Centennial Resource Development, Inc. (NASDAQ:CDEV) Q1 2019 Results Earnings Conference Call May 7, 2019 10:00 AM ET
Hays Mabry - Director-IR
Mark Papa - Chairman and CEO
George Glyphis - CFO
Sean Smith - COO
Conference Call Participants
Gabe Daoud - Cowen & Co
Neal Dingmann - SunTrust Robinson
Subhasish Chandra - Guggenheim Partners
William Thompson - Barclays
Kevin McCarty - Heineken Energy
Derrick Whitfield - Stifel
At this time, I will turn the call over to Hays Mabry, Centennial's Director of Investor Relations, for some opening remarks. Sir, please go ahead.
Thanks, Mara. 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 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 the 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 measures we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release available on our website.
And with that, I'd like to turn the call over to Mark Papa, Chairman and CEO.
Thanks, Hays. 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.
Thank you, Mark. During the first quarter Centennial ran six rigs which is a reduction of one rig from our 2018 program. Our current operational plan is to continue six rigs for the balance of 2019 and we will closely monitor the oil markets to determine in any rig count changes or warranted.
Capital spending in Q1 was in-line with our budgeted forecast while overall activity levels for completions in 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’re 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 GOR ear mar 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 work over expense associated with activities aimed at reducing production downtime.
Cash G&A per barrel was down 5.5% to a $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 of an exceptional low Q4 base. Despite the increase GP&T was still below the low end of our full year guidance range as a result of the continued modernization 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 other norm 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 non-cash 31.3 acreage impairment charge. The impairment was related to a Q1 divestiture of our remaining non-core 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&C CapEx was approximately a 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 six 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 of land related CapEx during the quarter as we saw good opportunities to add high quality acreage at attracted 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. Affected in late April, our borrowing base increased by 20% to $1.2 billion as a result of this primary determination.
At March 31, we had approximately $89 million of cash, zero borrowings under the revolving credit facility and $900 million of senior unsecured notes. Based upon our $800 million of 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 1.3 times.
With that I’ll turn the call over to Sean Smith to review operations.
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 six rigs for the majority of the quarter and as previously announced, we reduced our rig count from seven to six rigs in early January as a result of the sharp production at oil prices late last year.
During the 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’ve witnessed reduced cycle times for both drilling and completion activity. Just recently for example, we drilled a one-and-a-half mile lateral in the 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 barrels of oil per lateral foot basis with other operators in the Northern and Southern Delaware basins. As seen from the third-party source, our results are top tier and Centennial is certainly a technical leader among our SMID cap peers.
Maybe more importantly our well results continued 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 comprise a 3-Well Pad targeting the Wolfcamp Upper A with approximately 7,600 foot laterals. These wells delivered in average IP-30 of almost 1,800 barrels of oil equivalent per day or approximately 1,450 barrels of oil per day. This equates to a 190 barrels per day of oil per 1,000 foot of lateral per well.
The Doc Martens are notable not only because they’re performing well above our averaged 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 Marten Wells adding significant value to the newly acquired acreage. In our Miramar position in Reeves County, we brought online the strong fundamental A T45H targeting the Third 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 1,400 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 tests scheduled throughout the year and plant a co-developed 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 Second Bone Spring with an approximate 10,000 foot lateral. Completed in early January, the well continues to produce at 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 as 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 zero. 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 zero 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. Getting into second quarter as a result of our firm sales and firm transportation agreements, approximately 70% of our natural gas will receive Mid-Continent based pricing. Year-to-date Mid-Continent 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 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 the existing basis hedges.
Beginning next year, our pricing shifts 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 M base and 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 them to Centennial strategy. Oil prices have obviously rebounded strongly relative to early this year and we think this set up 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 seven to six 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 still running six rigs.
The other pieces of our business continue to perform ample or slightly better than expectations. Our well results on average are performing slightly better than prognose as indicated on slide five of our 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 CDF 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.
Thank you. [Operator Instructions] The first question comes from the line of Gabe Daoud from Cowen & Co. You may ask your question.
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 and now you’re in [indiscernible] I would have expected maybe a little bit of a tighter differentials to WTI even when accounting for your transport and gathering costs. So any clarity there that you can give would be helpful?
Yes, Gabe. I guess, the clarity I gave, we've got a contract that 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 is, what's the ratio of Brent pricing to WTI pricing.
And so, as we go forward in 2020 and 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 a 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 are going to expect in future years. So hopefully that gives you a little bit of color.
Yes thanks Mike. That's helpful. And then, I guess just as a follow-up on a higher level obviously M&A is pretty topical these days. I would just love to hear your updated thoughts on how you see the mid-cap space and just again broadly how you view M&A? Thanks a lot.
Yes. I think it's obvious we're seeing two trends out there. I mean, the first trend is that the IOCs or well, the first overall trend that point out is that 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, we're seeing a lot of noise from hedge funds and others expressing unhappiness with some of the mid-caps, so to 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 there's going to be probably less mid-caps than they’re 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 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 a NAV on us today.
Thank you, Gabe.
Our next question comes from the line of Neal Dingmann. You're line is open.
Good morning, gentlemen. My question, Mark, your 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 that you even get a pretty good ramp, I 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've 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 six 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 -- we'll end the year at a 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 three or four 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 two 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 one or two rigs, but at this point we're not -- 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 can pull in our horns more too. So that's the most honest answer I 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 3rd Bone Spring success. Just wondering how you all think about maybe potential change of plans for the D&C specifically in your area up there in the Northwest?
Yes. As indicated on the map that's attached, the slides that we put out today that expands the area of the 3rd Bone Springs to the North West, 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 to a negative effect on either one of those intervals. But I'd say it 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, but hopefully that will continue and all the 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 3rd Bone Spring development continues over the rest of our Reeves County acreage spread.
Thanks Mark, look forwards in the progress.
Our next question comes from the line of Subhasish Chandra from Guggenheim Partners. Your line is open.
Yes. Hi. Just on GP&T cost. I suppose the being below trend line or being below guidance there was subletting gas capacity as sort of the all dynamics 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 to the rest of the year with capacity as tight as it is in the basin?
Yes. George, you want to see with that?
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 was $7.5 million that we experienced in Q1 that was up from the Q4 level. It's not something that's -- that's easy to forecast in terms of what those level of monetization 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 monetization 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 that, the counterparty can find other users of that capacity and if that's correct and secondly, is there an ability there too to sort of hold onto what you have and sublet the oil capacity as well?
So the first part of that question Subash. This is Sean. It's correct that there is 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 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's correct.
Okay. Thanks. And just a final one and Mark, maybe if you'll. So on inventory, I think you mentioned 4x last year. So when you look at the inventory this year especially net of the Ward, so is that going to be through 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 wells to 75 wells this year. So, in round numbers if we replace 1.5x of that very, very rough numbers, that means if we -- 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 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 up-hold zones, the different zone and 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 two items will likely give us at 1.5x and 2x this year.
Okay. Thanks, Mark. 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 is some misconception that maybe CDEV has a lot of legacy parent wells that is resulting in high child -- child mixed. 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 legacy parent well, not tampering the result of multi-pad development?
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 earning calls, so -- but we've -- I basically have defined a child well is any second well drilled in a section. So we've 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&A section last quarter. Thank you.
So, we've had a very liberal definition of child wells. But that's probably I'll I need to say about it since we had a long discussion of child wells on the Q&A section last quarter. Thank you, William.
Okay. And just maybe a follow-up on slide six and eight. 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 maybe talk about the strong performance there or 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, 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 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 like it, but it really focus on, which is our averages are doing well. So that's the key point -- the key takeaway for the quarter.
Is there a function of any sort of completion design changes or what do you attribute that to?
I would continue to believe that among the mid-cap space well 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, the staffing I think are or 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 has really not been a question of the technical competency of our well completions efficacy and it's -- if you look last year, you look the year before and you look at 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.
Thanks for the color, Mark.
Our next question comes from the line of Kevin McCarty from Heineken Energy. Your line is open.
Good morning. With 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 six rigs looks like we will have a lot of efficiencies, then we'll do something to slowdown at 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've provided earlier is too optimistic and we're sitting at a $55 oil price here in the third quarter, 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 a number of rigs we have.
So that will be the same on the disappointing oil macro side, but hopefully you know 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 are getting more wells drilled with six rigs or we look at maybe we should add another rig or two. So that's the most honest answer I can 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 Reeves County acreage might we consider going to 660. So, in the Doc Marten 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 880's or not on 660s.
Great, thanks for the clarity.
This is Hays, I think we can go to the next question.
Next question comes from the line of [Indiscernible]. Your line is open.
Good morning everyone.
Just a quick question, as you all continue to consider whether or not rig activity could move from here what's been the internal thought process on hedging to or may be offset some of the commodities volatility that could occur?
Yes I'll give you kind of my thought process on the hedging. I mean, we're currently 100% un-hedged 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% un-hedged. 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 could lock in $70 for six 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.
That sounds good and could we just get a reminder on the net debt, the cap threshold that you all are targeting and how you continue to look to manage around that?
Yes. Six months ago before we had this massive oil price kind of crash, I would have said that the max, max threshold on the 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 room 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 cap that would be acceptable at this company. So 29%, 30% might be the number as opposed to the previous answer. I might have given a 25%.
That was very helpful. Thank you.
The last question comes in the line of Derrick Whitfield 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 have advantage 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. Hi Derrick. So I think as you mentioned, we actually, our advantage 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 few different transportation companies charging a higher fee for lighter grade crudes but that's something that we don't think it's 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 comments aid 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 is to you know 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 a macro picture other than it's probably going to slow down development for those particular portions of the Delaware basin would be my guess, as to how this plays out in a bigger picture. That's the only light I can shed on that subject matter.
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? You were to rank your children, and 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 when 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 zones above the Third Bone Springs that are potential but right now I'd say there are a couple intervals in a 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 comparably next year, the behind pipe stuff combined with just some organic leasing or probably going to carry the mail in terms of giving us very good inventory replacement rates and the significance of that force 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 that a six or eight drilling rate is about 10 years worth of inventory at least. So we're chugging along pretty well at replacing more inventory than we drill up and it is quality inventory. That's a good thing.
Thanks. That's very helpful.
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