Chesapeake Energy Corp (CHK) 2018 Q4 法說會逐字稿

Good day, and welcome to the Chesapeake Energy Corporation Q4 2018 Conference Call.

Today's conference is being recorded.

At this time, I would like to turn the conference over to Brad Sylvester.

Please go ahead, sir.

Good morning, everyone, and thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2018 full year and fourth 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 benefits of our transaction with WildHorse Resource Development Corporation, the expected timing for the transaction 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 facilitate comparisons across periods and with peers.

For any non-GAAP measures 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, and Jason Pigott.

Doug will begin the call and then turn the call over to Nick for a review of our 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, everyone.

Chesapeake has delivered another strong year of operational and financial performance, a year defined by improvements in every aspect of our business.

The investment thesis for Chesapeake Energy continues to grow as we advance our strategies of reducing leverage, achieving sustainable positive free cash flow and enhancing our margins.

The WildHorse Resource Development acquisition and the Utica divestiture are excellent examples of our progress and provide further momentum in our competitive transformation.

I just want to take a second and note the key attributes of our robust diverse portfolio and our business delivery capability.

These attributes include: 3 powerful oil assets with significant inventory and premium pricing; 2 of these, the PRB and the WildHorse assets, will drive 2019 absolute oil growth of 32% or 50% when adjusted for asset sales.

Two world-class gas assets with more than 27 net trillion cubic feet of gas resources geographically positioned to supply global LNG growth for decades to come, significant exploitation and exploration acreage for further value creation and/or monetization, industry-leading capital efficiency amongst our large independent peers, industry-leading cash cost amongst our large independent peers, radically improving midstream obligations and costs, nonprice-related margin improvements driven by oil growth and cash cost leadership, significant deleveraging progress and improved credit ratings, industry-leading experience and expertise to further optimize and deploy new technologies, while further enhancing recovery and development efficiencies.

And importantly, a commitment to safety excellence and environmental stewardship that has produced outstanding results.

From a challenging starting point 5 years ago, we began our transformation goal of becoming a top-performing unconventional E&P company, and we have made sequential improvements unmatched by our peers.

I'm very pleased with our progress toward this goal and the momentum we have established is a direct indicator of future performance.

Chesapeake's focus on increasing oil production is yielding impressive results, materially accelerating our strategic priorities.

Led by a 78% increase in net oil volumes from the Powder River Basin, we delivered 10% adjusted oil growth in 2018.

While improving price realizations and, importantly, lowering absolute cash costs, we ultimately recorded the highest earnings in EBITDA generated per barrel of oil equivalent since 2014 when oil averaged $90 a barrel and gas averaged more than $4 per cubic foot.

Accordingly, 2018 adjusted net income was $818 million or $0.90 per diluted share.

I'm especially pleased that we're able to accomplish these results, while once again, delivering industry-leading health, safety, environmental, and regulatory performance across our company.

The acquisition of the WildHorse assets now designated as our Brazos Valley business unit greatly enhances Chesapeake's oil growth platform, providing further profitability, flexibility and optionality to our diverse deep portfolio.

Through the Utica divestiture, we reduced our net debt by $1.8 billion, and I'm pleased that in total, we eliminated $2.6 billion of secured debt last year.

The new Brazos Valley business unit team is aggressively attacking numerous opportunities to drive capital efficiencies across the value chain.

Through a combination of operational improvements and supply chain savings, the team has already identified, implemented and negotiated $200,000 to $350,000 per well in capital savings within the first month of taking over operations.

I have high confidence we will see further capital savings on a per-well basis as the year progresses.

In addition, we have made early cycle-time improvements through increased drilling penetration rates and a 2-stage per day increase by the completions team.

Further, the Burleson Sand Mine recently commenced operations in February of 2019 and is anticipated to yield additional savings to the company's completions program.

As noted in our earnings release at today's strip pricing, we expect our cash flow to be meaningfully stronger in 2019.

Capital efficiencies and cash cost leadership will remain our central focus, serving as a recognized competitive advantage, while we further reduce our legacy debt and realize nonprice-related margin improvements.

We have decreased our absolute production costs each year since 2013 and anticipate reducing our cash cost an additional 3.5% in 2019.

In addition to driving costs out of our operations, we continue to develop innovative technology solutions to drive value and improve operating results.

For example, in the Eagle Ford South Texas area, we implemented a new digital field technology solution to reduce downtime across the field.

As a result, Chesapeake recorded a 17% reduction in controllable down volumes per day in 2018, which equated to an additional 1,100 barrels of oil sold every day.

We're currently expanding the use of this technology to other fields and expect to have it implemented across all business units by mid-year.

Financial discipline has been a pillar of Chesapeake's business strategy since we began our transformation, and simply put Chesapeake will continue to deliver more with less in 2019.

This starts with keeping our capital expenditures relatively flat, while still delivering significant oil growth.

We're relentlessly driving towards achieving our strategic priorities of delivering further debt reduction, enhancing margins, and reaching sustainable free cash flow.

Our 2,300 employees are highly motivated and powered and energized to further improve our operations and financial position in 2019, to takes full advantage of our strengths and thrive in any commodity price environment.

Our momentum is building, and we are excited to share our continued progress with you as we move through the year.

I'll now pass the call to Nick.

Thank you, Doug.

And good morning, everyone.

Our accomplishments in the fourth quarter and full year of 2018 were outstanding, focused on increasing margins and cash flow, the greater oil production is working and we continue to improve our balance sheet.

Starting with balance sheet, we used proceeds from Utica sale to repurchase debt, ending the year with $8.2 billion of debt outstanding, down from nearly $10 billion at the end of 2017.

Additionally, we refinanced our 2016 term loan into unsecured debt.

These combined balance sheet improvements reduced our interest expense by approximately $150 million annually and were key components in our recent credit ratings upgrades.

Operating cost structure tightened again in 2018, with $78 million or 3% reduction in combined G&A, GP&T and production expenses.

These improvements led us to higher profitability per barrel and better free cash flow for asset sales than we've had in many years.

Further, as these changes are related to shifts in our asset portfolio and other permanent reductions to our cost structure, they're sustainable and long in the high -- much higher mix of our total production coming from oils, have put us in position to further increase our profitability per barrel equivalent in 2019.

This is despite commodity prices forecasted to be lower across the board in 2019 on the NYMEX strip than we saw in 2018.

In 2019, approximately 75% of our D&C CapEx will be directed to higher margin and higher return oil assets in our PRB, Brazos Valley and Eagle Ford assets.

While total planned capital expenditures are relatively flat for 2018.

This focus will drive an increase in our oil growth and oil mix percentage.

Our operating cash flow structure in 2019 will be $200 million lower year-over-year, primarily due to the improvement in GP&T cost of $1.10 per barrel equivalent, partially offset by LOE and G&A.

The biggest driver of the GP&T improvement is the sale of the Utica assets, and we are also seeing improvements in several other basins.

In the PRB, we've contracted with a third party to have an oil gathering system built at a very competitive rate and the addition of the Brazos Valley barrels to the portfolio improved the average rate with their relatively low gathering and transport costs.

After years of being a significant drag on our profitability, our GP&T costs are forecasted to be $6.25 per barrel equivalent at the midpoint for 2019, which is highly competitive with the peer group.

We expect further improvements in this line item in future periods as both PRB and Brazos Valley assets should continue to see opportunities for increased GP&T, cost efficiencies as volumes grow.

We also expect to see improved realized pricing as we gain access to better markets through the year and into 2020.

On the liquidity front, we amended and restated our $3 billion revolving credit facility in the third quarter, extending its maturity to 2023 at effectively the same terms.

Additionally, we assumed the $1.3 billion WildHorse credit facility -- we've chosen to leave the WildHorse credit facility and bonds outstanding for the time being in an unrestricted subsidiary in Brazos Valley Longhorn, meaning the Brazos Valley legal entity and assets do not support Chesapeake debt and vice versa.

At the closing of the transaction, we had approximately $2.1 billion of liquidity on the Chesapeake credit facility and $575 million available on the Brazos Valley facility.

We have a robust hedge portfolio in place as we enter 2019 with more than 60% of our forecasted oil, natural gas and NGL production revenue hedged at strip prices, including more than 55% and 80% of our forecasted 2019 oil and natural gas production at averages of $57.12 per barrel and $2.85 per Mcf, respectively.

Lastly, we've hedged about 7 million barrels of our Eagle Ford volumes at a premium of approximately $6 per barrel to WTI NYMEX pricing.

We also continue to enjoy significant improvement in our average realized Marcellus bases and we believe in-basin pricing for our Marcellus gas will continue to improve year-over-year.

The transformation of Chesapeake over the past 5 years has been significant and is accelerating.

As previously mentioned, we look forward to relaying our progress to you in the coming quarters.

With that, we will turn the call over to the operator for questions.

(Operator Instructions) Our first question will come from David Heikkinen, Heikkinen Energy Advisors.

Congratulations on all the hard work on the GP&T side.

I know that was a big task and you all have made a heck of lot of progress.

Thinking about the integration of the WildHorse assets and then your comments on improving downtime on your base Eagle Ford, improving well cost, kind of curious about the Burleson Sand Mine cost per well, but just how you're thinking about through the year as you turn on those wells as a component of the total TIL schedule like what's the -- how do you integrate those assets and then how do those wells get turned online as well?

I'm just trying to think about that path of improving your integration.

Thanks, Dave.

I'll kick it off.

We all have a tremendous amount of energy around what we see in Brazos Valley business unit and what the team is doing with that integration.

As you'd expect, we've put some really talented folks on that attacking that whole value chain, and we are super excited in what we see.

We have been working really close along the time prior to closing of what we would actually would put in place and what we see on the drilling and completion sides immediate opportunity and service-related costs as well as supply chain synergies as we integrate it into the Chesapeake machine.

And before I hand it to Frank and Jason, I'll just comment that the hallmark, most notable quality in this company has been our operating expertise and experience with many years in many wells of knowing what to do and how to integrate these assets, so I'll pass it to these guys to share more with you.

Dave, this is Frank.

We're pretty excited about what we are seeing.

To be honest with you, we had a relatively conservative model going into the acquisition.

We're actually outperforming on a production side, both in the fourth quarter and in the first 2 months of this year.

But the more exciting things that we're seeing, we thought we could get to longer laterals late in the year, but we're actually going to be able to start moving the longer laterals much, much earlier.

We're seeing good response to a few very minor tweaks to choke management and artificial lift.

Everything we thought we were going to be able to see we're seeing it actually earlier.

So we're pretty excited about that.

The other thing that's really interesting is WildHorse has been pushing the Austin Chalk to the south of field down in Washington County, which is a very gas-prone area, but we had identified some areas to the north of the field that looked very oil-prone.

There's now 2 wells in the ground and falling back in the northern part, and they look good, and as well as we modeled them, if not better than we modeled them, really good deliverability, good oil cut, pretty low gas cut.

So everything we're seeing is really exciting.

We have a lot of work to do.

We are not going to plant a flag and say this was -- we are there yet, but that is -- I think what you're going to see is our pace is going to accelerate there.

So we are cautiously optimistic that, that's going to be a lot better than we thought.

The sand mine is up and running.

It started in February.

We're running about 2,000 tons to 2,300 tons a day, which is about half of our needs and definitely, we'll be up to our full needs somewhere in the next 4 to 6 weeks.

So things are going good on the ground there.

Great team in the field that came along with the asset.

Really proud of those guys.

They're really knocking it out of the park, lot of good changes, lot of positive changes.

With that, we have a lot of other opportunities, and I'd like Jason to kind of describe that the -- our base optimization opportunities.

Yes, I'll hit first on just some of the -- we talked about the capital savings, and I think that's one of the keys to this asset as we operate in multiple basins, we've been able to source the whole Brazos Valley team with existing people that we have.

We didn't have to go out to the street and hire.

So we brought in some of our best people to this asset.

They were able to hit the ground running.

I mean, our drilling team, they were able to change up mud systems, which equates to $30,000.

They changed bottom hole assembly which are $30,000.

They use supply chain and rebid some of the daily rentals which add up to $60,000.

So they are just attacking every aspect of the business to get these big changes.

On the completion side, one of the frac spreads came up for renewal.

We saw a huge decrease in the cost of that, which is almost $200,000 on that one crew that will be running out there as well as transportation expenses on sand.

I mean, that's one thing we haven't really advertised a whole lot of, but we have been silently decoupling sand.

It's proving to be a major advantage for us.

We're going to go from pumping 5 billion pounds of sand in 2018 to pumping 8 billion sand in 2019.

So really attacking those smaller parts of the supply chain add up to a big portion of our savings.

And it's not just for this asset, it's across the business.

And we're going to save almost $100 million on a gross basis just in sand work alone.

So those are huge for us, and we're really excited about bringing more and more through the Brazos.

We've only done parts of wells right now.

We've only drilled out some plugs.

We've only fracked that well.

We haven't drilled and completed a whole well out there ourselves, so we'll get the whole system working together.

We're really excited about that.

On the basin enhancement of the digital revolution, we've been talking about sometimes that's just seen as a buzzword, but for us, it's real.

And what we've been focused on is putting mobile technology in our operator's hands, and we've designed some software that fits for them plus it's part of our culture change.

We think about one Chesapeake, and so it's both the office and the field trying to optimize base performance every day.

And our real focus is trying to get the maximum amount of cash flow up.

And by focusing on that, we've really improved both the base performance and our EBITDA from the base by just attacking that as a fleet team.

That's helpful.

And then just on the TIL schedule, you had the 33 wells in the third quarter.

Is there a large pad?

Is there some spacing test?

Or was there something going on with kind of the steady 15 to 18 wells every other quarter in the Brazos Valley and you bump up to 33?

Or is that just timing of completions?

Dave, I think that's just timing of completions.

We're going to pad development in Brazos.

And so it's just the way it's going to fall out.

To be honest with you, I think that there's an opportunity to move those TILs around and accelerate some of those.

We just don't want to take too big a bite.

The teams are still getting their hands around how fast we can move.

Our next question will come from Neal Dingmann, SunTrust.

Doug, I guess, just in light of your forecast with the -- basically, my model shows just a slight outspend current, given the notable improvement you show in EBITDA per BOE, could you just talk about how you next sort of envision your future free cash flow?

Sure.

We've been very clear with our message out there that the focus on achieving sustainable positive free cash flow is a key priority for us, and we've indicated that given the divestiture of the Utica and as we ramp up activity in WildHorse and further ramp up the activity in the Powder, that we will be in a slight overspend in 2019.

And obviously, with the strength of this portfolio and the strength of our assets, we have a number of opportunities that we'll be evaluating to close that gap this year.

I fully anticipate that we will through continued efficiency in our operations, better capital performance, smaller asset sales, that we will close that gap in 2019 and organically be in position through our EBITDA generation to be in a sustainable situation if that's closed in 2020 going forward.

So heavily dependent upon commodity price.

As you are aware, we're in a good position with our hedging for 2019, and we -- while we see a slight overspend this year, we're extremely focused on it and the underlying business is performing to deliver that sustainable free cash flow.

This is Nick, and I'll just add to this.

When Doug talks about it being sustainable, that's really the key to us.

And so what we've been trying to do in the last couple of years and we're very close to now, especially in light of having completed the acquisition, is get our cash flow to a level that we can generate enough internally generated funds to run our capital program and grow and do all of that in the free cash flow -- within free cash flow.

And so what we are very focused on is that when we get there we will be able to stay there and not have a relatively short-term phenomenon of being free cash flow that really impairs future growth or put us in a position where we have to incur a longer-term outspend to satisfy an offsetting decline to stay at a reasonable level of cash flow and EBITDA.

It's really important to us that what we're doing is value generating to our investors and being free cash flow in the short term without being able to actually return cash to shareholders or grow future cash flows is not going to generate value to shareholders.

We are going to structure this in a way that when we get to a free cash flow positive position, we are generating value to shareholders either through returning that cash or continuing to grow the cash flow available to shareholders and that's what we're focused on.

Great add, Nick.

And then just my follow-up is just on infrastructure.

Certainly, it appears you've added a significant amount of infrastructure to your 2 key assets, the PRB and the Brazos Valley, could one of you will talk about how these infrastructure improvements will boost?

How you look at that?

How it will improve the growth in each of these areas?

Yes, so those are 2 pretty exciting areas for us when it comes to infrastructure.

So in the Powder, as I said in my notes, we have contracted for the build-out of oil gathering system that we're really excited about.

It's going to take all of our oil on pipe, all the way to Guernsey.

From Guernsey, there is a number of different options we have to get to end markets, and we'll evaluate all of those options.

At the moment, there is plenty of transportation at reasonable prices.

We can get good access to Cushing, and we're seeing pretty reasonable differentials.

There was a period of time there, December-January, where differentials got pretty wide, but it was bleeding.

And so we're going to be pretty focused on what the long-term solution there is, that is likely to yield for us an improvement in realized pricing.

So we're really pleased with the way that gathering system is going to be built out and then the access to markets we will have from the off-take point of that gathering system.

We can say that it has the potential to be a real advantage to us.

In the Brazos Valley, that asset being relatively new has relied on trucking for most of its production up to this point.

The WildHorse team was in the early stages of getting ready to start building a gathering system.

We will pick that up where they left off obviously and determine whether or not to put that out to bid.

It's likely we will put that out to bid for third parties to build the gathering system for us there.

So we think that can reduce the cost of trucking out of the system.

And once we get on pipe, we believe we can get to premium markets and have some optionality between Houston and Corpus and a number of places where we already have good relationships with marketers to get very good pricing.

As you can see, our Eagle Ford gets a great price, and we believe we can expose the Brazos Valley barrels to a similar pricing structure over time.

I'll tell you right now in our forecast, we don't have those barrels forecasted to receive the same kind of price that our Eagle Ford barrels do because we don't yet have them tied into the pipe system that will deliver those prices to us.

We'll close that gap we believe relatively soon.

So look for there to be uplift in the realized pricing on those barrels over time.

Our next question will come from Charles Meade, Rice Johnson.

I wanted to ask about the Marcellus.

And in particular, I find it intriguing that you guys hit a record gross production rate up there in January, and I think it's probably not coincidental that, that comes with -- at some of the strongest local pricing we've seen up there in a few years.

So I wanted to explore, is that a coincidence or is it connected?

And to what extent do you guys have metaphorically a dial that you can turn up there to deliver extra volumes whether through accelerated completions or added compression or anything along those lines to the extent that strong local pricing continues?

Thanks, Charles.

The Marcellus, as you know, Frank and I have -- we both have something to say about this.

Frank and I have worked assets across the globe, and this Marcellus asset is absolutely unbelievable in its productivity, in its efficiency, the teams are attacking it really, really well.

And I think that as you look at the macro and the opportunity for global LNG growth and the opportunity to deliver that gas and get it on the water, it's -- it is perfectly positioned with just huge resource potential.

And I'll just let Frank fill in the blanks there a little bit because it's just -- we could not be more excited about that world-class asset.

Charles, so the teams across the entire company have been relentlessly attacking the base and Marcellus is a great example of that.

We were in the process and have been in the process of doing a lot of pad compression to continue to fill the base in.

But then on top of that, the drilling completion team and reservoir team have been working through spacing, making sure our spacing is adequate, which we have spaced out relative to some of the offset operators.

That and we have also been able to start drilling longer wells.

We actually just landed this week, our first 15,000-plus foot well.

You have seen in the last few weeks, we have come out and talked about the JOEGUSWA wells, they were really high flow rates.

I'll give you a real quick update on that.

The JOEGUSWA well that -- had a IP of around 73 million a day.

In 90 days online, it has already made 3.4 Bcf.

The one that had the 62 million a day, it's been online for 84 days, and it has already made 3.9 Bcf.

These are horses, and we think we can replicate that across a lot of the field.

So what we are basically doing is making sure that we have the gas available when market opens up.

And I guess, Nick could talk to you a little bit about some of the opportunities to expand the market.

Yes, so we're pretty excited about what we're sitting up there in terms of market access.

Other pipes that have come online have certainly lifted the pricing for our in-basin pricing points.

And we have better confidence in those to the shoulder in summer seasons.

We've also seen that in the summer, demand has just been stronger the last couple of years.

And certainly, we have had some good hot summers, but there's clearly more -- that gas has more of a share with power demand in the summer than in years prior, and we think that's still playing out.

We did sign a transaction last year that we previously discussed, and I think it got some publicity this week from the counter-party that we are going to deliver starting in late 2020 or early '21 to a local LNG facility that will ultimately export that LNG into the Caribbean markets.

We're really excited about that transaction, and we've been approached by many others who are trying to figure out how to get access to Northeast gas and deliver it to offshore markets.

With that transaction, we put in place a pricing structure that we see as pretty favorable.

Having a floor to that in-basin pricing and it does have some upside sharing mechanisms associated with that as well.

So there's a lot to do there, and the access continues to open up.

You also see that we have a lot of discipline around how we grow production.

That incremental transaction that I was just discussing will give us an opportunity to modestly grow our ceiling on production.

But beyond that, we have a pretty good feel for what the market can absorb and we don't deliver above that.

And I think you've seen many of our peers in the Northeast talk about moderating growth rates up there as well, which effectively everyone can see at what point they begin to overrun the market with excess supply and we are getting better and understanding what the market needs and delivering those needs as opposed to over-delivering.

So I feel better about the pricing available to us and the access to market in the Northeast, and I think there's good opportunity for that to have a steady growth rate over the next several periods.

Got it.

That's helpful detail, guys.

And Frank, perhaps this is for you.

I noticed you guys in the PRB still running all 5 rigs, folks on the Turner.

Is there any change in the thinking about when you're going to test other zones about the prospectivity of zones -- other zones or just anything in that regard?

Any change from what you guys have talked about in the last 6 months?

Yes, Charles we are still batting around how do we get to those next zones.

Turner is just so good that it's hard to pull rigs off of that.

We will be drilling some and completing some Niobrara wells in 2019.

I think that's probably the next big play to work through.

So we may end up moving rigs around and maybe potentially bringing in another rig for a small period of time there, but we'll stay within the capital plan that we already have discussed.

We'll just have to manage that through our portfolio.

But yes, I want to get to the Niobrara, I want to get to some of these other zones faster than we are today.

It's just really hard to hit check the turnaround of the queue, but we are getting faster on the Turner.

We are getting -- our costs are coming down on the Turner.

We're learning a lot about the Turner.

It's really a play that I think once we get it into development mode, it's going to be a real, real key play for us.

Our next question will come from Brian Singer, Goldman Sachs.

As you seek to get to that free cash flow inflection and stay there as you mentioned, how do you see your decline rates evolving?

Where do you see the decline rate now?

And how is that changing by, say, year-end or 2020?

Is that the major base strategically that when you talk about getting there and staying there?

It's a good question, Brian.

The declining rate is something that we are very strongly focused on corporately.

As you know, with the significant number of wells that we have across the country, that we see excellent opportunity there and that's what really driving a lot of these base optimization initiatives, including the new technology of what we described in our prepared comments.

And our focus their on base optimization and how those technologies can help offset that decline is something that's real important to our future profitability.

The base decline for the company is really is unchanged.

It hasn't really changed for the past few years.

You're going to continue to see approximately 30% decline per year.

And then in that 30%, we expect the capital program and those efficiency to deliver greater volumes, greater margin improvement.

So that's going to help our free cash flow position.

And as we look for ways to capture these technologies, it will help add to the base.

So I don't -- I think that when you talk about decline, you're talking about a function of the rock.

And we understand the rock really well.

And through opportunities, such as IOR in South Texas, which we're super excited about and all the initial technical evaluation that we have and that they were thinking about, there could be several hundred, if not, thousands of wells of opportunity there with the IOR and to further enhance our recovery from the base and add additional value.

And as you think about the -- just the existing base and what we are doing with using these technologies across other assets, I expect to see really good value from that.

So there really, really is a lot of opportunity, but we don't see the base decline from the rock perspective or technically changing, it's how we are going about with our additional optimization operations that will help improve that and add further value to our free cash flow.

Great.

That's super helpful.

And then I had a follow-up to, I think, with David Heikkinen's question earlier with regards to the TIL schedule.

From a total company perspective, you have that on Slide 5 telling that step up in Q3 and I wondered if the trajectory of your CapEx by quarter matches the trajectory of the TIL schedule?

Or if the TIL schedule is lagged to the actual CapEx, i.e., should third quarter be the high from a CapEx perspective and second quarter be the low?

Yes, I mean, I think that you'll -- obviously, the capital is going to be a function of the activity, and I don't see it in the third quarter as being a drastic change because keep in mind a lot of the drilling and completion capital is being spent across the first, second and third quarter.

The Turner line schedule is more reflective of when we'll see initial production.

So I don't -- it will likely be high for the year in the third quarter, but I wouldn't read anything into that, and just remember that the capital discipline focus we have, Brian, is really strong as we proved in the past.

Our next question will come from Arun Jayaram, JPMorgan.

I do have a follow-up to David's question on the integration of the WildHorse assets.

So I was wondering if you could give us perhaps some expectations for the asset in 2019 current rates and what you expect to deliver over the course of the year along with CapEx?

Yes, Arun, so right now we entered the year basically relatively flat to what was going on at the end of the year.

First 2 quarters looked strong.

WildHorse had added some wells on the front -- in the front end of year or end of last year and beginning of this year down in that Washington County gas asset area that are their strong wells, but they're not as strong oil.

So oil is going to be pretty flat going into the first and second quarter, but then it's going to start to takeoff because we will move all the rigs into Eagle Ford and Austin Chalk.

So you're going to see a very focused effort on driving oil volumes in this asset going into the second quarter, third and fourth quarter.

So we're going to start to see the oil ramp up as we go through the year.

Great.

And I just had one housekeeping question for Nick.

Nick, if we look at the 4Q numbers relative to The Street, your EBITDA was about 5% above consensus yet cash flow look like it lagged.

So I was just wondering if there's anything unusual in the cash flow line item that could explain that variance?

And as well, I'd like to get your thoughts Nick, on when you think the company would reach a cash flow inflection point assuming strip pricing?

Yes.

So I'll answer the second question first.

Cash flow inflection point and strip pricing, we're pretty focused on getting through 2019 to have a higher level of production and therefore cash flow higher level of profitability, which is what we've laid out today and positioned ourselves for a much better answer on cash flow in 2020.

As Doug noted before, there's a lot of dependence on commodity prices there, but at the strip we feel pretty good about that as we sit today.

On the fourth quarter, the delta between EBITDA and cash flow, everybody's model is a little bit different.

And as we looked at that ahead of the call, we really didn't see any significant driver.

They're maybe hedged mark-to-market, a few other things like that, but happy to spend more time with you after the call digging through any of that.

We did not see a consistent driver across The Street on that.

Our last question will come from Jason Wangler, Imperial Capital.

I just had one.

You talked about in the release, dropping one rig in the Haynesville, and I think you're speaking about in the Powder River looking at maybe picking up a rig.

Just as you have the rig played out now, do you think that's a pretty fair assessment of how we should look at it both in '19 and going beyond that?

Jason, this is a Frank.

We continually manage our capital allocation and we move the capital to the best opportunities within the company.

So this is our plan as we see it today.

We went to one rig in Gulf Coast.

We have a lot of locations there to drill.

It's a great asset.

It just happens to be an asset that has one of the higher activation costs in today's commodity debt.

So we are slowing down a little bit there.

We are going to kind of keep a steady pace in Marcellus, and I think you'll see us do that continually as long as the market is there for us.

That's a really capital efficient asset and that it doesn't take as many wells to keep our production flat as a lot of other assets because the well -- the rock is just so good.

When we look at our oil assets, we could move rigs around between the oil assets depending on where we see the best value in a given year.

So what we've laid out for you here is our initial plan.

I think it's a really good plan, 5 rigs in the Powder.

If we brought on a sixth rig, we might drop down a couple of rigs at the end of the year to keep our capital at the same level.

I'm not talking about expanding capital here if we want to do that.

I'm talking about managing capital within our budget that we're laying out.

In South Texas, I think, 4 is a really good number.

And in Brazos, we are at 4 today.

We could absolutely go to more if that made sense, but we don't want to expand our capital plan today for sure.

And we also want to see how effective can we be with 4 rigs?

We might get the same number of wells with our drilling and completion team that 4 rigs -- with 4 rigs that what 5 rigs would have been in our original plan, that is very much within the realm of possibility.

So we just need to see how much efficiency we can gain there.

But like I said, we do capital allocation every week.

We take a look at where the value is and where the best place to spend the money is for the company and we can do that.

Mid-Con, we have 1 rig.

I think that is a good run rate for Mid-Con until we get some of these other plays, kind of the G&G and reservoir engineering complete analysis there.

So I don't see us moving off of where we are unless commodities change or we see a asset really take off and there is a better value proposition for us to pursue.

Speakers, at this time we have no further questions in the queue.

So I'll turn it over to you for any closing remarks.

Thank you, operator.

Thank you, everyone, for joining us today.

2018 was a great year for Chesapeake, and marked by the 2 significant transactions and as I mentioned upfront, the significant improvements across all aspects of our business.

We are excited about the opportunity.

We are excited about the momentum and excited about the business delivery that we have in front of us.

If you believe in energy, you should believe in Chesapeake Energy because we are going to continue to perform and we'll look forward to sharing more results as we progress through the year.

Thank you.

Thank you very much.

Ladies and gentlemen, at this time, this now concludes our conference.

You may disconnect your phone lines, and have a great rest of the week.

Thank you.