Good day, welcome to the Chesapeake Energy first quarter earnings conference call. All participants will be in listen only mode. Should you need assistance, please signal our conference specialist by pressing the star key followed by 0. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then 1 on your telephone keypad. To withdraw your question, please press star then 2. Please note, this event is being recorded. I would now like to turn the conference over to Brad Sylvester. Please go ahead.
Thank you, Chad. Good morning, everyone, thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2019 first quarter. Hopefully, you've had a chance to review our press release and the updated investor presentation that we posted to our website this morning. During this morning's call, we will be making forward-looking statements, which consist of statements that cannot be confirmed by reference to existing information, including statements regarding our beliefs, goals, expectations, forecasts, projections and future performance, the assumptions underlying such statements. Please note that there are a number of factors that will cause actual results to differ materially from our forward-looking statements, including the factors identified and discussed in our earnings release today and in other SEC filings.
Please recognize that except as required by applicable law, we undertake no duty to update any forward-looking statements, you should not place undue reliance on such statements. We may also refer to some non-GAAP financial measures, which help facilitate comparisons across periods and with peers. For any non-GAAP measures that we use, a reconciliation to the nearest corresponding GAAP measure can be found on our website and in our earnings release. With me on the call today are Doug Lawler, Nick Dell'Osso, Frank Patterson. Doug will begin the call then turn the call over to Frank and Nick for a review of our operational and financial results before we turn the teleconference over for Q&A. With that, thank you, I will now turn the teleconference over to Doug.
Thank you, Brad, good morning. Next month, I'll record my sixth anniversary at Chesapeake Energy, I am as excited today as I ever have been. Over the past six years, our strategy, commitment, tenacity to drive differential top quartile performance for our shareholders has been consistent, strong, vibrant, regardless of external or internal challenges. I'm very proud of our progress, accomplishments, I'm excited about the future trajectory of the company. During these transformation years, we have shared our significant progress on debt, obligation reductions, operating, capital efficiencies, profitability improvements, the simplification of our business. Importantly, for the last 16 quarters in a row, we have met or exceeded the street's consensus earnings estimates, demonstrating the strength of our employees, asset portfolio, strategy.
We have consistently executed and performed as we have projected, and we will continue to sharpen and improve our business delivery to drive greater value for our shareholders. The foundational improvements in our balance sheet, capital efficiency, and cash-generating capability, combined with our operational expertise and scale, have positioned the company to accelerate our rate of improvement and value creation from our diverse asset base. In the first quarter, Chesapeake continued to execute on its strategic priorities, delivering yet again strong financial and operational results. As we look at our performance, no asset exemplifies the energy, talent, and conviction of our employees to deliver significant change in a short period of time better than our new Brazos Valley asset, an asset we now project will be cash flow positive at the asset level this year.
During the last three months, we have rapidly integrated the new asset into our portfolio, eliminating approximately $500,000 in cost per well with improved drilling and completion techniques, highlighted by new records in drilling rate of penetration and number of fracture stimulation stages completed in a day. On several wells in Brazos Valley, we have already achieved capital cost improvements of more than $1 million per well. As you would expect, and as you know from our track record with our other assets, we will achieve further capital efficiencies in the future on an average well and full program basis. We are pleased with our savings and production improvements to date in Brazos Valley, and as we will share further in a moment, we believe there are additional opportunities to improve the returns and cash flow generating capabilities of the entire portfolio.
We averaged oil production of approximately 109,000 barrels per day in the first quarter, representing 18% in absolute growth compared to last year and 22% of our total production mix. That compares to 19% in the fourth quarter of last year. We remain on track to deliver the transformational 32% absolute oil growth we guided to in February, ultimately reaching a year-end oil production mix of approximately 26% of total net production. More importantly, our increase in oil production, along with our focus on reducing our costs, continue to improve our competitiveness and cash flow generating capability. We believe the rate of change in our cash flow is already noticeable in 2019. As we look ahead to the rest of the year, our talented employees are focused on delivering our strategic priorities and creating more value for Chesapeake while maintaining our safety and environmental leadership.
We look forward to sharing more of our progress with you throughout the year. With that, I'll now turn the teleconference over to Frank to cover additional operational and asset level detail.
Thank you, Doug. Good morning, everyone. As Doug mentioned, we're very pleased with the progress our team has made in just a little over 90 days integrating Brazos Valley into our portfolio
We are learning a lot. I'm pleased with what we've seen so far. On the production side, we have already started to redesign completions, namely by reducing fluids used and maintaining sand volumes combining this with better choke management on flowback. Early results are extremely encouraging as seen on the Easy Rider pad in Burleson County, where our choke management efforts have already delivered a 35% initial production uplift to historical wells in the area. Once we start to integrate longer laterals, we believe the results will only get better. The Bell pad in Burleson County represents our first true grassroots wells, and early results are promising. Filled with an average lateral length of 7,000 feet and completed with a reduction of 2,000 to 4,000 fewer barrels per completion stage.
This four-well pad was turned in line in late April and has reached a 24-hour production rate of over 2,700 barrels of oil per day. Production is still climbing. Comparing to other modern completions in this part of the field, this represents over 190% improvement in early flowback. When we took over operations February 1st, a majority of the rigs were working in the gas window of the Austin Chalk. We have now altered course, transitioning all four rigs to the oil window of the Eagle Ford, which we expect will result in our oil volumes picking up speed beginning in or around the third quarter. With costs dropping quickly and an increase in our projected 2019 volumes, we're right on schedule. As a result, at current strip prices, Brazos Valley now projects to be cash flow positive on an asset operating level this year.
This is a monumental feat for our team. We look forward to keeping you updated throughout the year on our continued progress. In our legacy Eagle Ford position in South Texas, we continue to generate significant free cash flow through steady high-margin oil production. Over the last 18 months, the South Texas team has focused on improving capital efficiency through the implementation of appropriate spacing and completion design, resulting in consistent oil volumes and markedly improved production declines. New well performance and a base production focus have driven very strong results. We see more opportunity available on the base optimization side. We have recently reallocated capital away from the Mid-Con and Marcellus areas and have redirected it to the Powder River Basin, adding a sixth rig to our program.
That rig began drilling in the Turner Formation this week and will transition to the Niobrara later in the year. As you may recall, the last four Niobrara completions in the field are some of the best-performing wells in the basin. We believe longer laterals and enhanced completions will unlock the full value of this play that underlies the majority of our leaseholds. The team's excited to move to the next phase of unlocking the value of the stacked pay in the Powder River Basin. Our Powder River operations have rebounded from the weather delays, which hampered operations and resulted in temporarily reduced production during the first quarter. As we have exited winter, operations are back to normal, and in April, we averaged approximately 39,000 BOE per day, including 18,000 barrels of oil.
As we enter the second week of May, our Powder River production continues to grow at a steady pace, reaching a new production record of approximately 42,000 BOE per day, including 20,000 barrels of oil Monday of this week. This recent rate was driven by a five-well DV pad and a new RRC well, which reached over 4,000 BOE per day, 75% of that was oil. This 24-hour single-well rate represents the highest oil rate in our PRB play to date. The RRC pad also produced the first barrels of oil down our new oil gathering pipeline over the weekend. We have initiated construction of our first central production facility, which will continue to drive costs down and promote efficiency. A majority of our 2019 drilling program will be near that new CPF, which is also the highest oil cut portion of the Turner play.
On the gas side of our operations, Chesapeake continues to generate significant free cash flow from the Marcellus Shale. We achieved a record daily gross production level of 2.5 Bcf a day in January, which resulted in a record average net production of 948 million cubic feet of gas per day during the first quarter. Appropriate spacing, enhanced completions, and longer laterals continue to be game-changers in the Marcellus. Given our continued improved well performance and our commitment to a disciplined capital expenditure program, we plan to drop a rig in the Marcellus in June. Combined with the planned decrease in drilling activity in the Haynesville, this means we anticipate averaging only three rigs in our gas assets for the second half of the year. All but one of these drops was contemplated in the original budget plan.
I stated earlier that Marcellus capital will be redeployed to the Powder River. Our field development program continues to impress in the Haynesville, yielding results highlighted by a recent two-well pad with initial flowback results exceeding 80 million cubic feet a day. Finally, in the Mid-Continent, we are taking a pause to review and interpret newly acquired 3D data, which we'll use to help high-grade our drilling inventory in anticipation of an increased activity next year. As we look towards the rest of the year, we will maintain our focus on capital discipline while continuing to allocate the majority of our capital to our oil assets, which we believe will drive substantial improved margins in 2019.
The momentum we have established quarter-over-quarter continues to grow. We look forward to continued program delivery. With that, I'll turn the telecom over to Nick to review our financial performance.
Thank you, Frank. Good morning, everyone. Compared to street estimates, we had an excellent first quarter in almost every measure. Our trend of generating higher margins continues, primarily driven by the strong oil production that Doug and Frank highlighted. Increased oil as a percentage of total production and lower operating expenses, which resulted in the best adjusted EBITDAX margin for BOE of production we've recorded in over four years. As Doug highlighted, our production stream for the first quarter was 22% oil compared to 19% in the 2018 fourth quarter and 17% oil a year ago. While the first quarter is traditionally our highest EBITDAX quarter for the year, it's important to note that margin improvements we're recognizing are not simply a function of oil price.
Our mix will continue to shift to oil throughout 2019 and 2020 as the Powder River Basin and Brazos Valley grow and have a greater contribution to the total. We expect to exit the year around 26% oil. The margin of this higher oil content is meaningful with our oil assets approximating $30 per BOE EBITDAX margin, led by the Brazos Valley reaching over $37 per BOE due to its low-cost structure and access to Gulf Coast premium pricing. The bottom line result is that while our capital program is lower than last year and commodity prices are currently forecasted to be lower for the full year, Chesapeake will deliver greater cash flow due to our improved oil mix and cost structure. Our cash operating cost structure improved over the first quarter by approximately $81 million, driven by continued improvement in our GP&T expenses.
Our GP&T expense of $6.29 per barrel equivalent was more than $1 per barrel lower than the 2018 average, driven by asset sales in 2018 and midstream and downstream contract restructuring. In the Powder River, we have begun to connect pads to our new oil gathering system. We estimate this will increase our certainty of delivery, improve our flow back and production management efforts, and ultimately lower our oil gathering expense in the field by approximately 75% going forward. In the Brazos Valley, our relatively low GP&T costs are contributing to the improved company averages. We are working with several third-party midstream and downstream providers to further reduce these costs. We currently expect an improvement of over $250 million in our GP&T line item in 2019 over 2018.
As seen in our press release this morning, we moved to the successful efforts method of accounting for oil and natural gas properties beginning this quarter. As you would expect, the primary changes in our financials when compared to the full cost method are a reduction in reported CapEx, with these costs moving to the income statement in the form of exploration expense, G&A, and interest expense. We will also have an increase in our DD&A rate due to less impairments under the successful efforts method compared to full cost. Our 10-Q and 8-K restating our previously filed 10-K will have additional detail along with a brief presentation we will post to our website on the changes. Brad or I would be happy to answer any further questions on this accounting change.
We've updated guidance this morning, which moved previously capitalized G&A and interest costs from capital expenditures to the income statement. We reduced our 2019 CapEx guidance by approximately $200 million to a new range of $2.1 billion-$2.3 billion for 2019, offset by G&A interest expense and a new line for cash exploration expense. Importantly, given the tailwind of higher oil prices in the quarter, along with approximately $100 million of asset sales proceeds closed or pending, we are closing the free cash flow gap significantly for the year. On the balance sheet side, in early April, we exchanged approximately $884 million of senior notes due 2020 and 2021 for $919 million of new 8% senior notes due 2026. This maturity extension left very manageable debt maturities in 2020 and 2021 of approximately $300 million per year.
In April, we also repaid at maturity $380 million principal amount of floating senior notes using borrowings under our credit facility. On the liquidity front, as of March 31st, we had borrowing capacity of approximately $2.1 billion under our $3 billion Chesapeake credit facility and approximately $565 million under the $1.3 billion Brazos Valley credit facility. We will look to retire additional maturities through cash flow generation and smaller asset sales. We look for market conditions that are conducive to refinance maturities. We have a robust hedge portfolio in place with approximately 70% and 80% of our remaining 2019 oil and natural gas production hedged, with downside protection at average prices of $58.75 per barrel and $2.83 per Mcf respectively. We also have 250 Bcf of gas and 13.2 million barrels of oil hedged at $2.75 per Mcf and $60.10 per barrel respectively for 2020.
Additionally, we have locked in Gulf Coast pricing for approximately six million barrels of our Eagle Ford volumes at a premium of approximately $5.69 to WTI and LLS pricing. To close, we're off to a great start in 2019 and are pleased to see our returns on capital invested continue to grow and cash flow continue to improve. Cost savings are being captured. Our production is on track to deliver significantly more oil as we roll into 2020. Operator, we'll now turn the call over for questions.
Thank you. We will now begin the question and answer session. To ask a question, you may press star then one on your telephone keypad. If you're using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star, then two. We please ask that you limit yourself to one question and one follow-up. If you have additional questions, you may re-enter the question queue. At this time, we will pause momentarily to assemble our roster. The first question will be from John Freeman with Raymond James. Please go ahead.
Good morning, guys.
Morning, John.
You all have made significant progress in a short time on the Brazos Valley, now it looks like you're spending about $40 million less than what you all previously thought. You're still going to bring online a couple more wells than previously expected. Can you just give us some color on what's embedded in the current guidance now in terms of where completed well costs are now, and if that's reflected, leading-edge wells reflected in the current CapEx allocation?
Yeah, sure, John. Frank and I will both comment on that. As you'd expect, we're super excited about the Brazos Valley asset and knew going into it that with the acquisition and the excellent work that had been done there by WildHorse, that there would be opportunities to take what we've learned elsewhere in our portfolio and apply it to Brazos Valley, and particularly with some of the completion efficiencies, stage efficiencies, and synergies that with our contractors and the way we approach our business could help drive those costs down. Up to this point in time, as we have shared, we firmly recognize $500,000 per well, of which there is a portion of that that is mostly drilling at this point in time.
With what we've been testing with some additional stages and longer laterals, the completion costs probably only represent about 20%-30% of that $500,000 at this point. That said, we still see a significant opportunity there, and I'll let Frank comment further on that.
John, I'd just like to point you to slide eight in the deck that we put out with the press release today. We've seen a pretty substantial lateral length increase, which was our plan. Historically, the lateral lengths were around 5,000-6,000 feet. We're pushing those lateral lengths out to somewhere around 9,200-9,300 feet for the year. We're way ahead of schedule on that. Our costs are coming down on a per-foot basis about 20%, as you can see on that. As Doug said, we're still working with the completion design, but the big game changer is the kind of Chesapeake methodology of getting stages put away. We've seen a 60% increase on stage count per day. If you look at Eagle Ford wells, you're probably looking at that range of $7.4 million-$8 million this year.
We think we can get it down a little bit lower than that going forward. We have some things that we want to try to mitigate some hole conditions that we see that cause us a little bit of extra time. When we go to the Austin Chalk, those wells require a little bit bigger frac jobs. I would say you're looking at probably an $8.4 million-$8.8 million type cost there. We're not going to drill a lot of Austin Chalk. 2019 and 2020 will be very focused on the Eagle Ford.
Great. Just want to follow up. Any update on the plans for a Brazos Valley gathering system? I know WildHorse was looking at having a system built, and I believe you all mentioned that you all are probably going to put that out to bid to third parties. Just any update?
Yeah, we do expect to put that out to bid to third parties relatively soon. We're just working through a bunch of logistics and planning for that.
Great. I appreciate it, guys.
Thanks, John.
The next question comes Biju Perincheril with Susquehanna. Please go ahead.
Hi. Good morning, all. Doug, I know you don't have any 2020 guidance out yet, looking at the tilt schedule and the momentum you have in the fourth quarter, looks like you have a lot of momentum going into 2020. Can you say anything about how you see the oil production progressing through next year?
Yeah, sure. That's a good question, Biju. I'm glad you asked it. When we first acquired WildHorse and have been integrating it into our portfolio, we had provided some certain estimates of what we thought rig activity would be, and we actually have recognized a lower rig count in response to commodity prices and our pursuit of free cash flow neutrality and generating free cash flow as quickly as possible. As Nick had highlighted, we anticipate to narrow that gap significantly and look for further improvements in 2019. The capital efficiency of the program and the rig activity and completion activity are largely geared towards how we continue to strengthen the entire company, not looking at just one or a single metric.
As that rolls into 2020, though, we are very excited about the efficiencies that we've accomplished, and as Frank noted, getting more from every rig in terms of capital employed, as well as more wells drilled and completed because of our efficiencies. Just it's a historical competitive advantage for this company, and we continue to recognize those improvements, and we're using that to help position us for greater oil volumes in 2020. While we have not put guidance out yet for 2020
Under the revised circumstances that we've recognized with the capital spend and the rig activity, we're encouraged about that profile and our 75% or 80% capital directed towards the oilier assets. You can expect similar levels of investment in 2020 and then continued growth in our oil.
That's very helpful. My follow-up was, at least looking at where 1Q numbers came in versus what I was modeling, one of the areas of positive surprise was legacy Eagle Ford oil. You touched on, in the presentation, some of the wider space wells. Last quarter, I think you talked about a lot of the work you've done on minimizing downtime, I was just wondering if you could just give a broad breakdown of how much of the improvement in Eagle Ford is from the productivity gains on the wells versus minimizing downtime and
Biju, this is Frank. I think it's really hard to say because as you recall, we went in and did a lot of work on spacing two years ago and determined that the down-spacing was really detrimental to the wells. What we're seeing now as a result of that work, there's actually a slide that kind of demonstrates it on page 13 of our deck. We've now re-spaced the field to the appropriate spacing for the rock type and the fluid type, we believe. We've also changed the completion design for each of those phases to maximize the recovery from the field. If you look at parent wells back when the field was first being developed and use that as a baseline, our new wells are performing at about 95% of parent. We think that's a real positive sign.
That gives us early production volumes on the wedge wells, it also reduces the decline rate on those wells in the out years. We're seeing good performance on the early wells, good performance on the wells once they go into the base. Then we're applying a lot of new technology and concepts to manage our downtime. It's a combination of all, I don't think you can go in and discretely break it out. I think what it is we are doing a really great job in the field and here in the office with the engineering team, basically managing this field for optimum results.
Great. Thank you.
The next question will be from Subash Chandra with Guggenheim Partners. Please go ahead.
Yeah, thanks. Hey, Doug. Happy sixth anniversary. This one certainly feels different from the outside. Congrats on the quarter. When I look at the PRB activity levels, and I think you have a few more wells completing this year, curious if that changes the outlook for PRB oil growth, which was previously provided?
Not at this point in time. Subash, we're encouraged, we're excited. Some of the activity and the way we've been continuing to optimize the drill schedule with the improvements that we've recognized. We're super excited about some of the rates, and as Frank noted, the total pad production here, recent performance is very encouraging. I would rather look at that and encourage you to look at it as upside rather than us putting a number on it at this point in time, and just asking you to continue to look at the track record as you've done of this company and the trajectory that we're on there. We should see continued improvements. Sharing those recent well results and some of the pad volumes are good indicators of directionally where we think we'll be going.
I'm going to try and jam a few questions into my follow-up. In Brazos Valley, am I thinking about this correctly that you're looking at all these production enhancements, spacing, and so on and so forth. This year, it's pretty much whole production volumes fairly flat, with an eye towards driving growth in 2020. If that's paired by lower Marcellus/Haynesville activity, that sort of gets you to that 30% type oil cuts for next year?
Yeah, that's essentially correct.
Okay. Brazos, would that require more rig activity to drive that growth beyond what you have or
It's actually the capital efficiencies that we expect to achieve or doing more with less, and actually seeing capital reductions in that program, as noted by the fact that we expect the asset level to be cash flow neutral or slightly positive there this year. That's more the indicative direction of how we expect to do more with less based on the capital efficiencies that we're achieving and recognizing.
Yeah. Subash, this is Frank. Just to give you a little bit more color on Brazos Valley, we've been working this a little over 90 days now. Most of the drilling activity was predetermined by the previous operator. We've been basically taking what was already planned and trying to correct course to the direction we want to go. We're really not seeing our full on plan yet.
We also have not taken the course that we need to take to get our reservoir characterization and our completions tweaked up. That will be happening in the next couple of months. On the wedge side, the wells that are the wedge wells, we're about where the budget was planned, and it's close. We're a little bit behind because of some delays getting off the Austin Chalk wells. What's been the real surprise is the base production. We have really changed the base production trajectory here. We think that bodes really well, because if we can change the base production, which is a pretty large number, and then we can move to the type of drilling and completion program we want, we probably can do exactly what we want to do or said we were going to do with 5 rigs, with 4 rigs.
That's a wag on my part right now, but I think it looks really good. We have not seen this thing hit its efficiency stride yet.
Okay. Good call it. Thanks, guys.
The next question comes from David Heikkinen with Heikkinen Energy Advisors. Please go ahead.
Hey, Frank. Actually, you just set up the question. Basically, you think you'll have a 20%+ improvement in wells per rig per year in Brazos Valley, kind of heading into next year with that four versus five rigs comment?
David, you know that we're also moving to longer laterals. The wells, what we're seeing is that with the penetration rate that we've been able to improve, we are getting basically a long lateral for the same time and cost of a short lateral. I think that's where we're headed. Yeah, that's about a 20% increase if you just think about it that way. I think there's still some room to go. The drilling team is working on some opportunities to potentially change out the well bore design. That could actually give us a little bit more. I think the other side of the equation is going to be on the completions. I think we still have room to go there, and I think we can optimize those completions.
The other thing is, we're not ahead right now, but we will get ahead on the facility side. This thing will start running a lot faster.
Your cost per foot comes down, and essentially, you have a long lateral for the time of a short lateral. Okay. I just want to make sure that was right. Do you think you'll see the same improvement in the Powder as you get to a scaled program of?
I think we'll
cost?
Yeah, I don't think we'll see the dramatic change you're going to see in Brazos Valley because we've been working the Powder for a couple of years now. We will see improvement. The big improvement on the Powder side, I think, is going to actually happen on the surface, because when we get to the central production facility and the oil and water gathering system put in place, I think that's going to allow us to really optimize the field development. As we've noted in the call, we had some weather delays. It snows, and it gets bad in Wyoming, and we're trucking all of our oil and all of our water, and when they shut down the highways, we're shut in. Once we get on pipe, now we have this consistency of development and production. I think we're moving in a really positive direction in Powder very quickly.
We will not see as big an improvement there because we've already seen pretty good improvement.
Don't model winter weather as significant next winter with the gathering? Okay.
Yeah. The model should be a lot more consistent next year once we get on pipe. The only thing we'll have is crews and equipment moving to rigs and to completion.
Cool. Thanks, guys.
The next question will be from Neal Dingmann with SunTrust. Please go ahead.
Morning, all. Nice. Great progress, guys. Doug, just maybe building on a little bit what Biju had asked earlier a little bit. You guys have done a nice job of quickly reducing your outspend, even while adding the WildHorse deal. Understanding, I think as Biju mentioned, that not having the full 2020 guidance out, can you talk more in just broad terms how you envision next year kind of going forward, the outspend and thus your leverage? I know you mentioned the prepared remarks, trying to get it down to two times. I guess it's more about the outspend. Is there an inflection point that you could talk about the next year or two hitting or anything you could give around that? Thanks.
Sure, Neal. The progress of the company with that respect has been really, really strong. As I think anyone would agree and attach to the progress we've made there has been quite significant and quite substantial. As Nick highlighted, we are narrowing the gap in 2019 and extremely encouraged. We see a minimal amount of smaller asset type sales, further productivity improvements, and basically, we're going to cross that
Bridge pretty quickly at being free cash flow neutral and ability to generate greater positive cash flow. In that time frame, we've not been specific. It's highly dependent upon price. We continue to put hedges in place to protect our capital program. The quality of the assets continue to outperform, and the way to look at it, Neal, is that it's very close. Very close. The underlying business here is powerfully strong, and the capital efficiencies continue to improve. As I've highlighted before, the accomplishments of this company over the past five years compare to no other. What you can expect is that this challenge of our debt reduction and achieving 2 times net debt to EBITDAX continues to be a major focus for us. It's essentially our number one priority, and we will continue to make progress on it.
The way that we are approaching it is through the excellent work being done with our current assets and looking for other smaller asset sales or other opportunities for us to strengthen our portfolio to continue to achieve that free cash flow neutrality, generate positive free cash flow and reduce that overall quantum of debt.
One last one just on looking over at the PRB. Obviously amazing well, that Turner well you all spoke of, the 4,000 with not only the big rates, 75% oil. Looking at slide 16, maybe Doug, for you or Frank, just wondering, can you give me a sense of when you all now look at your 213,000 acres, just the type of prospects you see as far as, just trying to get a sense of, is there a large area that can continue to have these phenomenal type wells or now that we've seen, again, not only the size, but just the oil cut behind that. I'm wondering as you're looking at the entire play.
Yeah, Neal, this is Frank. If you look at that map on 16, we put a star out there where the central production facility is. That whole northwestern portion of the field is high oil cut. As you get down into the meat of our acreage around that CPF, those wells are going to be big wells. Now, are they all going to be 4,000 barrels a day? No. We're seeing some variability, but they're all really strong wells, and when you take a look at them relative to other oil wells in the U.S., the Turner wells stack out pretty high in that stack. I think you're going to see us spend a majority of our time out on that northwest part of the field.
We will only drill a few wells over in the gassier area to maintain acreage, because there's also Niobrara and Mowry available to us in that acreage as well. We don't want to lose the acreage. The map is really deceiving, and I had them put a scale on here, but we have a huge acreage position here that's all contiguous. We have a lot of running room here in the Turner left. I'm really excited about getting into the Nio as well, because now we'll be able to stack the Nio right on top of that Turner.
That's a great detail.
The other thing, don't forget that we may see something better than 4,000 barrels equivalent a day.
It's just while we talk about excitement around that well, the continued improvement and say, "Well, are you going to stamp every well at 4,000?" You're going to have variability naturally, but we're excited enough and encouraged enough, there may be something better than that. Don't take that out of the equation either.
Wow, that's great to hear. Thanks, guys.
The next question will be from Charles Meade with Johnson Rice. Please go ahead.
Morning, Doug, Frank, and to the rest of the team there.
Morning, Charles.
If I could go back to that Brazos Valley completion. Could you elaborate a little bit more on what led you to go with this different completion design with the lower fluid volumes and higher sand concentration? Is this an experiment or is this close to what you think your final design is going to be and when are we going to know? When will you know if you struck on the right design?
You go ahead. Well, I just say it's all in a day's work at Chesapeake, Charles. Everything we look at is continued improvement in how we get better, how we take our learnings from elsewhere to the new asset. Basically, the sand concentrations are roughly the same. What we've principally reduced with the fluid, and we're going to continue to optimize and pull the levers that we know will be successful and what we've learned elsewhere. Frank can build on that.
Charles, I think when we talked to you and everybody on the call about this acquisition, one of the things we said was that the spacing needed to be spaced out wider to about 1,000 feet. We have now gone in and done a bunch of looking at wells, what it appears is that you need the sand concentration because the clay content is higher in this rock, we knew that. WildHorse had done a fantastic job discerning that. What was happening was there was a ton of fluid being pumped in every stage. What that was causing was really long frack wings, those frack wings were reaching out and basically interfering with each other. What we've done is we've used the same sand amount, but at higher concentration, pumping it away with a lot less fluid. That does a couple things for us.
It increases the complexity near the wellbore and shortens those frack wings. We might actually be able to see a spacing change once we understand the storage capacity here. The other thing about it that's really important is these wells took a ton of time to flow back because of the water that was being used.
We're going to be able to reduce the cost of pumping the jobs because less water. We're going to have a shorter flow back period, and we're going to have a stronger, earlier oil cut. Everything we've done, I think, is going to maximize or improve the economics of the wells. Are we at the endgame here? No. We probably have some other things we can work on, but this is a really good start, and we're encouraged by what we're seeing on the initial tests.
That's great detail, Frank. Thank you. If I could ask a follow-up on your CapEx in your overall portfolio. Doug, you mentioned that you have, what, 75%-80% of your CapEx going to oily plays. On the other side of that, you guys have really core, kind of center of the bull's eye positions in really the two dry gas plays that are really working right now, the Haynesville and the Marcellus. There've been some news reports in the last few days of Saudi Aramco trying to team up with Equinor to get into the North American natural gas market. Could you talk about how you see those two dry gas plays, the Haynesville and Marcellus? What role they're going to play in your portfolio, not in 2019, but in 2020 and beyond?
Sure, Charles. Those two assets are world-class. You got a world-class operator that can mobilize to develop those resources really quickly. We'll continue to monitor pricing environment, the LNG build-out. As more gas gets on the water, as additional demand makes sense, economically makes sense, Chesapeake will react accordingly and adjust our program accordingly. They're super strong assets. Extremely well run here corporately and particularly in the field. We can revise and modify and flex our capital at any point in time as economic conditions dictate.
Got it. Thank you, Doug.
Ladies and gentlemen, this concludes our question-and-answer session. I would like to return the conference to Doug Lawler for any closing remarks.
Yeah, thank you. I appreciate everyone's time today. In our prepared comments, we made several references to rate of change or rate of improvement. I just want to close today by highlighting that the underlying business continues to see excellent progress. While we have accomplished a great deal over the past few years, the portfolio, the capital allocation, and how we're approaching our business, the excitement that we have, the encouragement we have to continue the rate of change and rate of improvement across our portfolio is something that we are really pleased about and really excited about. I think it's differential. I believe that the company's performance continues to reflect a well-run organization and one that's going to deliver more value to our shareholders disproportionately in the future.
I thank you for everyone's time, and if there's additional questions, please follow up with Brad, and we'll respond accordingly.
Thank you, sir. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.