Good day and welcome to the Chesapeake Energy Corporation Q3 2016 Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Brad Sylvester. Please go ahead.

Thank you, Ashley. Good morning everyone, and thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2016 third quarter. Hopefully you've had a chance to review our press release and the updated investor slides 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 and you should not place undue reliance on such statements. We may also refer to some non-GAAP financial measures, which help facilitate comparisons across periods and with peers. For any non-GAAP measures we use, a reconciliation to the nearest corresponding GAAP measure can be found on our website and in our earnings release. With me on the call today are Doug Lawler, Nick Dell'Osso, Frank Patterson, and Jason Pigott. Doug will begin the call and then we'll turn the call over to Nick for a review of our financial results before we turn the teleconference over to Q&A. So, with that, thank you again. And I will now turn the teleconference over to Doug.

Thank you, Brad, and good morning. Over the past year, we've continued to make significant progress in building a stronger Chesapeake for the future. During our Analyst Day held a few weeks back here in Oklahoma City, we highlighted the strength in our asset base, technology and expertise. To briefly summarize, the financial and operational improvements of the company over the past few years are foundational and differential. We've reduced our total leverage by $10.9 billion, reduced cash cost by roughly 50%, substantially improved capital efficiencies and productivity and materially improved midstream gathering cost, all to build a more competitive, profitable Chesapeake that we forecast in 2018 to achieve free cash flow neutrality and the ability to generate more than $3 billion in EBITDA. All this progress has been made despite depressed commodity prices. At our Analyst Day, we released significant technical detail regarding the potential of our oil and gas portfolio, notably, the estimated net recoverable resources of 11.3 billion barrels of oil equivalent. We provided a roadmap that highlights the opportunity for profitable and efficient growth through our captured resources over time along with projected financial results through the end of the decade under certain reasonable price assumptions. I'd like to update you today on a couple of operational results of interests since our Analyst Day. In the Haynesville, we are currently fracking a 10,000-foot lateral well with 50 million pounds of sand, or roughly 5,000 pounds per lateral foot, at ultra-tight cluster spacing. This completion will have the largest number of stages we have ever pumped in the Hayneville in a single well, and the well should be placed to sales in the next few weeks. We are recognizing transformation value improvements in this asset and we look forward to sharing more results of our progress in…

Thank you. And we'll take our first question from Neal Dingmann with SunTrust. Please go ahead.

Hey, sorry about that, Doug. Can you hear me all right?

We can.

Okay. Sorry about that. Say, Doug, although not necessarily these ones earlier, could you talk about just any potential near-term and longer-term asset sale candidates?

Neal, as we've highlighted, the Haynesville is our principal area of focus, if I could point to the huge inventory of resources and the strong assets we've got to drill the locations. We haven't provided any other guidance yet. Although with that significant inventory across our portfolio, you can expect to see additional asset sale candidates potentially from any of the areas in 2017.

And then just secondly, just on the Eagle Ford, it looks like you continue to make a lot of improvements there. Could you talk a little bit about any upside you might be able to see, let's say, in 2017 from either the efficiencies or lower cost? I was just noticing on this slide that only about 25% has been drilled. So does that mean you can come back and return to existing pads, do improvement there? And do you see lower costs as well?

Yes, it absolutely does, Neal. That's part of the comp as we have in some of those continued capital efficiencies, operating efficiencies, we see significant potential there. And just as a highlight, too, is many other companies have reported – remember that Chesapeake's position, we often in many of our pad locations and sections, have just a single well. So it's not like we're coming out with very strong, aggressive downspacing. This is a significant development opportunity essentially from a blank slate with that many opportunities in front of us.

Great. Thanks.

And our next question comes from David Heikkinen with Heikkinen Energy Advisors.

Good morning, all. You sound remarkably well rested given the amazing end to the World Series last night. I'm just hoping that my energy levels can hold in as well. The question I was thinking about was in the Mid-Con, can you talk about your water volumes on the Wedge wells? Is there any – trying to get some details on zones. And I know you're not ready to do all that yet, but any indications of additional information would be helpful.

Yeah, this is Frank Patterson. Depending on what zone it is, it's less than, say, the Mississippian. But we're still in the early days trying to understand it. So, you've got multiple zones in there. You've got Chester, Meramec, Osage, and each of them are going to react differently. We really haven't got enough data yet to really give you a good feel for what the water cut is, but it looks like it's going to be less than the Mississippian as a whole. They're quite a bit different reservoirs. They're tighter than what the Mississippian play is.

And then around the Mississippian, what is the current status for water and water disposal and any impact of earthquakes or shut-ins for your assets?

Yeah, this is Frank again. We do have volume shut-in. We are in compliance with the OCCs requirements. We are in the process of converting some disposal wells to shallower zones. We're also shutting in wells or managing wells that are higher water cut. If you went to the Investor Conference, with the information we have today, we can actually target lesser water cut wells in our forward program. So it's an all hands on deck manage that process. But what we're seeing today is our volumes are starting to come back with the good work, the field and the teams have done on the technical side.

How much volume's shut-in?

Jason, do you remember how much longer we have shut-in?

I think they've got most of it opened up. With all the recompletions, we've been able to increase our capacity prior to any of the restrictions we had on. So early on, we took a hit on the water volume, but I think we're almost at full capacity right now. So any wells that are shut-in are shut-in just for economics and pricing situations, not due to restrictions from the water.

Your October volumes are like a true number. That's what I was getting at on that question. Thanks, guys.

Okay. Thank you.

And our next question comes from James Sullivan with Alembic Global Advisers.

Hey, guys. Good morning. A quick question on the marketing number. Could you just help us a little bit going through the math on that? I know that you've obviously got the forward sale contract, which I think in the report you said was factored into the results. So a little bit of help on the quarterly number. And then I know that the 2017 marketing margin was a little wider than it's been in the past. Is that I assume as well because of the forward sale? So just any help you can give us on that, that would be really great. Domenic J. Dell’Osso - Chesapeake Energy Corp.: Sure, James. You were trailing off a little bit there. So I think I got the gist of the question. If I don't answer it fully, just come back with more. But we did sell a long-term gas supply contract during the quarter. We had announced that previously. That had with it a mark-to-market gain on future periods of $280 million that had been in the asset section of our balance sheet. You can think of that fairly consistent with the way you would account for a hedge, where the future value of that contract was marked each quarter and was in a gain position, so it was an asset. So that came off. It was not included. The removal of that gain was not included in our adjusted earnings. What we did include was $146 million of actual cash proceeds we received from accelerating the value of that contract to the quarter, again, all received in cash. And we wanted to really highlight that. And so right in the paragraph where we discuss the things that we adjusted out, we highlighted that we included that in. The reason we…

Okay. Thank you. That's a very complete answer. I appreciate all that. Just if I could ask for also just a little bit more detail, switching over to the Haynesville here. You guys gave out the two packages that you're working on. I think you gave your anticipated PDP EBITDA. Can you break out just for each of those the acreage number? I know you've given an aggregate acreage number that you're looking to sell, but for the two packages, and I don't know if you want to go into this level of detail, but the acreage number, the slowing production and then just if you could repeat that anticipated EBITDA number, that'd be very helpful. Domenic J. Dell’Osso - Chesapeake Energy Corp.: Yeah, so there's a little more acreage in southern package than there is in the northern package. It's a bit of a mix of – it's not all core Haynesville acreage. There's a little bit of Bossier acreage in there as well. So we haven't, I don't think, broken out the exact acreage of the north and the south and we'll probably hold off on doing that today. But the southern package has more acreage, less cash flow. Northern package has less acreage, more cash flow is the way to think about those two.

Okay. Great. That's very helpful. Thanks, guys.

Next we will hear from David Tameron with Wells Fargo.

Yeah. Good morning. Doug, back to the Haynesville. Can you go through what you said your most recent completion is and how should we think about that as far as what do you need to see additionally from that well in order to justify the higher completion costs?

Yeah, you bet. Actually, I'm going to have Jason to answer it. This is so cool. You're going to love it.

So this is Jason Pigott. We've got a couple of tests underway right now. We've brought online and announced at our Analyst Day the first 5,000-pound per foot job. But that was on a shorter lateral. So we've got a really good test going on there right now where we've got a 3,000-pound per foot job flowing right beside one of the 5,000-pound per foot jobs. We've kind of tried to manage them and keep them as equal as we can, but the 5,000-pound per foot job is flowing back at, I guess a week later, 17 million cubic feet a day and 7,900 pounds, and the 3,000-pound job, that's 14.5 million cubic feet a day and 7,500 pounds. So we've definitely seen a big gain from going to 5,000-pounds per foot and we're excited about it. And we've updated our cost. It cost us about, if you extrapolated this to a 10,000-foot well, it's about $600,000 more to go to the – well, $1.2 million if you go all the way from 3,000 to 5,000 pounds. So it's not a huge incremental investment considering the gain that we see already on the side-to-side test. The record well that we also highlighted with the 50-million pounds has got all of its plugs drilled out and will be coming online Friday. So we're really excited about that. It will be the first 10,000-foot well with this bigger design on it. And then Doug highlighted in his notes one that tested the limits of even tighter perf clusters was the big job that they're getting ready to do as well. So we've got several exciting tests coming online. We're very encouraged by the incremental performance from the increased sand and perf clusters facing. We've got several other tests with 4,000-pound jobs that kind of split the difference coming up. So, very dynamic program in the Haynesville, but one we're very excited about and it seems that every little bit extra we do to these wells is producing a very positive return to us.

Yeah. So, hey, David, I might just add to that. So think 4 Bcf in 120 days.

Oh, okay. All right. Yeah. That's a big well. I guess one more just, I'll go with this one. Doug or whoever, when I start thinking about sand, start talking about those volumes of 50,000 pounds, logistically, if that becomes your standard design, how do you manage that from an operational standpoint just getting the sand from wherever it's coming to the well site, and especially when we start thinking about on the development program longer term over the next year to two, how do you manage that?

Well, I think it's just like any of our operations, there's quite a bit of detail and planning around it. And as you have experienced and seen with Chesapeake in the past, this company is capable of handling significant operations, significant detail complexity in our operations and managing of that as we narrow in on an optimum design, won't be any trouble for us at all. Keep in mind also that a lot of the cost efficiencies that we have accomplished have been a result of synergies and the number of jobs, the planning and engineering that goes into completing a very high number of stages on a daily basis, which creates significant opportunity for our contractors and service providers. And so we have great relationships there. And their interest in doing work for Chesapeake and being a part of our program is very strong and that helps us on the logistics and planning side as well. I don't know, Jason, do you have, Frank, anything you want to add to that?

I think the big thing for us, though, as we do a lot of work on the pre-planning of these jobs before we even show up on location. For one of these Haynesville 50 million pound job, there's 1,000 trucks full of sand that pull up there. But we did it our first try without a hitch, so it's just something that we do well. We plan ahead. Everybody knows what they're doing. That allows us to get more stages per day done, but also handle logistics as well.

Yeah, the other thing I would add – this is Frank – is I think there's kind of in your mind maybe thinking about our entire inventory receiving this type of a completion design, but we are designing our completions for the rock type and for the play. So it's working really, really well at high concentrations in the Haynesville. It might work in other plays, but other plays we might have a different recipe. So we're not talking about that type of sand in every single play.

I'm going down there in the next couple weeks, David. If you want to go, let me know.

All right. Sounds good. Yeah, I was just thinking about how many trucks it takes to get in there. But thanks for the color. I appreciate it.

And we'll take our final question from Jacob Gomolinski with Morgan Stanley.

Morning, guys. Thanks for taking the question.

Morning.

Morning. Thanks. I just had a quick question on the – just a quick clarification on the $280 million supply contract derivative and the $146 million cash addition. Just trying to get to what is an acceleration versus what would have been in Q3 to get to a run rate EBITDA number. Of that $146 million in cash realized that was added back, what would have been in Q3 on a run-rate basis? Domenic J. Dell’Osso - Chesapeake Energy Corp.: It had been running in the neighborhood of $15 million to $20 million. I didn't go back and calculate exactly what it would have been just for the quarter if that had stayed in place. Again, it's on a $4 floor, so that would have been I guess a little up Q3 to Q2, so it would have been a little less in Q3.

Okay. Thanks. And then I think you had said pro forma cash post the Barnett sale was $650 million. I don't know if you're able to do a walk from, there's like the $4 million as of 9/30, the $900 million from the Analyst Day and the $650 million. If don't know if that's driven by the payment to Williams or if there's something else to go from $900 million to the $650 million. Domenic J. Dell’Osso - Chesapeake Energy Corp.: Yeah, you got it. It's basically the payment to Williams is the big move there. It was $334 million. We had some other cash come through the company and then back out for contracts associated with the Barnett. So fair amount of moving pieces there. The biggest piece is Williams. That's done. The reason to have given that number today is that's done and that's where we sit from a liquidity perspective after all of that.

Okay. Great. And I just want to make sure I heard correctly. Domenic J. Dell’Osso - Chesapeake Energy Corp.: One other piece I just want to highlight there – sorry to butt in. But when you think about reconciling back to the proceeds we received from our convert at the beginning of October, we have already put to work about $100 million of that in open market purchases of 2017 and 2018 notes.

Right, right. Great. And then just a last question on the Haynesville asset sale. Were you saying that the – is the initial sale still expected to be before the end of the year, or is that moving into Q1 of next year? And if it is moving into Q1, is that just to give buyers more visibility into the most recent high-intensity well completions? Domenic J. Dell’Osso - Chesapeake Energy Corp.: We'll have an announcement on the first package before the end of the year. And whether or not it closes before the end of the year is kind of hard to predict as you get into holidays and, frankly, not that meaningful to us. We want to get the deal right and get it papered right. Second deal, like I said, we just opened the data room, and so not sure that we'll be able to announce that before the end of the year. And, again, want to make sure that we have the time for buyers to digest all of the things that Doug and Jason have commented on this morning with respect to the Haynesville and the incredible well performance there. So might stretch that one out a little bit in order to get the right answer.

Great. Thank you very much.

Thanks, Jake. Thank you all for joining us today. Please feel free to reach out to Brad. We're happy to share any additional information about our progress and the accomplishments of the company. And that concludes our teleconference. Thank you all for participating.

And, again, ladies and gentlemen, that concludes our conference for today. We thank you for your participation. And you may now disconnect.