Please standby, we are about to begin. Good day. And welcome to the Chesapeake Energy Corporation Second Quarter 2014 Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Gary Clark. Please go ahead.

Thank you, Doug. Good morning. And thank you all for joining our call today to discuss Chesapeake's financial and operational results for the 2014 second quarter. Hopefully, you've had a chance to review our press release and the updated investor presentation that we posted to our website this morning. During this morning's call, we will be making forward-looking statements, which consist of statements that cannot to 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 on Pages 86 of our August 6, 2014 10-Q and in the company's other filings -- 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. I would next like to introduce the members of management who are on the call with me today, Doug Lawler, our Chief Executive Officer; Nick Dell'Osso, our Chief Financial Officer; Chris Doyle, our Senior Vice President of Operations, Northern Division; and Jason Pigott, our Senior Vice President of Operations, Southern Division. We will next turn to prepared commentary from Doug and Nick, and then we will move to Q&A. Doug?

Thank you, Gary, and good morning. As Gary noted, I hope you have got an opportunity to review our 2014 second quarter results they were issued earlier this morning. Chesapeake had another strong quarter of production growth and operating performance. We continue to make foundational progress on our strategies of financial discipline and profitable and efficient growth from our high-quality assets. I am very pleased with our continued improvements in operating efficiencies, measured by cycle time improvements, capital spending reductions and cash cost leadership. Production for the second quarter averaged 695,000 barrels of oil equivalent per day. This represents an increase of 30% year-over-year after adjusting for asset sales. Our crude oil production was up 12%, NGL production was up 72% and natural gas production was up 7% all adjusted for asset sales. Once again we delivered a strong production growth while employing a very efficient capital expenditure program it was nearly 3% less than the year ago quarter. I am pleased to highlighted that we are increasing the midpoint of our 2014 production growth outlook by 10,000 barrels of oil equivalent per day or about 1.5%. The production increase is a result of our focus on base production, 35% increase in planned well connections during the second half of the year, as well as anticipated transaction timing of some of our previously announced A&D activity. Looking ahead, based on current performance and anticipated completion of new infrastructure, we are confident that our year end 2014 daily production exit rate will exceed 730,000 barrels of oil equivalent. Turning to capital expenditures, total spending during the second quarter was $1.3 billion before capitalized interest of which approximately $1.1 billion was for drilling and completion activities, approximately $50 million was for leasehold acquisition and approximately $130 million was for other capital expenditures.…

Thanks, Doug, and good morning. We are very proud of our operational and financial performance year-to-date, as well as the significant progress we have made towards our strategic objective of leverage reduction and balance sheet simplification. As a reminder, we are reducing debt and commitments by over $6 billion in two years and recently further simplified our capital structure with the repurchase of the CHK Utica preferred. During the second quarter the rating agencies raise our credit rating two notches such that we are now positioned just below investment grade. Turning to second quarter results, production growth was strong up 4% sequentially on an absolute basis versus the first quarter, while production expenses plus G&A expenses were down sequentially coming in at 589 per Boe in Q2 compared to 603 per Boe in Q1. Chesapeake reported adjusted earnings of $0.36 per share in the second quarter with adjusted EBITDA of approximately $1.3 billion. The primary driver of our sequential decreases in quarterly earnings and EBITDA with lower commodity price realizations specifically for natural gas, which we previously discussed in our press release dated July 29th. I’d like to take a few minutes to talk about our natural gas price realizations during the quarter and our expected -- expectations for the remainder of the year. I will also discuss some of the changes to our 2014 outlook. As previously announced on a company-wide basis, our natural gas price differential increased to a $1.91 per Mcf during the second quarter, which was up from a $1.08 per Mcf in the first quarter. Chesapeake’s differentials consisted two key components, basis, which is the discount to Henry Hub pricing that reflects various physical sales points at which Chesapeake sales its gas and non-basis, which includes gathering, transportation, processing and other marketing costs. I will…

Thanks, Nick. I just like to reiterate the Chesapeake is standing strong on four pillars today. We are growing production at a double-digit annual rate, we are demonstrating excellent capital efficiency and cost leadership, we are reducing our financial complexity and we are laser focused on creating shareholder value through a variety of strategic initiatives. Chesapeake is a growth company. We have the strategy, high quality assets and talented employees to deliver growth quarter-after-quarter. We are still targeting non-core divestures in 2014 and also evaluating other value creation opportunities within our portfolio. We will continue to look for these value creation opportunities such as the Powder River Basin acquisition, where we can focus our expertise and talent on further growth for our shareholders. We’ll now open the call up for questions. Operator?

Thank you. (Operator Instructions) And we will take our first question from David Tameron with Wells Fargo.

Hi. Good morning, Doug.

Good morning, Dave.

Let me jump in the detail. Utica, with Kensington plant coming on, I mean, you have 200 -- I think the number you put in press release, 210 wells, that are waiting on completion. Does that -- can you just talk about the infrastructure out there and obviously, the Kensington plant helps, but how quickly can you get down that backlog, how should we think about that over the next six months?

Yeah. Sure, Dave. Chris Doyle will have some additional comments on it. But as we look towards the year end we expect that inventory to continue to reduce as we build into the capacity we have available. Chris, do you want to provided any color?

Yeah. Sure. Hey, Dave, this is Chris Doyle. As you mentioned, Kensington 3 did come online as scheduled, actually a couple weeks ahead. It allowed us to ramp beginning at July and into this month. We've got one additional, as we laid out, actually a couple of additional projects coming online in the fourth quarter. Expansion of the Cardinal system with compression and then additional processing capacity at UEO Haynesville and that will get us to that target about 100,000 net barrels of production by the end of the year as we laid out at Analyst Day. As you correctly said, our beginning inventory this year is about 200 wells. By the end we see that around 150 to 160. The additional capacity will obviously allow us to bring those wells on throughout the remainder of this year. And I’ll also point out we probably have about 50 million a day of gas behind shale currently, it’s down a little bit from what we have talked about previously and Kensington 3 big part of giving that gas online.

Okay. That's helpful. And then just one more before I let somebody else jump on. If I just think about the Utica, I know you guys covered this at Analyst Day? But you are drilling a couple tests, I guess, you are drilling at Wetzel County, you're drilling the drygas test and then you're messing around with the oil window? Doug, can you remind me like what's your snapshot or whoever, or Chris, can you remind me of where you think this play heads over the next six months, I mean, obviously the drygas is attractive but can you just give me your snapshot?

Let me start with oil test, the oil window. We brought online the well we mentioned it at Analyst Day is called Parker well. Brought it online this quarter, last quarter I should say, it’s been on production for a couple of months. We continue to be encouraged with what we are seeing. It’s a highest IP that we have seen to-date. We saw an area that we were expecting about zero or very marginal return on investments is now in mid-20s and pushing higher, plan is we will continue to delineate that area, which I characterize be about 80,000 or 100,000 net acres to Chesapeake continued to delineate that over the next six months with probably two to four wells, some of those in moderate risk areas and continues to push out into what we currently characterize as higher risk as we continue to derisk this part of the play. The idea that we can take a forgotten part of the Utica and drive value for this company is really exciting for me. I’ll reiterate what I said at the Analyst Day the only company that can do that has to have cost leadership, has to demonstrate cost leadership and I stand behind what I think is the strongest operations team in the basin, really excited about what we are seeing there. And generally that would be a little bit slower build just because of the infrastructure but continue to like what we see. On the drygas Utica test that's the messenger well in Wetzel County, West Virginia. It will be completed later this month. Startup 6,-foot lateral, obviously we push the timing of that well back a couple weeks to give us additional capacity to flow the higher rates than we initially planned. And the reason for that what we saw in the pilot hole, what we saw in the logs and what we experienced during drilling. We are very excited to get this well online and continued to be very encouraged that the drygas play does not stop at the river.

Okay. And just to clarify, you mentioned the oil test, you said that the well you're referencing when you said 20% rates of return and headed higher?

Yes.

Okay. All right.

And there is as we’ve done and continue to do throughout the company is we are going to push laterals longer, we are going to optimize completions and drive returns higher.

Okay. Sounds good. Thanks.

Thanks, David.

And our nest question is from Mike Kelly with Global Hunter Securities.

Hey, guys. Good morning.

Hi, Mike. Good morning.

Good morning, Mike.

Got two questions for you, one on the PRB and one on Southwest Marcellus. In the PRB, just hoping you could give a little bit more color on the stack pay potential here? And really if you could define the opportunity set there and compare the potential IRR prospects there versus the 40% you've laid out for the Niobrara to-date?

Mike, this is -- thanks for question. This transactions up there really to me is an example of the whole company of all our assets of the exciting things going on and the of return opportunities where we are just driving additional value, seeing lower cycle times, seeing reductions in our cost and better return for our shareholders. It’s a really, really exciting incremental opportunities for us and I am going to ask, Chris, to just kind of run through a little bit more of that detail for you.

Yeah. Mike, as you know we have been very open about how excited we have been about the Powder River Basin assets that we have, especially on the sub-surface but honestly we had work to do. The first issue that we had to address was one of materiality, transitions we laid out last week, doubles our exposure to what, Doug, characterize is multiple stack pays, what I’ll tell you is, it’s the single largest concentration of stack pay potentials that we see in the basin. What we saw is little over a billion barrels of potentially recovery resource is now over 2 and that’s really being driven by a number things. One is the continued successful delineation of Sussex. As we laid out in those materials we have a play that stretches about 20 miles north to south that we fully delineated north to south with the most recent Sussex test. We are going back to work drilling longer laterals, currently drilling a 9,000-foot lateral in the Sussex and driving returns there. That Sussex 1 well is at Hoss the 9,000-foot lateral, 90,000-foot lateral is adjacent to it. So we are really excited about the Sussex. We continue to be excited about the Parkman and what I’ll point you to is what we look at, what John Kapchinske and his team is pushing towards the end of the year for additional Parkman test, Teapot test and Shannon test. I think the true story here, though is excited as we get on the Upper Cretaceous and some of the other potential out there is what is happen with the Niobrara. And course of a year a teams saw their rig count drop from 10 rigs to three had essentially rethink absolutely everything they were doing and all they’ve done in the first half is out execute any expectation I had them. They have delivered what was a 40 days spudder rig release well now in the Niobrara is 26 and added a 1000-foot lateral link. That’s a 35% reduction in cycle time and a 17% increases in lateral link. And that’s allowed us as a team to re-establish, this asset is a really important part of our portfolio going forward. I couldn’t be more excited about what they’ve done and excited to see what they will do in the next six months.

Great. Thanks, Chris. And maybe I’ll ask you as well just over to the Southwest Marcellus. Could you refresh me on the takeaway capacity there to get gas out of that portion of the basin and then what the prices, what do you expect in terms of realization up there and then really for you, Doug, just kind of being blunt here why or why not spin this asset out eventually?

Yeah. We talk about our takeaway in that area, that’s one thing that we look at is, is not only just our gas takeaway but also our ATEX commitment and ethane takeaway. We feel good of what we have established and our ability to execute on that asset as we continue to expand capacity. When we think about spinning this asset out and talk about it internally what we see is, is an asset that has really strong return but honestly, does not quite yet compete within our portfolio which is more testament to shrink the remainder of our portfolio than it is the underlying assets. It’s an asset that we look at every quarter and continually outperforms our expectations both in terms of reserve and well delivery, and just a phenomenal asset and we -- I get excited when thinking about putting that asset out on its own being able to fund its own growth especially capacity increases, what it could do and putting that team in competition with some of the other players in the area.

All right. Thanks guys.

And our next question is from David Heikkinen with Heikkinen Energy.

Good morning. Just a quick follow-up on a Powder River. You’ll talked about well cost of $8.9 million at the Analyst Day and roughly 30%, 40% rates of return and had these improvements? With the longer laterals and the shorter days, what do you see those returns more specifically?

So, we laid our in the materials last week and I think again today is very clearly where we see our 2014 program averaging about 5,800-foot lateral going into the year that’s a $8.9 million. So cycle time improvements get those returns back up over 20%, extending our lateral link where we see in the second half of this year about 6,800-foot laterals will increase capital little bit but drive returns over 30% and then as we’ve done in multiple plays reinvesting those capital savings into enhanced completions will drive our returns to 40% we see we get there fairly quickly.

Okay. And then just on the overall corporate cash flow guidance with the higher differential you brought that cash flow for ‘14 down and Nick, you talked about ’15? As you think about the CapEx of $5 to $5.4, that includes the acquisitions, just wanted to be clear on that?

No. $5 to $5.4 would not include the amount…

Okay.

… we plan to use to complete the RKI exchange?

Okay. And so…

Nor is it offset by asset sales either, Dave.

Right. But so on apples-to-apples basis you bought about 4,500 barrels a day and you are now growing 5,500 barrels equivalent a day more than what you expected previously, is that a fair number?

Yeah. Just the 4,500 barrels a day…

I guess, it’s only for the last couple of months.

Yeah. Just for the last couple of months of the year, it’s not even for the full second half.

And then as go through cash flow and CapEx balance, looking at the next three-year plan? How does that flow given what you just talk about from a differential headwind?

Well, we go through a pretty competitive capital allocation process every year and we are in the middle of that right now for 2015 looking at where the best investments can be made to maximize return for shareholders. And so we take into account all those things and as Chris noted in his Analyst Day presentation, an asset like the Marcellus North, which has the ability to produce incredible returns might stay flat for a period of time and be a cash flow -- free cash flow generator given the pricing dynamics we expect we will face coming into next year. Now, that being said, we look at opportunities all the time to try and improve those things and each team feels the pressure of wanting to have more capital and fights to find ways to increase the expected return. So it's a constantly evolving analysis as we think about that. But we feel very confident in our ability to continue to invest at this level and continue to achieve these growth rates. One of the things that, Doug, about at the beginning just before Q&A are the things on which this company is focused and a pricing differentials in the short-term around a cool summer and waiting some long-haul takeaway in the northeast don’t impact the way we think about those targets and our ability to achieve them.

I think just adding to that, the idea of the competitive nature of capital allocation. You think about it a year ago we probably couldn’t run away from out of there fast enough. These are wells that we were excited about but generally weren’t making money and now when we look ahead to next year we probably can’t put enough capital there.

Yeah.

So this is a process that drives competition among teams is very, very healthy for the company and for our shareholders.

I think that the oil acquisition makes a lot of sense. How many more of those type of in that size acquisitions, do you think you can do as you look at the next couple of years?

Well, we’ll be very focused on it, David.

As I noted in the prepared comments, we are presently evaluating a number of strategic initiatives, some of which we’ve discussed and some we’re working on that are in early stages. And the key for us going forward is that we execute on this financial discipline and look for differential ways to add value to our shareholders. So I think it’s important to note that why we’re not providing any color on it. So any specifics of any other transaction today that the company is looking at other opportunities and we’ll continue to look for other opportunities, where we can enhance those returns and get away from some of those high differentials volatility that we see around gas market and continue to grow the company.

And Dave, I’ll just jump back in here and at the risk of restating the obvious, the financial position the company finds itself in today where we can effectively struck a chat for that acquisition gets us pretty excited about looking at other opportunities. We certainly are in a place now where we can think about our portfolio in the right way. There is other things in our portfolio that need to be managed. And we talked about some of those things. We haven’t highlighted all of them. But there's lot of portfolio optimization to do and in doing that it left us very flexible to go out and seek new opportunities. So we feel really good about where we stand in our ability to go out and execute on opportunities that that we seek or they present themselves to us.

Yes, increase, nets anywhere you can guys. That’s a good deal. All right. Thanks guys.

Okay.

Our next question is from Neal Dingmann with SunTrust.

Good morning guys. Doug, my first question really just to stay on our differentials a little bit, I’m just wondering if you and Nick can, I guess, either operationally or financially are you trying to manage this around, obviously, the current weak NGL and natural gas prices in near term, maybe prove to have some new rig locations or if Nick is looking at hedges or is it just something you think kind of temporary we just have the ebb and flow of the seasons, kind of, return as we normally do in the winter?

Sure. Great question, Neal. I think it’s really good to highlight based on your question the fact that we built considerable flexibility into our program, reacting to current market conditions and providing competitive metrics versus our peers is what our focus is all about. And as we’ve said a number of times, how we highlight or how we grow value for our shareholders, based on that flexibility we built into our capital programs. So when you look at the present dynamic that’s taken place, we anticipate that we'll see an improved realizations as we go into the winter. But the key for us really, Neal, is we’re not running the company based on any particular forecast on gas or oil prices. We’re going to run this company on good prudent operations and sound financial discipline and that nuts and bolts approach with the quality of our assets and the talent of our employees will pay off large shareholders as we pursue this low-cost leadership and greater capital efficiency. So yes we will look at the opportunities for hedging to protect our cash flows, not on speculative basis but on capital preservation or capital -- ensure our capital program can be executed upon to provide that growth in competitive metrics. But we have to be competitive regardless of what the gas prices are and that’s exactly what we’re going to do.

That makes a lot of sense. And then building on that -- and just looking obviously at your slide, it’s pretty clear that you guys have some of the dominant acreage positions by looking at Eagle Ford and around some of the Utica. So my question around this is, are you continuing to sort of, do some trades, blocking this up, you certainly have cut, obviously just what you're spending in leases overall. But is there still a bunch of this going on or how do you kind of look at that on the acreage side?

I think there's significant opportunities for coring up in our high quality assets in the areas that we see future growth from. And when I say coring up, that may be increasing our net interest. It might be bolt-on acquisitions. It might be infill acreage in the areas that we see to have the greatest potential and opportunities. So I think you can expect to see a continued focus on that for the company.

Okay. And then just last one, just looking at dialing into the Utica, probably a question for Chris, just looking at slides 20 and 21. I know as you all mentioned on -- at the Analyst Day talking about being the most efficient and you guys do a good job of showing kind of what you’re spending per lateral foot. But maybe just walk me through on slide 20, I know you have brought out now on this slide a number of your -- and some of your newer dry gas wells. And obviously the headlines we hear are from some of the peers a little bit further south, some of these big number. So Chris, I guess, what I’m looking at just maybe, how you’re looking at that, how much lower I know like some of those in the south, I think are costing $10 million or $12 million per well. So I’m just trying to get a sense of how much yours are costing if they’re, obviously, coming a little bit less. How much less is the cost behind those?

That’s a good question, Neal. I wouldn't say that we have a large enough sample set when we look at our position to dry gas Utica in West Virginia to give you an affirmative answer. All I can tell you is that while we have established ourselves as cost leaders in the rest of Utica play, I’m very confident that we’ll continue to do that in West Virginia. Obviously, these wells are going to be more expensive as they are a little bit deeper. Some may improve requiring an additional casing string and that’s fine. But I’ll put my chips behind, again, what I think is a really, really strong operation state. We try to highlight on slide 20 some of those $30 million a day IP. It’s really just to get a sense of what we’re expecting as we cross the river in West Virginia. And just to reiterate what I mentioned earlier in the call, we’re very excited about what we saw in the Wetzel County messenger well and really excited to get that online and excited to, to further delineate as we approach the end of the year up into the Panhandle and really unlock significant value for our shareholders with dry gas test in West Virginia.

Chris, are you drilling -- and then lastly, are you drilling anything even further south than Wetzel anytime soon?

I have to check, get back with you on that Neal. I don’t believe so. When we look at, ultimately we will but when we look at where we’re focusing, it’s probably Wetzel Count, north into the Panhandle, just where the concentration of our acreage is. But we will definitely continue to push not only a little bit south but also further east.

Makes a lot of sense. Thank you.

Our next question is from Charles Meade with Johnson Rice.

Good morning to everyone. I could ask a question about the northern Marcellus. You guys have a slide in your presentation you put out today. Talks about the new completion sign and it looks like it’s pretty attractive nonexistent decline. I wonder if you could talk about what you are doing differently and maybe where you're doing that. And if that’s perhaps a function of where geographically it is, like, I know that Wyoming County is relatively untested but highly prospective and just give us a sense of how applicable across the whole position this kind of completion might be?

Charles, this is Chris Doyle. It’s very applicable across the entire position, not just in Marcellus but we see it across the entire north and southern division of entire company. What we’re doing here is optimizing value equation. What that means to the northern Marcellus and the slide that you are pointing to is additional sand being comped, stage facing being contracted, pumping more efficient completion design. And it cost us about an initial $1 million but results in over a Bcf of incremental production as this example alludes to, in the first year. The key point of this slide is that these two wells are in the same exact area. This is not a difference of being in the core area versus a non-core area. These are two core wells in the same exact area. The only difference is really the completion. And so we get really excited as I'm sure you would be seeing the results here. We’ll continue to push more and more sand tighter spacing not only here but in other assets as well. In the Northern Marcellus, what that has allowed us to do is keep production flat and we’re running four rigs right now. And I would say going into the year we would've projected probably running about six or seven but the completion optimization of the capital efficiency gains that we’ve seen in the first half of the year, it gives clarity to reduce rig count there. And so we’re excited about that.

Got it, Chris. That’s good detail. And just to clarify that, so these wells are both producing against the same kind of gathering pressure with the same sort of compression and all that other stuff?

Same system, same area.

Got it, thank you. And then transition over to be Powder River Basin. I know going back 18 or 18-plus months ago, one of the big constraints was takeaway. I guess it’s processing but also just oil takeaway. And I know that you guys said that you got this, you expect a gas processing plan to come on in Q4, that’s going to give you guys a boost there. But can you talk more generally about what other above-ground bottleneck you might be dealing with there whether it’s on the processing or permitting side?

Sure. Our biggest constraint right now is gas processing as you allude to. And Buckinghorse coming on at the end of the year is going to open that up, that’s $120 million a day that we anticipate being on line at the end of the year. I continue to be excited as we see that capacity expand. We will build into that capacity and probably hit capacity at Buckinghorse in the first, early second quarter of 2015 and then continue to grow into tallgrass capacity we currently have. That’s our biggest surface production constraint. You alluded to permitting and got a lot of questions about how quickly can you ramp up with permitting issues in Wyoming. I can tell you this company and his team has a lot of history dealing with a longer protracted permitting timing and it’s up there, we work into our plans. And so you won't see us go to 30 rigs next month. What you’ll see is a nice steady build towards the end of the year and into 2015 as we fill up capacity and get that permit machine go on. So those are -- you hit on, I would say two above-ground pressure points that we’re attacking aggressively all over.

Great. Thanks for the detail.

(Operator Instructions) And our next question comes from Jason Wangler with Wunderlich Securities.

Good morning, guys. Up in the Utica or even Southwest Marcellus, is there an ability to kind of try and get some of that gas out of the basin? I know some other operators are starting to look at pushing it to Midcon or Gulf Coast, just your thoughts around that opportunity, if there is any?

Yes. So we are looking at some of those opportunities. We’ve had a number of good conversations with the takeaway partners, looking at building new project out of basin and those are all pretty active discussions. So I’ll kind of leave it at just saying that we’re looking at ways to further increase our takeaway in other parts of the country.

Okay. And then, just curious on the Utica as you’re looking at kind of the reemergence of the different windows if you will. You’ve got eight rigs up there now. How do you see that rig count as far as just within that. Is that mostly just in the condensate or wet gas area and then anything in the dry gas or even oil would be incremental at least in the near term or maybe even in the ‘15?

I think that’s a fair way to look at it. As we look at the pace of our drilling activity up there, one thing that’s just absolutely critical to their company as we’re not going to part capital on the ground and not get a cash on cash return as quick as possible. So strategically, as we look at our capital allocation with the areas where we can ramp up rigs and be flexible on our program and capture the greatest returns. It is where we’re going to be focused versus parking capital on the ground and waiting for infrastructure in six months or a year or longer to allow us to sell our product. So as we look at -- we’ll be continuing to drill in the gas windows and doing some of our limited testing to prove up the other areas. And as Nick noted looking for opportunities to secure addition takeaway, as we see the economic support.

The only think I would add there, this is Chris Doyle, is we will be seven to nine rigs next year. But in a fact, what we’ll be doing is adding more wells because of continued cycle time reductions. Point two, what they've been able to accomplish in the Utica, but also at North, this is an area that we had drilled going into this year 800 wells and year-to-date we’ve seen a 20% reduction in cycle times. What that means is I can peel a rig back and effectively have not lost any delivery of this asset. And so, we’ll think more in terms of well delivery than we will rigs. And it’s one of the great value drivers for this company as we continue to see the cycle times coming down.

I appreciate you guys. Thank you.

Our next question is from Matt Portillo with Tudor, Pickering, Holt.

Good morning, guys.

Hey, Matt.

Just two quick questions for me. I wanted to ask first on the completion side, particularly in the Eagle Ford, I was wondering if you could provide maybe a little bit of color on kind of where you are in completion optimization, and how you think about, I guess, industry moving towards bigger profit, longer laterals and tighter stages, and the opportunity set you guys see on your Eagle Ford assets.

This is Jason. We are looking at that with all across the company and we’ve got a completions team that spun off as part of our transformation initiative. We’re looking at it. They’ve got 50 initiatives as far as completions going on across the company. We’re very excited about it. So all the things that you mentioned, we’re in the process of testing right now. We’ve really seen some cost leadership from that team. They’ve been able to drive costs down in every single asset that we operate with the Eagle Ford being no exception. At our Analyst Day, we highlighted $6.4 million. Wells were our year-end target, but they’re already achieving that today. So we’re very excited of the progress we’re going to make. Another big change for us as we’ve transition to some of these interventionalists completions. These are sliding sleeves, dissolvable plug systems that we've tested in the Haynesville successfully, We’re going to be moving those to the Eagle Ford. Those systems are safer, faster and cheaper for us. We’re very excited to tell you about the results in the Eagle Ford as we progress those systems moving forward. We’ve also tried similar to they have in the North. We have been very successful tighter per cluster spacing test, more sand. Some of our cost savings have come from reducing the amount of gel and being able to get same profit concentrations away with water .So really expecting to make some big moves on our completion costs side and the Eagle Ford going forward. We’re also going to be testing some 330 foot spacing test out there. Those will be going down in the third and fourth quarter. That can hopefully optimize the ultimate recovery from our asset in the future spell, so lots of great things going on in the Eagle Ford overall.

Great. And I guess, just specifically to the Eagle Ford, we've seen recently, particularly in an area where you guys are developing pretty significant increases in the amount of sand content in the well, is that something you guys are testing at the moment? And is there any context you could just provide as to kind of where you are today on a profit per foot or profit per stage perspective, and maybe where that could trend to?

I do not have the pounds per foot with me right now, but I guess -- its something that as you go to these increased density clusters, we’re not diluting our sand over that interval. So every -- by testing tighter intervals, we by default pump more sand and more fluid into the well. So we’re testing up to 20% to 50% increases in some of our sand out there. It’s really just looking at and maximizing the MPV of these test cost you more money, so do you get incremental EUR from them. Those are the things we’re looking at. And they just take time to really see the impact in EUR. But we have observed some of our offset operators are pumping more sand out there but we’ve got a system that works for us. We’re just looking to tweak in.

Great. Last question for me, just on the completion front you mentioned accelerating completions into the back half of ‘14 by 35%, or wells on line. Could you give us some context of where those will primarily be? Is that primarily in the Utica and the Eagle Ford or just any incremental color, you could provide on those completion accelerations?

Sure. Matt, that’s principally the main areas. Utica is a big component of it, Eagle Ford as well. But really across the whole portfolio, our focus and drive towards capturing greater value, it’s just consistent with all of our planning.

Already I’d mentioned is the Powder where we strategically deferred some completion in the first half of the year because of weather and because of capacity constraints. We are back at it right now and completing wells and accelerating completions in the second half of this year as we get ready for Buckinghorse at the end of this year.

Thank you.

And our next question is from Doug Leggate with Bank of America Merrill Lynch.

Thanks. Good morning, everybody. I apologize, I was a little late jumping on the call, Doug, so maybe I missed a couple of these things. My question is, kind of, on the portfolio simplification, to kick us off here. The asset sales that you've announced on the outlay, I guess, of the Utica preferred, kind of, balance, I guess, if you add it up. And I'm just kind of wondering, is that how we should think about this simplification effort going forward that's going to be self funding, if you like? And what kind of -- where would you say we are in that process in terms of getting where you want the portfolio to be and I've got a follow-up, please.

Sure. It’s a good question. So we’ve covered a lot of ground in the past 18 months. And as Nick noted, we’ve had a significant number of asset sales or non-core divestitures. And as we look forward into the remainder of 2014, I see a number of other opportunities. It will be looking to execute upon and there will be some in 2015 as well. And the key there is really that we’re going to continue to mold and shape and optimize this portfolio around what I consider to be some of the absolute highest quality assets in the United States. And as we look for core-up opportunities or divesting of non-core affiliates or things that we’re not getting competitive returns on, you could absolutely expect to see more of it. And we've got other things that we’re presently are evaluating in looking at for 2014.

As part of that process, Doug, I know it's a long time ago since we talked about debt targets, but are you comfortable with the balance sheet as of now, or do you see any urgency in bringing that down? I'm not so much thinking about the credit issues and so on. I'm thinking more just about the interest rate burden that you have relative to the rest of the operating cash flow generally. So what's the priority for trying to bring the debt down?

Yeah. So Doug you know that I’m a huge capital efficiency guy. And you know that I'm a huge cash cost leadership guy. And part of that whole cash situation with the balance sheet where we have obligations that consumer cash flow or consume cash. We are focused on continuing to improve. And when you look at the portfolio, when you look at our product mix, I'm not happy with where we are. And we’re going to continue to make improvements into it. As you noted, it’s not specifically that we are targeting investment grade. Investment grade is a byproduct of running our business right. And so we expect to reach investment grade because we’re going to clean up the excessive debt that can be a burden on our capital program in higher price environment or low price environments. But the financial stability of the company as Nick had noted, this is -- we're in a position today of really a very good strength. And it creates optionality for when we can either pay off debt, payoff of other obligations, and continue to mold and improve the portfolio to capture the greatest value we can from these high quality assets.

Appreciate the answer, Doug. My last one is hopefully a very quick one. Over the course of the last year, I guess, and particularly the last six months, we've seen a number of your competitors talk about signing long-term gas contracts or at least signing up for that. The most recent one, which was a little bit of a surprise, was Southwestern in the Fayetteville. They didn't disclose details but they did say they had signed a contract for LNG. So where are you guys in that? And obviously how would it impact your Haynesville, assuming the back end of the curve did come up in this one for that? And I will leave it there. Thanks.

Yeah. So, that’s a good question as well. I think, if I were a purchaser of LNG, I’d want to go to the company that had the best assets in the country and that’s Chesapeake. And so for long-term deliverability and capturing the greatest price opportunity for our gas, we will continue to look at opportunities to secure LNG contracts at pricing that we would consider to be favorable. And we’ve not signed anything yet but we have had a number of discussions. And we’ll continue to discuss with those purchasers that offtake capacity from the new liquefaction facilities being built on the Gulf Coast. And there's a direct line of site to the Haynesville and part of the reason we went into the Haynesville is we believed -- went back to the Haynesville rather as we believe that huge value in that asset have been captured in applying the teams the way they’re reducing cost and adding value there as significant. And there was a second part of that that we also believe that the competitiveness of the asset would be a fantastic source for LNG purchasers if we could be more competitive. So we’re recognizing that and seeing outstanding result in the Haynesville. Our team is doing a fantastic job and we’re in great position to move forward, provided we capture the value from an LNG contract or any other sales contract that we might pursue.

Appreciate it, Doug. Thank you.

Thank you.

And that concludes today’s question-and-answer session. At this time, I will turn the conference back to our speakers for any additional remarks.

Thank you very much. We appreciate everyone’s time. Just to encourage if there is subsequent follow-up questions, please contact Gary. And what you are going to expect with the company like Chesapeake, it will continue to drive towards greater value. And just want to reiterate one more time the year-end exit growth rate of 730,000 barrels equivalent per day is a very realistic expectation for us. We’re really excited about our programs. So thanks everyone.

This concludes today’s conference. Thank you for your participation.