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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 presentations 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. Just want to take a second and note the key attributes of our robust diverse portfolio and our business delivery capability. These attributes include three powerful oil assets with significant inventory and premium pricing. Two of these, the PRB and the WildHorse assets will drive 2019 absolute oil growth of 32% or 50% when adjusted for asset sale.
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 mid-stream obligations and cost, non-price 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 are further enhancing recovery and development efficiencies. Importantly, our commitment to safety excellence and environmental stewardship that has produced outstanding results.
From a challenging starting point five years ago, we began our transformation goal of becoming a top-performing unconventional E&P company. And we have made sequential improvement unmatched by our peers. I'm very pleased with our progress toward this goal and the momentum we have established as a direct indicator of future performance.
Chesapeake's focus on increasing oil production is yielding impressive result, 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 realization and importantly lowering absolute cash cost, we ultimately recorded the higher earnings and EBITDA generated per bill 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 of $0.90 per diluted share. I'm especially pleased that we are able to accomplish these results while once again delivering industry-leading health, safety, environmental and regulatory performance across our company. The acquisition of 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 improvement through increased drilling penetration range and a two-stage per day increase by the completions team. Further, the Burleson Sand Mine recently commenced operations in February 2019 and is anticipated to yield additional savings to the company's completions program.
As noted in our earnings release, at todays' 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 non-price 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 cost 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 are 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 are 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, empowered and energized to further improve our operations and financial position in 2019 to take full advantage of our strengths and thrive in any commodity price environment. Our momentum is building and we're 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 that was nearly $10 billion at the end of 2017. Additionally we refinanced our 2015 term loans as unsecured debt. The combined balance sheet improvements reduced earning expense by approximately $150 million annually and we're pleased about this in our recent credit rating upgrades.
Operating cost structure tightened again in 2018 with a $78 million or 3% reduction in combined G&A, GP&T and cost expenses. These improvements led to higher profitability per barrel and better free cash flow for asset sales than we have had in many years. Further, these changes are related to shifts in our asset portfolio and other permanent reductions to our cost structure, they are sustainable and along in the high – much higher mix of our total production coming from oils, as further synchronization further increases our profitability per barrel equivalent in 2019.
Despite commodity prices forecast to be lower across the board for 2019 on the NYMEX strip in response to 2018. In 2019, approximately 75% of our D&C CapEx will be directed to our higher margin and higher return on oil assets, in our PRB, Brazos Valley and Eagle Ford assets, while total planned capital expenditures are relatively flat with 2018. [indiscernible] decrease in our oil growth and oil mix percentage. Our operating capital expenditure for 2019 will be $200 million lower year-over-year, primarily due to the improvement in GP&T cost of $1.10 per barrel equivalent, particularly offset by LOE and G&A. The biggest driver of GP&T improvement is the sales of the Utica assets, but we are also seeing improvement in several other basins.
In the PRB, we've contracted with a third part to have an oil gathering system built at a very competitive rate. And the addition to the Brazos Valley barrels to the portfolio improve the average rate with their relatively low gathering and transport cost.
After years of being a significant drag on our profitability, our GP&T cost 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 at 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 third quarter, extending its maturity to 2023 at effectively the same terms. Additionally, we assume the $1.3 billion WildHorse credit facility and we've chosen to lead the WildHorse credit facility in bonds outstanding for the time being in an unrestricted subsidiary in Brazos Valley Longhorn, mean 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 forecast 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 a significant improvement in our average realized Marcellus basis and we believe in-basin pricing for our Marcellus gas will continue to improve year-over-year. The transformation of Chesapeake over the past five has been significant and is accelerating. As previously mentioned, we look forward to relaying our progress to you in the coming quarters.
With that, I will turn the call over to the operator for questions.
Thank you very much. [Operator Instructions] Our first question will come from David Heikkinen, Heikkinen Energy Advisors.
Good morning guys and thanks for taking my question. And congratulations on all the hard work on the GP&T side. I know that was a big task and you all 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 Burleson Sand Mine cost per well, but just how are you 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 what's – 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 would expect, we've put some really talented folks on that attacking that whole value chain, and we're super excited on what we see. We've been working really close along the time prior to closing of what we actually would put in place and what we see on the drilling and completion side is immediate opportunity and service related cost as well as supply chain synergy as we integrate it into the Chesapeake machine. And before I hand it 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 and many wells of knowing what to do and how to integrate these assets. So, I'll pass to these guys to share more with you.
Dave, this is Frank. We're pretty excited about what we're 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 two 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 TIL 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 have been pushing the Austin Chalk to the south what we have done in Washington county which is a very gas prone area. But we had identify some area north of the field that looked very oil prone. There is now two wells in the ground and falling back in the northern part, that looks good and as well as we model 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're not going to kind of flag and say this was – we're there year. But that is – I think what you are going to see is our pace is going to accelerate there.
So, we're 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 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 four to six 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 are really knocking it out of park. Lot of good changes, lot off positive changes. With that, we have a lot of other opportunities and I'd like Jason kind of describe that – our base optimization opportunities.
Yes. I'll pick first on just some of the – we talked about the capital savings and I think that's one of the keys to this asset is we operate in multiple basins, we've been able to source the whole Brazos Valley team with existing people that we had. We didn't have to go out to the street and hire. So, we've brought in some of our best people to this asset and they were able to hit the ground running. And when our drilling team, and they were able to change up mud systems which equates to $30,000. They changed bottom-hole assembly which were at $30,000. They used 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 spread came up for renewal, we saw 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've been silently decoupling sand and 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 of sand in 2019. So, really attacking those smaller parts of the supply and that's a big portion of our saving, and it's not just for this asset, it's across the business. We're going to save almost a $100 million on gross basis just in sand alone.
So, those huge for us and we're really excited about bringing more and more to the Brazos. We've only done parts of wells right now. We've only drilled out some plugs, we've only frac the well. We haven't drilled and completed a whole well there. So, when we get the whole system working together, we're really excited about that.
On the basin, of the digital revolution we've been talking about sometimes that's just seen as a buzzword, but for us it's real. We've been focused on as putting mobile technology in our operators hand and we've designed some software that is fit for them, plus its 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're really improved both the base performance and our EBITDA from the base by just attacking with a complete 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 is there something going on with the kind of the steady 15 to 18 wells every other quarter in the Brazos Valley, then you bump up to 33 here, that's just – that's timing of completion?
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 is an opportunity to move those TILs around and accelerate some of those. We just don't want to take too big of a bite. The teams are still getting their hands around how fast we can move.
That make sense. I just didn't – that's helpful. Thanks guys.
Thank you. Our next question will come from Neal Dingmann, SunTrust.
Good morning guys. Doug, I guess just you know in light of your forecast with the – you know basing in my model show just a slight outspend in 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 will be evaluating to close that gap this year. I fully anticipate that we will through continued efficiency in our operations, better capital performance, smaller assets 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 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 over spend this year, we are extremely focused on it and underlying business is performing to deliver that sustainable free cash flow.
This is Nick, I'll just add that when Doug talked about it being sustainable, that's really the key to us. And so, what we've been trying to do the last couple of years and are very close to now, especially in light of having completed the acquisition is to get our cash flow to a level that we can generate, and that's internally – 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 relatively short term phenomenon of being free cash flow that really impairs future growth or puts 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 growth future cash flow is not going to generate value to shareholders. We're going to structure this in a way that when we get to a free cash flow positive position, we're generating values 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. It certainly appears you've added a significant amount of infrastructure to your two key assets, the PRB and the Brazos Valley. Could, one of you'll talk about how these infrastructure improvements will boost, how you look at that, how it will improve the growth in these areas? Thank you.
Yeah, so those are two pretty exciting areas for us. When it comes to infrastructure, so in the Powder, as I've said in my notes, we have contracted for the build out of an 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 and improvement in real-life 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, because it has the potential to be a real advantage to us.
And 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 was 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 a 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 systems 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.
Thanks for the details.
Thank you. Our next question will come from Charles Meade, Johnson Rice.
Good morning, Doug to you and your whole team there. 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 comes with – you know 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 accelerate 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 we'll both have something to say about this. Frank and I have worked assets across the globe and this Marcellus asset is absolutely unbelievable and it's unbelievable in its productivity and its efficiency. The team 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 is perfectly positioned with this 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're 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 and completion team and reservoir team have been working through spacing, making sure our spacing is adequate which we've spaced out relative to some of the offset operators. That and we've 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've 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 has already made 3.4 Bcf, the one that had the 62 million a day has been online for 84 days and 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're basically doing is making sure that we have the gas available and market opens up and I guess Nick can 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 seeing up there in terms of market access to other pipes that have come online and 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 in the summer demand has just been stronger in the last couple of years and certainly we have some good hot summers, but there is clearly more – gas has more of a share of power demand in the summer than in years prior and we think that 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 counterparty that we are going to deliver starting in late 2020 or early 2021 to a local LNG facility that will ultimately export that LNG into the Caribbean markets. We are 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 is pretty favorable. Having a floor to that in-basin pricing and it does have some upside sharing mechanisms associated with it as well.
So there is a lot to do there and the access continues to open up. We 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 modesty 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 at understanding what the market needs in delivering those needs as opposed to over delivering. So I feel better about the pricing available to us in access to market in the Northeast. And I think there is a 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 five rigs, folks on the Turner. Is there any change in the thinking about when you are going to test others 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 six months?
Charles, we are still batting around how do we get to those next zones. Powder is so good that it's hard to pull rigs off to 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 bring 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 though 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 check with the turnaround of the queue, but we are getting faster on the Turner. Our costs are coming down on the Turner. We are learning a lot about the Turner. It's really a play that, I think once we get it into development modes, it's going to be a real, real key play for us.
Thanks, Brian.
Thank you very much. Our next question will come from Brian Singer, Goldman Sachs.
Thank you. Good morning. As you seek to get to that free cash flow inflection and stay there that you mentioned. How do you see your decline rates involving? Where do you see that decline rate now and how is that changing let say yearend or 2020? Is that a major play strategically that when you talk about getting there and staying there?
That's a good question, Brian. The decline rate is something that we are very strongly focused on corporately. As you know with the significant number of wells 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 there on base optimization and how those technologies can help to 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 in that 30% we expect the capital program and those efficiency to deliver greater volumes and greater margin improvement, so that's going to help our free cash flow position. And as we look for ways to capture these technologies that help add to the base.
So I think that when you talk about decline, you are talking about a function of the rock. And we understand a lot of 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 that we're thinking about, there could be several hundred, if not thousands of well of opportunity there with IOR and to further enhance our recovery from the base and add additional value. And as you think about 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 in the – from the rock perspective technically changing, it's how we are going about with our additional optimization operations that will help to improve that and add further value to our free cash flow.
Thanks helpful. And then I had a follow-up to, I think with David Heikkinen question earlier with regards to the TIL schedule. From a total company perspective, you have that on Slide 5, showing that step-up in Q3. And I wondered if trajectory of your CapEx by quarter matches the trajectory of a TIL schedule or if there is a – if the TIL schedule lagged to the actual CapEx i.e. should third quarter be the high from a CapEx perspective and second quarter be the low?
I mean, I think obviously the capital is going to be a function of the activity and I don't see it in the third quarter to be in a drastic change because keep in mind a lot of drilling and completion capital being stand across the first, second and third quarter. The turn-in-line schedules are more reflective of when we'll see initial production. So, 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.
Great. Thank you.
Thank you very much. Our next question will come from Arun Jayaram, JPMorgan.
Good morning. 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.
Yeah, Arun. So right now, we entered the year basically relatively flat to what was going on at the end of the year. First two quarters look strong. WildHorse had added some wells on the front – in the front end of the year or end of last year and the beginning of this year down in that Washington County gas asset area that are strong wells, but there not as strong oil. So oil is going to be a pretty flat going into the first and second quarter, but then it's going to start to take off because we will move all the rigs into Eagle Ford in 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 are 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 is anything unusual in the cash flow line item that could explain that variance and as well I'd like to get your thoughts Nick. And when you think the company would reach a cash flow inflection point assuming strip pricing?
So I'll answer the second question first. Cash flow inflection point and strip pricing, we are pretty focused on getting through 2019 to have a higher level of production in there for cash flow, higher level of profitability which is what we've laid out today. And position ourselves for a much better answer in cash flow in 2020. As Doug noted before, there is 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 that maybe hedged mark-to-market up, 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.
Okay, thanks.
Thank you very much. Our last question will come from Jason Wrangler, Imperial Capital.
Good morning. Just had one and you talked about in the release of 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 laid out now, do you think that's a pretty fair assessment of how we should look at it both of 2019 and going beyond that?
Jason, this is 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 that has one of the higher activation costs in today's commodity debt. So we are slowing down a little bit there. We're 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. In that it doesn't take as many wells to keep our production flat as a lot of other assets because the rock which is 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 laid out for you here is our initial plan. I think it's a really good plan, five rigs in Powder. If we bought on a six rig, we might drop down a couple of rigs at the end of the year to keep our capital at the same level. I am not talking about expanding capital here. If we want to do that, I am talking about managing capital within our budget that we're laying out.
In South Texas I think four is a really good number and in Brazos we are at four 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 four rigs. We might get the same number of wells with our drilling and completion team with four rigs that what five 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 one 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 the 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.
I appreciate the color. Thank you very much.
Thank you. 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, and thank you everyone for joining us today. 2018 was a great year for Chesapeake marked by the two 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 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.