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Filed by Chesapeake Energy Corporation (Commission File No. 001-13726) Pursuant to Rule 425 under the Securities Act of 1933 and deemed filed pursuant to rule 14a-12 under the Securities Exchange Act of 1934 Subject Company: WildHorse Resource Development Corporation (Commission File No. 001-37964) |
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The following is a transcript of a conference call hosted by Chesapeake Energy Corporation on October 30, 2018. |
Q3 2018 Earnings Call - Acquisition of WildHorse Resource Development Corporation by Chesapeake Energy
Company Participants
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• | [0B432N-E Domenic J. Dell'Osso] |
Other Participants
MANAGEMENT DISCUSSION SECTION
Operator
Good day, and welcome to the Chesapeake Energy Acquisition Announcement and Third Quarter 2018 Earnings Conference Call and Webcast. All participants will be in listen-only mode. [Operator Instructions] After today's presentation, there will be an opportunity to ask questions. [Operator Instructions] Please also note, today's even is being recorded.
I would now like to turn the conference over to Brad Sylvester, Vice President, Investor Relations. Please go ahead.
Brad Sylvester
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 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 that 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 for our operational and financial results, before we turn the teleconference over to Q&A.
So, with that, thank you. And I will now turn the teleconference over to Doug.
Robert Douglas Lawler
Thanks, Brad. Good morning, and thank you for joining us today. A little over five 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 for our shareholders.
We have 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 strategic 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 the significant depth of oil growth opportunities in the portfolio, reduce waiting to natural gas, and improve financial leverage while pricing 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 2 times. Chesapeake is uniquely positioned to drive greater value from the WildHorse assets and enhance our ability to profitably 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 gives us two 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 de-leveraging efforts by approximately 40% over the next two 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 is second to none. Our proven operational track record and geotechnical expertise provide great confidence that we will deliver material savings across all aspects of the operation.
Specifically, we anticipated keeping 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 improved 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 operations support and reservoir technology centers, the impact of longer laterals and enhanced completions, and our logistic capabilities, which will eliminate additional oil field 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.
Frank J. Patterson
Thanks, Doug. Good morning, everyone. As we get started this morning, I would like to commend the WildHorse team for putting together an incredible acreage position in the Eagle Ford. They've 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 [ph] lose 00:07:57 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 [indiscernible] 00:08:10 system elements best fits the model as a result of a lot of regional work that we've 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 well is 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'll 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're running five rigs in the Powder River Basin. To-date, our focus has been on appraising and drilling and spacing tests in the Turner. We have now delineated about 60% of our prospective Turner acreage and are rapidly entering into the development stage. Production has increased a 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'll continue to monitor the production and pressure of these wells as well as other turnover completions with the objective to make a decision on final field spacing in the coming months.
In our step-up program, we've proven the northern and western portion of our acreage with three 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 cut confirming our geological model.
We're currently evaluating adding a sixth rig likely targeting department [indiscernible] 00:10:47 in 2019. With our strong oil growth, we are focusing on more efficient facilities, 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 the 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 condition.
Our Marcellus shale continues to drive free cash flow which continue to see strong performance from our extended laterals and larger completion designs. In the Haynesville, while performance continues to improve and we see completion costs drop. But we currently plan to reduce our rig count moving forward in 2019 as we focus our capital spend
on higher margin opportunities. We're making progress in every asset in 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.
[0B432N-E Domenic J. Dell'Osso]
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 will focus on our Q3 results. In September, we amended and restated our revolving credit facility extending the maturity date from December 2019 to September of 2023. In addition, we issued $1.25 billion of unsecured bonds through both a 2024 and 2026 tranche and use 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 reduce 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 average just over $59 a barrel and we also started to hedge a modest portion of 2020 oil with swaps over $69 a barrel.
We've also added certainty to our Gulf Coast oil basis exposure in 2019 and are now hedged over a third 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 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 and 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 what we've been paying for in-basin sales via trucking or one-third 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 assets 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 returns.
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'd 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.
Q&A
Operator
Thank you. We will now begin the question-and-answer session. [Operator Instructions] At this time, we will pause momentarily to assemble our roster. Today's first question comes from Neal Dingmann of SunTrust. Please go ahead.
<Q - Neal D. Dingmann>: Good morning, guys. Congrats on the deal. Looks great, Doug. Doug, I was looking at slide – for you or Nick, slide 6 on the prepared slides, and my question around there, just kind of looking at how you expected the company to delever as well as the oil mix, is that based on – I know right now Frank mentioned going from five to six rigs in the PRB and I think you and WildHorse each have four running the Eagle Ford. Is that – could you just maybe talk around some of the call – I know you don't have full 2019 details out yet, but maybe just higher level expectations in the two bigger plays of what you might be running?
<A>: Yeah. Sure, Neal. Thank you for the question. And I'm going to ask Frank to give the detail around that rig allocation.
<A - Frank J. Patterson>: Yeah. Neal this is Frank. So right now, we are running a solid five-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've been running a five-rig program, they may be down to a four-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 five-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 five-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. But that's kind of the plan going forward. We still have a couple of rigs running in MidCon which – there's a growth rig in then the Oswego rig and in the Marcellus we have a couple of rigs probably will move to a third rig in the Marcellus next year. Haynesville, we will be dropping back potentially to one to two rigs.
<Q>: Okay. And then just lastly...
<A>: [indiscernible] 00:19:46.
<Q>: Go ahead. I'm sorry.
<A>: I just want to expand on that. One of the fun things 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 with the rig count is we can get a lot more wells drilled with fewer rigs in the current operations, which is one of the synergy that we see from Chesapeake bringing our horsepower ups and a lot of our technology to this play.
<Q>: Yeah. Great explanation. And then, one maybe follow-on to that, Jason, for you or Doug, just when you look 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, what you just walked through which you all think about maybe that undeveloped piece or is it because of looking at slide 8, because of the synergies or the takeaway or is the combination?
I'm just wondering, Doug, really if there's any sort of one or two things that stuck out with this area of what really got you focused on here initially?
<A - Robert Douglas Lawler>: Thanks for the question, Neal. Yeah. It's really all of those things. 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 and 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've noted.
<Q - Neal D. Dingmann>: I agree. Thanks. Makes all the sense, guys. Thanks so much.
Operator
And our next question today comes from David Heikkinen of Heikkinen Energy Advisors. Please go ahead.
<Q - David Heikkinen>: Good morning, guys. And thanks for taking my question. First on the acquisition. I'm not as familiar with WildHorse but became more familiar this morning. When we pulled the well result, there seemed to be a decline and kind of wealth quality recently and just curious if that was some step-out of 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?
<A - Frank J. Patterson>: Yeah. Hi, this is Frank. Really appreciate that question. Yeah, we recognized the same thing. I think what you're seeing is a degradation due to too tight of well spacing. As we work through this analysis, we got a lot of the existing PBT analysis have gone back through and remap the poor 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 is 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 to 750 or 500 point. There are wells within the current delineation plan
that are much tighter than 500 feet. And I think you're seeing that response when you look at the wells. So, we will spend a lot of time and effort and properly space this, lengthen the wells out, put the appropriate completions on it. And I think we'll drive a maximum value out of this acreage position.
<Q - David Heikkinen>: 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 costs in the second quarter of 2019, Nick?
<A - Domenic Dell'Osso>: Yeah. So we will move to an oil gathering line, so rather than trucking. And so it'll be less than half of what we're paying today to have barrels trucked than currently we're selling at basins. 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 is a more than half improvement.
<Q - David Heikkinen>: What's trucking costs then maybe as the starting point, on a dollar per barrel basis?
<A - [0B432N-E Domenic J. Dell'Osso]>: Yeah. So today we're in the neighborhood of $2, sometimes a little bit more dollars a barrel.
<Q - David Heikkinen>: Okay. Thanks.
<A - [0B432N-E Domenic J. Dell'Osso]>: And so, this is going to be well under half.
<Q - David Heikkinen>: That's helpful. Thank you.
<A - [0B432N-E Domenic J. Dell'Osso]>: Thanks.
Operator
And our next question today comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.
<Q - Doug Leggate>: Thanks. Good morning, everybody. Can you hear me okay?
<A>: We can.
<Q - Doug Leggate>: Yeah. Good stuff. 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?
<A>: Okay. Thanks, Doug. Frank would be excited to comment on that as well. When we look at the portfolio, the oil growth engines 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. It's just a phenomenal play. It's very strong cash flow generating asset for the company.
As is the Eagle Fordm, as you're aware, our existing asset, 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 is 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 very encouraged by is through the past five years despite all this challenging environment that we've had with our legacy issues and the commodity price environment is that this is a world-class portfolio of unconventional assets. And it gives us tremendous flexibility in 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 costs, our capital efficiency, and it will continue to be reflected in our capital allocation as to where we direct that capital to capture the greatest value. Do you want to add anything, Frank?
<A - Frank J. Patterson>: No, that was good. Thanks.
<Q>: So just to be clear, we should consider that the combined portfolio is a pretty stable model going forward?
<A>: That's absolutely right. And keep in mind, as we've highlighted, we will 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 will continue to evaluate and look for opportunities to further enhance value for our shareholders. And so, the divestiture of the Utica successfully completed that yesterday, having two powerful oil growth engines and the strengths of the gas portfolio gives us tremendous optionality to capture value going forward.
<Q>: Terrific. At the risk of upsetting Brad, I wonder if I could just have two 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 ideas to how you see the drilling backlog 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 that deal or is that still – is it still early days? Should we expect those numbers to go up? And I'll leave it there. Thanks.
<A - Frank J. Patterson>: Yeah. I'll handle the Powder question and pass it over to Nick for the synergies. On the Power side, as I said we're probably 60% delineated in the Turner. We still have some room to expand that footprint and we'll 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 four wells per section. We're more in the range of three wells per section and we haven't made that decision to move to that. Our current assessment is two 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 in our portfolio or 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 fracs, 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 unlock in the next couple of years because it – 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 efficiency.
With that, Nick, do you want to talk synergies?
<A - [0B432N-E Domenic J. Dell'Osso]>: Yeah. 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
upfront. 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'll be a significant savings from G&A. We will obviously not have any corporate redundancies, and so there's a lot of savings from that alone.
In addition to that, we'll be able to do some things with LOE, 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 feel very comfortable with that.
On the capital side, Frank and Doug have already touched on this. Our drilling and completion costs are just materially lower given the scale of operations that we have, the success that we've had with 10,000-feet 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're 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 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 two 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
all-gathering system in the field and they have begun that project. So, that's under way 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 pre-closing, and we know that with our track record of producing costs and delivering better performance out of our assets, there's considerably more to do here.
<Q - Doug Leggate>: Guys, appreciate all the answers. And congrats, Doug, on getting the deal done.
<A - Robert Douglas Lawler>: Thanks, Doug.
Operator
And our next question today comes from Bob Brackett of Bernstein Research. Please go ahead.
<Q - Robert Brackett>: Hey. Good morning. 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?
<A - Frank J. Patterson>: This is Frank. All of 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'll 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.
<A>: 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 U.S. 15% to 20% per well savings?
<A>: Yeah. That's reasonable. And again, we see – it's going to be pieces here and there that will aggregate into a larger whole.
<A>: Bob, if you take a look at that slide on our deck, page 10, it really highlights for you 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 of great value to and that's levered by the strength of our operating center and Reservoir Technology Center, 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.
<A - Frank J. Patterson>: Bob, to be fair – this is Frank again – the WildHorse acreage required potentially an additional casing stream. We're going to work through that. So they're drilling different styled wells in South Texas, but we still see huge savings, primarily through our Operations Support Center and being able to keep wells in zoned, mitigate the need to sidetrack and basically staying on bottom longer and more effectively as we drill these wells.
<Q - Robert Brackett>: And arguably they were still in sort of an exploration or delineation mode and this would eventually had taken to a sort of a factory mode?
<A>: 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 – we've shown that across our portfolio as well. Once you go into development and we get some confidence in what we're doing, we can really drive some costs down.
<Q>: Thanks.
<A>: There's other opportunities [indiscernible] 00:37:35 in completion side. It's Jason. So for example, they complete about six stages per day and we averaged eight and a half 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 with just efficiency not only on drilling but our completion operations as well.
<Q>: Right. I appreciate it.
Operator
And our next question today comes from Arun Jayaram of JPMorgan. Please go ahead.
<Q - Arun Jayaram>: Good morning. 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?
<A - Frank J. Patterson>: Yeah, Arun. It's really hard to describe the core. They've 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 of 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'll have a much better handle on that and what it does to drilling longer laterals 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.
<Q - Arun Jayaram>: Great. Nick, the Eagle Ford was generating a significant amount of free cash flow for you guys in 2018. When you put the two 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, just wondering if you can maybe provide some color on that versus the stand-alone Chesapeake basis.
<A - [0B432N-E Domenic J. Dell'Osso]>: Absolutely, Arun. So when you think about our portfolio here, we have a very large established basin production in the Eagle Ford, and that's what puts us in a place to have that asset be free cash flow positive. You
think about our Powder River asset, if you think about this asset, they're 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're doing in the Powder this year that we've talked about, which is that in the Powder, we will double production again in 2019 over 2018 and then likely again double in 2020 over 2019, you have a cash flow profile that at a five rig count becomes free cash flow positive during the year of 2019 and then on an annual basis from there on.
The WildHorse assets in a relatively similar position, the way we'll run this asset, if we continue with five 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 2019 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 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.
<Q>: Great. My final question Doug, NGP, a very sophisticated player in private equity is obviously supporting this transaction. Any perspective that you have and any thoughts on that?
<A - Robert Douglas Lawler>: 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'll do together to drive value to NGP and all of our other shareholders. And I think that that's demonstrated by their large percentage in the stock and what they will continue to hold having representation of the WildHorse shareholders on our board speaks further to that confidence. And we're looking forward to driving pretty significant value to NGP and all the shareholders.
<Q>: Thanks a lot.
Operator
And our next question today comes from Kashy Harrison of Simmons Energy. Please go ahead.
<Q - Kashy Harrison>: Hi. Good morning, everyone, and thanks for taking my questions and congratulations on the transaction. So, just...
<A>: Thank you.
<Q - Kashy Harrison>: ...two quick ones from me and really just building on the prior question. So, Nick, can you talk about the timeline of free cash flow neutrality for the combined entity? 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 neutral.
<A - [0B432N-E Domenic J. Dell'Osso]>: Yeah. It certainly looks more like a 2020 event, Kashy. 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 growth with this investment profile of this asset and the way that we're shifting some capital away from gas to an asset like this. So, the timeline 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.
<Q - Kashy Harrison>: Got you. And then, maybe, a question for Frank and just touching on the synergies again. So, in terms – kind of like what you guys were saying, the market is, when it comes to the synergies, it's 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 2019 the moment you get that asset, we'll start to see you transition to longer laterals and whatnot or is it something where maybe it starts to manifest in 2020, more so on the capital side then on the on the corporate side?
<A>: I'd like to tag team that a little bit with Jason and 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'll start making changes as soon as 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.
<A - Jason Pigott>: Yeah. I mean, those for us – 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 real advantage for us is pulling all that together, but longer laterals definitely drive the efficiency. So the land department will be critical in just putting those units together and allow us to drill longer laterals. We should, by the third quarter, start to see that and well into end 2020 which should be fully up and running. So expect to drive those synergies very quickly into the operations, some on the completion front.
We move franc crews from Eagle Ford to Haynesville and immediately saw gains in performance there. So, those are some things that we look on the completion side and drilling side, which we see right away. And we have an operations support center that monitors all of our drilling 24/7. So there's 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 could 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.
<Q - Kashy Harrison>: Got it. And actually, if I could just sneak one more in. And this one's 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 a consolidator in that area to build up on? I know there's some holes within Burleson County on WildHorse disposition, and there's some nearby operators both on the eastern side, on the western side. So, how do you think about it in terms of just consolidating that? Is that something you'd be interested in the Northeast Eagle Ford area?
<A - Robert Lawler>: 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 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.
<Q>: All right. That's it for me. Thanks for the time, guys, and congratulations again.
<A>: Yeah. Thanks a lot.
Operator
And our next question today comes from Dan McSpirit of BMO Capital Markets. Please go ahead.
<Q - Dan McSpirit>: Thank you, folks. Good morning. Curiously, at the time of second quarter earnings, WRD removed their single Eagle Ford type curve from the corporate presentation. I guess two 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 company provide more than one curve, more than one type curve as WRD intended to do in early 2019?
<A - Frank J. Patterson>: 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 oil in the south. So, I think you will see us 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 [ph] GOR 00:51:00 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 we manage those quite differently on the drilling and completion side. So that I think you'll see us handle this asset in the same way.
<Q - Dan McSpirit>: Got it. Thank you. And as follow-up to that, how did the first year new well decline rates on what was acquired compared to the legacy Eagle Ford in PRB?
<A>: 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 [indiscernible] 00:52:17sand. And those decline curves are flatter than you see in field [indiscernible] 00:52:23.
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's being provided to us. But the – you're going to see across the play, if you drill to tight a spacing, you're going to see too high of a decline rate. 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 the bottom line. It all changes. And we're used to doing work in fields like this. So, we're very comfortable with what we're seeing. It is not behaving abnormal to what we would expect.
<Q>: Understood. And then, just one last one here. Will the company complete WRD's in-field sand project – and forgive me if you discussed that already – in our potential well cost reductions included in the synergy savings that you estimate?
<A>: Yeah. The sand is something that we'll continue to evaluate. I mean, it's not necessarily our core business, but we can also – look, 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 advantaged of fairly quickly.
<A>: And notice that on top of that, the sand mine is – it's an excellent asset to have. And so, completing it out and being operational gives us a lot of flexibility. So we – 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.
<Q>: Understood. Got it. And just one last one here. The cost on the additional casing string that you mentioned earlier or is that added to the well?
<A>: 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 – a string 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 you go back to drilling.
<Q>: Understood. And thanks again – go ahead.
<A>: Yeah. I'm just saying the time is really important to that when you consider rig costs, spread rates I mentioned earlier. And we're drilling wells nearly twice as long for about five days faster. So, those incremental costs shouldn't be that huge to us. The gap is huge between there, again, $1,200 a foot and ours $600 per foot a lateral. So, I mean, there's lots of opportunity for us to improve fairly quickly in this deal.
<Q>: Very good. Thanks again for the answers and for all the color. And good luck. Thank you.
<A>: Thank you.
<A>: Thanks.
Operator
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.
Robert Douglas Lawler
Yeah. 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. It 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.
Operator
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.
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Cautionary Statement Regarding Forward-Looking Information
This communication may contain certain forward-looking statements, including certain plans, expectations, goals, projections, and statements about the benefits of the proposed transaction, WildHorse’s and Chesapeake’s plans, objectives, expectations and intentions, the expected timing of completion of the transaction, and other statements that are not historical facts. Such statements are subject to numerous assumptions, risks, and uncertainties. Statements that do not describe historical or current facts, including statements about beliefs and expectations, are forward-looking statements. Forward-looking statements may be identified by words such as expect, anticipate, believe, intend, estimate, plan, target, goal, or similar expressions, or future or conditional verbs such as will, may, might, should, would, could, or similar variations. The forward-looking statements are intended to be subject to the safe harbor provided by Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934, and the Private Securities Litigation Reform Act of 1995.
While there is no assurance that any list of risks and uncertainties or risk factors is complete, below are certain factors which could cause actual results to differ materially from those contained or implied in the forward-looking statements: the possibility that the proposed transaction does not close when expected or at all because required regulatory, shareholder or other approvals are not received or other conditions to the closing are not satisfied on a timely basis or at all; the risk that regulatory approvals required for the proposed merger are not obtained or are obtained subject to conditions that are not anticipated; potential adverse reactions or changes to business or employee relationships, including those resulting from the announcement or completion of the transaction; uncertainties as to the timing of the transaction; competitive responses to the transaction; the possibility that the anticipated benefits of the transaction are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of the two companies; the possibility that the transaction may be more expensive to complete than anticipated, including as a result of unexpected factors or events; diversion of management’s attention from ongoing business operations and opportunities; the ability of Chesapeake to complete the acquisition and integration of WildHorse successfully; litigation relating to the transaction; and other factors that may affect future results of WildHorse and Chesapeake.
Additional factors that could cause results to differ materially from those described above can be found in WildHorse’s Annual Report on Form 10-K for the year ended December 31, 2017 and in its subsequent Quarterly Reports on Form 10-Q for the quarters ended March 31, 2018 and June 30, 2018, each of which is on file with the SEC and available in the “Investor Relations” section of WildHorse’s website, http://www.wildhorserd.com/, under the subsection “SEC Filings” and in other documents WildHorse files with the SEC, and in Chesapeake’s Annual Report on Form 10-K for the year ended December 31, 2017 and in its subsequent Quarterly Reports on Form 10-Q for the quarters ended March 31, 2018 and June 30, 2018, each of which is on file with the SEC and available in the “Investors” section of Chesapeake’s website, https://www.chk.com/, under the heading “SEC Filings” and in other documents Chesapeake files with the SEC.
All forward-looking statements speak only as of the date they are made and are based on information available at that time. Neither WildHorse nor Chesapeake assumes any obligation to update forward-looking statements to reflect circumstances or events that occur after the date the forward-looking statements were made or to reflect the occurrence of unanticipated events except as required by federal securities laws. As forward-looking statements involve significant risks and uncertainties, caution should be exercised against placing undue reliance on such statements.
Important Additional Information
This communication relates to a proposed business combination transaction (the “Transaction”) between WildHorse Resource Development Corporation (“WildHorse”) and Chesapeake Energy Corporation (“Chesapeake”). This communication is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the Transaction or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law.
In connection with the Transaction, Chesapeake will file with the SEC a registration statement on Form S-4 that will include a joint proxy statement of Chesapeake and WildHorse and a prospectus of Chesapeake, as well as other relevant documents concerning the Transaction. The Transaction involving WildHorse and Chesapeake will be submitted to WildHorse’s stockholders and Chesapeake’s shareholders for their consideration. STOCKHOLDERS OF WILDHORSE AND SHAREHOLDERS OF CHESAPEAKE ARE URGED TO READ THE REGISTRATION STATEMENT AND THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION WHEN IT BECOMES AVAILABLE AND ANY OTHER RELEVANT DOCUMENTS FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THOSE DOCUMENTS, BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION. Investors will be able to obtain a free copy of the registration statement and the joint proxy statement/prospectus, as well as other filings containing information about WildHorse and Chesapeake, without charge, at the SEC’s website (http://www.sec.gov). Copies of the documents filed with the SEC can also be obtained, without charge, by directing a request to Investor Relations, WildHorse, P.O. Box 79588, Houston, Texas 77279, Tel. No. (713) 255-9327 or to Investor Relations, Chesapeake, 6100 North Western Avenue, Oklahoma City, Oklahoma, 73118, Tel. No. (405) 848-8000.
Participants in the Solicitation
WildHorse, Chesapeake and certain of their respective directors, executive officers and employees may be deemed to be participants in the solicitation of proxies in respect of the Transaction. Information regarding WildHorse’s directors and executive officers is available in its definitive proxy statement, which was filed with the SEC on April 2, 2018, and certain of its Current Reports on Form 8-K. Information regarding Chesapeake’s directors and executive officers is available in its definitive proxy statement, which was filed with the SEC on April 6, 2018, and certain of its Current Reports on Form 8-K. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the joint proxy statement/prospectus and other relevant materials filed with the SEC. Free copies of this document may be obtained as described in the preceding paragraph.