Chesapeake Energy Corp (CHK) 2019 Q1 法說會逐字稿

Good day, and welcome to the Chesapeake Energy first quarter earnings conference call.

(Operator Instructions) 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, and 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 and 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, and you should not place undue reliance on such statements.

We may also refer to some non-GAAP financial measures, which help to 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 and Frank Patterson.

Doug will begin the call and 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.

So with that, thank you, and I will now turn the teleconference over to Doug.

Thank you, Brad, and good morning.

Next month, I'll record my sixth anniversary at Chesapeake Energy, and I'm as excited today as I ever have been.

Over the past 6 years, our strategy, commitment and tenacity to drive differential top quartile performance for our shareholders has been consistent and strong and vibrant regardless of external or internal challenges.

I'm very proud of our progress and accomplishments, and I'm excited about the future trajectory of the company.

During these transformation years, we've shared our significant progress on debt and obligation reductions, operating and capital efficiencies, profitability improvements and 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 and strategy.

We've 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 continue to execute our 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 3 months, we've 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 in 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 the year-end oil production mix of approximately 26% of total net production.

But more importantly, our increasing oil production, along with our focus on reducing our cost, 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 into -- Brazos Valley into our portfolio.

We are learning a lot and I'm pleased with what we've seen so far.

On the production side, we've already started to redesign completions, mainly by reducing fluids used maintaining -- and maintaining sand volumes and combining this with better choke management on flow back.

Early results are very -- are extremely encouraging and 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.

Drilled with an average lateral length of 7,000 feet and completed with a reduction of 2,000 to 4,000 fuel barrels per completion stage.

This 4-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 and production is still climbing.

Comparing to other modern completions in this part of the field, this represents over a 190% improvement in early flowback.

When we took over operations February 1, the majority of the rigs were working in the gas window of the Austin Chalk.

We've now altered course, transitioning all 4 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 are 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, and 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, and we see more opportunity available on the base optimization side.

We have recently reallocated capital away from Mid-Con and Marcellus areas and have redirected it to the Powder River Basin, adding the 6th 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 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 leasehold.

The team is excited to move to the next phase of unlocking the value of this stacked pay in the Powder River Basin.

Our Powder River operations have rebounded from 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 5-well BV 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 today.

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 efficiencies.

The majority of our 2019 drilling program will be near that new CPF, which is also the highest oil cap 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 plan to decrease in drilling activity in Haynesville, this means we anticipate averaging only 3 rigs in our gas sales assets for the second half of the year, although one of these drops was contemplated in the original budget plan.

As stated earlier, the Marcellus capital will be redeployed to the Powder River.

Our field development program continues to impress in the Haynesville, yielding results highlighted by 2 recent -- by a recent 2-well pad with initial flowback results exceeding 80 million cubic feet a day.

While we drop a rig from the Haynesville this month, the team remains focused on optimizing base production and increasing our competitiveness by driving additional costs out of our operations.

And finally, in the Mid-Continent, we are taking a pause to review and interpret newly acquired 3D data, which we 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, and we look forward to continued program delivery.

With that, I'll turn the teleconference 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 per BOE of production we've recorded in over 4 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 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 assets approximately -- 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 mainstream and downstream contract restructuring.

In the Powder River, we have begun to connect pads through our new oil gathering system.

We estimate this will increase our certainty of delivery, improve our flowback 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, and 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 2018 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 low 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.

Later, I would happy to answer any further questions on this accounting change.

As a result, we've updated guidance this morning, which moved previously capitalized G&A and interest costs from capital expenditures to the income statement.

As a result, we reduced our 2019 CapEx guidance by approximately $200 million to a new range of $2.1 billion to $2.3 billion for 2019, offset by G&A, interest expense and our 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 free cash -- closing the free cash flow gap significantly for the year.

On the balance sheet side in early April, we exchange 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 31, 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'll look to retire additional maturities through cash flow generation and smaller asset sales and we look for market conditions that are conducive to refinance maturities.

We have a robust cash 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 barrel per Mcf and $60.10 per barrel respectively for 2020.

Additionally, we have locked in Gulf Coast pricing for approximately 6 million barrels of our Eagle Ford volumes at a premium of approximately $5.69 WTI NYMEX pricing.

To close, we are 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, and our production is on track to deliver significantly more oil as we roll into 2020.

Operator, we will now turn the call over for questions.

(Operator Instructions) The first question will be from John Freeman from Raymond James.

You've made significant progress in a short time on the Brazos Valley.

And 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 of more wells than previously expected.

Can you just give us some color on kind of what's embedded in the current guidance now in terms of where completed well costs are now?

And if that's reflected -- leading edge well reflected in the current CapEx allocation?

Yes, Sure, John.

Right now, both comment on that -- as you'd expect, we are super excited about the Brazos Valley asset and knew going into it that with the acquisition and 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 efficiency, 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.

Because with what we've been testing with some additional stages and longer laterals to completion costs, probably only represent about 20% to 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 8 in the deck that we've put out with the press release today.

And we've seen pretty substantial lateral length increase, which was our plan.

Historically, the lateral lengths were around 5,000 to 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 bases about 20% as you can see on that.

And then 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 to $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 try to mitigate some hold conditions that we see that causes a little bit of extra time.

And then 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 to $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.

And then I just want a follow-up.

Any update on the plans for Brazos Valley gathering system?

I know WildHorse was looking at having a system built, I believe.

You all mentioned that you're probably going to put that out to bid to third parties.

Just any update.

Yes, we do expect to put that out to bid to third parties relatively soon.

We're working through a bunch of logistics and planning for that.

The next question comes from Biju Perincheril with Susquehanna.

Doug, I know -- you don't have any 2020 guidance out yet, but looking at the total 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?

Yes, sure.

It'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 generating free cash flow as quickly as possible.

As Nick highlighted, we anticipated to narrow that gap significantly and look for further improvements in 2019.

So that 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 1 or 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.

So 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, it's -- we are 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 continued growth in our oil.

That's very helpful.

And my follow-up was, I'm just looking at what 1Q numbers came in versus what I was modeling.

One of the areas of positive surprise was Eagle Ford legacy, Eagle Ford oil.

And you touched on, in the presentation, some of the wider space wells, and last quarter, I think you talked about a lot of the work you've done on minimizing downtime.

And 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...

So 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 2 years ago and determined that the down spacing was really detrimental to the wells.

So what we're seeing now as a result of that work, there is actually a slide that kind of demonstrates in on Page 13 of our deck.

We've now respaced the field to the appropriate spacing for the rock type and the fluid type, we believe.

And we've also changed the completion design for each of those spaces to maximize the recovery from the field.

So 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.

And we think that is -- that's a real positive sign.

That gives us early production volumes on the wedge wells, but it also reduces the decline rate on those wells in the out years.

So we're seeing good performance on the early wells, good performance on the wells once they go into the base.

And then we're applying a lot of new technology and concepts to manage our downtime.

So it's a combination of all.

And I don't think you can go in and discreetly 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.

The next question will be from Subhasish Chandra with Guggenheim Partners.

Doug, happy sixth anniversary.

This one certainly feels different from the outside.

So congrats on the quarter.

And when I look at the PRB activity levels, and I think you have a few more wells completing this year, curious if that changes your -- the outlook for PRB oil growth, which was previously provided?

Not at this point in time, Subash.

We are 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 were super excited about some of the rates and as Frank noted, the pad -- 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.

And sharing those recent wells results and some of the pad volumes are good indicators of directionally where we think would be going.

Okay, got it.

And I'm going to try and jam a few questions into my follow-up.

But 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.

So this year, it's pretty much oil production volumes fairly flat with an eye towards driving growth in 2020?

And then if that's paired by lower Marcellus Haynesville activity, that sort of gets you to 30% type oil cuts for next year?

Yes, that's essentially correct.

Okay.

So 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 are doing more with less and actually seeing capital reductions in that program is noted by the fact that we expected the asset level to be cash flow neutral or slightly positive there this year.

So 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.

Yes, Subash, this is Frank.

So 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.

So we've been basically taking what was already planned and trying to correct course to the direction we want to go.

And so we're really not seeing our full-on plan yet.

We also have not taken the cores that we need take to get our [reservoir] characterization and our completions tweaked up, that is -- that will be happening in the next couple of months.

So on the website, the wells that, the wedge wells, were about where the budget was planned and it's close.

We're little bit behind because of some delays getting off the Austin Chalk wells, but 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.

And that's a lag on my part right now, but I think it looks really good.

So we have not seen this thing hit its efficiency stride yet.

Our next question comes from David Heikkinen with Heikkinen Energy Advisors.

Frank, actually you just set up the question.

So basically, you think you'll have a 20%-plus improvement in wells per year in Brazos Valley heading into next year with that 4 versus 5 rigs comment?

So David, you know that we're also moving to longer laterals so the wells, what we're seeing is that with the penetration rate that we have been able to improve, we are getting basically a long lateral for the same time and cost for the short lateral.

And I think that's where we're headed.

So yes, that's about 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 wellbore design that could actually give us a little bit more.

But 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, so this thing will start running a lot faster.

So the cost per foot comes down and essentially, you have a long lateral for the time of a short lateral.

So you're -- okay, 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?

I think we'll -- yes.

Yes, I don't think we will see the dramatic change we're going to see in Brazos Valley because we have 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 was really -- it snows and it gets bad in Wyoming and we are trucking all of our oil and all of our water.

When they shut down the highways, we are shut-in.

Once we get on pipe, now we have this consistency of development and production.

So I think, we're moving in a really positive direction in Powder, very quickly.

We will not see as big of an improvement there, because we've already seen pretty good improvement.

So don't model winter weather as significant next winter with the gathering.

Okay.

Yes.

The model should be a lot more consistent next year once we get on pipe.

Then, the only thing we'll have is crews and equipment moving to rigs and completion.

Our next question will be from a Neal Dingmann with SunTrust.

Doug, just maybe building on a little bit Biju had asked earlier, a little bit, you guys have done a nice job of quickly reducing the outspend even while adding the WildHorse deal.

So understand, I think I think that Biju had mentioned that not having a 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 in the prepared remarks trying to get down it down to 2 times, so I guess it's more about the outspend, is there an inflection point that you could talk about the next year or 2 hitting or anything you could give around that?

Yes, sure Neal.

The progress of the company with that respect has been really, really strong as I think, any -- anyone would agree and attach to the progress we've made there has been quite significant and quite substantial.

We are -- as Nick highlighted, we are narrowing the gap in 2019, and extremely encouraged.

We see minimal amount of smaller asset type sales for the productivity improvements and basically we are going to cross that bridge pretty quickly of bringing 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 continued 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, very close -- very, very close.

The underlying business here is powerful, strong and the capital efficiencies continue to improve and as I've highlighted before, the accomplishments of this company over the past 5 years compare to no other.

And what you can expect is that this challenge of our debt reduction and achieving 2x net debt-to-EBITDA continues to be a major focus for us.

It's essentially our #1 priority and we will continue to make progress on it and 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.

Okay.

And then one last one.

Just looking on the PRB, obviously, amazing well that Turner well you all spoke of, the 4000 BOE with not only the big rate, 75% oil.

So looking at Slide 16, maybe Doug, for you or Frank, just could 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, I mean, are there, trying to get a sense of is there a large area that can continue to have these phenomenal type wells or now that we have seen, again, not only the size but just the oil cut behind that I'm wondering as you're looking at the entire play.

Yes, 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 kind of northwestern portion of field is high oil cut, as you get down into the meat of our acreage around that CPF those well are going to be big wells.

Now, are they all going be 4,000 barrels a day?

No.

We're seeing some variability but they are 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.

So 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 kind of the gassier area to maintain acreage because there is 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 hadn't put a scale on here but we have a huge, huge acreage position here that's all contiguous.

And so, we have a lot of running room here in the Turner left.

But I'm really, really excited about getting into the Nio as well because now we will be able to stack the Nio right on top of that Turner.

The other thing, don't forget that we may see something better than 4,000 barrels equivalent a day.

So it's just while we talk about excitement around that well with continued improvement and say you're going to stamp every well at 4,000, we're going to have variability naturally, but we're excited enough and encouraged enough there may be something better than that, so don't take that out of the equation either.

The next question will be from Charles Meade with Johnson Rice.

So go back to that the Brazos Valley completion.

Could you elaborate a little bit more on what led you go with this different completion design with lower fluid volumes and higher sand concentration and, I guess, is this an experiment or is this, I guess it is an experiment, but is this close to what you think your final design is going to be and when are we going to know, or when will you know if you struck on the right design?

Yes, you go ahead.

Well, I just say it's only a day's work at Chesapeake, Charles.

I mean, everything we look at, has continued improvement and how we get better and how we take our learnings from elsewhere to the new asset and this -- the way we -- basically the sand concentration's roughly the same, what we've principally reduced was the fluid.

And we're going to continue to optimize and pull the levers that we know will be successful in what we've learned elsewhere.

And 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've now gone in and done a bunch of looking at wells.

And what it appears is that you need the same concentration because the clay content is higher in this rock and we knew that.

WildHorse had done a fantastic job discerning that.

But what was happening was there was a ton of fluid being pumped in every stage.

And what that was causing was really long frac wings and those frac wings were reaching out and basically interfering with each other.

What we've done is we've used the same sand constant -- -- same sand amount but at higher concentration, pumping it away with a lot less fluid.

That does a couple of things was for us; one, it increases the complexity near the wellbore and shortens those frac wings so we might actually be able to see a spacing change once we understand the storage capacity here.

But 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 and so we're going to be able to reduce the cost of pumping the jobs because less water, we're going to have shorter flow back period and we're going to have a stronger, earlier oil [catch].

Everything we have 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, really good start and we are encouraged by what we're seeing on the initial test.

I would like to ask a follow-up on your CapEx and your overall portfolio.

Doug, you mentioned that you have about 75% to 80% of your CapEx go to oily plays, but on the other side of that you guys have really core, center-of-the-bulls-eye position and really the 2 dry gas plays that are really working right now in the Haynesville and the Marcellus.

There have been some news reports in last few days of, like, Saudi Aramco trying to team up with Equinor to get into the North American natural gas markets.

So could you talk about how you see those 2 dry gas plays at Haynesville and Marcellus?

What role they're going to play in your portfolio, not in 2019 but in 2020 and beyond?

Sure, Charles.

Those 2 assets are world-class.

And you got a world-class operator that can mobilize and develop those resources really quickly.

And we will continue to monitor pricing environment, the LNG build-out and more gaskets on the water as additional demand makes sense and economically makes sense.

Chesapeake will react accordingly and adjust our program accordingly.

So we note super strong assets, extremely well-run here in corporately and particularly in the field.

And we can revise and modify and flex our capital at any point in time as economic conditions dictate.

Ladies and gentlemen, this concludes our question-and-answer session.

I would like to return the conference to Doug Lawler for any closing remarks.

Yes, thank you.

I appreciate everyone's time today.

In our prepared comments, we made several references to rate of change or rate of improvement.

And I just want to close today by highlighting that the underlying business continues to see excellent progress, and 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 and encouragement we have to continue the rate of change and rate of improvement across our portfolio is something that we are really, really pleased about and really excited about.

And I think it's differential and, 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.

So I thank you for everyone's time and if there is additional questions please follow-up with Brad and we'll respond accordingly.

And thank you, sir.

The conference has now concluded.

Thank you for attending today's presentation.

You may now disconnect.