Chesapeake Energy Corporation (CHK) Q4 2018 Earnings Conference Call Transcript

Chesapeake Energy Corporation (CHKA.Q)
Q4 2018 Earnings Conference Call
Feb. 27, 2019, 8:30 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants
  
  See all our earnings call transcripts.

Prepared Remarks:

Operator

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.

Brad Sylvester -- Vice President, Investor Relations

Good morning, everyone. 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 consists 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.

Robert Douglas Lawler -- President, Chief Executive Officer

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 Resources 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. Two of these, the PRB and the WildHorse assets, will drive 2019 absolute oil growth of 32%, or 50%, when adjusted for asset sale. 2 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 among our large, independent peers. Industry-leading cash cost among our large, independent peers.

Radically improving midstream 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, while further enhancing recovery and development efficiencies. Importantly, the 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 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 for 2018, while improving price realizations, and importantly, lowering absolute cash costs, we ultimately recorded the highest earnings in EBITDA, generated per BOE of oil equivalent, since 2014, when oil averaged $90.00 a barrel, and gas averaged more than $4.00 per cubic foot.

Accordingly, 2018 adjusted net income, was $818 million, or $0.90 per diluted share. I'm especially pleased that we were 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 portfolios.

Through the Utica divestiture, we reduced our net debt by $1.8 billion, and I'm pleased that, in total, we've 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, at 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, and 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 non-price related margin improvements. We have decreased our absolute production costs each year, since 2013, and anticipated 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 down time 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 toward 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.

Domenic J. Dell'Osso -- Executive Vice President, Chief Financial Officer

Thank you, Doug, and good morning, everyone. Our accomplishments in the fourth quarter and full year 2018 were outstanding. Increase in margins and cash flow, greater oil production is working, and we continue to improve our balance sheet.

Starting with balance sheet, we used proceeds for the Utica sale, repurchased debt, ending the year with $8.2 billion of debt, outstanding, nearly at $10 billion, at the end of 2017. Additionally, we refinanced our 2016 term loan, unsecured debt. The combined balance sheet improvements reduced our interest expense by approximately $150 million annually, and we're keeping -- in our recent credit rating upgrades. Our operating costs structure tighten again in 2018, with $78 million, or 3% production in combined G&A, GP&T, and production expenses. These improvements led to higher profitability per barrel, and better free cash flow before 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're sustainable, and along with a much higher mix of our total production coming from oils, that put us in position to further increase our profitability per barrel equivalent in 2019.

Despite the manufacturer's forecast to lower, across the board, in 2019 on the NYMEX strip, as we saw in 2018. In 2019, approximately 75% of our D&C CapEx, will be directed to a higher margin, a higher return oil asset, in our PRB Brazos Valley and Eagle Ford assets. While, total plan capital expenditures are actively flat for 2018. This doesn't provide an increase in our oil growth, and oil mix percentage.

Our operating cash flow structured in 2019, will be $200 million lower year-over-year, primarily, due to improvement in GP&T cost of a $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. But we are also seeing improvements in several other basins. In the PRB, the contractor with the third party to have an oil gathering system built, at a very competitive rate, and the addition to the Brazos Valley barrels to the portfolio improved the average rate with the relatively low gathering and transport cost.

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 third quarter, extending its maturity to 2023, at effectively, the same terms. Additionally, we assume the $1.3 billion WildHorse credit facility. We've chosen to lead the WildHorse credit facility in 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 a significant improvement in our average realized Marcellus basis, and we believe in-basin pricing from 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, we will turn the call over to the operator for questions.

Questions and Answers:

Operator

Thank you, very much. Ladies and gentlemen, at this time, we would like to open the floor for questions. If you would like to ask a question, please press *1 on your telephone keypad, now. If you are using a speakerphone, please make sure your mute function is turned off, to allow your signal to reach our equipment. Again, press *1 to ask a question. We'll pause for just a moment to allow everyone an opportunity to ask a question.

Our first question will come from David Heikkinen, Heikkinen Energy Advisors.

David Martin Heikkinen-Heikkinen Energy Advisors LLC -- Analyst

Good morning, guys, and thanks for taking my question. 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 a 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. Just, how are you thinking about, through the year, as you turn on those wells, as a component of the total TIL schedule, how do you integrate those assets in? And then, how do those wells get turned online, as well? I'm just trying to think about that path of improving your integration.

Robert Douglas Lawler -- President, Chief Executive Officer

Thanks, Dave. I'll kick it off. We all have a tremendous amount of energy around what we see in the 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. We're super excited in what we see. We've been working really close, along the time prior to closing of what we actually would put in place. What we see on the drilling and completion side is immediate opportunity, and service-related costs, as well as supply chain synergies, as we integrate it into the Chesapeake machine.

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 it. These guys will share more with you.

Frank J. Patterson -- Executive Vice President, Exploration and Production

Hi 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 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 have been pushing the Austin Chalk to the south, as we have done 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 that look good. 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're not going to plant a flag, and say we're there, yet. 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. Definitely, we'll be up to our full needs somewhere in the next 4-6 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. A lot of good changes. A lot of positive changes. With that, we have a lot of other opportunities, and I'd like Jason to kind of describe our base optimization opportunities.

Jason Pigott -- Executive Vice President, Operations and Technical Services

Well, 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 into 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. With our drilling team, they were able to change up mud systems, which equates to $30,000. They changed bottom-hole assembly which were $30,000. They used supply chain and rebid some of the daily rentals, which add up to $60,000. So, they're 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 huge decrease in the cost of that, which is almost $200,000 on that one crew that'll 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 [pounds] sand in 2019. So, really attacking those smaller parts of the supply add up to a big portion of our savings. It's not just for this asset, it's across the business. We're going to save almost a $100 million on a gross basis, just in sand, alone.

So, those are 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 fracked the well. We haven't drilled and completed the whole well on there. 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's fit 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. 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 with a complete team.

David Martin Heikkinen-Heikkinen Energy Advisors LLC -- Analyst

That's helpful. 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, that's just -- that's timing of completion?

Robert Douglas Lawler -- President, Chief Executive Officer

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.

David Martin Heikkinen-Heikkinen Energy Advisors LLC -- Analyst

That makes sense. That's helpful. Thanks, guys.

Operator

Thank you. Our next question will come from Neal Dingmann, SunTrust.

Neal D. Dingmann-SunTrust Robinson Humphrey, Inc. -- Analyst

Good morning guys. Doug, I guess, just in light of your forecast, basing, 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 and Nick sort of envision your future free cash flow?

Robert Douglas Lawler -- President, Chief Executive Officer

Sure. Well, 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. 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.

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 2020, going forward. So, heavily dependent upon commodity price.

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

Domenic J. Dell'Osso -- Executive Vice President, Chief Financial Officer

This is Nick. I'll just add that when Doug talks about it being sustainable, that's really the key to us. 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 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. What we are very focused on is that when we get there, we will be able to stay there, and not have relatively shor-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. 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're going to structure this in a way that when we get to a free cash flow positive position, we're generating value to shareholders either through returning that cash for continuing to grow the c f available to shareholders, and that's what we're focused on.

Neal D. Dingmann-SunTrust Robinson Humphrey, Inc. -- Analyst

Really great add, Nick. Then, just my follow-up is just on infrastructure. It certainly appears you've added a significant amount of infrastructure to your 2 key assets: the PRB and the Brazos Valley. Could one of you talk about how these infrastructure improvements will boost? How you look at that, how it'll improve the growth in each of these areas? Thank you.

Domenic J. Dell'Osso -- Executive Vice President, Chief Financial Officer

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 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's a number of different options. We have to get to end-markets, and we'll evaluate all of those options. At the moment, there's 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. 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. 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, we're 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. 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.

Neal D. Dingmann-SunTrust Robinson Humphrey, Inc. -- Analyst

Thanks, for the details, Nick.

Operator

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

Charles A. Meade-Johnson Rice & Co. LLC -- Analyst

Well, that's one way to say it. Good morning, Doug, to you, and your whole team, there. I wanted to ask about the Marcellus. In particular, I find it intriguing that you guys hit a record gross production rate up there, in January. I think it's probably not coincidental that that comes with 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?

Robert Douglas Lawler -- President, Chief Executive Officer

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. This Marcellus asset, is absolutely unbelievable, and it's unbelievable in its productivity, and its efficiency. The teams, are attacking it really, really well. 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 just huge resource potential. 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.

Frank J. Patterson -- Executive Vice President, Exploration and Production

Charles, 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. 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 an 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. 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 when market opens up. I guess, Nick, could talk to you a little bit about some of the opportunities to expand the market.

Domenic J. Dell'Osso -- Executive Vice President, Chief Financial Officer

We're pretty excited about what we're seeing up there, in terms of market access, the other pipes that have come online have certainly lifted the pricing for our in-basin pricing points. 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. We think that's still playing out.

We did sign a transaction last year that we previously discussed. 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'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, is pretty favorable; having a floor to that in-basin pricing. It does have some upside sharing mechanisms associated with it, as well.

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. 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. We're getting better at understanding what the market needs in delivering those needs, as opposed to over-delivering. I feel better about the pricing available to us in the access to market in the Northeast. I think that there is a good opportunity for that, to have a steady growth rate over the next several periods.

Charles A. Meade-Johnson Rice & Co. LLC -- Analyst

That's helpful detail, guys. Frank, perhaps this is for you. I noticed you guys in the PRB, still running all five rigs; focus on the Turner. Is there any change in the thinking about when you're going to test others zones about the prospectivity of other zones, or just anything in that regard? Any change from what you guys have talked about in the last six months?

Frank J. Patterson -- Executive Vice President, Exploration and Production

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. 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 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're getting faster on the Turner. 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.

Charles A. Meade-Johnson Rice & Co. LLC -- Analyst

Thanks, Frank.

Operator

Thank you, very much. Our next question will come from Brian Singer, Goldman Sachs.

Brian Singer -- Goldman Sachs -- Analyst

Thank you. Good morning. 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 a major play strategically that, when you talk about getting there and staying there?

Robert Douglas Lawler -- President, Chief Executive Officer

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 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. Our focus there, on base optimization, and how those technologies can help offset that decline is something that's really 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. In that 30%, we expect the capital program, and those efficiency to deliver greater volumes, greater margin improvement, so that that's going to help our free cash flow position, and as we look for ways to capture these technologies to help add to the base. When you talk about decline, you're talking about a function of the rock. We understand the rock really well. 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 wells of opportunity there, with IOR, and to further enhance our recovery from the base, and add additional value.

As you think about the existing base, and what we're 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, are technically changing, it's how we're going about with our additional optimization operations that will help improve that, and add further value to our free cash flow.

Brian Singer -- Goldman Sachs -- Analyst

Great, thanks. That's super helpful. 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, showing that step-up in Q3. I wondered if 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?

Frank J. Patterson -- Executive Vice President, Exploration and Production

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 being a drastic change because, keep in mind, a lot of the drilling and completion capital's being spanned across the first, second, and third quarter. The turn-in-line schedules are more reflective of when we'll see initial production. It will likely be high for the year, and the third quarter, but I wouldn't read anything into that. Just remember that, the capital discipline focus we have, Brian, is really strong, as we've proved in the past.

Brian Singer -- Goldman Sachs -- Analyst

Thank you.

Operator

Thank you, very much. Our next question comes from Arun Jayaram, JP Morgan.

Arun Jayaram -- JP Morgan Securities LLC -- Analyst

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

Robert Douglas Lawler -- President, Chief Executive Officer

Right now, we entered the year basically relatively flat to what was going on at the end of the year. First two quarters looked strong. WildHorse, had added some wells 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. They're strong wells, but they're not as strong oil. So, oil, is going to be pretty flat going in to 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 end of second quarter, third, and fourth quarter. So, we're going to start to see the oil ramp up, as we go through the year.

Arun Jayaram -- JP Morgan Securities LLC -- Analyst

Great. 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 looked like it lagged. I was just wondering if there's anything unusual in the cash flow line item that could explain that variance. 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?

Domenic J. Dell'Osso -- Executive Vice President, Chief Financial Officer

I'll answer the second question first. Cash flow inflection point and strip pricing were pretty focused on getting through 2019 to have a higher level of production in there, for cash flow, a 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'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. As we looked at that ahead of the call, we really didn't see any significant driver that maybe hedgedmarked to market, a few other things like that. 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.

Arun Jayaram -- JP Morgan Securities LLC -- Analyst

Thanks.

Operator

Thank you, very much. Our last question, will come from Jason Wangler, Imperial Capital.

Jason Wangler -- Imperial Capital -- Analyst

Good morning. Just had one. You talked about, in the release, the dropping one rig into Haynesville, and I think you were speaking about, in the Powder River, looking at maybe picking up a rig. As you have the rigs laid 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?

Frank J. Patterson -- Executive Vice President, Exploration and Production

Jason, this is Frank. We continually manage our capital allocation, and we move the capital to the best opportunities within the company. 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're 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 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. What we've laid out for you here, is our initial plan. I think it's a really good plan: five rigs in 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. 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. 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. We just need to see how much efficiency we can gain there.

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 MidCon. We have one rig, I think, that is a good run rate for MidCon, until we get some of these other plays, the G&G, and the reservoir engineering complete analysis there. I don't see us moving off of where we are, unless commodities change, or we see an asset really take off, and there's a better value proposition for us to pursue.

Jason Wangler -- Imperial Capital -- Analyst

I appreciate the color. Thank you, very much.

Operator

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.

Robert Douglas Lawler -- President, Chief Executive Officer

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. 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.

Operator

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.

Duration: 46 minutes

Call participants:

Brad Sylvester -- Vice President, Investor Relations

Robert Douglas Lawler -- President, Chief Executive Officer

Domenic J. Dell'Osso -- Executive Vice President, Chief Financial Officer

Frank J. Patterson -- Executive Vice President, Exploration and Production

Jason Pigott -- Executive Vice President, Operations and Technical Services

David Martin Heikkinen-Heikkinen Energy Advisors LLC -- Analyst

Neal D. Dingmann-SunTrust Robinson Humphrey, Inc. -- Analyst

Charles A. Meade-Johnson Rice & Co. LLC -- Analyst

Brian Singer -- Goldman Sachs -- Analyst

Arun Jayaram-JPMorgan Securities LLC -- Analyst

Jason Wangler -- Imperial Capital -- Analyst

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