Chesapeake Energy Corp (CHK) 2018 Q3 法說會逐字稿

Good day, and welcome to the Chesapeake Energy Acquisition Announcement and Third Quarter 2018 Earnings Conference Call and Webcast.

(Operator Instructions) Please also note today's event is being recorded.

I would now like to turn the conference over to Brad Sylvester, Vice President of Investor Relations.

Please go ahead.

Thank you, Rocco, and good morning, everyone.

Thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2018 third 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 proposed transaction with WildHorse Resource Development Corporation, the expected timing for the completion of the transaction and the assumptions underlying such statement.

Please note that there are 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 Frank and Nick for a review of our operational and financial results before we turn the teleconference over for Q&A.

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

Thanks, Brad.

Good morning, and thank you for joining us today.

A little over 5 years ago, our Board of Directors, leadership team and employees began a major business transformation of Chesapeake Energy.

During this period, we have fundamentally improved all aspects of our business, demonstrating a commitment, passion and tenacious determination to drive value to our shareholders.

We had decreased our total debt and leverage by more than $12 billion, eliminated legacy commitments and obligations by more than $10 billion, significantly reduced complexity, delivered industry-leading capital efficiency and eliminated more than $1 billion in annual cash costs, all while preserving a world-class portfolio of unconventional assets in an extremely challenging commodity price environment.

Today is a special day for our company.

I'm thrilled to be speaking with you about the significant strategy acquisition of WildHorse Resource Development.

We are very excited about the future of Chesapeake and our ability to create tremendous value for our shareholders, and this transaction only further increases our enthusiasm.

We believe there is an incredible upside opportunity in our stock for investors.

The compelling investment thesis in this powerful combination is anchored in a significant depth of oil growth opportunities in the portfolio, reduced weighting to international gas and improved financial leverage, while priced at an attractive multiple of 2019 EBITDA and at a value that is accretive to our NAV.

Further, the WildHorse acquisition strengthens and accelerates delivery of our near-term strategic priorities of margin improvement, sustainable free cash flow and a net debt-to-EBITDA ratio of 2x.

Chesapeake is uniquely positioned to drive greater value from the WildHorse assets and enhance our ability to profitability grow through our proven unconventional development expertise.

The complementary WildHorse assets build upon our existing Eagle Ford position.

And with our Powder River Basin position, it gives us 2 powerful oil growth engines in our portfolio.

We expect to more than double our oil production by the end of 2020, while accordingly increasing our overall oil production mix to 30%.

Importantly, with this transaction, we project our EBITDA margin will grow by approximately $6.50 per BOE during that period, an improvement of over 50%.

The enhanced margins in oil growth from the WildHorse assets will also have an immediate impact on our financials and balance sheet.

Assuming current strip prices, we expect the incremental EBITDA created by this transaction alone will improve our debt-to-EBITDA ratio, accelerating our deleveraging efforts by approximately 40% over the next 2 years.

Today, WildHorse has one of the premier Eagle Ford positions, spreading across approximately 420,000 acres in the play, 80% to 85% of which are undeveloped.

This acreage has enviable access to premium Gulf Coast pricing, while the long runway and future development opportunities attracted us to the assets, we are also very pleased with the alignment of our strategic priority of increasing our competitiveness by improving our margins as WildHorse's EBITDA per barrel of oil equivalent is one of the highest of any independent E&P operator in the United States.

Additionally, we believe there are numerous opportunities to build upon WildHorse's impressive performance and further enhance the return profile of the asset.

Chesapeake is a leading operator in the Eagle Ford, and our capital efficiency in the basin is demonstrated by our ability to consistently drill and complete the longest laterals at the lowest cost per foot in the basin as second to none.

Our proven operational track record in geotechnical expertise provide great confidence that we will deliver material savings across all aspects of the operation.

Specifically, we anticipate achieving an average of $200 million to $280 million in annual savings over the first 5 years to be realized through our capital-efficient drilling and completion operations in the field as well as improve downtime, lease operating expenses and the elimination of redundant corporate overhead.

The savings are expected to be driven not only by the sheer scale of our operations but also by our ability to provide technical expertise through our operation support and reservoir technology centers; the impact of longer laterals and enhanced completions; and our logistic capabilities, which will eliminate additional oilfield service and supply chain costs.

Further, we expect to create additional value through our existing oil transportation options, demonstrating the truly complementary fit with our legacy Eagle Ford position.

We will look to further optimize this asset into our current transportation portfolio, which provides access to premium MEH and LLS pricing in both Houston and Corpus Christi, additional flow assurance synergies within a company of our scale.

We will provide a full update on our 2019 plans upon the closing of this transaction, but expect that over 80% of our drilling and completion activity will be focused on our high-margin oil assets in the Eagle Ford and PRB, while we continue to generate free cash flow from our Marcellus and Haynesville positions.

I will now pass the call to Frank to update us on our operations.

Thanks, Doug.

Good morning, everyone.

As we started this morning, I would like to commend the WildHorse's team for putting together an incredible acreage position in the Eagle Ford.

They have also done a really solid job delineating the play and building a strong production foundation.

We're really excited to turn our subsurface and operations team loose on over 400,000 acres of a play that's just now entering the development stage.

We're not starting with a blank slate on the subsurface side.

We already have a really strong understanding of the petroleum system elements and petrophysical model, as a result of a lot of regional work that we have been doing.

Also, a majority of the acreage is covered with 3D, and right now, WildHorse is actually reprocessing that 3D to get a better product.

We have gathered available fluid analysis and the core data from the public domain and from data room.

All this has been combined with the existing well performance, and we have a working model that ties very, very well with historical productivity of the wells.

We will augment this analysis on the fly with additional core pressure testing and fluid data as development wells are drilled allowing for very quick transition to a full field development plan.

With our in-house capabilities, the learning curve will be pretty quick.

As we take everything learned from our Eagle Ford and South Texas as well as the other basins, we will hit the ground running.

We will focus on moving towards longer laterals, reducing drilling and completion costs and optimizing spacing to drive for the greatest value out of this contiguous acreage position.

We also see potential in the Austin Chalk on the acreage footprint and look forward to additional appraisal opportunities.

This gives us a third oil engine in our portfolio and a second one with direct access to premium markets in the Gulf Coast.

Now a quick update on our current program.

We are running 5 rigs in the Powder River Basin.

Today, our focus has been on appraising and drilling spacing tests in the Turner.

We have now delineated about 60% of our perspective Turner acreage and are rapidly entering into the development stage.

Production has increased 107% since the third quarter of 2017 and 32% sequentially.

Looking forward, we anticipate net production to reach an exit rate of approximately 38,000 barrels a day in 2018 and then double again in 2019.

Our 1,980-foot spacing tests have shown no degradation after 190 days online.

We will continue to monitor the production and pressure of these wells as well as other Turner completions with the objective to make a decision on final field spacing in the coming months.

In our step-out program, we've proven the northern and western portion of our acreage with 3 wells having 24-hour flow rates of between 1,480 and 2,725 barrels of oil per day, and more importantly, these wells averaged 82% oil confirming our geologic model.

We are currently evaluating having a sixth rig, likely targeting the Parkman and Niobrara in 2019.

With our strong oil growth, we are focusing on more efficient facility design, common production facilities and gas plant expansion.

In Nick's section, he'll discuss a new oil transportation agreement, which will allow us to continue to unlock the value of this stacked acreage position.

In the Eagle Ford, recent flooding slowed our logistics in September and October.

But in spite of this, we anticipate the asset to deliver approximately $560 million of free cash flow in 2018.

I'm extremely proud of the work done by the operations, drilling and completion teams to adapt and maintain strong execution in spite of the challenging conditions.

Our Marcellus Shale continues to drive free cash flow.

We continue to see strong performance from our extended laterals and larger completion designs.

In the Haynesville, well performance continues to improve, and we see completion costs dropping, but we currently plan to reduce our rig count moving forward in 2019 as we focus our capital spend on higher-margin opportunities.

We are making progress in every asset of our portfolio, and our teams continue to drive for value every day.

As a result, Chesapeake continues to grow stronger and more competitive.

With that, I'm going to turn it over to Nick.

Thank you, Frank, and good morning, everyone.

We're pleased with our third quarter results and continue to make progress on our strategic priorities of reducing our leverage, improving our margins and reaching sustainable cash flow.

With today's announcement regarding our planned acquisition of WildHorse, we believe these priorities will be accelerated.

Given Doug and Frank's comments on the acquisition, I'll focus on our Q3 results.

In September, we amended and restated our revolving credit facility, extending the maturity date from December '19 to September '23.

In addition, we issued $1.25 billion of unsecured bonds through both a '24 and '26 tranche and used the proceeds to refinance our 1.5 lien term loan.

Yesterday afternoon, we closed our previously announced Utica sale transaction and have called the remaining outstanding second lien notes.

The refinancing of the term loan and the redemption of our second lien notes will save the company approximately $150 million annually based on current interest rates.

With the Utica sale closed, we believe our debt maturity profile will look significantly better as we exit 2018 versus when we started the year.

At the beginning of 2018, we had over $4 billion of maturities due through 2023.

By the end of the year, we expect to have reduced that number to a little over $2 billion, well within the company's expected liquidity profile.

However, we will look for opportunities to retire that maturing debt through cash flow generation, targeted asset sales as well as potentially refinance the longer dated maturities when market conditions are constructive to do so.

During the third quarter, we were very active in hedging 2019 gas.

And currently, we have downside protection on over 60% of our forecasted 2019 gas production at $2.81 per Mcf.

Additionally, our current 2019 oil hedges averaged just over $59 a barrel.

And we also started to hedge a modest portion of 2020 oil with swaps over $69 a barrel.

We also added certainty to our Gulf Coast oil basis exposure in 2019 and are now hedged over 1/3 of our Gulf Coast oil at a premium to WTI of over $6 per barrel.

We are beginning to see significant improvement in our average realized Marcellus basis, as demonstrated by the $0.50 increase compared to the third quarter of last year.

With Atlantic Sunrise now in service and basis tightening in Northeast Pennsylvania, we believe that in-basin pricing for our Marcellus gas will continue to improve over the next several quarters.

We have further strengthened our realized pricing for a portion of our Marcellus volumes by recently entering into a long-term supply agreement with a third-party LNG provider.

We expect these types of structured, physical gas purchase contracts to become more prevalent, both for Chesapeake and the industry, resulting in driving long-term demand higher as the demand for secure access to natural gas by global consumers increasingly focuses on the U.S. export markets.

Finally, in the PRB, we are close to finalizing a crude oil gathering agreement, which will take our crude oil volumes via pipeline to the Guernsey market beginning in the 2019 second quarter at a cost that's approximately half of what we've been paying for in-basin sales via trucking or 1/3 of the current market rate for truck transport to Guernsey.

We are also evaluating long-haul transportation options to take volumes further to Cushing, Oklahoma.

As Doug stated, we look toward 2019, we believe that the vast majority of our CapEx will be focused on higher margin and higher return oil assets in the PRB and Eagle Ford and now including our planned acquisition of the WildHorse asset, with a smaller amount of activity and capital to be directed to gas.

To close, we remain highly focused on executing on our priorities of reducing leverage, increasing our margins and achieving sustainable positive cash flow.

We believe the announcement of our planned acquisition of WildHorse will position the company for improved future shareholder return.

First, it creates an immediate positive benefit to our portfolio by adding tremendous oil assets, both currently producing and to develop with our technically advantaged approach and cost structure for many years at an attractive discount to peers, as Doug and Frank have stated.

In addition, the transaction, obviously, provides a significant equitization of our balance sheet.

WildHorse's debt-to-EBITDA is, obviously, relatively low.

Therefore, the combined company has a much improved ratio relative to Chesapeake stand-alone.

As these assets grow with such a high-margin profile, we project significantly improved free cash flow over time from our portfolio.

We always said we will be judicious with our equity and would only think about using it for the right opportunity.

We believe adding an asset with this much strategic value is that opportunity, and we look forward to creating significant additional value for our shareholders from this transaction for years to come.

With that, I'd like to turn the call over to the operator for questions.

(Operator Instructions) Today's first question comes from Neal Dingmann of SunTrust.

Congrats on the deal.

It looks great, Doug.

Doug, I was looking at, per Nick, Slide 6 on the prepared slides and my question around there, just kind of looking at how you expect the company to delever as well as the oil mix.

Is that based on -- I know, I think right now Frank mentioned going from 5 to 6 rigs in the PRB and I think you and WildHorse each have 4 running in the Eagle Ford.

Is that -- could you just maybe talk around some of the call?

I know you don't have full '19 details out yet, but maybe just higher level expectations in the 2 bigger plays of what you might be running?

Yes, sure, Neal.

Thanks for the question.

And I'm going to ask Frank to give the detail around that rig allocation.

Yes, Neal, this is Frank.

So right now, our -- we are running a solid 5-rig program as of July in the Powder.

And I think that those rigs will stay focused on the Turner.

I think that will be our plan going forward.

What we don't want to do is disrupt the delivery of that Powder program.

So the idea would be to bring in a sixth rig to test additional zones, so we can continue to expand the opportunity set in the Powder.

With regard to the WildHorse asset, I believe they have been running a 5-rig program.

They may be down to a 4-rig program today.

We see the opportunity there to potentially create a little bit stronger fleet with a little bit bigger rigs going in there and maintaining a 5-rig program.

We don't know, after we start to apply some of the techniques and operational expertise we have, how much we could actually get out of that 5-rig program.

So I don't know that we would expand that program initially.

We will be taking, as I said, some core and a lot of -- gathering a bunch of information as we drill wells moving into that program.

The plan going forward, we still have a couple of rigs running in Mid-Con, which -- there is a growth rig and then the Oswego rig.

And in the Marcellus, we have a couple of rigs.

Probably, we'll move to a third rig in the Marcellus next year.

Haynesville, we will be dropping back potentially to 1 to 2 rigs.

Okay.

And then just -- go ahead, I'm sorry.

Just want to expand on that one.

One of the -- the fun thing for us is, we had a great quarter in Eagle Ford, and we drilled almost 10,000 feet per well at 9.5 days versus WildHorse's 15 to 17 days for 6,500-foot well.

So we're drilling nearly twice as fast and more footage.

I mean, that's one of the things we think about what the rig count is.

We can get a lot more wells drilled with fewer rigs in the current operations, which is one of the similar synergies that we see from Chesapeake bringing our horsepower, ops center, a lot of our technology to this play.

Got it.

Great add, Jason.

And then one maybe follow on to that, Jason, for you or Doug.

Just when you looked at -- when you initially looked at these assets, I'm looking here particularly at Slide 5 and then -- or Slide 8 or both, was it -- there's a large component here that's undeveloped.

And I'm just wondering is it because of Jason, which you just walked through what you all think about may be that undeveloped piece?

Or is it because of looking at Slide 8 because of the synergies of the take away or is it a combination?

I'm just wondering, Doug, really, if there's any sort of 1 or 2 things that stuck out with this area of what really got you focused on here initially?

Thanks for the question, Neal.

Yes, it’s really all of those things.

It -- this acquisition hits all major strategic objectives of Chesapeake.

And when you look at a large contiguous acreage position, such as the WildHorse asset offers, that is just begging for the Chesapeake weapons to be deployed on it.

And we are excited about what we can do with it on the drilling and completion side, the cost synergies that we can capture; our experience and expertise, as I noted, we drilled -- or noted in the presentation, we drilled or completed more than 2,000 wells in there.

So it's having 80% to 85% undeveloped just gives us a tremendous runway, while complementing and adding and accelerating to all of our strategic objectives that I noted.

And our next question today comes from David Heikkinen of Heikkinen Energy Advisors.

First on the acquisition, I'm not as familiar with WildHorse, but became more familiar this morning.

When we pulled the well results, there seemed to be a decline in kind of well quality recently.

And just curious if that was some step-out drilling?

Or if there is anything that you guys identified through the work you guys did as far as the distribution of well quality?

Or any concentrations on their assets or their acreage that we should think about as you kind of step forward?

Yes, Heik, this is Frank.

I really appreciate that question.

Yes, we recognize the same thing.

I think what you're seeing is a degradation due to too tight of well spacing.

As we worked through this analysis, we got a lot of the existing PVT analysis, have gone back through and remapped the core volume and tied it all together and created a model that really ties really well with the historical well performance.

It's one of the reasons we're not coming out and saying there's x number of wells on this acreage.

This acreage is 80% to 85% undeveloped within the Eagle Ford.

What is the proper spacing?

I think it's going to be just like our South Texas acreage.

In that, in portions of the acreage, the spacing may be necessary to be 1,000 feet or potentially greater.

In some parts of this acreage, the spacing may be a little bit tighter, pushing the 750 or 500 point.

There are wells within the current delineation plan that are much tighter than 500 feet.

And I think you are seeing that response when you look at the well.

So we will spend a lot of time and effort and properly space this, lengthen the wells out, put through appropriate completions on it.

And I think we'll drive the maximum value out of this acreage position.

That's definitely helpful and explained things.

On the Powder, I didn't quite catch the numbers?

What is your gathering agreement change your dollar per BOE cost in the second quarter of '19, Nick?

Yes.

So we will move to an oil gathering line rather than trucking.

And so it will be less than half of what we are paying today to have barrels trucked than currently we are selling in basin.

So we're going to pipe those barrels all the way up to Guernsey and -- which is a premium market to what we would get in basin today by a couple of dimes and then, a few dimes, and then we will do that, again, for a significantly less cost than the trucking, less than half.

So our netbacks here should improve pretty significantly.

The agreement isn't finalized yet, Dave.

And so I don't have a precise dollar per barrel to give you, but we know it's -- it is a more than half improvement.

What's trucking costing?

Maybe at the starting point on a $1 per barrel basis?

Yes.

So today, we are in the neighborhood of $2, sometimes a little bit more, per barrel.

And so this is going to be well under half.

And our next question today comes from Doug Leggate of Bank of America Merrill Lynch.

Can you hear me, okay?

We can.

Yes, good.

Guys, I'm just curious what the transaction does to the balance of the portfolio?

Does this change in any way your view of what's core and noncore across the rest of the asset base?

And if so, how would you think about potential monetization opportunities?

Yes, thanks, Doug.

Frank will be excited to comment on that as well.

When we look at the portfolio, the oil growth engine is between the Powder and the WildHorse asset are very, very strong for us.

Interestingly, the competitive economics and as we look at capital allocation, the Marcellus attracts capital to the limit of the infrastructure available in the basin is just a phenomenal place, very strong cash flow generating asset for the company, as is the Eagle Ford, as you are aware, our existing asset in the Eagle Ford.

We know that this asset has just such strong growth potential that it will be very competitive in our portfolio, but we also want to note that the strength of the other assets it's not that this is just a single asset that comes into the portfolio and commands or attracts capital from the rest of the portfolio.

What we have been very proud of, Doug and Barry encouraged by, is through the past 5 years despite all this challenging environment that we've had with our legacy issues in the commodity price environment is that this is a world-class portfolio of unconventional assets.

And it gives us tremendous flexibility and how we allocate our capital, tremendous learning and shared resources across the assets for us to drive greater value.

So that's been reflected in our operating cost, our capital efficiency and will continue to be reflected in our capital allocation as to where we direct that capital to get -- capture the greatest value.

You want to add anything, Frank.

No.

That was good.

Thanks.

So just to be clear, we should consider that the combined portfolio is a pretty stable model going forward?

That's absolutely right.

And keep in mind, as we've highlighted that we'll continue to look at all opportunities, all levers to capture greater value from that portfolio and continue to improve our business.

So keep in mind that business development is one of the planks of our strategy, and we'll continue to evaluate and look for opportunities to further enhance value for our shareholders.

And so the divestiture of the Utica successfully completing that yesterday, having 2 powerful oil growth engines in the strengths of the gas portfolio, gives us tremendous optionality to capture value going forward.

Terrific.

At the risk of upsetting Brad, I wonder if I could just have 2 quick follow-ups.

One, Frank, just very quickly.

Last time, we spoke about the Powder River.

Obviously, you touched on the de-risking today, but can you give some idea as to how you see the drilling back log at this point relative to what you've previously suggested.

Are we still in the de-risking phase?

Or has the industry managed to help you along in your understanding of that?

And my final one is, just very quickly, on the synergies.

Can you just give a high level as to how deep you've gone in establishing the synergies on the deal?

Or is that still -- is it still early days?

Should we expect those numbers to go up?

And I'll leave it there.

Yes, I'll handle the Powder question and pass it over to Nick for the synergies.

On the Powder side, as I said, we're probably 60% delineated in the Turner.

We still have some room to expand that footprint.

And we will be working through expanding that footprint across our entire acreage position next year.

So we are going to move into the development phase, which will, basically, start pad drilling in the Turner.

We're already starting that process.

The real question we have to answer is, what is the absolute spacing that we want to land on.

As we've talked before, Doug, the industry is kind of landed on 4 wells per section.

We're more in the range of 3 wells per section, and we haven't made that decision to move to that.

Our current assessment is 2 wells per section.

What the industry has helped us do is, there's more activity and more information coming out on the Niobrara and the Mowry.

And those are things that we still have to derisk.

We have a lot of Nio wells that we have in our portfolio, are actual wells that we've already drilled.

We've done spacing test there.

We know what the spacing needs to be on that.

The question is, can we commercially make that work with the larger fracks, and we think we can, and that's where we're going to move next year.

The Mowry is something that is I would like to get unlocked in the next couple of years because in between the Nio and the Mowry, they cover our entire acreage footprint, and that would be a huge boost to us.

Then we could go in and develop pads with Mowry, Nio and Turner on top of each other and really, really drive some efficiencies.

With that, Nick, you want to talk synergies?

Yes.

So Doug, the synergies in this transaction are tremendous for us.

And look, synergies are -- we understand that synergies are often hard for investors to give value to up front.

But in this case, we believe the synergies here are very well justified.

Think about what comprises them.

We broke out in the slides that we posted today essentially income statement synergies versus capital synergies.

The income statement synergies, there will be significant savings from G&A.

We will obviously not have any corporate redundancies, and so there is a lot of savings from that alone.

In addition to that, we will be able to do some things, so that way we will be managing downtime in the assets, things that best practices that we have delivered within our own assets and know the improvements available and know what's there.

We've done our diligence and be very comfortable with that.

On the capital side, Frank and Doug have already touched on this.

Our drilling completion costs are just materially lower given the scale of operations that we have, the success that we have with 10,000-foot laterals and the ability to deliver wells at approximately half the drilling completion costs on a per foot basis.

And so these synergies to us are very real, and there's more to be had.

Those are things that we know we can deliver today, they are sort of right in front of us to touch and feel.

An element of synergies that are additional, that are not included in that number, that we're pretty excited about, is marketing.

When we think about the WildHorse asset and when we think about the transportation portfolio that we have access to coming out of our legacy Eagle Ford position, we have significant access to both the ECHO terminal in Houston, which gives you access to the entire Houston and then worldwide market as well as the Corpus Christi terminal.

We have excess capacity across those 2 pipes today that we currently pay for.

And so with a little bit of further work with our midstream partners, we believe we can gain access to a balanced market of Gulf Coast pricing, premium Gulf Coast pricing, and do so for very little incremental cost to Chesapeake to deliver these barrels, given that we pay a reservation charge for that capacity today.

It's available to us, and we can flow these barrels directly into it and get that premium pricing.

So we're really excited about what that means.

WildHorse has done a very good job in preparing to build an oil gathering system in the field, and they have begun that project.

So that's underway and will be a great thing for us to pick up and continue to deliver on.

And there's just a ton here to do.

So these are the things that we've identified preclosing, and we know that with our track record of reducing cost and delivering better performance out of our assets, there is considerably more to do here.

And the next question today comes from Bob Brackett of Bernstein Research.

I had a question on how to think about the inventory for WildHorse?

Are you thinking about the black oil window working?

Is it the volatile oil window?

Is it the wet gas window?

Or is it some combination?

This is Frank.

All the above.

All the above at the appropriate spacing for the fluid type that you're working with.

So we see multiple type curve areas, if you want to talk about it in that context.

And we ascribe value to every single type curve area, but we ascribe it at different spacing and potentially different lateral lengths and completion designs.

That will all evolve as we get more data, but we have a pretty good model right now with -- like I said, a really strong history match, which we were really pleased with.

And if I think about the capital efficiencies, if the annual number is $150 million to $200 million and WildHorse's CapEx run rate is around $1 billion a year, should I think of that in terms of -- you see 15% to 20% per well savings?

Yes.

That's reasonable.

And again, we see it's going to be pieces here and there that will aggregate into a larger whole.

And Bob, if you take a look at that slide on -- in our deck, Page 10, it really highlights the operating performance of what we have been delivering in our Eagle Ford asset.

And from that, you can see that, basically, cutting the D&C cost by half is something that we anticipate in delivering those savings and that capital efficiency.

And as we noted previously that the time in which we execute the operation is a great value, too, and that's levered by the strength of our operating center and reservoir technology center and just the shared learnings across the portfolio.

So I would hesitate to put any sort of limit whatsoever on what the efficiencies that we can capture based on our scale and experience and expertise.

Bob, to be fair -- this is Frank, again, the WildHorse acreage requires potentially an additional casing string.

We're going to work through that.

So they are drilling different styled wells in South Texas, but we still see huge savings, primarily through our operation support center and being able to keep wells in zone, mitigate the need to sidetrack and basically stay on bottom longer and more effectively as we drill these wells.

And arguably, there were still in sort of an exploration or delineation mode, and this would eventually take into sort of a factory mode?

That's correct.

They were drilling wells in a step-out since, so that is always more challenging than when you go into development.

And that's -- we've shown that across our portfolio as well.

Once you go into development and we get some confidence on what we're doing, we can really drive some cost down.

There's other opportunities even on the completion side -- this is Jason.

So for example, they complete about 6 stages per day.

We averaged 8.5 stages per day in the Eagle Ford last quarter.

So when you're getting more stages done per day, those pumping charges go down.

So those are some things that we can also bring to the table.

It's just efficiency, not only on drilling but our completion operations as well.

And the next question today comes from Arun Jayaram of JPMorgan.

Frank, I was wondering if you could maybe give us a sense of any thoughts that you have on what could be the core in terms of an acreage footprint.

Obviously, they have a big acreage footprint here, but any thoughts on how big the core is?

And perhaps, geologically, what are some of the bigger risks that you see in terms of the deal?

Yes, Arun, it is really hard to describe the core.

They have done a good job delineating quite a big area.

So there will be areas from a core perspective commercially, just because of fluid type and rock quality.

But as we look at this what we know today, the rock quality looks pretty reasonable across the area.

It's a very reasonable drilling depth.

The piece that is not completely factored in and it's an opportunity.

And as you might want to think as a risk is the structure as far as faulting and things like that, but we have a pretty good handle on that.

Today, we will have a much better handle on that and what it does to drilling lateral once we get the reprocessed 3D.

But as we look at this, we don't see this as a risky position.

And we don't see this as something that we're going to not have a significant amount of the acreage available to drill.

Great.

Nick, the Eagle Ford was generating a significant amount of free cash flow for you guys in '18.

When you put the 2 Eagle Ford assets together, do you -- maybe you could talk about some of the free cash flow characteristics you see for this asset?

And one of the points you guys have made is accelerating the point to getting the free cash flow.

So I was just wondering if you can maybe provide some color on that versus the stand-alone Chesapeake basis.

Absolutely, Arun.

So when you think about our portfolio here, we have a very large established production in the Eagle Ford, and that's what puts us in a place to have that asset be free cash flow positive.

If you think about our Powder River asset, and if you think about this asset, they are a little bit more similar to each other in terms of where they are from a free cash flow maturity perspective.

So when you think about what we are doing in the Powder this year that we've talked about, which is that, in the Powder, we will double production again in '19 over '18, and then likely again double in '20 over '19, you have a cash flow profile that at a 5-rig count becomes free cash flow positive during the year of '19 and then on an annual basis from there on.

The WildHorse asset is in a relatively similar position.

The way we'll run this asset if we continue with 5 rigs, which would be our current plan right now and push our cost synergies into it, it becomes free cash flow positive at the asset level pretty quickly.

And then it's going to continue to grow on a similar ramp to what we see in the Powder with that level of investment activity, the production profile, which is going to be vastly oil and very, very high-margin oil will grow very rapidly, and so the cash flow from that grows just as rapidly as your production and you see the free cash flow profile of it expand quickly.

And so what that does for Chesapeake is as we've been aiming for '19 to be a year where we were restoring the cash flow loss from the Utica, this really accelerates that position dramatically and puts us in a place where we will have excess free cash flow much sooner as a result.

So we'll have our full guidance and rolled up assumptions out to the market ahead or around the time of closing, depending on the timing of how everything comes together here, and I'll be able to give you more clarity on that.

But with the margin profile, the growth profile and the capital efficiency profile of this asset, it is absolutely one that delivers higher opportunities for return of cash to our shareholders and deployment of cash in the most optimal way for our shareholders.

And that is a significant driver of our desire to do this deal.

Great.

My final question, Doug.

NGP, a very sophisticated player in private equity, is obviously supporting this transaction.

Any perspectives that you have and any thoughts on that?

Absolutely, I'm thrilled to have NGP as a major shareholder.

And I believe that they are extremely excited to partner with us and invest in Chesapeake.

We are excited about the things that we will do together to drive value to NGP and all of our other shareholders.

And I think that's demonstrated by their large percentage in the stock and what they will continue to hold having representations of the WildHorse share -- WildHorse shareholders on our board speaks further to that confidence.

And we're looking forward to driving a pretty significant value to NGP and all the shareholders.

And our next question today comes from Kashy Harrison of Simmons Energy.

Congratulations on the transaction.

So just 2 quick one -- just 2 quick ones from me, and really just building on the prior question.

So Nick, can you talk about the time line of key free cash flow neutrality for the combined entity?

Just do you think it's more of a 2020 event, more of a 2021 event?

Just trying to get some high-level thoughts on when you think the combined entity could be free cash flow neutral?

Yes.

It certainly looks more like a 2020 event, Kashy.

It's a -- we've been stating all along that 2019 was going to be a year where we're restoring the Utica cash flows and doing so with very high return projects that are putting us in a position for great returns to shareholders.

But that cash on cash return, again, the confidence in the delivery of that grows with this investment profile of this asset and the way that we are shifting some capital away from gas to an asset like this.

So it just -- the time line is pretty similar, but our confidence in it and the magnitude of cash flow that we will generate when we get there grows dramatically with this transaction.

Got you.

And then maybe a question for Frank and just touching on the synergies again.

So in terms of, kind of, like, what you guys were saying, the market is when it comes to synergies, seeing is believing.

And so when do you think we'll start to see the impact from those capital synergies?

Is that something second half of '19 the moment you should get that asset, we'll start to see you transition for longer laterals and whatnot?

Or is it something where maybe it starts to manifest in 2020, more so on the capital side than on the corporate side?

I'd like to tag team that a little bit with Jason, let him talk about the drilling and completion transition here.

But I think from my perspective, we're going to start seeing the synergies play out right up front.

We will start making changes as soon we can.

And as soon as the changes make sense, you'll see those changes, I think, first on the drilling and completion side.

So I'll let Jason, kind of, talk about where we would go.

Yes.

I mean those for us, well, what's great about Chesapeake is it's not just learning from the Eagle Ford.

We have drilling challenges in Powder River, for example, that we deal with on a daily basis.

So a real advantage for us is pulling all that together, but longer laterals definitely drive the efficiency, so that land department will be critical, and just putting those units together will allow us to drill longer laterals.

So I think we should, by the third quarter, start to see that.

And well into 2020, we should be fully up and running.

So expect to drive those synergies very quickly into the operations.

Some on the completion front -- I mean, we moved frac crews from Eagle Ford to Haynesville and immediately saw gains in performance there.

So there were some things to look on the completion side and drilling side, which you should see right way.

Then we have an operation support center that monitors all of our drilling 24/7.

So there's an immediate benefit from being able to monitor our wells live.

We also have a data analytics team that is tied into that operation support center that can help us spot problems before they occur.

So those things should really happen fairly quickly.

We've also seen a lot of improvements, just not necessarily in the WildHorse but across the company with sand sourcing, and there's $100 million in cost reductions we expect to see the next year just by supplying our own sand or going to regional sand in these areas.

So lots of gains across the company coming forward in 2019.

Got it.

And actually, if I could just sneak one more in.

And this one is more so for Doug.

When you think about the -- you've added another leg to the stool in the Northeast Eagle Ford.

And so do you see yourself as the consolidator in that area to build up on?

I know there's some holes within Burleson County on WildHorse's position and there's some nearby operators both on the eastern side and the western side.

So how do you think about it in terms of just consolidating that.

Is that something you would be interested in, in the Northeast Eagle Ford area?

Sure.

It's a great question.

And absolutely, in and around any of our assets, we look for opportunities where we can bolster our position, bolt-on type of opportunities or synergies that can be captured from our scale.

So keep in mind that, that goes back to really a broader question around portfolio management, and how we continue to develop and drive the greatest value from our portfolio.

And that comes from an active business development program, which means that we will actively use our experience and expertise to drive the greatest value from our -- the assets that we have, and we will look at additional opportunities in and around our assets of how we can drive greater synergies and create more value.

So you can absolutely expect going forward that business development will be a part of our business strategy.

And today, we've got a big challenge in integrating this asset, and we're excited about it, and think that we're uniquely positioned to do it with WildHorse.

And as we integrate that asset and put the Chesapeake machine at work, we will always be looking for other opportunities to drive further value.

And our next question today comes from Dan McSpirit of BMO Capital Markets.

Curiously, at the time of second quarter earnings WRD removed their single Eagle Ford type curve from the corporate presentation.

I guess, 2 questions on that observation.

One, will the company bring back the type curve to help guide investors on the resource potential of what was acquired?

And then two, will the company provide more than one curve -- more than one type curve as WRD intended to do in early 2019?

Okay.

This is Frank.

What I believe happened was, as data became available, it could not be defined by a single type curve.

As you move across the field from basically north to south, in general, you go from a black oil to a volatile oil to a much more volatile in the south.

So I think you will see as we look at it in a very similar sense, we've already got it broken up into multiple type curves.

So what that means is, one, the well performance will change slightly, especially on the GOR side, but also the spacing and completion design, as we've discussed, will change across the field as well.

So it's not one type of a reservoir, it is a reservoir that changes across the play.

This is no different than the Eagle Ford in our producing area.

We have the same type of philosophy in our producing area.

We have black oil, we have volatile oil and we have basically gas condensate in portions of the field.

So -- and we manage those quite differently on the drilling and completion side.

So I think you will see us handle this asset in the same way.

Got it.

And as follow-up to that, how did the first year new well decline rates on what was acquired compare to the legacy Eagle Ford and PRB?

So the legacy Eagle Ford wells decline rates have actually improved by going to the appropriate spacing.

So we're seeing that change over time.

In the PRB, we're early there, but those wells are actually in a reservoir that is actually a silty sand.

And those declined curves are flatter than you see in a shale play.

What I think you're going to see in the WildHorse asset -- and we don't have all the information today because we're still working with the information that is being provided to us.

But the -- you're going to see across the play -- if you drill too tight of spacing, you're going to see too high of a decline rate.

And if you drill the appropriate space, I think you're going to see a very reasonable decline, probably pretty similar to what you're seeing in South Texas.

It also depends on the completion style.

So all of that is -- there's not one-size-fits-all, is a bottom line.

It all changes, and we are used to doing work in fields like this.

So we are very comfortable with what we're seeing.

It is not behaving abnormal to what we would expect.

Understood.

And then one last one here.

Will the company complete WRDs infield sand projects?

And forgive me if you discussed that already.

And are potential well cost reductions included in the synergy energy savings that you estimate?

Yes, the sand is something that we'll continue to evaluate.

I mean, it's not necessarily our core business, but we can also -- we can either use it or get regional sand at the same -- at similar price.

So that isn't necessarily a synergy that's included in this operation.

We can get those across the board, but again, expect to see operational synergies fairly quickly.

We can modify completion designs, which actually can reduce sand and increase -- cut our cost and not degrade well performance.

So those are things that we do differently in the Eagle Ford versus the WildHorse.

So all those type of things can be taken advantage of fairly quickly.

Notice that, on top of that, the sand mine is an excellent asset to have.

And so completing it out and being operational gives us a lot of flexibility.

So we're looking to capture value and create synergies across the portfolio, and the sand mine will be fully utilized and optimized to capture that value.

Understood.

Got it.

And just one last one here.

The cost on the additional casing strength that you mentioned earlier.

What does that add to the well?

I don't have that number in front of me.

It's just a matter of -- in portions of this field, the old Giddings, Austin Chalk field overlies a portion of the acreage.

In that area, you have to basically run a complete -- spring a liner across the Austin Chalk to allow you to drill into the higher pressure Eagle Ford.

That is not necessarily the case across the entire field, and we'll work through that.

And what we'll do is we'll just minimize the time it takes.

The actual liner is not that expensive.

It's just the time to drill the well, pull out, clean up and then run the liner and then go back to drilling.

Yes, I was just saying, the time is really important for that when you consider rig costs and spread rates.

As I mentioned earlier, we're drilling wells nearly twice as long for about 5 days faster.

So those incremental costs shouldn't be that huge to us.

The gap is huge between their, again $1,200 a foot and our $600 per foot of lateral.

So I mean, there's lots of opportunities for us to improve fairly quickly in this field.

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

I'd like to turn the conference back over to Doug Lawler for any closing remarks.

Yes, thank you.

Just in closing, we're very excited about the acquisition of these premier assets.

And I'd like to congratulate the shareholders and Jay Graham and the WildHorse leadership team for building an outstanding asset.

We're really excited to go to work on it.

This transaction accelerates our progress towards achieving our strategic and financial goals and makes Chesapeake more competitive across all metrics, and positions the company to deliver significant value to our combined shareholders for years to come.

I could not be more encouraged or excited about the opportunity that presents itself for Chesapeake's future.

Thank you for joining our call, and we look forward to sharing more about our progress with WildHorse and the other parts of our strong portfolio with you in the near future.

Thank you.

And thank you, sir.

Today's conference has now concluded, and we thank you all for attending today's presentation.

You may now disconnect your lines, and have a wonderful day.