Good morning, 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 21st, 2019 by dialing 855-859-2056 and entering the conference ID number 8788490, or by visiting Centennial's website at www.cdevinc.com. At this time, I will turn the call over to Hays Mabry, Centennial's Director of Investor Relations for some opening remarks. Hays, you can go ahead.
Thanks, Myra. 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, Sean Smith, our Chief Operating Officer. Yesterday, May 6th, 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'd 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 in the forward-looking statements section of our filings with the SEC, including our annual report on Form 10-K for the year ending December 31st, 2018. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, 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.
Thanks, Hays. Good morning, 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. I'll follow with my macro review, 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 to run six 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.
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 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-over-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 of an exceptionally 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 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. 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 non-cash $31.3 million 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 $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 and 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 31st, 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 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 reduction in 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 have witnessed reduced cycle times for both drilling and completion activity. Just recently, for example, we drilled a one-and-a-half 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 five compares our well results on a 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 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.
Turning to our recent well results on slide six. In Reeves County, the Doc Martin comprise a three-well pad targeting the Wolfcamp Upper A with approximately 7,600-foot laterals. These wells delivered an 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 190 barrels per day of oil per 1,000 foot of lateral per well. The Doc Martin are notable not only because they are performing well above our 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 six, the Doc Martin 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 Martin 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 IP 30 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 IP 30 of over 1,400 barrels of oil per day.
As you can see on the map on slide seven, 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 plan to co-develop most of these tests with the Wolfcamp Upper A. Turning to the Northern Delaware on slide eight, Centennial drilled the Airstream 24 State Com 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 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 would 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 lack 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.
Beginning in the 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 a $1-$2 premium to WAHA. As noted on slides 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%-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 are pleased to have signed these agreements as our marketing portfolio as a whole is flexible in nature. 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 Smith. 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, we think the setup is positive for prices in the $65-$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, we would monitor the oil macro during 2019, we might adjust our rig count either up or down. We're currently in a monitoring mode and still running six 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 five of our IR presentation.
Our CapEx is in line, our unit costs are running a bit lower than we targeted. I'd also refer you to slide four, 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, slide four 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 1.5 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 the rest of the year. Thanks for listening, we'll go to Q&A.
Thank you. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing star, then the number one on your telephone keypad. Questions are limited to one question and one follow-up question. If you would like to withdraw a question, press the pound key. First question comes from the line of Gabe Daoud from Cowen and Company. You may ask your question.
Hey, good morning, everyone, thanks for the prepared remarks. Maybe just starting with your oil price realization guidance, definitely appreciate that, could you maybe just give a little more clarity on the contracts? I guess just given your Gulf exposure, a narrowing Midland-Cushing diff, I would've expected maybe a little bit of a tighter differential to WTI, even when accounting for your transport and gathering costs. Any clarity there that you can give would be helpful.
Gabe, I guess the clarity I'd give, we've got a contract that this year a significant proportion is based on MEH pricing. Next year, a component of the pricing is based on Brent pricing. 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. 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. As you know, that's a little hard to forecast today. We're giving you the best guess we have right now based on where we sit with the futures market.
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. 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. Hopefully that gives you a little bit of color.
Thanks, Mark. That's helpful. I guess just as a follow-up on a higher level, obviously M&A is pretty topical these days. Would 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. Thanks a lot.
I think it's obvious we're seeing two trends out there. The first overall trend I'd point out is that it's obvious that the Permian Basin is the coveted asset that pretty much everybody wants. 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. I think you're going to see that the IOCs are definitely going to get bigger in the Permian Basin. Whoever's 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, let's say, shareholder dissatisfaction pushing for M&As, pushing for mergers. 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 there are today. 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 has shown to be if you do an NAV on us today. Thank you, Gabe.
Our next question comes from the line of Neal Dingmann. Your line is open.
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 pad cadence that you see through the remainder of the year and starting next year? It looks like you've got a pretty good ramp. I just want to make sure I'm thinking about it the right way. Thanks.
Yeah. In terms of the rig cadence, 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 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 end the year at a higher price, perhaps a $5 higher WTI than we're sitting at today. 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 and crude oil supply is not growing wildly, as we've seen at least the last two months, 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. At this point, we're not at the point of making that decision yet.
Yep.
That's where we're at right now. We're cautiously optimistic, but not sufficiently optimistic to pull the trigger on adding any rigs. On the other hand, if things get really ugly out there, we could pull in our horns more, too. That's the most honest answer I can give you as of today on where we stand.
No, I like that flexibility, Mark. Then just lastly, with the certainly the notable Third 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.
Yeah. As indicated on the map that's attached to the slides that we put out today, that expands the area of the Third Bone Spring 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 Third 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. That's our plan for the Third Bone Spring. The key with the Third Bone Spring, though, is really seeing if we can make sure that we can co-develop the Third Bone Spring with the Upper Wolfcamp A, without having a negative effect on either one of those intervals. I'd say that was a very pleasant surprise in that Strong Fundamental well, because we didn't expect the well that good.
The Third Bone Spring continues to just give us better than expected results on our acreage, and hopefully that'll continue. 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 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, Subash Chandra from Guggenheim Partners. Your line is open.
Yeah. Hi. 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 are captured in the differential. If that's correct, 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?
Yes. George, you want to field that?
Sure. Hi, Subash. There's a note, if you read the 10-Q, we actually disclose the amount of the credit, which is $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. What I'd say is we've factored that into our GP&T guidance to some degree for the year. I think Q1 was a little bit better than expected, and I think for the balance of the year, we expect GP&T to 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, I'm going to probably goof up my definition of it seems like sort of use or lose, you don't have a committed capacity necessarily that you have to pay for. If you don't use it, the counterparty can find other users of that capacity 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?
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 a use it or lose it, to put it in 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. At this point in time, you expect to fully use the capacity that you've announced?
Yes, that is correct.
Okay. Thanks. Just a final one, and Mark, maybe for you. On inventory, I think you mentioned 4x last year. 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?
Yeah. To explain the inventory thing, we're saying we're going to drill 65 to 75 wells this year. In round numbers, if we replace one and a half x of that, very rough numbers, that means if we drill 70 wells, we'd need to find new locations of, let's just say round numbers, 100 new locations this year. 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.
Through some successful testing of some up-hole zones, a different zone than the Third Bone Spring that we've had, that we'll probably talk about later on in the year as we get some confirmation tests. Those two items will likely give us that 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%+ of your wells this year will be child wells, 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 actually fits the traditional child well definition of being bounded by a legacy parent well, not simply the result of multi-pad development.
I don't want to get into a big discussion on this since we beat this subject to death on the last couple of earnings calls.
Yeah.
We've basically have defined a child well as any second well drilled in a section. We've had a very liberal definition of child wells. 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, William.
Just maybe a follow-up on slide six and eight, it looks like the Doc Martin 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?
Again, our model for the wells is maybe a little bit conservative, and as what we're finding here is that on average, we're beating our model. I would say, yeah, 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. The overall point I'd make is, and I believe it was on slide four, 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%. That's the one that I'd like everybody to really focus on, which is our averages are doing well. 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 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. 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. We place a lot of emphasis on that, and I think it's just shining through, really. I think really, since we started this company, there's really not been a question of the technical competency of our well completion efficacy. 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 mid caps and really second-best in the area only to the previous company I ran.
That's a pretty high bar to have.
Thanks for the comment.
You bet.
Our next question comes from the line of Kevin MacCurdy from Heikkinen Energy Advisors. 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?
Yeah, 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'll have a lot of efficiencies, then we'll do something to slow down that pace to stay within the original CapEx guidelines. What I'd point you to there to 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. Yeah, if it turns out that the macro input that I provided earlier is too optimistic and we're sitting at a $55 oil price here in the third quarter or so, we'll ramp down activity.
Whether that is 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. That'll be the thing on the disappointing oil macro side. 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, "Wow, we're getting more wells drilled with six rigs," or we look at maybe we should add another rig or two. That's the most honest answer I can give you at this time, Kevin.
Thanks for the clarity on that. Given the Doc Martin 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?
Yeah, just an overview answer. Our base inventory in Reeves County is based on 880 spacing. We generally have concluded that 880 spacing is the correct spacing for our acreage for the predominant portion of our Reeves County acreage. Only in certain portions of our Reeves County acreage might we consider going to 660s. In the Doc Martin 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. 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 Hays. I think we can go to the next question.
Next question comes from the line of Jamal Lorduis 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?
Yeah. I'll give you my thought process on the hedging. 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 backwardated, and it's really not too backwardated today, then we would consider hedging if we could lock in $70 for six months or a year. That's our threshold number. Stay tuned if there's a possibility that could occur sometime late this year or perhaps early in 2020.
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 you continue to look to manage around that?
Yeah. Six months ago, before we had this massive oil price crash, I would've said that the max threshold on our debt to cap was 25% for this company. We've got to have some wiggle room in that, and I'd say the max that I would consider tolerable for this company would be maybe 29%, maybe 30%. One of the painful things that the oil price swoon has caused us to do is we're going to have to flex a little bit more than I would've been happy with on what's the max net debt to cap that would be acceptable for this company. 29%, 30% might be the number as opposed to the previous answer I might have given of 25%.
Okay. That was very helpful. Thank you.
Last question comes in the line of Derrick Mitchell from CFOL. Your line is open.
Okay.
Thanks. Good morning, all.
Hey, Derrick.
Perhaps for Mark Papa, 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.
Yeah. I don't know, Sean, do you want to take that question?
Sure, I'll take it. Hey, Derrick. 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. 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. Feel good about our position that we're not going to have any issues going forward. We've definitely heard of a few different transportation companies charging a higher fee for lighter grade crudes, that's something that we don't think is going to be a concern for us going forward.
Yeah. Just to amplify that a little bit, Derrick. It's our understanding that a lot of people are just trying to put condensate in the line, 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 the western part of the northern Delaware there in Eddy County. 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, would 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.
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 do you like the best?
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 prospective there. In Reeves County, there's still a couple zones above the Third Bone Spring that are potential. Right now, I'd say there are a couple intervals in the New Mexico side of our acreage that look like they have a good chance of working out for us there. 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.
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 six-rig drilling rate is about 10 years worth of inventory at least. 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.
Okay.
This is Hays. Do we have any more calls in the queue, Myra?
There are no questions at the moment.
Well, great. Well, this is Hays. Just want to thank everybody for joining in. If you have any questions, feel free to call. You can disconnect at this time. Thank you.
Thank you again for joining us today. This concludes today's call, and you may now disconnect. Have a great day, everyone.