Good day, and welcome everyone to the Chesapeake Energy 2012 Second Quarter Earnings Results Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Jeff Mobley. Please go ahead, sir.

Good morning, and thank you for joining our conference call today. I'd like to introduce the members of the management team that are on the call this morning. We have Aubrey McClendon, our Chief Executive Officer; Nick Dell'Osso, our Chief Financial Officer; Steve Dixon, our Chief Operating Officer; John Kilgallon, and Gary Clark from the Investor Relations team, and this is Jeff Mobley speaking. Following the comments of the management team, we will take your questions this morning. And as I’m sure you can understand, we are not going to be able to comment on matters that are subject to litigation or other enquiries. As usual, our call will last one hour. And now I'll turn the call over to Aubrey.

Good morning and thank you for joining us today. Despite experiencing the lowest natural gas prices in over 10 years during the 2012 second quarter, we're pleased with the company's performance during this challenging time for our industry. For example, our production surged ahead by 25% year-over-year and 4% sequentially. However, had it not been for our 330 million per day gas curtailment during the quarter, Chesapeake's production would have actually been up a remarkable 36% year-over-year. These production increases are obviously impressive, but they are especially so for a company as large as ours. Most importantly, our oil production growth has really taken off. Starting from a base of 26,700 barrels per day in January 2010, in the past 10 quarters we have increased our oil production by 201% to 80,500 barrels per day. Our natural gas liquids production growth has been very strong too, growing from 10,600 barrels per day in January 2010 to nearly 50,000 barrels per day in the second quarter, an increase of 370%. Taken together, Chesapeake’s total liquids production over 130,200 barrels per day has now risen to 21% of our total production mix and we expect this percentage to continue trending upward to 35% of total production by 2015. In addition, our second quarter liquids production was up 65% year-over-year and 15% sequentially. Looking across the industry, our year-over-year liquids production growth is the third best in the industry on an absolute basis, and on a percentage basis, it is the second best. Chesapeake is now the 11th largest liquids producer in the U.S. and we hope by 2015 to be knocking on the door of the top five liquids producers in the U.S. You may recall that in 2010, when we had a very modest liquids production of about 30,000 barrels per…

Thanks, Aubrey. It was a very good quarter operationally, and I’m particularly pleased to highlight our strong production results. we produced 3.8 Bcfe per day, an overall sequential increase of 4%. but more importantly, we achieved a 15% sequential increase in liquids production. this quarter, we began reporting oil and NGL separately, now that our NGL production reserves have increased to a material level. I’d like to highlight the liquids production volumes for the second quarter was about 62% oil and 38% NGLs, and also that our rate of growth in oil production has substantially outpaced our growth in NGL production over the past year. We’re also very pleased with the continued strength in our oil price realizations, which were 96% of NYMEX before the effects of hedging this quarter. These high realizations are a direct result of the hard work by our subsidiary, Oilfield Trucking Solutions in the Eagle Ford as well as enhanced pipeline connectivity out of the basin, both of which contribute greatly to robust overall pricing. Thanks to strong growth in the Eagle Ford, 45% of our companywide net oil production during the quarter is now sold at a Louisiana light sweet correlated price versus 0% in the year-ago quarter. looking ahead to 2013, we are currently forecasting flat year-over-year oil differentials, but we do see potential for these to improve further. You will see in our results that like many of our peers, we reported challenging NGL price realizations. however, we believe these realizations are bottoming and expect them to improve moderately for a couple of reasons. First, we currently sell 50% of our NGL to Conway. in 2013, we will access Mont Belvieu pricing for a portion of those volumes based on new pipelines and resulting basis compression. Second, industry wide rejection of ethane…

Thanks, Nick. I am very pleased and impressed with our operational performance, and I am very proud of the efforts and the results that our team at Chesapeake has been able to deliver for our shareholders this year. As Nick just outlined, our strong liquids production growth during the second quarter has prompted us to raise our forward liquids production guidance outlook for the remainder of 2012 and 2013, to an average of 135,000 barrels per day to 170,000 barrels per day respectively. These are increases of 12% and 9% respectively and are net of volumes associated with projected asset sales. I’d also like to point out that the majority of this growth will be in our oil production versus our NGL production. We mentioned in our last quarterly call that in response to low natural gas prices we would reduce drilling in our dry gas plays from 47 rigs at the beginning of 2012, to just 11 rigs by year-end. We have accomplished this goal and now plan to further reduce this amount to eight rigs at year-end. At our high-water mark back in March 2010, we were drilling with 104 gas rigs. As you might imagine, this will have profound impact on our gas production. In 2013, we are now projecting a 7% decline in gas production. Moving on to the cost side of our business, we are beginning to realize significant benefits from lower service costs and rising drilling efficiencies as we optimize our activity levels and move more fully into harvest mode. Consequently, we plan to drill the same number of net wells with fewer rigs operating and have accordingly reduced our projected yearend 2012 liquids rig count from 115 down to 93. In the second half of 2012 and in 2013, we plan to spend…

Thank you. (Operator Instructions) And we’ll go first to Brian Singer of Goldman Sachs. Brian Singer – Goldman Sachs: Good morning.

Good morning, Brian. Brian Singer – Goldman Sachs: Wonder if you could connect a few dots with regards to the production and asset sales guidance that you’ve revised. It seems like you expect less proceeds from asset sales in aggregate in 2012 to 2013, a greater negative impact on ongoing production resulting from these asset sales. But as you highlighted both oil and gas production guidance was taken higher, in the interest of trying to determine how much of this change in guidance is driven by performance versus restructuring. can you just add a little bit of color on the moving pieces please?

Hi, Brian. When you talked about less asset sales proceeds, I think what you are really pointing to is that we took VPP off a while ago. The increase in production relative to performance and unrelated to asset sales is about 140 Bcfe in 2013. Does that answer your question? Brian Singer – Goldman Sachs: Yeah. And I guess can you break, since both oil and gas was impacted, can you break that down or I know you highlighted Eagle Ford in Steve comments, but are there major drivers on the oil side versus the gas side?

There are, and so it’s approximately 50-50 of that would be gas versus liquids and then the oil and NGL split would be as related to our base production, so a little better than 60-40 to the oil. Brian Singer – Goldman Sachs: Okay. And then, you highlighted your Eagle Ford backlog, you’ve got a big backlog in the Marcellus, what are your expectations for how this backlog will change and what’s baked into that guidance for 2013?

Brian, this is Steve. We are working part of that off and part of that was our overspend on capital running quite a few frac crews in the Eagle Ford to catch that up as well as Marcellus. Brian Singer – Goldman Sachs: Got it. I’m sorry, so do you expect that backlog to be eliminated by the end of next year or is that what’s baked in?

A big portion of our Eagle Ford backlog is normal course. Brian Singer – Goldman Sachs: Okay.

So we don’t expect it to be eliminated. And the Marcellus backlog will stay with us for some time, as we are doing some appropriate backlog reduction there but we are not exactly raising. Brian Singer – Goldman Sachs: Thanks. And if I could ask one more, you highlighted in the release an expectation for may be a greater strategic update with the third quarter results, can you just talk to whether you think that will be dramatically different versus this latest change in 2013?

I do not expect it to be dramatically different, no. Brian Singer – Goldman Sachs: Thank you

Okay. Thank you, Brian.

We’ll go next to Dave Kistler of Simmons & Company. David Kistler – Simmons & Company International: Good morning guys.

Hi, Dave. David Kistler – Simmons & Company International: Just following up on Brian’s real quick, can you break out just specifically the Eagle Ford, VPP and the implications that had on production guidance for 2012 and for 2013.

Well, the VPP in and of itself was projected into our 2012 and 2013 production guidance. When we pulled it out, we had a reduction or an add back of about 30 Bcfe in 2012. And again about 50% of that is – sorry, I misspoke really when I gave the number to Brian – about 50% of that is oil, 25% NGL, and 25% gas of the Eagle Ford. Of what we are adding back in the 140 Bcfe to 2013 that is performance related, that's about 50-50. David Kistler – Simmons & Company International: Okay, that's helpful. I appreciate that and…

In 2013, the VPP impact was about 35 Bcfe. David Kistler – Simmons & Company International: Okay, great. I appreciate that and then, are we to come to the assumption though that VPP for the Eagle Ford is completely off the table or is that something that comes back on the table as perhaps crude prices get a little bit better, NGL prices get a little bit better, any color on that would be helpful as we think about divestiture plans into 2013.

For now, it's off the table. David Kistler – Simmons & Company International: Okay, appreciate that. And then one last one just on the Niobrara as you guys talked about cracking the code there, can you talk a little bit about what's your thinking? The initial rates of return on those wells look like and maybe anything around well cost, well design et cetera.

Yeah, Dave, this is Steve. It’s still pretty early there. I think we have improvements that we want to make on our well cost, but we’ve certainly found a sweet spot with this over pressured high in liquids basin center that we’re really hoping to get some production history and improve on. David Kistler – Simmons & Company International: Okay, so to be determined over time is the best way to think of it?

It’s still early. We’ve got some, I think some big improvements to make on the cost side. We’ve been still doing a lot of science in defining this sweet spot.

David, I’d just say that, anytime when we’re in a liquids play, the goal is to have greater than 50% rate of returns. So if we’re for some reason not there yet on these production rates we intend to get our cost to that point. So these are big wells and they can come in at 1,000, 1,500 boe per day. We’ve got some gas production takeaway issues that are going to take a little bit of time to resolve, we probably have some flaring issues associated with that, but we really like where we are and of course we’ve got CNOOC paying most of the cost there. So if you take into consideration the carry, our returns from the Niobrara basically- well, through the stratosphere when you’re only paying for a quarter of your cost. David Kistler – Simmons & Company International: Great, I appreciate the added color there. Thanks guys.

David, thank you.

We will go next to Doug Leggate of Bank of America Merrill Lynch. Doug Leggate – Bank of America Merrill Lynch: Thank you, good morning everybody. I am going to try just a few quick ones, if I may. I don’t know how much you can share about the assets sales at Aubrey, but obviously you talked about 1.5 million acres in the Permian and you’ve give a range of values around that. It looks like you’ve spilt into more than three packages. Could you give any colors to, order of magnitude, what’s still left on the table and I guess level of confidence that these are going to get done in the third quarter? I’ve got a few follow-ups, please.

Okay, sure. Doug, when we started out, we operated in both one entire package, but also in the data room there were three packages, there was the Midland Basin package, which was the smallest and then there was the New Mexico Delaware Basin, and the Texas Delaware Basin. So we’ve mentioned, we've signed a purchase and sale agreement with EnerVest, we’ve mentioned that we have two acceptable bids on the other packages, and we are negotiating purchase and sale agreements there. So we would have loved to have been able to have all three come across the finish line by the end of the quarter, but just weren’t able to get there, but as Nick mentioned in his remarks, we expect to get those completed in the next 30 days or so. Doug Leggate – Bank of America Merrill Lynch: So Aubrey you are very clear in the release that you sold the producing assets in the Midland, does that mean that there are still bunch of acreage, undeveloped acreage, still on the table?

Yeah, sure, Doug. we will have our remaining acreage in the Midland Basin to either develop ourselves or more likely to go through another process and look for a home for it, there are lots of different ideas there, private equity ideas, there are other producers who were maybe intimidated by the size of the package and now when you take the production out of it, I think we'll get some more kind of growth to the drill bit companies to come back and take a look at the acreage. So we’ve got a lot of options there, and it’s just kind of emerged in the last few weeks that we’ll go through frankly a fourth process to finish up basinal exit from the Midland side of the Permian. Doug Leggate – Bank of America Merrill Lynch: Okay, I don’t suppose you’d care to comment on the $4 billion to $6 billion original range you gave relative to your, what you think you're going to realize?

Doug, no, we will continue to just let the process play out and as we have final numbers we will certainly share them with everybody. Doug Leggate – Bank of America Merrill Lynch: Great. My only other one is really on the activity levels particularly in the Mississippi Lime. I guess similar kind of issue on the joint venture there, any update you can share there. But it also looks like you’ve lowered the rig count from the original planned to 18 versus I think it was 22 originally, so is it just better well results and if so are you prepared to take the type curve up. And just a general update on the Miss would be appreciated and I’ll leave it there. Thanks.

Okay, couple of things there. First of all, we have reduced the rig count in the Miss Lime but we haven’t done so in all of our plays. That’s just basically the scale down of our enterprise from – at the start of the year we were planning to run 200 rigs in 2013 and now we are planning to run 100. So we certainly needed to scale down. In addition in the Miss Lime, we have decided to pursue [less just] (ph) pure HBP drilling and go into some core and some infill drilling there to help our returns and also to not get too far ahead of our infrastructure. You can spend a lot of money on infrastructure across a big area there. With regard to EURs, last time I checked we haven’t taken them up although I noticed in what we call JV 1 area I think we are pushing 600,000 boe on the numbers that I saw, but I don’t think we’ve taken our pro forma up across the whole area. Let’s see JV is still continuing our discussions, there is obviously private equity interest there, there is international interest. And we’ve also been approached for 100% exit some parts of the Mississippi as well. So we will have lots of options there during the couple of months as we sort out what we want to do in that area. But we’re certainly pleased with our results and obviously watching EURs creep up from other players in the area as well. Doug Leggate – Bank of America Merrill Lynch: Thanks, Aubrey.

Okay. Doug, thank you.

We will go next to David Tameron of Wells Fargo. David Tameron – Wells Fargo: Hi, good morning. Asset sales, let’s go back to that. 2013 or two questions, one, the third quarter, does that include any assumptions for Mississippi Lime JV or is that pushed off for the time being?

I don’t believe that’s in our third quarter. That’s more of a fourth quarter expectation. David Tameron – Wells Fargo: Okay. So then if I think about 2013, what packages, I mean what - the numbers you threw out for your asset sale target, what do you have, what would that be? Would that be – obviously, Chaparral is still out there, some of the services business, but can you talk about big picture, what would be included in that package?

First of all, it’s a much smaller number than we’ve been looking at this year. So you are right that Chaparral is out there, we’ve announced that we intend to sell a non-core asset like that, we’ve mentioned that we’d like to exit our investment in Frac Tech or FTS International at some point at well, and then we have our service company IPO that we have put-off to 2013. Beyond that I’m not going to say, but we have plenty of other bits and pieces of assets that we have that we’ll be shaving off to reach the goal of $4 billion or $5 billion in 2013. I would like to emphasize as Nick mentioned that from a liquidity perspective, we don’t have to sell anything next year, but we certainly want to be able to continue to keep an undrawn revolver and associated with keeping our debt at the $9.5 billion level. David Tameron – Wells Fargo: Okay. And then one more question, if I just look at what you did on the hedging side, it looks like you are kind of implying the 3, somewhere in the 3 to 3.25 is kind of where you think gas topped out at least for the remainder of this year. can you talk about, is that the right read on what you did based on your hedging and if so can you talk about your projections for the second half of the year, where you guys think gas…?

Sure. Yeah obviously, we had a nice run from the lows of late April to the above the $3 level. And I think we just wanted to be careful and conservative about our budget in the second half of the year, knowing that even with hot weather, we were going to be working off a lot of storage overhang, but there were obviously potential issues in September and October if storage got full, it looks like we’re probably going to avoid the storage box now. So we’re not intending to hedge anything at this point for 2013. At today’s levels, we don’t think there’s any chance that you have a 2013 strip that stays where it is today, if you have a complete reversal of the 900 Bcf overhanging it’s had in April of 2012, if you get the 900 Bcf storage deficits in April of 2013. But clearly you’re going to have to have higher prices in the $3 in 2013 to incentivize producers to come back. So for us, it’s got to be a pretty healthy price to pry our rigs away from our liquids production, our liquids focused areas. Steve, remind me, in 2013, how many rigs did we have allocated for dry gas?

Looks like eight.

So I think yeah, eight rigs out of the 100 in 2013 for dry gas. So this has been a four-year down cycle, and a lot of headwinds in the last four years. but we think a multiyear up-cycle is now underway, and frankly, all the die has been cast, Chesapeake’s is on the table, have been played and now it’s just a matter of physics and time for them to play out. David Tameron – Wells Fargo: And just following up on those comments, do you have any feel for and I realize it’s play specific, but do you have any feel for where gas would have to get back to before you start to allocate away from liquids into - back to gas?

No, we’re not going to give out those kind of numbers, it’s different from play to play. But it’s a number, and I think the industry has said that the number is probably a north of $5 before gas plays generate the same kind of returns, which you can get from oil around $90. The Marcellus may be a little bit lower than that, but gas prices have a way to go to catch up to levels that equal the returns we get from our liquids-focused plays. And we’ll just wait for it to play out, and we’ve got enormous backlog of gas drilling opportunities, and we’ll take advantage of those when the gas market pays us to do so. David Tameron – Wells Fargo: All right, thanks for the color.

Okay, David, thank you.

We'll go next to Biju Perincheril of Jefferies. Biju Perincheril – Jefferies: Hi, good morning. A couple of questions, first in the Utica, in the oil window can you give us some color, how many wells you have now completed? And Aubrey, in the past you’ve said, Utica, it’s at least it’s as good as the Eagle Ford. Can you make that statement about if you’re only looking at the oil window of the two plays?

I don’t think I would make that statement comparing the oil plays, it’s just way too early on the Utica side, and we’ve not focused much of our efforts in that area, most of our acreage is in the wet gas and the dry gas side. So, we’re basically allowing other companies to work on the oil side; we’ve got plenty of acreage over there. But right now we love what we see on the wet gas side and frankly the dry gas side is just as good as the Marcellus. So we’re only drilling there, though where we kind of have to for acreage exploration issues. So we think when it's all said and done, the wet gas in the Utica, and the wet gas in the Eagle Ford are likely to be competitive. But I'm not willing to compare oil and oil yet because I just don't have enough information out of Utica. It goes without saying that we love what we’re doing on the oil side in the Eagle Ford. Biju Perincheril – Jefferies: Got it. And the Eagle Ford, you’ve mentioned, I think 15% decline in cost, can you say what costs are running currently?

Little over $7 million, right around $7 million per well.

Biju, did you hear that $7 million? Biju Perincheril – Jefferies: Yeah.

Okay. Biju Perincheril – Jefferies: Yeah, that's all I have for now. Thanks.

That's great, thank you.

We’ll go next to Charles Meade of Johnson Rice Charles Meade – Johnson Rice: Good morning gentlemen. Couple of questions, if I could go back to that divestiture question for 3Q, you guys put in your headline for that section in the press release, a target of $7 billion. Am I right in that the two biggest pieces of that are number one, the Midstream, the remaining $2 billion Midstream sale to GIP and then the Permian sale, I guess the question really is, is there another big piece that’s going add up to that $7 billion?

Just to clarify, Charles, the $2 billion sale to GIP, that actually occurred in the second quarter, so it's done. What is projected in the third quarter is the remaining part of our midstream business, which is housed in an entity called CMD, that's our 100% owned Midstream. What got sold in the second quarter was CHKM now remain a CMP I think, access. So those are the two headline events in the third quarter and of course we will have some miscellaneous assets to sell off. Charles Meade – Johnson Rice: Okay. Great, and then going back to the Utica, could you tell us what the lateral links were for those 28 wells that you highlighted in your focus area?

I don’t know if we’ve got it exactly but we can go ahead and tell him, what on average we do there.

Little over 5,000. Charles Meade – Johnson Rice: Got it. And the TVD I know it kind of – it goes down as you descend into that gas window. But in general what’s the kind of that TVD range for the wet gas down to now?

6,500 to 7,000. Charles Meade – Johnson Rice: Got it.

One of the attractive parts of that of course is we are now seeing wells get down to TD in 15 to 18 days something like that, so one could all the way drill the horizontal out. So as we really move into manufacturing mode there one of the advantages that the Utica will have over the Eagle Ford and some other plays will be that it’s a shallower and a bit cheaper. Charles Meade – Johnson Rice: Well, and that’s exactly, you knew exactly what I was trying get to – are you prepared or do you have anything you’d share for what you think a development mode will cost you there?

That Steve can make a core estimate.

[It’s more like] (ph) down to about 6. Charles Meade – Johnson Rice: Got it, got it. And then one other question for you Aubrey, is there anything that you can share about what the focus of some of the new Board members has been or what area is their attention has been drawn to or what questions that are top of mind for them?

Sure. We’ve only had one meeting to date. We just finished it last week. So it was a – we decided to have a mid-cycle meeting to get everybody acquainted with each other and they are looking at the things that you’d expect them to look at, the big topics for us, which are asset sales and CapEx, and efficiency of our operations. So that’s where the needle get’s moved and that’s obviously where their level of interest is. Charles Meade – Johnson Rice: Great, thank you very much guys.

Okay, Charles, thank you.

We’ll go next to Neal Dingmann of SunTrust. Neal Dingmann – SunTrust Robinson Humphrey, Inc.: So a quick follow-up Aubrey, just on the Utica, maybe for you or Steve, just wondering on those wells now, are you still I guess in that kind of wet window that you're drilling in letting most of those wells still rest after you complete those or what are you doing on that front?

Yes, sir, we are - most to these will come on - have been waiting on pipeline really for the most part, but yes, there have been having some set time. Neal Dingmann – SunTrust Robinson Humphrey, Inc.: So you still believe, I mean – and is that kind of really going on - on a go forward basis, Steve you’ll continue to do that even if you have the takeaway you’ll continue to do that to a degree?

Neal, it ranges from dry towards liquids in the heavier oil and liquids, we think more benefit from it. So it will be a variable. Neal Dingmann – SunTrust Robinson Humphrey, Inc.: Got it, got it. And then just wondering on the Marcellus, you mentioned about the gas rigs you are going to let go. I think in the press release, so you talked about in the Marcellus having at least still six rigs going for dry gas, the reminder of ‘12. So would you let some of those go after ‘12, is that what that is implying or what will you do in that dry gas Marcellus window?

Yes, we think we can get down to four rigs there and hold our key acreage. Neal Dingmann – SunTrust Robinson Humphrey, Inc.: Okay, okay. And then just lastly, you just had a small increase, I noticed on the acquisition of unproved properties. Just wondering is that just bolt-ons or what was just the small add-in guidance on that part?

Yes, it's basically just accounting for the fact that we had to clean up a number of transactions in the Utica. I think Nick may have mentioned that about half of our leasehold spend for the 2012 is targeted for the Utica, I think another 25% for the Anadarko Basin including the Miss Lime and 25% spread everywhere else. so it’s dropping very dramatically. in fact, I think our first quarter’s leasehold spend was about $955 million, and dropped to $375 million or so in the second quarter, and we’ll continue to drop off quite remarkably dramatically rather, which I guess will be remarkable. But we’re targeting for 2013 a $100 million a quarter. and we think that maintenance mode will be even lower than that. I’d love to say, we could get to a lower number than that in 2013, we’ll certainly try to, but there’s still a lot of little holes out there, particularly in the Utica and often in the Marcellus as well, and it jeopardizes a much bigger investment when you fail to go out and kind of complete your unit. but in the Eagle Ford and most of our other plays really down to almost zero in terms of additional leasehold buys. Neal Dingmann – SunTrust Robinson Humphrey, Inc.: Okay, thanks guys. Solid quarter, and great progress.

Okay, great, thank you Neal, I appreciate the support.

We’ll go next to Bob Morris with Citi. Robert S. Morris – Citigroup: Good morning. Steve, a question on the rigs, you’re going to drop down to 100 rigs at year-end and that’s what you’re planning to hold that for next year. as I recall, 100 rigs is what Chesapeake own [at Ryder] (ph) under sale leaseback. So at that point, do you expect you’d just be running your own rigs and to drop out third-party leased rigs then by year-end?

We’ll still have some third-party rigs. and so we’ll have to stack some of our older mechanical rigs. Robert S. Morris – Citigroup: Has Nomac tried to lease some of your rigs to third parties at this point or do you think you might be able to do that in the future?

Yes, sir. We have, I think 10 or 12 lease to others right now. Robert S. Morris – Citigroup: Okay, all right. Thank you.

Bob, thank you.

We’ll go next to Jason Gilbert of Goldman Sachs. Jason Gilbert – Goldman Sachs: Hey, good morning, guys. Most of mine have been asked already. I was wondering, I think you had mentioned in the past your desire to do a couple more JVs in the Utica, just wanted to hear what your latest thinking was there?

Certainly, Jason, we’ll do at least one in the dry gas part of the play, and we’ll wait till 2013 though to do that when we’ve got better gas prices. So that is certainly one of the assets sales that we have in mind for 2013. On the oil side, it just remains to be seen, if the results allow us to do that and we also have a couple of other JV ideas out there. So we think the JV market is still strong, and it's been supplemented by the interest of private equity players during the past year or so. It’s probably been the biggest change in the market out there in the past year, which is the arrival of frankly several tens of billions of dollars of assets that private equity players have brought to the table. Jason Gilbert – Goldman Sachs: Thanks. And then my second one was, on the spending guidance increase you mentioned in the comments that were just spillover from late '11 and early '12? Just sounds like inertia, really. But if I remember correctly, you had reiterated your guidance as recently as July in the investor presentation, which maybe suggests to me that you don't always have a lot of visibility with this. And I was just wondering if you can say with confidence that these spillover costs are now behind you and that we’re over the hump on the CapEx increases.

We really think they are, and in terms of affirmation in July, I don’t remember that so much other than we only change our guidance once a quarter. So in July it would have been what we put out in April, and so we kind of just live with it till we have a earning into the quarter earnings release like we have now. So this is obviously something that we scrub very hard, we’re not happy about the increase, and really determined that with our new numbers that they are numbers that we can not only meet but to live with them. Jason Gilbert – Goldman Sachs: Great, thanks. I’ll turn it back.

And we’ll go next to Scott Hanold of RBC Capital Markets. Scott Hanold – RBC Capital Markets: Good morning.

Hi, Scott. Scott Hanold – RBC Capital Markets: So on the 100 rigs you’re going to be running in 2013, how many of those do you think are going to be HBP versus drilling for economics?

First of all, I’d say that even if it’s drilling to HBP acreage, I mean it will be an economic activity, but I think I understand your question, certainly well that – is the second or third well in the unit and is likely to be better than the first well. So, Steve do you have an estimate of that or not?

Fairly small percentage, we are focusing in the core, like you said HBP-ing within the core, but not necessarily multiple wells within the unit. Scott Hanold – RBC Capital Markets: So as most of your, I guess – if you look at your leasehold, how much do you think with the reduced rig count is, I guess the term would be at-risk for exploration or is some of the stuff that could expire in that stuff that could be potentially up for an asset sale and/or you may not want it anyway?

I think that’s really the right way to think about it. Scott, one of things we’re doing is not only selling assets that are not core, but also looking at our 10 core areas, and determining what we just don’t have the capital to get to, and what we don’t have the time to get to. So I think you will see us sell some of our leasehold in plays that are absolutely core to us, and over the next six months or so as we recognize that, we have acreage that may fit other companies better or we have acreage that would expire unless we went and drilled it. So as we pull in our horns and focus and concentrate our drilling in areas that are going to generate the highest returns, it’s a very different strategy than what we viewed for last few years, which is to lock down this asset base that we’ve taken from being a temporary asset base subject to exploration to a permanent asset base. And so for example nobody today thinks a whole lot about value from the Haynesville but we’ve had something like 7,000 wells to drill in the Haynesville that are HBP, so that are future drilling opportunities on acreage that’s been HBP. So that’s - I don’t think it’s fully baked in our forecast going forward, the increases in efficiency that are going to be generated, and certainly the increases and returns on investment as we continually move towards a program of drilling wells that will be on acreage that’s already HBP rather than on acreages that’s just sitting out there to be drilled at some point. So stay tuned for other areas or parts of our core areas that we might be willing to let the rest of the industry take a look at rather than spend our own capital chasing those opportunities to HBP further acreage. Scott Hanold – RBC Capital Markets: Okay, I appreciate that. And one follow-up, just so I understand that’s right. So when you look at your drilling CapEx in 2013 being down $750 million, I mean when I look at that, how much is related to just better drilling efficiencies, versus a planned further reduction to rig count versus I guess changes in planned asset sales or divestitures?

And there is certainly some associated with efficiency and hopefully some cost savings as well as obviously the price of fracs have come down in other parts of the drilling and completion operation, but mostly it just drop of rigs as we move down to 100 rigs for 2013. Scott Hanold – RBC Capital Markets: Okay, so most of the stuff you directly could control in theory?

We’re not saying that we’re going to assume there is a 15% efficiency factor and that allows us to drop our CapEx by 15% or something like that; it’s really related to rigs and if we’re able to drive efficiencies higher, if we are able to drive cost lower than that hopefully will be icing on the cake for us. Scott Hanold – RBC Capital Markets: Thanks guys.

Thank you. Scott, one other thing I might – mentioned, as you lower your cycle time, you can drill more wells, with the lower number of rigs, so for example in the Eagle Ford as we drop I think, Steve, we’re scheduled for 25 in 2013. Is that right?

No.

22, sorry.

22, and we are already seeing lots of wells in the teens and so I hope that that can go down even more, 22 rigs (inaudible).

: Scott Hanold – RBC Capital Markets: Got it, thanks, guys.

Okay, thank you, Scott.

We will go next to Matt Portillo of Tudor, Pickering, Holt. Matthew Portillo – Tudor, Pickering, Holt & Co. Securities, Inc.: Good morning, guys. Just a couple quick questions from me, just a quick follow-up on the Eagle Ford question. Could you give us an idea, I think in the second quarter you guys drilled around 121 wells in the Eagle Ford versus the first quarter of 62. What’s the – I guess the expected run rate over the next few quarters in terms of completions in the Eagle Ford? And then I guess kind of once you get down to 22 rigs in 2013, what would be a normalized quarterly well count for you there?

Matt, this is Steve. It should be similar to this, low 30s per month [turn] (ph) in line base.

The way I’d like to think about, Matt, during the last quarter we completed a Eagle Ford well every 18 hours and going forward, I think we can probably do better than that. Matthew Portillo – Tudor, Pickering, Holt & Co. Securities, Inc.: Perfect. And then just in terms of the wells you put in the release, obviously a lot of detail on kind of the larger category of wells here, with I think peak IPs of around 500 barrels a day equivalent. Could you give us an idea of roughly what the 30 day rates look like there, and maybe just your new expectations around what the EUR would be?

I think Steve can help you with both of those. Matt, while he is looking do you have anything else? Matthew Portillo – Tudor, Pickering, Holt & Co. Securities, Inc.: Yes, sure, just two final questions from me. On the CapEx side, just curious on 2013 if you were to, at high enough gas price, desire to flat line your gas production next year what sort of capital increase would we need to see on your development budget to get to that level of flat production?

That’s a good question Matt. I don’t have that right now, but we can certainly dial it up for you. Again, it would take quite a bit stronger price than what’s in the forward curve right now for us to be interested in doing that, but clearly, we have the assets to do it now and have the capability to do it. And remember, this is a issue where I think a lot of investors and analysts perhaps think about it in the abstract or in a vacuum which is what’s a gas price that gives you a reasonable rate of return on a well in the Marcellus or Haynesville or Barnett. and that’s only part of the equation. The other part of the equation is capital is finite obviously. and so you have to not only generate an attractive return, but you have to generate return as competitive with your other returns. So it’s not do we make money at $4 gas or $5 gas, it’s do we make as much money drilling the gas well at that price compared to what we make drilling an oil well at $90 a barrel. And so that’s I think a part of the equation that’s missing for most people’s analysis of the gas market going forward. Steve, do you have anything to follow-up with on?

Yeah, I mean we actually break the Eagle Ford in multiple pro formas because we’re wet gas, [oil and the shale oil] (ph) but the blend is about 9,000 barrels for first month.

Anything on NGLs or gas? we don’t produce a whole lot of gas out there. I let him continue to look, and we can come back, and given that we’re kind of over our hour I don't know how many folks are left to answer your questions, but we’re - in courtesy to everybody, we’re going to take two more questions and then if for some reason, you didn’t get a question asked and answered, please dial it in to Jeff, John, or Gary and they’ll get back to you. Operator, we’ll take two more please.

Yes sir. We’ll go next to Bob Brackett of Bernstein Research Bob Brackett – Bernstein Research: I had a question on the Utica, two-part, one is that it looks like you had a well producing in the Tuscarawas County, which is pretty oily. any color on that would be appreciated. And also ignoring land retention, where would you put that last rig, in the Miss Lime or in the Utica?

That’s tough man. First of all, good morning to you, let’s see I would say right now, Carroll and Columbiana counties are tough to beat. On the Utica, Alfalfa and Woods are tough to beat in the Miss Lime. So I’m not going to declare a winner between those two, but I would say that each of them has a little bit of HBP work to be done in those counties probably more to be done in Carroll and Columbiana, than in Alfalfa and Woods. But that’s a – we will go back and play with that a little bit, but both of those are very, very attractive areas and hopefully we’d end up being very competitive with any – for any incremental capital. Bob Brackett – Bernstein Research: And that Tuscarawas county well.

Yeah, I’m not – do you have a name for it?

Yeah, I’ve got that, they came on about 227 barrels of oil a day and 1.3 million.

What’s the name of the well?

Gribi.

Yeah. Bob Brackett – Bernstein Research: Okay. And are you guys looking to get any new plays or is that pretty much done?

We’re pretty much done. We have an acreage position in an area that we’ve not talked about. Probably that I’ve mentioned a little bit about a year ago. We still continue to poke around there. It’s pretty cheap area there and we will get some wells drilled or tested in the next three to six months and see if it’s something worthwhile or not. But we haven’t spent much money there to-date and if it becomes a core area for us, great, if not, we will be happy with the 10 that we have. Bob Brackett – Bernstein Research: Thank you.

Okay. Bob, thank you.

And we will take our final question from Joe Magner of Macquarie Capital. Joseph Magner – Macquarie Capital Markets: Good morning. Thanks for taking my question. Just any update on the divestiture efforts for the DJ and Utica properties that were announced over the last couple of months?

I don’t think so, but those would both be pretty – well, DJ would be modest I think given our lack of success in that area and the industry hasn’t done well outside of Wattenberg. So we’ll get what we can there and move on. Utica [French] (ph) process is underway. We’ll have something to say there in the next couple of months as we definitely will have successful leasehold sales in that area. And the Utica is clearly an area of intense interest for the industry. Given our first mover status there, a lot of people who want to establish positions come to see us. So we look forward to sharing some good news there later. Joseph Magner – Macquarie Capital Markets: Okay. And along the lines of Utica, can you update us just on takeaway capacity, what we might expect to see some of those – I guess, wells could turn to sales and production start to ramp up there?

Mostly in 2013, but Nick, if you want to address that or Steve, you want to address that, we’ve got a big program there underway and kind of lost track with all the different entities involved but you want to try and put that up?

Well, I don’t have any real specific dates other than there is one big infrastructure project underway and we’re have it all mapped out and looking forward to bringing on more wells. We’ve been trying to focus our drilling as close to existing pipelines as we can, and so we are doing our best to minimize it in the meantime, but there is lot of infrastructure added to the Utica.

Yeah, processing, there is going to be NGL takeaway adds in their projects, one that go to Philadelphia projects, one that go to Belvieu. So we are going to be a foundational shipper likely in any project that originates from the Utica. So there is going to be plenty of liquids there and we think plenty of opportunities to get the Belvieu pricing or Belvieu equivalent pricing over time. Joseph Magner – Macquarie Capital Markets: Okay. And just one last one. Nick, any anticipated amount for the ceiling test write down in the third quarter and could you provide us with what I guess where the cushion sits (inaudible)?

No anticipated amount, there is too many in and outs between now and then to give a number even within a range. So I’d like to hold off on doing that right now. And the cushion is pretty significant in my view, but I don't think we’re prepared to disclose what that is today. Joseph Magner – Macquarie Capital Markets: All right, that's all I have, thanks.

Okay Joe, thanks for your questions. And thanks to everybody else. And again if you have additional questions send them in to our IR team, they will get back to you shortly. Thanks again. Bye, bye.

This does conclude today's conference. We appreciate everyone's participation today.