Good day, and welcome to the Chesapeake Energy First Quarter Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions Please note, this event is being recorded. I would like to turn the conference over to Brad Sylvester. Please go ahead.

Thank you Chad and good morning everyone and thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2019 first quarter. Hopefully, you have 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 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, you should not place undue reliance on such statements. We may also refer to some non-GAAP financial measures, which help to facilitate comparisons across periods and with peers. For any non-GAAP measures that 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. 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.

Thank you, Brad and good morning. Next month, I will record my sixth anniversary at Chesapeake Energy and I’m as excited today as I ever had been. Over the past six years, our strategy, commitment and tenacity to drive differential top quartile performance for our shareholders, has been consistent and strong and vibrant regardless of external or internal challenges. I'm very proud of progress and accomplishments and I'm excited about the future trajectory of the Company. During these transformation years, we have shared our significant progress on debt and obligation reductions, operating and capital efficiencies, profitability improvements and the simplification of our business. Importantly, for the last 16 quarters in a row, we have met or exceeded the street consensus earnings estimates demonstrating the strength of our employees, asset portfolio and strategy. We are consistently executed and performed as we have projected and we will continue to sharpen and improve our business delivery to drive greater value for our shareholders. The foundational improvements in our balance sheet and capital efficiency and cash generating ability, combined with our operational expertise and scale have positioned the Company to accelerate our rate of improvement and value creation from our diverse asset base. In the first quarter, Chesapeake continued to execute on strategic priorities, delivering yet again strong financial and operational results. As we look at our performance, no, asset exemplifies the energy, talent and conviction of our employees to deliver significant change in a short period of time rather than our new Brazos Valley asset, an asset we now project will be cash flow positive at the asset level this year. During the last three months, we have rapidly integrated the new asset into our portfolio, eliminating approximately $500,000 in cost per well with improved drilling and completion techniques, highlighted by new records…

Thank you, Doug. Good morning, everyone. As Doug mentioned, we were very pleased with the progress our team has made in just a little over 90 days integrating Brazos Valley into our portfolio. We are learning a lot and I'm pleased with what we have seen so far. On the production side, we have already started to redesign completions, namely by reducing fluids used and maintaining sand volumes and combining this with better choke management -. Early results are extremely encouraging, and have seen on the Easy Rider pad in Burleson County where our choke management efforts have already delivered a 35% initial production uplift to historical wells in the area. Once we start to integrate longer laterals, we believe the results will only get better. The well pad in Burleson County represents our first true grassroots wells. And early results are promising, proven from average lateral length of 7000 feet and completed with expansion of 2000 to 4000 fuel barrels per completion stage. This whole pad, is turned in line in late April, and has reached a 24 hour production rate of over 2700 barrels of oil per day and production is still climbing. Comparing to other modern completions in this part of the field, this represents over 190% improvement in early flowback. When we took over operations in February 1st, the majority of the rigs were working in the gas window of the Austin Chalk. We have now altered course, transitioning all four rigs of the oil window at Eagle Ford which we expect will result in our oil volume picking speed beginning in or around the third quarter with cost dropping quickly and an increase in our projected 2019 volumes we are right on schedule. As a result at current strip prices, Brazos Valley now projects to…

Thanks Frank and good morning everyone. Compared to street estimates, we had an excellent first quarter in almost every measures. Our trend of generating higher margins continues, primarily driven by strong oil production that Doug and Frank highlighted, increased oil as a percentage of total production and lower operating expenses, which resulted in the best adjusted EBITDAX margin per BOE production we have recorded in over four years. As Doug highlight, our production stream for the first quarter was 22% oil, compared to 19% in the 2018 fourth quarter and 17% oil a year ago. While the first quarter is traditionally our highest EBITDAX quarter for the year, it's important to note that margin improvements we are recognizing are not simply a function of the price. Our mix will continue to shift oil throughout 2019 and 2020 as the Powder River Basin, Brazos Valley grow and have a greater contribution to the total. We expect to exit the year around 26% oil, the margin of this high oil content is meaningful with our oil assets approximately $30 per BOE EBITDAX margin lead by the Brazos Valley reaching over $37 per BOE due to its low structure and access to Gulf Coast premium pricing. The bottom line result is that while our capital program is lower than last year and commodity prices are currently forecasted to be lower for the full year. Chesapeake will deliver greater cash flow due to our improved oil mix and cost structure. Our cash operating cost structure improved over the first quarter by approximately $81 million, driven by continued improvement in our GP&T expenses. Our GP&T expense of $6.29 per barrel equivalent was more than $1 per barrel lower than the 2018 average driven by asset sales in 2018 in the midstream and downstream contract restructuring.…

Thank you. We will begin the question-and-answer session. [Operator Instructions] The first question will be from John Freeman with Raymond James. Please go ahead.

Good morning guys.

Good morning John.

You have made significant progress in a short time on the Brazos Valley and now it looks like you are spending about $40 million less than what your previously thought, you are still going to bring online a couple more wells than previously expected. Can you just give us some color on kind of what is embedded in the current guidance now in terms of where completed well costs are now and if that is reflected and leading edge wells reflected in the current CapEx allocation?

Yes sure, John. Frank and I will both comment on that. As you would expect that we are we are super excited about the Brazos Valley asset and we are going into it that with the acquisition and the excellent work that had been done there by WildHorse. There would be opportunities to take what we have learned elsewhere in our portfolio and apply it to Brazos Valley and particularly with some of the completion efficiency, stage efficiencies and synergies that with our contractors and the way we approach our business could help drive those costs down. Up to this point in time, as we have shared, we firmly recognize $500,000 per well of which there is a portion of that that is mostly drilling at this point in time, because with what we have been testing with some additional stages and longer laterals, to completion costs probably only represent about 20% to 30% of that 500,000 at this point. That said, we still see a significant opportunity there and I will let Frank comment further on that.

John, I just like to point you to Slide 8 in the deck that we put out with the press release today. And we have seen pretty substantial lateral length increase, which was our plan. Historically, the lateral lengths were around 5000 to 6000 feet. We are pushing those lateral lengths out to somewhere around 9200 to 9300 feet for the year. We are way ahead of schedule on that. Our costs are coming down on a preferred basis about 20% as you can see on that and then Doug said, we are still working with the completion design. But the big game changer is that the kind of Chesapeake Energy methodology of getting stages put away. We have seen a 60% increase on stage count per day. If you look at Eagle Ford wells, you are probably looking at that range of 7.4 million to eight million this year. We think we can get it down a little bit lower than that going forward. We have some things that we want to try to mitigate some whole conditions that we see that causes a little bit of extra time. And then when we go to the Austin Chalk, those wells require a little bit bigger frac jobs. I would say you are looking at probably an 8.4 to 8.8 types cost there. We are not going to drill a lot of Austin Chalk, 2019 and 2020 will be very focused on Eagle Ford.

Great. And then just want to follow-up, any update on the plans for Brazos Valley gathering system, I know WildHorse is looking at having a system built, and I believe you all mentioned that you are probably going to put that out to bid to third-party sustaining of fleet?

Yes. We did in expect to put that out to bid to third-parties relatively thin. We are working through a bunch of logistics and planning for that.

Great. I appreciate it guys.

Thanks Joe.

The next question comes from Biju Perincheril with Susquehanna. Please go ahead.

Hi. Good morning all. Doug, I know you don’t have any 2020 guidance out yet, but looking at the total schedule and the momentum you have in the fourth quarter looks like you have a lot of momentum going into 2020. Can you say anything about how you see the oil production progressing through next year?

Yes. Sure. That is a good question Biju. I'm glad you asked it. When we first acquired WildHorse and have been integrating it into our portfolio. We had provided with some certain estimates of what we though rig activity would be and we actually have recognized a lower rig count in response to commodity prices and our pursuit of free cash flow neutrality and generating free cash flow as quickly as possible. As Nick had highlighted, we anticipate to narrow that gap significantly and look for further improvements in 2019 and so the capital efficiency of program and the rig activity, inclusion activity are largely geared toward how we continue to strengthen the entire Company not looking at just one or single metric. As that rolls into 2020 though, we are very excited about the efficiencies that we have accomplished and as Frank noted getting more from every rig in terms of capital employed as well as more wells drilled and completed, because of our efficiencies, it’s a historical competitive advantage for this Company and we continue to recognize those improvements and we are using that to help position us greater old lines in 2020. So, while we have not guidance out yet for 2020, under the revised circumstances that we have recognized with the capital spend and rig activity, we are encouraged about that profile and are 75% or 80% capital directed towards the oil a year asset. You could expect similar level of investment in 2020 and continued growth to that well.

That is very helpful. And my follow-up was, at least looking at where Q1 numbers came in versus what I was modeling. One of the areas of positive surprise was Eagle Ford, legacy Eagle Ford oil and you touched on in the presentations some of the wider spreads well and last quarter I think you talked about a lot of the work you have done on minimizing downtime. And I was just wondering, if you can just give a broad breakdown of how much of the improvement in Eagle Ford is from the productivity gains on the wells versus minimizing downtime and…

So Biju this is Frank. I think it’s really hard to say because as you recall, we went in and did a lot of work on spacing two years ago and determined that the down spacing was really detrimental to the wells. So what we are seeing now as a result of that work, there is actually slide that demonstrates it on Page 13 of our deck. We have now re-spaced the field to the appropriate spacing for the rock type and the fluid type we believe and we have also changed the completion design for each of those spaces to maximize the recovery from the field. So if you look at parent wells back when the field was first being developed and use that as a baseline, our new wells are performing at about 95% of parent and we think that is a real positive sign. That gives us early production volumes on the wet wells, but it also reduces the decline rate on those wells and the years. So we are seeing good performance on the early wells, good performance on the wells once they go into base go into the base and then we are applying a lot of new technology and concepts to manage our downtime. So it's a combination of all, and I don’t think you can go in discretely break it out. I think what is, is we are doing a really great job in the field and here in the office with the engineering team basically managing this field for optimum results.

Great. Thank you.

The next question will be from Subash Chandra with Guggenheim Partners. Please go ahead.

Yes, thanks. Hey Dough, happy sixth anniversary, this one certainly feels different from the outside. So congrats on the quarter. And when I look at the PRB activity levels and I think you have a few more wells completing this year, curious if that changes the outlook for PRB oil growth which was previously provided.

Not at this point in time. Subash we are encouraged, we are excited, some of the activity and the way we have been continuing to optimize the drill schedule with the improvements that we recognized, we are super excited about some of the rage in this path as Frank noted the pad, total pad production here, recent performance is very encouraging. I would rather look at that and encourage you to look at it, is upside rather than us putting a number on and at this point in time and just ask you to continue to look at the track record as you done of this Company and the trajectory that we are on there. We should see continued improvement and sharing those recent well results in some of the pad volume are good indicators of directionally where we think would be going.

Okay, got it. And I’m going to try and jam a few questions in my follow-up. But In Brazos Valley am I thinking about this correctly that you are looking at all these production enhancement, spacing and so on and so forth. So this year it's pretty oil production volumes fairly flat with an eye towards driving growth in 2020, and then if that is paired by lower Marcellus, Haynesville activity that sort of gets you that 30% type oil cuts for next year?

Yes, that is essentially correct.

Okay, so Brazos, would that require more rig activity to drive that growth beyond what you have or…

It's actually the capital efficiencies that we expect to achieve or doing more with less and actually seen capital reductions in that program as noted by the fact that we expect the asset level to be cash flow neutral or slightly positive there this year. So that is more of the indicative direction of how we expect to do more with less based on the capital efficiencies that we are achieving and recognizing.

Yes. Subash this is Frank. So just to give you a little bit more color on Brazos Valley. We have been working this a little over 90 days now. Most of the drilling activity was predetermined by the previous operator. So we have been basically taking what was already planned and trying to correct at course to the direction we want to go. And so we are really not seeing our full on plan yet. We also have not taken the course that we need to take to get our reservoir characterization and our completions tweaked up. That will be happening in the next couple of months. So on the website, the wells there, the wet wells, we are about where the budget was planned and it's close. We are a little bit behind because of some delays getting off the Austin Chalk wells. But what has been the real surprise is the base production. We have really changed the base production trajectory here. We think that bodes really well because if we can change the base production, which is a pretty large number and then we can move to the to the type of drilling and completion program we want. We probably can do exactly what we want to do or said we were going to do with five rigs with four rigs and that said I must - a lag on my part right now, but I think it looks really good. So we have not seen this thing hit its efficiency stride yet.

Okay. Good color. Thanks, guys.

Our next question comes from David Heikkinen with Heikkinen Energy Advisors. Please go ahead.

Hey, Frank actually you just set up the question. So basically, you think you will have a 20% plus improvement in well per rig, per year in Brazos Valley kind of heading into next year with that four versus five rigs coming?

So David, you know that we are also moving to longer laterals, so the wells - what we are seeing is that with the penetration rate that we have been able to improve, we are getting basically a long lateral for the same time and cost of a short lateral. And I think that is where we are headed. So yes, that is about a 20% increase if you just think about it that way. I think there is still some room to go. The drilling team is working on some opportunities to potentially change out the wellbore design that could actually give us a little bit more. But I think the other side of the equation is going to be on the completions. I think we still have room to go there and I think we can optimize this completions. The other thing is, we are not ahead right now, but we will get ahead on the facility side. So this thing will start running a lot faster.

So that your cost per foot comes down and essentially you have a long lateral for the time of a short laterals. Okay. I just wanted to make sure that was right. Do you think you'll see the same improvement in the Powder as you get to a scaled program?

Yes. I don't think we’ll see the dramatic change you’re going to see in Brazos Valley because we’ve been working the Powder for a couple of years now. We will see improvement. The big improvement on the Powder side I think is going to actually happen on the surface because when we get to the central production facility, and the oil and water gathering system put in place, I think that's going to allow us to really optimize the field development. As we’ve noted in the call, we had some whether delays. It was really -- it snows, and it gets bad in Wyoming. And we're trucking all of our oil and all of our water, and when they shut down the highways, we’re shut in. Once we get on pipe, now we have this consistency of development and production. So, I think we're moving in a really positive direction in Powder, very quickly. We will not see as big an improvement there, because we’ve already seen pretty good improvement.

So, don't model winter weather as significant next winter with the gathering? Okay.

Yes. The model should be a lot more consistent next year, once we get on pipe. Then the only thing we’ll have is crews and equipment moving to rigs and the completion.

Next question will be from Neal Dingmann with SunTrust. Please go ahead.

Good morning all. Nice. Great progress, guys. Doug, just, maybe building out a little bit what Biju had asked earlier a little bit. You guys have done a nice job of quickly reducing outstanding even while adding the WildHorse deal. So, I understand, I think Biju had mentioned that not having the full 2020 out. Can you talk more in just broad terms how you envision next year kind of going forward the outspend and thus your leverage. I know you mentioned in prepared remarks trying to get it down two times. So, I guess, it's more about the outspend how -- inflection point that you could talk about next year to getting or anything you’d give around that. Thanks.

Yes. Sure, Neal. The progress of the Company in that respect has been really, really strong, as I think anyone would agree attached to the progress we’ve made there has been quite significant and quite substantial. As Nick highlighted, we are narrowing the gap in 2019 and extremely encouraged. We see minimal amount of smaller asset type sales for the productivity improvements. And basically, we're going to cross that bridge pretty quickly being free cash flow neutral and ability to generate greater positive cash flow. In that timeframe, we’ve not been specific. It's highly dependent on price. We continue to put hedges in place to protect our capital program, quality of the assets continue to outperform. And the way to look at it Neal is that it’s very, very close, very, very close. The underlying business here is powerful, strong, and capital efficiencies continue to improve. And as I’ve highlighted before, the accomplishments of this Company over the past five years compare to no other. And what you can expect is that is this challenge of our debt reduction and achieving 2 times net debt-to-EBITDA continues to be a major focus for us; it’s essentially our number one priority. And we will continue to make progress on it. And, the way that we are approaching is through the excellent work being done with our current assets and looking for other smaller asset sales, or other opportunities for us to strengthen our portfolio, to continue to achieve that free cash flow neutrality, generate positive free cash flow and reduce that overall quantum of debt.

Okay. And then, one last one, just looking at the PRB, obviously amazing well, that Turner well you all spoke of the 4,000 with not only the big rates, 75% oil. So looking at slide 16, maybe Doug for you or Frank, give me a sense of when you all now look at your 213,000 acres just the type of prospects you see as far as -- I mean, are there -- just trying to get a sense of, is there a large areas that can continue to have these phenomenal type wells or now that we’ve seen -- again, not only the size but just the oil cut behind that. I’m wondering if you’re looking the entire play.

Yes, Neal. This is Frank. If you look at that map on 16, we put a star out there where the central production facility is. That’s all kind of northwestern portion of the field is high oil cut. As you get down into the meat of our acreage around that CPF, those wells are going to be big wells. Now, are they all going to be 4,000 barrels a day? No. We're seeing some variability, but there are really strong wells. And when you take a look at them relative to other oil wells in the U.S., the Turner wells stack out pretty high in that stack. So, I think you’re going to see us spend a majority of our time out on that northwest part of the field. We will only drill a few wells over in kind of the gassier area to maintain acreage because there is also Niobrara and Mowry available to us in that acreages as well. We don’t want to lose the acreage. The map is really deceiving and I hadn’t put a scale on here. But, we have a huge, huge acreage position here and it’s all contagious. And so we have a lot of running room here in the Turner left, but, I’m really, really excited about getting into the Nio as well because now we we’ll be able to stack to Nio right on top of that Turner. The other thing, don’t forget that we may see something better than 4,000 barrels equivalent a day. So, it’s just why we talk about the excitement around that well, the continued improvement and say, are you going to stamp every well at 4,000? Well, you are going to have variability naturally, but we're excited enough and encouraged enough, there may be something better than that. So, don’t take that out of the equation either.

The next question will be from Charles Meade with Johnson Rice. Please go ahead.

Could you go back to that Brazos Valley, could you elaborate a little bit more on what led you to go with this different completion design with lower fluid volumes and higher sand concentration? And I guess, is this an experiment or is this -- I guess it is experiment but is this close to what you think your final design is going to be and when are we going to know, or when will you know if you struck on the right design?

Yes. I’ll just it’s all days work at Chesapeake, Charles. I mean, it’s everything we look at, it’s continued improvement and how we get better and how we take our learnings from elsewhere to the new asset. And this -- the way we -- basically the same concentrations, roughly the same, what we’ve principally reduced with the fluid. And we're going to continue to optimize and pull the levers that we know will be successful and what we’ve learned elsewhere. And Frank can build on that.

Yes. Charles, I think, when we talk to you and everybody on the call about this acquisition, one of the things we said was that this spacing needed to be spaced out wider to about 1,000 feet. We have now gone in and done a bunch of looking at wells. And what -- it appears is that you need the sand concentration because the clay content is higher in this rock, and we knew that. WildHorse had done a fantastic job discerning that. But, what was happening was, there was a ton of fluid being pumped in every stage. And what that was causing was really long frack wings, and those frack wings were reaching out and basically interfering with each other. What we've done is, we've used the same sand content or the same sand amount but at higher concentration, pumping it away with a lot less fluid. That does a couple of things for us. One, it increases the complexity near the well bore and shortens those frack wings. So, we might actually be able to see a spacing change, once we understand the storage capacity here. But the other thing about it that's really important is, these wells took a ton of time to flow back because of the water that was being used. And so, we're going to be able to reduce the cost of pumping the jobs, because less water, we're going to have shorter flowback period, and we're going to have a stronger earlier oil cut. So, everything we've done, I think is going to maximize or improve the economics of the wells. Are we at the end game here? No. We probably have some other things we can work on. But, this is a really, really good start. And we're encouraged by what we're seeing on the initial tests.

That's great detail, Frank. Thank you. And then, if I could ask a follow-up on your -- I guess your CapEx and your overall portfolio. Doug, you mentioned you have about 75% to 80% of your CapEx going to oily plays. But on the other side of that, you guys have really core -- center of the bulls eye positions in really the two dry gas plays that are really working right now the Haynesville and Marcellus. And there have been some news reports in the last few days of like Saudi Aramco trying to team up with Equinor to get into the North American natural gas market. So, could you talk about how you see those two dry gas plays at Haynesville and Marcellus, what role they're going to play in your portfolio -- not in 2019 but in 2020 and beyond?

Sure, Charles. Those two assets are world class, and you got a world class operator that can mobilize, develop those resources really quickly. And we'll continue to monitor pricing environment. The LNG build-out and as more gaskets on the water as additional demand makes sense and economically makes sense, then Chesapeake will react accordingly and adjust the program accordingly. So, they’re super strong assets, extremely well-run here in corporately and particularly in the field. And we can revise and modify and flex our capital at any point time as economic conditions dictate.

Ladies and gentlemen, this concludes our question-and-answer session. I would like to return the conference to Doug Lawler for any closing remarks.

Yes. Thank you. I appreciate everyone's time today. In our prepared comments, we made several references to rate of change or rate of improvement. And I just want to close today by highlighting that the underlying business continues to see excellent progress. And while we have accomplished a great deal over the past few years, the portfolio, the capital allocation and how we are approaching our business, the excitement that we have and the encouragement that we have to continue the rate of change and rate of improvement across our portfolio is something that we are really, really pleased about and really excited about. And I think it's differential. And I believe that, the Company's performance continues to reflect a well-run organization and one that's going to deliver more value to our shareholders disproportionately in the future. So, I thank you for everyone's time. And if there is additional questions, please follow up with Brad and we’ll respond accordingly.

Thank you, sir. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.