Resource Development's conference call to discuss its first quarter 2018 earnings. Today's call is being recorded. A replay of the call will be accessible until May 23rd, 2018 by dialing 855-859-2056 and entering in the conference ID number 1872225, 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. Please go ahead.
Thanks, Ashley. Thank you all for joining us on the company's first quarter 2018 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 8th, we filed a Form 8-K with an earnings release reporting first quarter earnings results for the company and operational results for our subsidiary, Centennial Resource Production, LLC. We also posted an earnings presentation to our website that we will reference during today's call. You can find the presentation on our website homepage or under presentations at www.cdevinc.com. I would like to note that many of the comments during this earnings call are forward-looking statements that involve risk and uncertainties that could affect our actual results and plans.
Many of these risks are beyond our control and are discussed in more detail in the Risk Factors and Forward-Looking Statements section of our filings with the Securities and Exchange Commission, including our annual report on Form 10-K for the year ended December 31st, 2017. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially. We may also refer to non-GAAP financial measures that help facilitate comparisons across periods and with our peers. For any non-GAAP measures we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release available on our website. With that, I'll turn the call over to Mark Papa, Chairman and CEO.
Thanks, Hays. Good morning and welcome to Centennial's first quarter 2018 earnings call. Our presentation sequence on this call will be as follows. George will first discuss our quarterly financial results, updated hedge position, and liquidity. Sean will then provide an operational update for the quarter, as well as give an overview of our current midstream arrangements, and then I'll follow with my views regarding the oil macro, our strategy as a function of the macro, and closing comments. Now, I'll ask George to review our financial results.
Thank you, Mark. During the first quarter, we averaged seven operated rigs and completed 16 wells. As you can reference on page five of the earnings presentation, oil production for Q1 increased 15% from Q4 and averaged approximately 31,575 barrels per day. Average equivalent production was up 22% and totaled approximately 54,070 barrels equivalent per day. Oil volumes as a percentage of total equivalent production were 58%, which was right in line with our expectations. During the first half of the year, we expect our oil mix to range from 58%-59% and increase to 60%-61% during the second half of the year. Revenues for the first quarter totaled approximately $216 million, which was up 30% from the prior quarter because of higher sales volumes and a higher average realized oil price.
The company's realized oil price before basis hedges increased sequentially by 17%, reaching $61.53 per barrel during the first quarter compared to $52.45 in Q4. This represents a 98% realization versus the average NYMEX price for the quarter. While oil differentials are now a key point of focus for the sector, Q1 benefited from a benign Mid-Cush differential of positive $0.34 per barrel. Turning to costs, unit costs for the quarter came in better than expected. We experienced unit cost decrease from the prior quarter for lease operating expenses, gathering, processing and transportation, cash G&A, and DD&A. Given that all of these unit costs were below the low end of our full year guidance, we expect to see some modest degree of escalation during the balance of the year and are not changing any of our full year unit cost estimates at this time.
Adjusted EBITDAX totaled approximately $162 million, which was a 34% increase compared to $120 million in Q4. This was driven primarily by higher production volumes, higher realized oil prices, and a solid cost profile. Net income attributable to our Class A common stock totaled $66.1 million or $0.25 per diluted share, doubling from $0.12 per diluted share in Q4. Centennial incurred approximately $238 million of total capital expenditures during the quarter, of which approximately $182 million was related to drilling and completion activity. As I mentioned on the last earnings call, D&C CapEx now excludes well level facilities costs for Q1 2018 and going forward, so that our results are more comparable to our peers and conform with our 2018 guidance. Well level facilities infrastructure, which includes SWD facilities, seismic acquisitions, land, and other capital, totaled approximately $56 million during the quarter.
Turning to slide eight, Centennial continues to be completely unhedged on fixed price oil, which provides full exposure to the recent increase in WTI NYMEX prices. This strategy has significantly benefited our average realized oil price in Q1 compared to previous periods and has, in turn, enhanced revenue, cash flow, and earnings. Given that many of our peer producers have hedged calendar 2018 oil prices for over 60% of their estimated production volumes at average prices in the mid to high 50s, we believe Centennial is receiving and will continue to receive superior realizations after hedges in today's price environment. Although we haven't hedged WTI, we have implemented some basis hedges. For the period from April to December 2018, we have hedged the Mid-Cush basis for 10,000 barrels per day, which represents approximately 27% of our 2018 midpoint estimated oil production at an average differential of $1.77 per barrel.
We've also added 6,000 barrels per day of Mid-Cush hedges in Q1 of 2019 at an average differential of $5.34 per barrel. Our expectation is that new 2019 projects for oil takeaway capacity out of the basin will significantly improve the differential relative to what we are seeing today. While we view the current heightened Mid-Cush differential as a transitory issue, we continue to evaluate options to reduce basis price risk. Turning to natural gas, which Sean Smith will cover in more detail shortly, our primary focus has been flow assurance with the secondary objective of maximizing price realizations. Gas revenues represented approximately 9% of our total revenue stream in Q1. Given activity levels in the Permian and limited takeaway capacity out of the basin, we do expect natural gas pricing at WAHA to continue to deteriorate from current levels.
In the first quarter, we added 30,000 MMBtu per day of Henry Hub fixed price hedges at $2.78 per MMBtu for full year 2019. We also added 30,000 MMBtu per day of WAHA basis hedges at $1.46 per MMBtu for full year 2019. Please see slide 12 of our earnings presentation for a detailed hedge schedule. Referencing page 10 of the presentation, we summarize our capital structure and liquidity position. At March 31st, we had approximately $38 million of cash and $400 million of senior unsecured notes outstanding, with no borrowings on the revolving credit facility. On May 4th, we finalized a five-year commitment for a new revolving credit facility with an initial borrowing base of $800 million, which is up from $575 million last fall. Elected commitments under the new facility are $600 million.
At quarter's end, pro forma for the elected commitment, we had approximately $637 million of liquidity. Centennial's net debt to book capitalization stood at 10% and net debt to Q1 annualized EBITDAX was 0.6 times. With that, I will turn the call over to Sean Smith to review operations.
Thank you, George. During the first quarter, Centennial continued to make strides in evaluating and developing our acreage position. We brought online our first well in the Wolfcamp A in the northern Delaware, as well as a strong Wolfcamp B well and two exceptional Wolfcamp A wells in the southern Delaware. During the quarter, we spud 19 wells and completed 16 wells and are on track for our full year completion guidance of 75-85 gross operated wells. The wells completed this quarter outperformed our internal estimates and delivered an average IP30 of 1,200 barrels of oil per day per well. These results, combined with our lower unit costs, drove our strong financial performance during the quarter. Turning to our well results on slide six, we recently completed the Juliet 1-H targeting the Wolfcamp A.
We are excited about the Juliet well, which represents our first Wolfcamp test in Lee County, New Mexico. The well was drilled with an approximate 4,000-foot lateral and had an IP30 of 1,450 barrels of oil equivalent per day with 78% oil or 1,100 barrels of oil per day. On a per lateral foot basis, the Juliet reported an impressive 280 barrels of oil per day per thousand foot of lateral. These results are very encouraging as we believe the Wolfcamp will be developed across a significant portion of our Lee County position. Since adding a rig to these assets in September of last year, we completed wells in multiple intervals consisting of the Avalon, Second Bone Spring, and Wolfcamp reservoirs. All of these tests have either met or exceeded our expectations.
This is a testament to our team and their knowledge of the acreage. We expect to delineate additional zones throughout the year. During the first quarter, Centennial also brought online several strong wells in Reeves County, Texas. The Carpenter State 30-H and 39-H were drilled on a two-well pad and landed in the Wolfcamp Upper A approximately 880 feet apart. The average lateral length was approximately 6,900 feet. The Carpenter 30-H had an IP30 of 2,000 barrels of oil equivalent per day, 84% oil, while the Carpenter 39-H had an IP30 of 1,500 barrels of oil equivalent per day with 86% oil. The two wells averaged 1,500 barrels of oil per day per well over the first 30 days. Also in Reeves County, we completed the Sieber B 13-H in the Wolfcamp B reservoir.
This well had an effective lateral length of 9,100 feet and an IP30 of 1,900 barrels of oil equivalent per day with 77% oil. The well averaged over 1,400 barrels of oil per day over the first 30 days online. This successful test of the Wolfcamp B further de-risks the zone on our acreage in Reeves County. Finally, last quarter, we released an IP10 for the Weaver 34-H, which was the company's first modern test of the Third Bone Spring Sand. As a follow-up to last quarter's early flowback result, the well has delivered an IP30 of 2,100 barrels of oil equivalent per day with 73% oil or approximately 1,600 barrels of oil per day. The Weaver now has an IP60 of approximately 1,400 barrels of oil per day and continues to outperform expectations, producing over 82,000 barrels of oil during its first 60 days online.
We plan to have additional drilling results in this zone during the remainder of 2018. Turning to midstream, I'd like to review our arrangements for both oil and natural gas, highlighting our confidence in the flow assurance we have for both commodities. As you all know, most of the investor concern recently has been related to oil takeaway out of the Permian Basin. While I'll go over our oil gathering contract shortly, we remain most focused on securing natural gas takeaway both to the WAHA hub and out of the basin. With current Permian Basin residue gas production at approximately 7.5 Bcf a day and effective takeaway capacity closer to 8 or 8.5 Bcf a day, we believe there is a significant risk that some operators will either need to flare their wet gas at the wellhead or curtail production at some point in the future.
Since the beginning of last year, it has been our goal that we ensure our crude oil production will not be curtailed or shut in due to potential gas constraints. Additionally, we are operating under the assumption that the Railroad Commission of Texas will not allow us or the industry to flare gas for an extended period when takeaway capacity is full. Therefore, Centennial has put several transportation service agreements in place in order to ensure delivery of its natural gas to market. The vast majority of our wet gas is gathered and processed by EagleClaw Midstream through an acreage dedication in Reeves County. Thus, we have secured capacity that gets our product to the plant tailgate. The EagleClaw system, which is undergoing a new expansion, provides Centennial with ample processing capacity for the next several years.
From there, through firm transportation and firm sale agreements, we have contracted capacity on El Paso Line 1600 and other pipelines connected to the EagleClaw plant to be able to transport 100% of our expected 2018 gross residue gas volumes from the tailgate of EagleClaw's processing plants to the WAHA hub, a liquid hub with approximately 10 Bcf a day of physical capacity. For the remainder of the year, we remain confident in our ability to sell gas once at WAHA. As George previously noted, our natural gas represents less than 10% of our total revenue. Therefore, our top priority is to ensure we move and sell our gas, and our secondary concern is maximizing product prices. Our goal is to have transportation agreements in place, not only to the WAHA hub, but also out of the basin for 100% of our expected gross residue gas through 2021.
We will achieve this by entering into firm transportation, firm sales, and backhaul agreements. Currently, we are in the final stage discussions with various midstream partners and firm capacity holders on export pipelines from the basin to provide these services to Centennial through 2021. We hope to have final contracts in place during the next few months, which we'll discuss in more detail on our next quarterly call. Please note that while these contracts do come at a cost, we view them as buying insurance or flow assurance so that we can achieve our 2020 oil production goal of 65,000 barrels of oil per day. Now, turning to crude oil, we feel very comfortable with our arrangements that get us our oil on pipe and sold into liquid markets.
In Reeves County, our properties are under an acreage dedication to Oryx Midstream, who gathers our oil via pipeline at the wellhead and delivers it to liquid hubs in Midland or Crane. Oryx's pipeline network is comprised of a 205,000 barrels of oil per day gathering system. Oryx is currently completing their first phase of expansion to approximately 425,000 barrels of oil per day, which will be in service around mid-year, and to 600,000 barrels of oil per day by late Q4. We are a committed shipper on this gathering system and will have 85,000 barrels of oil per day of firm capacity, which is more than adequate to support our 2020 oil target and beyond.
Additionally, Centennial sells its crude at the wellhead under term sale agreements to the marketing arms of large firms such as BP, Shell, and Oxy, using the firm capacity we have on the Oryx system. Once at delivery points in Midland or Crane, our sales counterparties utilize their respective FT arrangements out of the basin. As George mentioned, we have approximately 10,000 barrels of oil per day of Mid-Cush basis hedges in place for [audio distortion] 2018 at an average negative differential of $1.77 per barrel. Our remaining crude not covered under basis hedges will be exposed to Midland pricing, but we do not expect to truck or rail oil from our properties in Reeves County, which significantly cuts down transportation costs. Lastly, we believe that the recent widening of the oil basis is somewhat transitory in nature and has been exacerbated by local refinery downtime and jittery markets.
Therefore, we believe Midland oil differentials will see some relief around the second quarter of 2019 as additional pipeline capacity is put in place later that year. The bottom line is that we are taking the necessary steps to procure flow assurance for both our crude oil and natural gas and feel confident that these regional price dislocations are only temporary in nature until new pipelines are built. Additionally, we feel that we have adequate gas processing and takeaway capacity for our NGL product stream. In the meantime, we will continue to execute on our game plan, which is characterized by having one of the highest oil growth rates versus our peers with one of the lowest leverage metrics in the industry. With that, I will turn the call back over to Mark.
Thanks, Sean. Now I'll provide some thoughts relating to the oil macro picture and relate them to Centennial's strategy. I'll also provide comments regarding how I view CDEV's position for the rest of the year and for the next several years. The oil macro posture is developing as expected, and prices have reacted in a manner consistent with my commentary on previous earnings calls. I continue to believe that the overall U.S. supply response in 2018 and later years will be less than currently predicted by the EIA, IEA and OPEC, resulting in more severe supply-demand tightening than currently forecasted by these agencies. CDEV's response is to continue to remain unhedged regarding oil. We will employ some tactical oil basis hedges from time to time, but it's unlikely we'll hedge WTI anytime soon.
Given our macro view, we see no need to change our industry-leading targeted growth trajectory towards 65,000 barrels of oil a day in 2020. As noted by our previous speakers, CDEV is currently firing on all cylinders. During the first quarter, we hit or surpassed all of our production and cost targets. The driver of these results is our well quality. We continue to make excellent wells, and I believe we're the second best in the entire industry in shale oil exploitation, and that's not too bad for a one-and-a-half-year-old company. Additionally, the 60-day production performance of our initial Third Bone Spring Sand well indicates this zone will provide a meaningful high ROR inventory addition, essentially for free, because it's on existing acreage. That's a much more efficient way of adding inventory than doing an expensive M&A.
Another key accomplishment this quarter has been excellent progress in locking up firm transportation commitments for our casing head gas, both to and away from Waha, for the period 2019 through 2021. As you know, during this period, there's a possibility that some gas may be backed up in the Delaware Basin, and we want to be sure that our product can move to market. I also want to provide my views regarding how I see CDEV evolving over the next several years. I visualize CDEV continuing its industry-leading high oil growth rate phase through 2020, where we will likely reach a max debt-to-cap level of slightly less than 20%. We'll begin to generate free cash flow in 2020, when I'd expect us to moderate our production growth and likely institute a dividend that same year.
I visualize the transition from a very high oil growth rate company to a growth rate comfortably higher than the peer average commencing in 2021, leveling off with a high teens debt-to-cap and free cash flow used each year for dividends and buybacks. As I've stated many times, we don't aspire to be the biggest company in the Delaware Basin. We simply want to be the most technically competent pure play and generate some of the highest GAAP ROEs and ROCEs. Thanks for listening, and now we'll go to Q&A. Ashley, can you pick up the call here?
Yes, sir. At this time, if you have a question, please press star then the number one on your telephone keypad. We ask that you please limit your questions to one question and one follow-up question. Your first question comes from Scott Hanold with RBC Capital Markets.
Thanks. Good morning, congratulations on the quarter. Mark, I always appreciate your macro thoughts and certainly playing out beneficial to CDEV's lack of hedges, I guess, at this point in time on NYMEX. When you step back and look at where we are on the prompt month and the forward curve, what is your view of what the forward prices will eventually play out, and is there a point where you do feel more comfortable to go out there and secure some stronger prices?
Yeah. Just overview, Scott. As you know, the IEA and EIA are forecasting total U.S. oil growth this year in a range of 1.3 million-1.4 million barrels a day. My forecast is about 0.95, and my forecast for 2019 is lower than that. I think that with that, in 2018 and 2019, we'll see just a further constriction in global supply and demand, even if you exclude the Iranian sanction situation. Even at the current $70 WTI price level, I see a strong possibility of further strengthening in WTI over the next couple of years. We would intend to remain unhedged. Yes, there's certainly a price when we would lay on some WTI hedges, but at this point, I wouldn't divulge what that price is. It would be a fluid situation. But I can tell you that price is not $70.
As far as the futures curve with the severe backwardation, I would say it's laughable. That would be my term for it. It's ridiculous. That's my view of the macro. Then CDEV strategy is simply, we would intend to be one of the fastest oil growth entities in the U.S., in what we believe will be a very strong WTI pricing environment over the next multiple years. The last comment I would make, [to you], is one of the groupthink items that's out there is short cycle times. The concept is you have strong oil prices, that turns on the shale machine, and the shale machine generates a vast amount of oil, which pushes oil prices down, i.e., short cycle times.
I believe that groupthink is 100% wrong, and the concept of short cycle times is incorrect, because even if capital gets poured into the shale machine, the shale machine will disappoint in terms of aggregate oil production growth. I think the industry and the world is going to have to conclude that the short cycle time groupthink is an incorrect way of looking at global supply demand over the next multiple years.
That's great. I appreciate that color. As my follow-up question, I think, George, you had mentioned you do expect oil cuts to move up into the 60%-61% range in the back half of the year. Can you talk about how some of those Southern Delaware, when those rigs start shifting and the zone that you'll be targeting to push that shift a little bit higher to the higher oil?
Yeah.
Yeah, sure.
Yeah. Just briefly, we would intend to run pretty much one rig in the Northern Delaware, in Lee County, throughout the year. That's a higher oil cut. That's about an 80% oil cut. That'll be relatively constant. The subtle shift between 58%-62% is really just how many rigs we run on our Silverback acreage, if you will, and at what point in time do we run those rigs there. The Silverback acreage is slightly gassier than the rest of our Reeves County acreage. What you'll see there is that, as we have the wells scheduled, the fact that our mix will change a little bit there throughout the year is just a function of how many wells we have slotted, and when they're slotted to go onto the Silverback acreage.
Got it. Those oil cuts in Silverback and Legacy Centennial acreage down there all produce about the same oil cuts, or the same oil barrels, is that right?
Yeah, except the Silverback acreage in Reeves County has got a little higher gas-oil ratio.
Right.
That's what swings it a little bit between this 58%-62% throughout the year.
Appreciate that. Thanks.
Okay.
Your next question comes from Leo Mariani with NatAlliance Securities.
Hey, guys. Wanted to dig in a little bit into the oil diffs here. Obviously, they've expanded quite rapidly over the last month or so. Do you guys have any expectation as to where those diffs may settle out if we work our way into the second half of 2018? Additionally, is there some level of oil diff, where if it really were to blow out, in a much, much more meaningful fashion, that you guys would consider slowing down a little?
We don't think those oil diffs are going to reach the point where it would change our drilling program, Leo, if that's the direction of your question. We think if oil diffs did get wide enough, it would activate more rail out of the basin, which there hasn't been a lot of rail out of the Permian Basin here just in the last couple of months. That's the safety valve, if you will, on there. We believe that by the second half of 2019, those differentials will shrink again, and that's pretty much indicated by the futures market for the differential, just as you get additional pipeline capacity. We think it is a transitory item that's probably nine months in duration at the most.
We can't really give you an idea of, is the differential going to stay at $10-$12, or is it going to shrink back to $7? We don't have enough intrinsic knowledge to give you a good estimate of what it might be for the second half of the year, and we can't pretend to understand how much is the downtime on the Borger Refinery and some of those things. How big of a factor is that in this whole differential thing? Our guess is there's a fair amount of emotion in this differential right now which makes it even harder to forecast for the second half of the year, Leo. Sorry, we can't give you a lot of specificity on that.
No, I think those were very good thoughts, for sure, and helpful, I think, to everyone. Just looking at your start to the year in the first quarter, obviously, very strong production here. Just wanted to get you all's thoughts there. Was that just largely driven by better than expected well performance as you guys see it. Just wanted to get your opinion on that. Certainly looks to me as though based on the strong start, I think you guys plan on continuing to execute on the operations side, that production guidance looks more towards the upper half on your numbers here.
Yeah. We're not going to fall in the trap of telling you to raise your guidance. What we'd recommend you use the midpoint of the guidance on there. What you can conclude from the first quarter is we hit the high end of the production range with less completions than we expected, and the reason was the average well for the first quarter ended up being stronger than we expected. The good news out of all that was that the well results for the first quarter were remarkably consistent. If I showed you a graph of all the completions in the first quarter, it was a pretty tight performance graph in that you didn't have a wide spread of the results. We're seeing very consistent results, and frankly, they're consistent above our type curve expectations.
That's what we really have been striving for, is a set of consistent results. Right now, we're just making consistently good wells, and that's why I made that comment in my prepared talk that I truly believe that if you gave CDEV a square mile of oil shale acreage, that we will extract more oil out of it. We're second best in the industry right now, and I believe the first-best company is my former company, but we're second best out of all the companies in the industry of shale oil extraction. We've come that far in our technology improvement. That's showing up in our well quality.
Okay. That's very helpful. Thanks, guys.
Your next question comes from Irene Haas with Imperial Capital.
Hey, good morning. My question has to do with your Lee County Wolfcamp A well. That certainly is a very strong well, and just wondering, how far does this trend extend northward in Lee County? Secondarily, how much have you counted the Wolfcamp A within your inventory?
Sean, you want to take that?
Sure. Hey, Irene. We're certainly excited about the well results there in Lee County. That's our first Wolfcamp A well to test up in that area, and it certainly is higher than what we expected going in, which is fantastic. I think it certainly does add some inventory, as we only counted maybe a small portion of our position when we made the acquisition in Lee County that we paid for during the acquisition. I think with this well result, it expands the possibility of the Wolfcamp going over a large portion of our position in New Mexico.
If I may ask one more question. How does the Wolfcamp behave as you move from Reeves County northward? Does it change in character? Is it better or worse? Just some general color.
The main difference there is that as you go to the north, you have what's called the Wolfcamp XY, which is a classic section that sits on top of the Wolfcamp shale. That is not present in the Southern Delaware, so you may have some extra footage, AKA other targets there to target in the Upper Wolfcamp that you might not have in the Southern Delaware. That's the main difference. Very pleased with the results in both areas from the Wolfcamp A, that continues to be a highlight for our portfolio.
Great. Thank you.
Again, for any questions, please press star, then the number 1 on your telephone keypad. Your next question comes from Park Clear with Scotia Howard Weil.
Hey, good morning, guys. First question on Takeaway. Fully knowing that you're all still in negotiations, is it possible to get some additional detail, maybe on the in-service date, the direction of the flow? Then on the oil side, is there a contract with these marketers? Are you getting Midland or some other oil price for that?
Sean, you want to take that?
Sure. We do price off Midland pricing for the majority of our crude, as we said in the call, just to address that a couple different ways. From a crude perspective, we've got ample capacity in the Oryx system to get us to Crane or Midland, that's where we ship all of our crude, is to one or both of those destinations. As you well know, those are very liquid markets. That being said, we do price off Midland for the majority of our crude from the wellhead. We are exposed to the Mid-Cush differential, if that's what you were going after. We don't price anything right now off of other indexes. Then, I think if you're going the gas route, we've got, again, firm transportation from the plant to Waha, for 100% of our volumes in 2018.
We can get all of our gas to a, again, very liquid market. At that point, we are again subject to the Waha differential. As we said, that's not a huge revenue driver for us, less worried about that. We can get all of our product Both oil and gas to a market of which we can have very liquid sales.
Okay, great. Thanks. Maybe a follow-up on that Wolfcamp A, knowing it's very early, that was a great result. Is there maybe some opportunity to transition a rig full time to that later in the year or next year if it holds up?
As Mark stated a minute ago, I think right now we do not plan on changing our current plans for our capital expenditures from north to south. We currently have a rig in the northern Delaware running, and that will test all the various formations that we've talked about. We've already got wells in the Avalon, the Second Bone, and now the Wolfcamp. I would look for us next year to expand on that and maybe we deploy a second rig into Mexico at that point.
Just one final, if I could. The lateral length made a big jump sequentially. Is that something we should be holding flat from here? I know y'all are planning on increasing the lateral length year-over-year, but just how should we look at that into 2Q and beyond?
I think for the quarter, we averaged 7,700 feet. Our model has us averaging 7,500 feet for the remainder of the year.
Got it. Thanks. Congrats on the quarter.
Thank you.
Your next question comes from Matthew Sorensen with Seaport Global.
Hi. Thanks, guys. I was hoping you could expand a little on your Lee County midstream infrastructure and what the oil takeaway out of Lee County currently looks like.
Sure. I'll take that, Mark. Right now, we've got a contract in place for the gas where it's in area dedication. We are committed there similar to our Reeves County position. We're fully dedicated there to a company to move our gas out of the basin to WAHA. Feel very comfortable in the gas position. On the oil side, we're in the final negotiations with a service provider. We'll be able to talk about that next quarter. We're in the crossing the Ts and dotting the Is situation on that contract.
Okay, thanks. As it pertains to your 2020 target of 65,000 barrels a day, if you continue to see outperformance from your wells as you did in Q1, how do you think about that target? Would you look to maintain the current level of activity planned for now through 2020, in which case that 65,000 barrels a day would move higher? Or would you look to potentially reduce activity and still achieve that target, in which case maybe that free cash flow could start coming a little earlier?
Yeah, I think the 65,000 barrel a day target is. At this point, we don't have any plans to adjust that number. Even if our well out performance would indicate that, gee, we could maybe beat that 65 and move it to 70 or something. At this juncture, we're not looking to raise that number. If we continue to make wells that turn out to be better than our type curve, what I would expect we would do is that might allow us to hit free cash flow numbers earlier, and help with the financial side of things, as opposed to saying we're likely to raise the volume growth target. You might recall, we just recently raised that volume growth target from 60 to 65, so that's a pretty fresh number.
Right. Okay, thanks. That's it for me.
Okay.
Your next question comes from Daniel McSpirit with BMO Capital Markets.
Thank you, folks. Good morning. As early as this time last year and maybe earlier than that, you spoke to midstream takeaway as the biggest risk to growth. A statement may be more general to the industry than about the company. It sounds like your concerns have not only not lessened but maybe increased. Is that a fair observation, and how bad is it going to get for the industry? That is the worst-case scenario reflected in your own sub-million barrels a day U.S. oil growth forecast?
Yeah, Dan. Our concern, even a year ago, was really on gas takeaway from the Delaware Basin. We still are very concerned on gas takeaway in the Delaware Basin for the period 2019 and 2020. Part of that has really been particularly with Apache's development of Alpine High, which is certainly going to put a lot of gas toward the WAHA hub. I view as a fairly high probability that in 2019 and 2020, there could be a pretty tense situation with gas exiting the WAHA hub from particularly the southern Delaware Basin, that's why we have a very high priority on securing FT both to WAHA and away from WAHA. You heard Sean discuss that at length here just a little while ago.
That has not really played much of a part in my view of the fact that the shales in aggregate are going to disappoint relative to the IEA and EIA estimates. My view is, again, that both the Eagle Ford and the Bakken are a bit long in the tooth, that these parent-child issues in the Permian are going to limit production. The last point is that the pressure from institutional investors to put value over volumes is also going to play a part. I think all of those items are just going to ensure that the total U.S. oil production is going to be a bit less than what people are currently predicting.
In any case where global demand is galloping along at 1.6 to 1.7 million barrels a day per year, I think that's just going to put further pressure on the global crude market, we're seeing that manifestation occurring as we speak. That's just my overview, Dan, of the bigger picture. It's not really related to short-term takeaway positions in constraints in the Permian, per se.
I understand, I appreciate your response, particularly the points about value over volumes. That's a good setup for my follow-up question. What resonates most with me from your prepared remarks is the statement about not aspiring to be the biggest, but the best. That said, how do you manage the inventory to drive better returns at the corporate level, either adding or subtracting to it? How do differentials play into planning location, thinking that maybe some acreage may be allowed to expire or traded as it may not compete for capital?
I'm a big believer in, even though with my previous company, we became the largest shale producer in the U.S. I'm a big believer that M&A is not the way to create the best equity performance. We never did that at my previous company. We're not a big M&A company, and I'm not a big believer at it at CDEV. The best example I can give you here is this Third Bone Spring Sand. I believe that once we get a few more well results to go with our first well result, which is an excellent well result, it's going to show that we've added a significant amount of high ROR inventory, essentially for free. We could have gone the other route.
We could have done an expensive M&A, then issued a press release and said, "Wow, we've added a bunch of inventory in the Permian at 30 or $40,000 an acre." Instead, we will have added a bunch of inventory in the Permian for free. That's, I think, how you build true value in an E&P company. I think we just have a textbook example here with this Third Bone Spring Sand of how you really build a value in an E&P company. Hopefully that gives you a little bit. We'll do some tactical additions, like the WPX Energy deal we announced last quarter in the Northern Delaware, but don't look for us to make a monster M&A to proclaim that we're twice as big in the Delaware as we were last week. That's not the kind of growth that I'm looking to do with CDEV.
Very good. Thanks again. Have a great day.
Okay. Thank you.
There are no further questions. I will now hand the call back over to Mark Papa for closing remarks.
Okay. I have no further closing remarks, and we'll talk to everybody next quarter. Thank you.
That concludes today's conference. Thank you for your participation. You may now disconnect.