Good morning, and welcome to Centennial Resource Development Conference Call to discuss its First Quarter 2019 Earnings. Today's call is being recorded. A replay of the call will be accessible until May 21, 2019 by dialing 855-859-2056 and entering the conference ID number 8,780,493 or by visiting Centennial's website at
www.cdevinc.com.
At this time, I will turn the call over to Dave Miele, Centennial's Director of Investor Relations for some opening remarks. Sir, please go ahead.
Thanks, Myra, and thank you all for joining us on the company's Q1 2019 earnings call. Presenting on the call today are Mark Pappa, 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 ks 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.cedevinc dot 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 filings with the SEC, including our annual report on Form 10 ks 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 Pappa, Chairman and CEO.
Thanks, Hayes. Good morning, and welcome to Centennial's Q1 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.
Thank you, Mark. During the Q1, 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 with 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 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 up 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 Golar Miramar area.
We still expect to average an approximately 59% oil mix for the full year. Revenues for the quarter totaled approximately $215,000,000 which was 3.6 percent 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 percent 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 and A per barrel was down 5.5 percent to $1.89 as notional G and A declined by $600,000 compared to Q4. GP and T expense per barrel increased by 20 percent to $2.32 off of an exceptionally low Q4 base. Despite the increase, GP and T was still below the low end of our full year guidance range as a result of the continued monetization of excess Feet capacity.
DD and A expense declined by 6.6 percent from Q4 to $14.89 per BOE given solid D and C expenditure levels and upward revisions to reserves during Q1 that resulted from good well performance. Finally, severance NAV alone 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 $141,000,000 for Q1. This was 15% lower than the prior quarter primarily because of the previously mentioned increases. We recorded a GAAP net loss attributable to our Class A common stock of $8,100,000 due to a noncash $31,300,000 acreage impairment charge.
The impairment was related to a Q1 divestiture of our remaining noncore leasehold in Ward County as well as the expiration of mostly non op leasehold on the southern portion of our Reeves County position. Turning to capital spending. D and C CapEx was approximately $188,400,000 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 Q1 and anticipate that D and C spending will have peaked in Q1 under the 6 rig program. Facilities, infrastructure and other capital totaled $45,600,000 which was down from $73,000,000 in Q4.
Facility spending was tracking higher than forecast as we took the opportunity to prebuild locations in preparation for future wells. Specifically, we prebuilt 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 $11,000,000 in land related CapEx during the quarter as we saw good opportunities to add high quality acreage at attractive valuations.
Overall, Centennial incurred approximately $245,000,000 of total capital expenditures during the quarter compared to $282,000,000 in Q4. On Slide 12, we summarize our capital structure and liquidity position. In March, we issued $500,000,000 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 percent to $1,200,000,000 as a result of the spring redetermination. At March 31, we had approximately $89,000,000 of cash, 0 borrowings under the revolving credit facility and $900,000,000 of senior unsecured notes.
Based upon our $800,000,000 elected commitment, the company had approximately $890,000,000 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. Thank you, George. The Q1 represented another quarter of solid execution for Centennial as overall well results continue to perform in line with our expectations.
We operated 6 rigs for the majority of the quarter. And 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 the Q1, 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 for both drilling and completion activity. Just recently, for example, we drilled a 1.5 mile lateral in New 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 bearable well per lateral foot basis with other operators in the Northern and Southern Delaware basins. As seen from the 3rd party source, our results are top tier and Centennial is certainly a technical leader among our smooth 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 Q1. 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 comprise a 3 well pad targeting the Wolfcamp Upper A with approximately 7,600 foot laterals.
These wells delivered an average IP30 of almost 1800 barrels of oil equivalent per day or approximately 14.50 barrels of oil per day. This equates to 190 barrels per day of oil per 1,000 foot of lateral per well. The Doc Martens are notable not only because they are performing well above our average 2018 well, but also because these wells are spaced at 6 60 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 4th 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 we can replicate the results of the Doc Marten wells adding significant value to the newly acquired acreage. In our Miramar position in Reeves County, we brought online the strong fundamental AT45H targeting the Third Bone Spring sand with an approximate 9,000 foot lateral. This well had an IP30 of 2,400 wells well equivalent per day. As expected for this portion of our acreage, the well had an oil cut of 59%, representing an IP30 of over 1400 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 Third Bone Spring Sand Northwest into our Miramar position.
We have additional Third Bone Spring Sand test scheduled throughout the year and plan to co develop most of these tests with the Wolfcamp upper A. Turning to the Northern Delaware on Slide 8, Centennial drilled the Airstream 24 State 502H in the 2nd Bone Spring with an approximate 10,000 foot lateral. Completed in early January, the well continues to produce at strong rates. Over its 1st 90 days, the Airstream averaged almost 1900 barrels of oil equivalent per day or over 1500 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 first 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 year and a half 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 could continue to 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 Q4. Fortunately, Centennial has limited exposure to Waha prices. Beginning in the Q2, as a result of our firm sales and firm transportation agreements, approximately 70% of our natural gas will receive midcontinent based pricing.
Year to date, midcontinent based pricing is traded at approximately $1 to $2 premium to Waha. As noted on Slide 11, our gas takeaway agreements also mean we continue to experience immaterial amounts of natural gas flaring due to pipeline takeaway constraints. Centennial is 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 existing basis hedges. Beginning next year, our pricing shift to a more diversified mix with even 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 costs. Overall, we're 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 will turn the call back over
to Mark.
Thanks, Sean. Now I'll provide some thoughts regarding the oil macro picture and relate to the Centennial strategy. Oil prices have obviously rebounded strongly relative to early this year and we think the setup is positive 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 prognost 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'd 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 CDIF performed well during the low oil price Q1 and should post solid results the rest of the year. Thanks for listening.
And now we'll go to Q and A.
Thank you. The question and answer session will be conducted electronically. First question comes from the line of Gabe Daoud from Cowen and Company. You may ask your question.
Hey, good morning, everyone, and thanks for the prepared remarks. Maybe just starting with your oil price realization guidance, definitely appreciate that. But could you maybe just give a little more clarity on the contracts? I guess just given your Gulf exposure, a 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 gasoline costs. So any clarity there that
you can give would be helpful.
Well, yes, Gabe, I guess the clarity I give, we've got a contract that this year is based a significant proportion is based on NEH 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 forward in 2020 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 entered into these 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.
Yes. Thanks, Mark. That's helpful. And then I guess just as a follow-up a higher level, obviously, M and A is pretty topical these days. We'd just love to hear your updated thoughts on how you see the mid cap E and P space and just again broadly how you view M and A?
Thanks a lot.
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 I'd point out is that the 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, so let's say, shareholder dissatisfaction, pushing for M and 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 and A space, but clearly 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.
Our next question comes from the line of Neal Dingmann. Your line is open.
Good morning, gentlemen. My question, Mark, for you or Sean, just could you talk a little bit about you've got a nice stable program running now. I'm just wondering, could you talk a bit about maybe the pop cadence that you see through the remainder of the year and kind of starting next year? It looks like you've got a pretty good ramp and just want to make sure I'm thinking about it the right way. Thanks.
Yes. In terms of the rig cadence, I mean, we're as you heard on the prepared remarks on the call, we said that we may move the rig count up or down or just a 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'll end the year at 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 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've 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're 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 could 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.
No, I like that flexibility, Mark. And then just lastly, with that certainly the notable Third Bone Spring success, just wondering how you all think about maybe potential change of plans for the D and C specifically in your area up there in the Northwest?
Yes. As indicated on the map that's attached to the signs that we put out today, That expands the area that Third 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 co develop 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 the well that good. And so the 3rd Bone Spring continues to just give us better than expected results on our acreage and hopefully that will continue. And our 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 that Third Bone Spring development continues over the rest of our Reeves County acreage spread.
Thanks, Mark. Look forward to the progress. Okay.
Our next question comes from the line of Subash Chandra from Guggenheim Partners. Your line is open. Yes.
Hi. Just on GP and T costs. I suppose the being below trend line or being below guidance there was subletting gas capacity as sort of the oil dynamics are captured in the progress through the rest of the year with capacity as tight as it is in the basin?
Yes. George, you want to see a sense?
Sure. Hi, Subash. Yes, I mean, there's a note if you read the 10 Q, we actually disclose the amount of the credit, which is $7,500,000 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 and 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 and T to kind of increase over time, but hope to continue to see those monetizations occur.
Thanks, George. 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?
So the first part of that question, Subash, this is Sean, is correct. There's no monetary penalties occurred. We don't fill our commitments there. It is kind of a use it or lose it to put it near 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 do at this point in time.
Okay. So at this point in time, you expect to fully use the capacity that you've announced?
Yes, that
is correct.
Okay. And just a final one and Mark maybe for you. So on inventory, I think you mentioned ForEx last year. So when you look at the inventory this year, especially net of the Ward sale, is that going to be to the land or do you see it organic?
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'd need to find new locations of, let's just say, round number is 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 Q1 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 uphold zones, different zone in the 3rd Bone Springs that we've had, we'll probably talk about later on in the year as we get some confirmation tests. So those two items will likely give us that 1.5x and 2x this year.
Okay. Thanks a lot. Thanks guys.
Our next question comes from the line of William Thompson from Barclays. Your line is open.
Hey, good morning. 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 is resulting in a high child mix. Maybe it'd be helpful to understand roughly how much of your child well mix is actually fits the traditional child well definition of being bounded by a legacy parent well, not simply the result of multi pet filament?
Yes. I mean, I don't want to get into a big discussion on this since we beat this subject to death on the last couple of 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 of child wells on the Q and A section last quarter. Thank you.
Okay.
And just maybe a follow-up on Slide 68, it looks like the Doc Marten 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?
Yes. Again, our model for the wells is maybe a little bit conservative and what we're finding here is that that on average, we're beating our model. And I would say, yes, we're very pleased with those wells because it does offset the acquisition that we made last year. So that's why we highlighted it there. But the overall point I'd make is, and 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.
Is that a function of any sort of completion design changes or what would you attribute
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 and 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 place 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 and you look this year of our relative well quality, it's always been the best among midcaps and really 2nd best in the area, only to the previous company I ran and that's a pretty high borrower to have.
Thanks for the
color, Mark. You bet. Our
next question comes from the line of Kevin McCarthy from Heineken Energy.
With the efficiencies, it looks like 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?
Yes. 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 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 result last year where we were one of 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 at a $55 oil price here in the Q3 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 will 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 why we're getting more wells drilled with 6 rigs or we look at maybe we should add another rig or 2. So that's the most honest answer I give you at this time, Kevin.
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 space to 660 and what that could do to your overall inventory count?
Yes, 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 a 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 were 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.
Great. Thanks for the clarity.
This is Hayes. I think we can go to the next question.
Next question comes from the line of Jamal Erday from TPH Company. Your line is open.
Hey, good morning, everyone.
Hey, Jamal.
Just a quick question. As you all continue to consider whether or not 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? Yes. 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.
But 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 backwardated and it's really not too backwardated today, then we would consider hedging if we could lock in $70 for 6 months or a year. So that's kind of our threshold number. So stay tuned if there's a possibility that could occur sometime late this year or perhaps early in 2020.
All right. That sounds good. And could we just get a reminder on the net debt to cap threshold that you all are targeting and how you continue to look to manage around that?
6 months ago, before we had this massive oil price kind of crash, I would have said that the max, max threshold on a debt to cap was 25% for this company. Now we've got to have some wiggle room in that. And 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 swoon has caused us to do is we're going to have flex a little bit more than I would have been happy with on what's the max net debt to cap that would be acceptable with this company. So 29%, 30% might be the number as opposed to the previous answer I might have given it, 25%.
Okay. That's very helpful. Thank you.
Last question comes from the line of Derek Chung from Stifel. Your line is open.
Thanks. Good morning all. Perhaps for Mark, we've heard increasing concerns in recent weeks 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 we could see.
Yes. I don't know, Sean, do you want to take that question?
Sure. I'll take it. Hey, Derek. 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 could even come down further. So 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.
Yes. Just to amplify that a little bit there. It's our understanding that a lot of people are just trying to put condensate in the line and that's got 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 as to what are going to be the exit routes for those people who are in 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 slow down 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.
That'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 do you like the best?
Yes. For us, we still got several intervals that in terms of just behind pipe zones, we still got several intervals, I'd say, in New Mexico on our 16,000 acres, several zones, shall we say shallower zones to test in New Mexico that look perspective 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 a couple of intervals in the New Mexico side of our acreage that look 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 just some organic leasing are probably going to 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 and A activity or so to buttress our years of inventory, which that is 6 rig drilling rate is about 10 years worth of inventory at least. So we're chugging on pretty well at replacing more than more inventory than we drill up, and it is quality inventory. That's a good thing.
Thanks. That's very helpful.
This is Haze. Do we have any more calls in the queue, Myra?
There are no questions at the moment.
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