.

[Operator]

Our next question comes from the line of Kevin [ McCurdy from Heineken Energy].

[Unknown Analyst]

With the efficiencies, it looks likes you're on pace to turn more wells to sales than guidance, even without adding another rig. Can you talk about how you might approach the decision to complete more wells? Is it similar to the decision to add a rig or is it different?

[Mark Papa, executive]

I mean, that's a good question, Kevin. If we view that the oil price is going to be disappointing in the second half of the year, and if our pace with 6 rigs looks like we will -- will have a lot of efficiencies, then we'll do something to slow down that pace to stay within the original CapEx guidelines. And what I'd point you to there to kind of give you some verification is CDEV's results last year, where we were one of the very few companies to actually stay within our original budget guidelines through the whole year. So yes, if it turns out that kind of the macro input that I provided earlier is too optimistic and we're sitting to $55 oil price here in the third quarter or so, we'll ramp down activity, and whether that is ramping -- cutting loose a rig or whatever, we'll do that to stay within the CapEx guidelines, if we're operating very efficiently and drilling too fast with the number of rigs we have. So that'll be the thing on the disappointing oil macro side. But hopefully, that doesn't occur and we end up on the more positive oil macro side and we're viewing it from the other point of view, which is, while we're getting more wells drilled with 6 rigs, or we look at the maybe we should add another rig or 2. So that's the most honest answer I can give you at this time, Kevin.

[Unknown Analyst]

Thanks for the clarity on that. And then, given the Doc Marten wells and the promising results there, any initial estimates on how much your inventory could be down-spaced to 660, and what that could do to your overall inventory count?

[Mark Papa, executive]

Just an overview answer. Our base inventory in Reeves County is based on 880 spacing. And we generally have concluded that 880 spacing is the correct spacing for our acreage for the predominant portion of our Reeves County acreage. And only in certain portions of our Reeves County acreage might we consider going to 660s. So in the Doc Martens area, that might be an area where we might end up in 660s and that's why, we're a little excited about the 660 spacing area. But even if it works in that particular area, if you take the majority of our acreage in Reeves County, at the end of the day, as we view it today, it would end up being spaced predominantly on 880s and not on 660s.

[Hays Mabry, executive]

This is Hays. Excuse me, this is Hays. I think we can go to the next question.

[Operator]

Next question comes from the line of Jamal [ Ridar ] from PPH Company.

[Unknown Analyst]

Just a quick question. As you all continue to consider whether or nor rig activity could move from here, what's the internal thought process on hedging to maybe offset some of the commodity volatility that could occur?

[Mark Papa, executive]

I'll give you kind of my thought process on the hedging. I mean, we're currently 100% unhedged on the base crude. We have a little bit of basis differential hedged on crude oil and that's articulated in the IR slides that we disclosed. On crude, we're 100% unhedged currently. If crude oil gets to the range of $70 WTI and we could hedge that out, in other words, if the curve turns out to be not severely backward-dated, and it's really not too backward-dated today, then we would consider hedging, if we can lock in $70 for 6 months or a year. So that's kind of our threshold number. So stay tuned. If there is a possibility that could occur sometime late this year or perhaps early in 2020.

[Unknown Analyst]

All right. That sounds good. Could we just get a reminder on the net debt to cap threshold, that you all are targeting and how do you continue to look to manage around that?

[Mark Papa, executive]

Yes. Six months ago, before we had this massive oil price kind of crash, I would have said that the max, max threshold debt to cap was 25% for this company. Now we've got to have some wiggle room in that, I'd say kind of the max that I would consider tolerable for this company would be maybe 29%, maybe 30%. So one of the painful things that the oil price swing has caused us to do is, we're going to have to flex a little bit more than we would be happy with on what's the max net debt to cap would be would be acceptable for this company. So 29%, 30% might be the number as opposed to the previous answer, I might have given it 25%.

[Operator]

Next question comes in the line from Derrick Whitfield from Stifel.

[Derrick Whitfield, analyst]

Perhaps for Mark. We've heard increasing concerns recently it's regarding quality adjustments for Permian oil, while you guys are advantaged relative to your peers, I'd certainly appreciate your views on the severity of the concern for the sector and the degree of quality adjustments that we could see?

[Mark Papa, executive]

I don't know, Sean, do you want to take that question?

[Sean Smith, executive]

Sure, I'll take it. Derrick, so I think, as you mentioned, we actually are advantaged there in the fact that we are below 44 for our weighted average API gravity that we produce and sell to the market. So we haven't seen any discounts and don't foresee any of that going forward. In fact, as we continue to ramp up production in New Mexico that will -- could even come down further. We feel good about our position that we're not going to have any issues going forward. We've definitely heard of some, a few different transportation companies charging a higher fee for lighter-grade crudes, but that's something that we don't think is going to be a concern for us going forward.

[Mark Papa, executive]

Just to amplify that a little bit there. It's our understanding that a lot of people are just trying to put [ comments right in to ] the line and that's going to come from just more of the wet gas phase windows, which have to be in either the Western part of Reeves County or kind of the Western part of the Northern Delaware there in Eddy County. So how this is going to play out, I don't know. What are going to be the exit routes for those people who run those portions of the phase window. I'm not exactly sure how that plays out in the macro picture other than it's probably going to slowdown development for those particular portions of the Delaware Basin, will be my guess, as to how this plays out in the bigger picture. That's the only light I can shed on that subject matter.

[Derrick Whitfield, analyst]

It's very helpful. I imagine that combined with gas prices will probably deter some degree of activity in those areas. As a follow-up on your earlier inventory comment, where do you see the greatest opportunity for interval or location additions, if you were to rank your children, which ones you like the best?

[Mark Papa, executive]

Yes, for us, we've still got several intervals that in terms of just behind 5 zones, we've still got several intervals, I'd say in New Mexico on our 16,000 acres, several zones, should we say, shallower zones to test in New Mexico that look prospective there. And in Reeves County, there's still a couple of zones above the Third Bone Springs that are potential. But right now, I'd say, there are couple of intervals in the New Mexico side of our acreage that looked like they have a good chance of working out for us there. So at this point, at least for this year and probably next year, the behind pipe stuff combined with some organic leasing, are probably carry the mail in terms of giving us very good inventory replacement rates. And the significance of that for us is that it means that it's unlikely we're going to have to do anything like significant M&A activity or so to buttress our years of inventory, which at a 6 rig drilling rate is about 10 years worth of inventory, at least. So we're chugging along pretty well at replacing more than -- more inventory than we drill up and it is quality inventory that's a good thing.

[Hays Mabry, executive]

This is Hays. Do we have any more calls in the queue Mayra?

[Operator]

We have no questions at the moment.

[Hays Mabry, executive]

Well, great. This is Hays. I just wanted to thank everybody for joining in. And if you have any questions, feel free to give us a call and you can disconnect at this time.

[Operator]

Thank you again for joining us today. This concludes today's call, and you may now disconnect. Have a good day, everyone.