Good day and welcome to the 2012 Q3 Chesapeake Energy Earnings Conference Call. Today’s conference is being recorded. At this time, I would like to turn the conference over to Mr. Jeff Mobley. Please go ahead, sir.

Good morning and thank you for joining our 2012 third quarter earnings conference call. Joining me today is Aubrey McClendon, our Chief Executive Officer; Steve Dixon, our Chief Operating Officer; Nick Dell’Osso, our Chief Financial Officer; as well as John Kilgallon and Gary Clark as part of the Investor Relations team. Our prepared remarks this morning should last about 15 to 20 minutes and then we’ll turn it over to Q&A. Aubrey?

Good morning. We especially appreciate those of you who are joining us from the Northeast Corridor today. We appreciate the effort you are making to be with us this morning and we hope your lives get back to normal as quickly as possible. Turning to the 2012 third quarter, I would first like to highlight Chesapeake’s strong operational achievements during the quarter. Our daily average production was up 24% year-over-year and 9% sequentially. We believe both measures will lead our large cap peers and rank as one of the very best operational performances for companies of any size in our industry. Especially important is the steady transformation of our asset base from an exclusive focus on natural gas three years ago to a focus that today and in the future, will remain more balanced between natural gas and liquids production. As evidence of the magnitude of our transformation, during the third quarter, our daily average liquids production was up 51% year-over-year and 10% sequentially. Those liquid growth percentages would have been even higher at 57% and 13%, respectively, if we hadn’t rejected 467,000 barrels of ethane processing during the quarter because of very low ethane prices especially at Conway, Kansas. Even more significantly, our daily average oil production was up 96% year-over-year and 21% sequentially. We believe it’s very important for our investors to recognize that Chesapeake’s liquids growth story is primarily an oil production growth story more than an NGL growth story. Obviously, not all liquids are made alike and so we are certainly focused on increasing oil production more than NGL production. Starting from just 33,000 barrels per day of liquids production three years ago, in the 2012 third quarter, we produced an average of 143,000 barrels per day of liquids, a more than fourfold increase in just…

Thanks, Nick. As Aubrey and Nick mentioned, CHK’s third quarter was truly exceptional from a production growth standpoint. Rather than review the growth rates already mentioned by Aubrey and Nick and in the press release, I’d like to provide some color around production in the quarter for each of our three products: oil, NGLs and natural gas. Last quarter, we emphasized that oil production, much more so than NGLs, would be our primary growth driver going forward, and that was indeed the case during the third quarter. We averaged net oil production of approximately 98,000 barrels per day in the quarter, which is up a remarkable 18,000 barrels per day from the second quarter of 23%. All of our key plays contributed to this quarter-over-quarter strength, but the Eagle Ford clearly led the way. Oil production would have been even higher than reported had we not experienced an unplanned plant outage in the Eagle Ford, which I’ll address in a moment. On the NGL side, reported volumes were down sequentially, about 9% compared to the second quarter. However, had we chosen not to reject approximately 7,400 barrels per day of ethane during July and August, NGL volumes would have been roughly flat with the second quarter. We do not anticipate rejecting as much if any ethanes during the fourth quarter, which should positively impact our reported NGL volumes in the coming quarter. On the natural gas front, we are down to our target of 9 rigs drilling. That’s five in Northern Marcellus, two in the Barnett, and two in the Haynesville. And as a reminder, last year, we were running as many as 81 natural gas rigs, so it’s quite a remarkable turnaround for the nation’s most active drilling program. Despite that slowdown in drilling, natural gas production grew a…

Thank you. At this time, we will start the question-and-answer session. (Operator Instructions) We’ll take our first question from Doug Leggate at Bank of America. Doug Leggate – Bank of America: Thanks. Good morning, guys. Thanks for taking my questions. Excuse me. I’ve got a cough...

How are you doing, Doug? Doug Leggate – Bank of America: Not too bad, if I can get past my frog in my throat here. I’ve got a couple of questions, please. First of all, on the disposals, the absence of any material commentary around the Mississippi Lime joint venture and the addition of some Eagle Ford and I don’t know if this is actually correct, but there is also some murmurings about Hogshooter asset sales as well. I’m just wondering if you can bring us up-to-date with the process and the additional assets you’ve put in the – what appears you put in the pot as it relates to your refocusing strategy, particularly on the Mississippi Lime. It seems to be a little quiet there. Any color would be appreciated.

You got it, Doug. Thanks for your questions. Let me go in reverse order. The Hogshooter, not clear why there was so much confusion on this, but let me see if I can clear it up. We have an asset package out called West Turkey Creek. It’s actually a Granite Wash package centered around the town of Elk City in Western Oklahoma. It’s to the west of our Colony Wash play. Our teaser that the broker has out on it mentions that there is Hogshooter potential on this acreage, but it is primarily a Granite Wash package. And it is, gosh, I think close to 100 miles away from our big Hogshooter wells out in the Texas Panhandle. So, to be clear, we are not selling anything in the core of our Hogshooter production across the Texas Panhandle and it comes into a little bit of Far Western Oklahoma. Then with regard to the Eagle Ford, we do have a portion of our Eagle Ford acreage, what we call the Northern Block that we have on the market today. That’s I think being marketed through Jefferies. And that is a very attractive amount of acreage that we need to sell because we simply do not have the capital to go drill all the wells that are required there to HBP that acreage. We’re more focused on the southern part of our block in what we call the wet gas area. This is all up in the oil area. And I think it has around 10,000 or 11,000 barrels a day of production at this point. So, it should be a very attractive package for another company, and again, we hope to have news on that by the end of the year. With regard to the Miss Lime, it has been…

Thanks, Doug, this is Steve. We’ve been very pleased with our results really in all of our areas and the core of the core strategy allows you to focus on your best rates of return areas. We probably are exceeding a lot of our type curves areas and are in the process of updating those; excellent results to date. Doug Leggate – Bank of America: So, no – so, we’ll get those updates when we should expect some news on that some time or will you just continue to report quarterly?

We haven’t been providing the specifics for a little while, Doug, and I don’t know that that will change in the near future. Doug Leggate – Bank of America: Okay. There’s a bit of debate around the choke size, Steve. If you could tell us what you’re running down there, that’d be great.

These wells are free flowing so they are on choke. We – and most all of our liquids-rich plays, we don’t open those up wide open. We keep back pressure on them. Multiple reasons for that; one is just for the equipment and facilities, to right size those to last through the longer life of the well. Some debate still on whether that actually increases your recoveries, but we’re certainly pleased with the results we’re seeing with our program. Doug Leggate – Bank of America: All right. I’ll leave it there, fellows. Thanks for your time.

Okay, Doug. Thank you.

We’ll take our next question from Dave Kistler with Simmons & Co. Dave Kistler – Simmons & Company: Morning, guys.

Morning, Dave. Dave Kistler – Simmons & Company: Real quickly on the CapEx that you mentioned, Nick, and the decline in the drillbit CapEx spending. Can you walk us through how that relates to the rig count that you shared with us? Are you at the right level at this point to achieve that decline that you’re targeting or should we expect to see additional declines in the rig count? Nick Dell’Osso: I think we’re getting down to where we want to be in rigs. We’re at 89 rigs today, but we’re actually physically operating about nine more than that as we’re still under a transition agreement in the Permian, but none of those dollars are obviously burdening us. So – but that’s really where we probably ought to be today and there would be small fluctuations through the fourth quarter and into the first quarter of next year, but pretty representative of our – being done with our ramp down. So, yeah, what we’re really seeing now is that the roll through of the lag of bookings coming down as rigs have come off is showing up in the numbers. So, we’ll see that October and November continue to decline and then it should begin to flatten out into December. Dave Kistler – Simmons & Company: Okay. That’s helpful. And maybe tying that a little bit to the Miss Lime, in the second quarter, you guys had talked about running 22 rigs throughout the balance of the year and it looks like right now you’re at 9 rigs. Can you walk us through a little bit of what changed and why you’re making those kinds of adjustments there?

Yes, Dave, this is Steve. Part of that is CapEx reduction, core of the core focus, but a big part of it is that we were outrunning our infrastructure there. These wells move a lot of water and so we need to get disposal systems built out, get electrification in place to be able to run those wells more economically. So, it was really that probably more than anything. Dave Kistler – Simmons & Company: Okay. And then just one last one, if I might. With respect to taking out some of the typical disclosures that were in Schedule A, can you talk a little bit about what you’re thinking about for spending in the oil service and midstream side of things? I think that was removed as well – I may have missed it somewhere else in the release. Nick Dell’Osso: You’re right, Dave. We did move it – we did remove it. Midstream for 2013, we expect to be zero because we expect not to own it any further. And services will be down pretty well from 2012 as well. We’ve largely completed our build-out of PTL, which is our pressure pumping business. And the combined total of midstream and all other – sorry, services and all other CapEx should be about $1 billion or in that neighborhood, but – which is not different than we’ve said before, but we just felt that with the loss of midstream from the projections, it really became less interest on that number, so we took it out. Dave Kistler – Simmons & Company: Great. I appreciate the clarification, guys. Thank you. Nick Dell’Osso: Yep.

We’ll take our next question from Neal Dingmann with SunTrust. Neal Dingmann – SunTrust: Morning, gentlemen. Say, just two quick questions. First, Aubrey, just your thoughts on, you mentioned about going after the core of the core, and your thoughts in the Eagle Ford, obviously, the results look spectacular there. And just wondering on that reduction in rig count, does that just have to do with overall CapEx that Nick or Steve was suggesting or just maybe your thoughts on Eagle Ford sort of activity going forward?

Well, I think what we’re seeing in the Eagle Ford as we’re seeing across all of our plays is just quicker cycle times and we continue to drive those numbers down and so we can get done what we want to do with fewer rigs today than what we thought six months or a year ago. So, you can basically spend about the same amount of money, but you get far more wells with reduced cycle times. So, I think if you talk to service companies across the sector, particularly drillers, they will see that this is a phenomenon that’s giving them a little bit of consternation that the industry is becoming so much more efficient. So, as a consequence of lower cycle times and of needing to hit a glide path where our CapEx and operating cash flow are in balance in 2014, we have needed to reduce our CapEx across the company, and in 2013, we’re planning for it to be about a third lower than it was in 2012. And so, we can’t drill everything that we have; we’re long assets and short capital. So, we are strategically moving towards the best parts of our plays and so, we’ve identified an area in the Eagle Ford that we think will provide very attractive returns for a company that’s not there or a company that’s there and trying to expand its operations. For us, we will focus all of our efforts in the Eagle Ford down in the southern portion where I think Steve said we have another 3,000 or 4,000 wells to drill in that area. Neal Dingmann – SunTrust: Aubrey, any HBP issues in kind of those top eight or nine plays that Chesapeake covers at which you’re kind of referring to when moving these rigs around?

Well, that’s certainly an important consideration and I think I said in my remarks that by the end of 2013, we should be largely HBP in most of our plays, that won’t quite be true in the Utica, for example, but in the Marcellus, and the Eagle Ford and certainly in the Haynesville and the Barnett, where we’re just about there today. We’ll be in a position where we will have far more flexibility than we’ve historically had. And as Steve mentions, the returns that you get from drilling a second and third well on the pad compared to a first well are exceptionally better and so now that we have built an inventory of future wells to drill, and have incurred that heavy lifting of those costs, our returns on capital will go much higher. I saw some work the other day that part of our company had done where we looked at in our top 10 plays, what percentage of our acreage was PDP, and it was less than 10% and yet the HBP portion of it was well over 50%. So, you’re beginning to see that we have a lot of acreage held that’s not yet on our reserve books, and that would be the focus of the company for the years to come. Neal Dingmann – SunTrust: Okay, very good, and then last one if I could, just on the Utica, obviously, a number of – a large number of wells drilled there, but not tied in yet. Your thoughts on timing of when you could get to that sort of equilibrium point looking at next – is that something next year or will you be running such and the build-out will be such on midstream that it might take even longer than next year?

Neil, this is Steve. I’ll answer that. We are working hard building both pipelines, but then also processing facilities need to be put in place. And some of those take longer lead times, but 2013, we have a lot of processing coming on and again construction every day on the pipelines to get these wells hooked up. So, 2013, we’ll see a big, big increase. Neal Dingmann – SunTrust: Got it. Thank you all.

We’ll take our next question from David Tameron with Wells Fargo. David Tameron – Wells Fargo: Hi, good morning. Aubrey, in the guidance, there’s a little line in there about this – I guess the forward guidance remains at the risk of the Board or Operating Committee adjusting that going forward. Has the Board signed off on this 2013 or do you anticipate any other changes for 2013 as you go through the next few months?

Yeah. Dave, good question. Where we are is our Board meeting in December is geared towards discussing our 2013 budget. That’s kind of the rhythm that most oil and gas companies have. So, we had other issues that we wanted to focus on, and September and December will be the time where we address the budget. So, that’s why we’ve said that we don’t have an officially approved 2013 budget. But obviously, we have to have a plan that we’re working on right now and that’s the plan that we’ve laid out today, but certainly it’s subject to further discussion with the Board. David Tameron – Wells Fargo: Okay. Thank you. And then for – a couple of bigger picture questions. On the ethane front, you talked about or Steve did maybe, you talked about ethane rejection in the quarter. Can you give us your outlook for 2013? How you see those markets and have you guys built any assumptions into your guidance?

Yes, we continue to build low NGL prices in our budget driven by low ethane prices. And we, obviously, have an oversupply of NGLs, primarily ethane. Actually some of the NGL components are above the prices where they were a year ago. But this is going to take a couple years for the demand for those products to increase. Propane would certainly be something that would benefit from a colder winter than last year. So, in our view, these things are all getting fixed through demand growth and also you’ll see, I think two pipelines completed in 2013 that will connect Conway to Belvieu. So, the huge differentials that you’ve seen during 2012 in Conway compared to Belvieu should go away. So, we try to move as much of our product to pricing at Belvieu, but we still have substantial exposure to Conway. So, we look for low prices in 2013 but steady improvement by the back half of the year into 2014 with, of course, a normal winter being quite beneficial to us on – across the board on NGLs. David Tameron – Wells Fargo: Okay. And then last question – and that’s helpful color. The last question on the natural gas front – and obviously you laid out your case for a bullish scenario, but why not go ahead and take some risks off the table and hedge out that – your 2013 program a little bit? What – can you give us your thought process around that?

Sure, I’d be happy to. So, for starters, we like to hedge. We’ve been successful hedgers, about $8.8 billion of hedging gains since 2006. So, it’s something that we talk about every day, our hedging committee is Jeff, and Nick and myself. And so, we’re charged with mitigating risk but also with optimizing returns and our view of the market is driven by information that we have that maybe not everybody else has in terms of where we think our production is headed and how we model the production of our competitors as well. And we simply view that today’s strip for 2013 and frankly, for years beyond that, does not reflect a full appreciation of what happens when big producers like us reverse course and go in to managed decline. And as Nick said in his remarks, we’ll be down 7% year-over-year. That will be the first year in 23 years that our company had experienced a gas production decline, Chesapeake has been responsible for about 30% of all the gas production growth the whole industry has generated in the past five years. And so, when we roll over, we think we will pull the whole market with us and we think that the prices that we see out in 2013 do not reflect that. In fact, I saw one Wall Street piece even this morning that projected the Haynesville will be flat to up in 2013 gas production. That’s simply impossible. Our production is already down 25% from a peak. Our Barnett production is already off 11% from its peak. Steve mentioned that our Haynesville production will be declining by 9% quarter-over-quarter, third quarter to fourth quarter. David Tameron – Wells Fargo: Okay. So, even the Marcellus kick that we’re going to get with the additional infrastructure -?

Yeah. We just don’t see – I mean, we model all that; we’re the biggest producer in the Marcellus and we just don’t see the Marcellus being able to overcome the declines that are going to happen in the Haynesville and in the Barnett along with all the other conventional gas that today, of course, still represents about more than 50% of all the gas production in the U.S. So, it’s simply a matter of trying to pick our spot and we haven’t yet seen our spot, but we will – by the time that we talk again, after the first of the year, my guess is that we would have started to layer in some hedges. We are... David Tameron – Wells Fargo: All right, I appreciate.

Yes. We are very well-hedged on oil. I would like to point that out. David Tameron – Wells Fargo: Thank you.

Thank you, Dave.

We’ll take our next question from Scott Hanold with RBC Capital Markets. Scott Hanold – RBC Capital Markets: Thanks. Just a follow-up on that sort of gas price question. When you all step back and look at your drilling activity, I know in the past you’ve said before that your gas plays have to compete with your oil plays – plays on a heads-up basis. Can you give us a little bit more color, I mean, if gas got to $5 to $6, I mean, and oil was in this $85, $90 range, does that start making that transition back to gas happen again?

Yeah, and, Scott, to be clear, you said $5 to $6, right? Scott Hanold – RBC Capital Markets: Yes, that’s right, that’s right. And $5-plus – so let’s just say $5-plus, get above $5, yeah.

Well, certainly $4 to $5, we’ve said then no change in our approach. $5 to $6 we’d probably – we would evaluate and take a look. The Marcellus is certainly competitive with oil projects at inside that $5 to $6 range. The Haynesville and Barnett it still may be a toss-up, but remember also, we and other companies still have acreage that needs to be HBP on the oil side. So, just as rig activity was sticky on the gas side when economics indicated that you might reduce your count, the industry kept it pretty high because it needed to convert options with a one or two-year life to them to options that have no expiration to them. And you’ll see that on the oil side as well. Scott Hanold – RBC Capital Markets: Okay. So, you sense that the rig count could be pretty sticky with the oil plays here for at least the next few years is generally what...

Yes, that’s what you’ll see from us. Scott Hanold – RBC Capital Markets: Okay. All right. And then on the Utica Shale, I think when you all first started talking about this play pretty aggressively, you had sort of dubbed it as better than the Eagle Ford or something pretty close to that. And with obviously over 100 wells now drilled and a few dozen on line, what are your thoughts right now? Does it – it seems like it’s a little bit more gassy with some of the results. And how does your kind of the core of the core strategy work in the Utica? When do you think you could really start fine tuning that a little bit better?

Well, I think we have a really good handle on where the core of the core is and we feel like we own it in Columbiana and Carroll and Harrison Counties. And so, we went after the wet gas here. We picked up some oil acreage in some of our deals and haven’t been in the process of really selling the oil acreage to companies that we’re more focused on that part of the play than us. So, I think in the wet gas – the best of the Utica wet gas is absolutely competitive with the best of the Eagle Ford wet gas. And so, the question is really is – has the area of wet gas narrowed somewhat? Probably it has a little bit. But so did the Eagle Ford wet gas window and we’ve dealt with that. And we have acreage in the right spot for the Eagle Ford wet gas; and then Utica, I think, our Utica wet gas acreage is between 300,000 and 400,000 acres out of our million-plus acres there. So, we’re thrilled with the Utica. It’s just taken a while to be able to show results because we simply are waiting on midstream build-out to occur which will be starting in 2013 and extend on into 2014. So, I think if you look around and look at the wells that Gulfport’s announced and some of the other wells that other companies have announced that if you’re in that corridor which stretches from Columbiana down through Carroll and Harrison, and maybe a little further south from there, you have results that are as good as any from any play in the country. Scott Hanold – RBC Capital Markets: Understood, thanks. And one real quick one. I think, Steve, you may have mentioned that you are running nine rigs on the Permian obviously for the purchasers. Nick, could you just give a little color? How does that run through the financials? Will we be seeing some of that rolled through Chesapeake CapEx and back out somewhere else or is that going to be sort of a non-impact to any kind of CapEx you could report in the fourth quarter? Nick Dell’Osso: It’s a non-impact. We do that through a Transition Services agreement.

So, basically we just bill them for 100% working interest and they pay us for that. Scott Hanold – RBC Capital Markets: Understood, thanks.

We’ll take our next question from Jason Gilbert with Goldman Sachs. Jason Gilbert – Goldman Sachs: Hey, guys. Thanks for taking my question. I’m going to ask you my usual one on CapEx. Spending was higher in the quarter than I think any of us had been expecting. I was just wondering if you could talk about what drove this, if it was HBP or rig – term rig contracts? And in our numbers, 4Q CapEx is going to have to be down something like 30% in order to meet your guidance. So, I was just wondering if you can elaborate on how nimble you can be in reducing the spending? I know you spoke to it a little bit in the prepared comments, but just wanted some more detail. Nick Dell’Osso: Sure, Jason. The short answer is we can – you can call it nimble or you can call it, I guess, completed. But at the current rig count, we’re there. So, it’s really a matter of the lag from the ramp-down that you see rolling through. And one of the things to keep in mind here is that as you bring rigs off, which we’ve been doing since, I guess, mid to late spring, you still have a number of associated costs after the rigs go away. You have frac crews that have to complete their work on the wells that have been drilled. You have other mobilization costs, et cetera. And so, that has taken more time than any of us probably anticipated to run through the system. But we are absolutely seeing the lower month-over-month numbers now that will drive us to exactly where you’re looking fourth quarter. I agree with your assessment of the decrease that’s required and we think we’ll hit it. We’re on target to do so.

Jason, I might also mention that we did take the high end of our CapEx estimate for the year up by $250 million but apparently some people lost the point that we also reduced our leasehold spend by an equal amount of $250 million. So, leasehold is really a forward-looking indicator of CapEx and it has really fallen off in the last few months and will continue to decline further and we’re taking it from $1.750 billion in 2012 to only $400 million in 2013. So, that run rate is dropping very aggressively as well. So, I hope people do recognize that net-net we ended up flat on our CapEx guidance. Nick Dell’Osso: And then the... Jason Gilbert – Goldman Sachs: That’s... Nick Dell’Osso: Go ahead, Jason.

Go ahead, Jason. Jason Gilbert – Goldman Sachs: That’s helpful. I appreciate that. I had a follow-up also on the Haynesville. And I was just wondering, what is the longer-term strategy for that asset? Based on your comments, it sounds like you need at least $5 gas, and possibly higher to have it compete with oil projects, and it’s also got to compete with the Marcellus. I mean, is this an asset you still consider to be core?

Yes, it’s one of our 10 core assets along with Barnett and eight others. So, and I think it’s a great point that people are not fully appreciating which is that I think there’s a case out there for gas prices that most people aren’t willing to contemplate because they run individual well math that says, oh, at $4.50 or $5 or $5.50, you can make money drilling that Barnett well or that Haynesville well. And, yes, the answer is you could, but capital is always scarce and, as a consequence, you have to pursue projects that have the best returns. And today those best returns are in plays like the Eagle Ford, the Utica and other liquid-focused plays. And that will remain the case. And we are comfortable with our gas production continuing to decline for as long as is required for gas prices to become attractive enough for us to take rigs away from oil plays and go put them in gas plays. And so, right now, we have one of the biggest gas storage reservoirs in the world sitting there in the Haynesville and sitting there in the Barnett and sitting there in the Marcellus. And it has incredible option value and I think what you’ll see is the demand for gas increase over the next one to five years to get to a point where the gas curve is going to have to go be competitive with the oil curve for projects for additional drilling in these fields. And when the gas curve pays us to take on those responsibilities of drilling those additional wells, we’ll do so. But not until then. Jason Gilbert – Goldman Sachs: Great. And one final one, if I may. Just is there any update on the additional Utica JV you’ve mentioned in the past as to what timing might be there?

Sure. That project we talked about in 2013 that would be a JV on the dry gas side. So, just to remind everybody, we have a JV with Total on the wet gas side. And we do not have a partner on the dry gas side. So, we’re – that’s a 2013 project and we anticipate that gas prices will become attractive enough during 2013 to get some interest there. There’s lots of companies that are looking to export gas from the U.S. who need some domestic exposure. And as a consequence of that, we think we will have plenty of people to take a look at it. And the results, I would say, on the dry gas side of the Utica are very, very strong, and in fact, quite competitive with what we see in the Marcellus in the northeastern part of the dry gas play, the Northeastern Marcellus. Again, it’s not something that you talk about very much in a time of low gas prices. But we have drilled a number of Utica dry gas wells that are very strong and will generate rates of return competitive with our Marcellus drilling. Jason Gilbert – Goldman Sachs: But to be clear, that process has not started yet, right?

It has not started. It’s a 2013 process. You’re right. Jason Gilbert – Goldman Sachs: Okay. Great. Thanks so much. I’ll turn it back.

Okay. Thanks, Jason.

We’ll take our next question from Brian Singer with Goldman Sachs. Brian Singer – Goldman Sachs: Good morning.

Hi, Brian. Nick Dell’Osso: Good morning, Brian. Brian Singer – Goldman Sachs: Just following up on the Utica. Can you talk a bit more towards production mix, oil, NGLs and gas given the variability that we’ve seen in some of the wells that have been drilled and then some more detail on backlog changes and the gas contribution you expect from Utica in the context of your 7% overall gas decline next year?

Hi, Brian. This is Steve. I’ll start on that. I mean, like the Eagle Ford, the Utica has a dry gas window, wet gas window and oil window, and so with very limited well results to date, it’s really weighted towards wherever those wells are. And so, it’s – I don’t think you can say that it’s going to be gassier or oilier. It’s really where the well mix is producing. We’re very, very pleased with the results. We’re very pleased with what we think hydrocarbons in place are in the Utica. So, it’d really just be where processing midstream and the wells get drilled. Brian Singer – Goldman Sachs: I guess, to be specific, what percent gas do you expect and what percent oil do you expect from the core wet gas or whatever you would call core of core that drives the strong rates of return versus the Eagle Ford?

Brian, this is Aubrey. I’m looking at something that our natural – our NGL yield is about 40% to 45%. And I’m sorry that I don’t have the break between processed gas and oil but we can get back with you on that. But again, it’s pretty consistent with what we’ve seen in wet gas plays like in the Eagle Ford. But we’ll – we can get back with you off line. Brian Singer – Goldman Sachs: Okay, that’s great. And then speaking of the Eagle Ford, when you think about core of core and I apologize if you mentioned this already, can you just talk about the acres that you would put in the core of core and has it been those acres that has been the major driver so far of the production increases that we’ve seen recently?

I’m sorry, which were you referring to, a particular play or just... Brian Singer – Goldman Sachs: Yes, I’m sorry, in the Eagle Ford shale. When you think about the north versus south in the core of core, how many acres would you call the core of core and have those acres been the major driver of your growth here in the last couple of quarters?

I don’t have the exact percentage, but it’s going to be probably in the 60% to 65% range. And, yeah, it’s definitely – those have been the ones driving it, although I think I did say that our gross production is around 10,000 or 11,000 barrels of oil per day on what’s for sale and so obviously a disproportionate part of our production is in the southern part of the play. Back to your Utica comment, I mean one thing you could do is just look at three wells that we’ve highlighted there and add up our liquids production compared to natural gas production and come up with a percentage of natural gas. Brian Singer – Goldman Sachs: Do you think those wells are representative of the averages that we’ll see on a going-forward basis for your acreage?

In the core, wet gas phase, absolutely, yeah. Brian Singer – Goldman Sachs: Okay. That’s great. And then lastly, it was asked earlier on the – you talked about the December Board meeting and the 2013 budget. Would you expect any meaningful changes as a result of that Board meeting in terms of the operational plans, any major shifts in growth that you’re projected out of spend when all is said and done?

Brian, I really can’t speculate on that at this time. We’ll just have to have the discussion, see where oil and gas prices are and see how our plays stack up and make those decisions at that point. And as soon as those decisions have been made, we’ll be able to get back to you. Brian Singer – Goldman Sachs: That’s great. Thank you.

Thank you.

We’ll take our next question from Biju Perincheril with Jefferies. Biju Perincheril – Jefferies: Hi, good morning. A couple of questions. On the reserves front, there was a sizeable negative provision. Can you give some color where that is and what drove that? Not price-related revisions.

Predominantly, it was all price-related. We had some that were just aged PUDs come off but it was not a big number, Biju, it was pretty much price-related. Nick Dell’Osso: The other aspect of that, of course, is that with lower rig counts, there’s PUDs that we no longer can model within our five-year rule. So, as we’ve lowered our rig count this year, we have to remodel what will fit as PUDs and so there’s a component that includes that. Biju Perincheril – Jefferies: Got it. So, would it...? Nick Dell’Osso: The reserves are still – of course, the reserves are still on the ground and to the extent acreage is held-by production, we’ll get to them in better price times. Biju Perincheril – Jefferies: Okay. Okay. And then, on slide 12 of your latest deck, if I look at the growth coming from associated gas, you are forecasting a lower number now as compared to the previous slides. Is that just lower drilling activity or a shift in your mix where you’re drilling or are you expecting any lower productivity in any of the areas?

Certainly not lower productivity. I think that’s related to just lower activity overall as we seek to glide down to our projected CapEx for 2013. Biju Perincheril – Jefferies: Okay. And then one last question on the CapEx. Can you talk about sort of your monthly rate where you are now with sort of 89 rigs versus where you were, I think, over close to 120 rigs a quarter ago? Nick Dell’Osso: Yes. Biju, I’ll just repeat what I said before which was September was down 18% from August and October looks to be down pretty significantly again and then we expect November to be a further decline from there. So, again, it doesn’t tie on a calendar perspective exactly with when the rigs come off because there’s a lag in the bookings and there’s a lag in the associated capital that comes behind the rigs. So, it’s a little bit hard to tie it to exactly when the rigs come off, but I’ll just, again, guide you back to what we are seeing in month-over-month changes which is very material. Biju Perincheril – Jefferies: Got it. All right. Thank you.

I believe we have time for about two more questions, particularly out of courtesy to other companies and their earnings calls. So, operator, if you could open it up for a couple more.

We’ll take our next question from Charles Meade with Johnson Rice. Charles Meade – Johnson Rice: Thanks, guys, for letting me be one of these last two. This will be quick. Nick Dell’Osso: Hi, Charles. Charles Meade – Johnson Rice: Can you tell us where you are and kind of what the remaining tasks are to get the CMD divestiture closed and does it make sense to think about it in like a percentage of completion? Nick Dell’Osso: We probably have some work plans around here with a percentage of completion on them. But, no, it doesn’t really make sense to think about it like that. Look, this is our fifth deal that we’ve done with GIP over the last several years when you include the original transaction and the drop-downs that we’ve completed taking the MLP public, et cetera. So, we know these guys well. We have a high degree of confidence in where we’re headed. This is across multiple basins. Some of our partners are, of course, impacted here. And we need to talk to them about what we’re doing and we’re in the process of doing all that. So, it’s just a big complicated process with have a lot of paper to move and we’re progressing forward with it as expeditiously as we can. Charles Meade – Johnson Rice: Got it. Thank you. And then I wanted to go back to one comment that you guys made a couple of times in your prepared remarks when you said that you were going to stay at or below $9.5 billion of total debt going forward. What is the timeframe on that or what are the kind of the conditions associated with that? Because it doesn’t really make sense as a perpetual goal. Nick Dell’Osso: Well, I think that’s a fair comment, Charles, other than the fact that we really believe that our balance sheet got stressed over the last several years as we made a transition and then that transition occurred during a time of very low natural gas prices. So, we acknowledge that we would like to have less debt on our balance sheet. As reserves and production grow into the future, we could always choose to revisit that. But for the period we see in front of us, we would like to be clear that the company knows or has a view as to what an appropriate level of debt is and we’re going to get there and stay there. So, we’re not ones to say never about anything, but on this one, we’re pretty firm about where we want to be and we’re going to stay there for the time being. So, things could change over the future to impact that, but for now, we’re focused on that goal. Charles Meade – Johnson Rice: Great. Thank you, Nick. That’s it for me.

And we’ll take our last question today from Michael Hall with Robert W. Baird. Michael Hall – Robert W. Baird: Thanks. I guess, just one quick one for me. As I think about backlogs and efficiencies, I know you talked a lot about it on the call. I guess, first, what’s the current backlog up in the northeastern part of the Marcellus from your all’s side of things? And then second, do you have any sort of estimates around what sort of capital is associated with bringing the backlogs on, particularly in the Eagle Ford and also the Marcellus, and the timeline for reducing those down to what you might call a more normalized level? Sorry, a few questions in there.

I know. We got it. I think Steve is going to take these, just gathering information. Michael Hall – Robert W. Baird: Thanks.

In the Marcellus, we still have over 200 wells in backlog. We took quite a few of those off already this year. And we’ll plan on reducing that further in 2013.

And I think that’s in our press release, in the Eagle Ford, for example, we have 233 wells that have been drilled... Michael Hall – Robert W. Baird: Right.

Aren’t producing. But none of those are really what you would consider backlog waiting on a whole lot of infrastructure and most of that is in a spot where it’s the normal course of business. Michael Hall – Robert W. Baird: I guess, that’s – Nick Dell’Osso: And we do project the capital for that as well or do our best to project the capital for that as well. So, it should not lead to – that in and of itself we hope won’t lead to surprises in CapEx. Michael Hall – Robert W. Baird: Okay. Any willingness to disclose that capital or no? Nick Dell’Osso: I still think I have it split out here but...

Basically, our well costs are about half for drilling and about half for completion, so you can always work off that. Nick Dell’Osso: But some of those wells will have already been completed and just waiting on a pipeline and require very little capital. Some are waiting on completion. So, there’s just a variety of things in that mix. Michael Hall – Robert W. Baird: Okay, fair enough. And then as you think about these drilling efficiencies that the industry and yourselves are seeing, I mean, is it fair to think that as you get surprised to the upside, if you will, on efficiency gains that drives some sort of creep higher in capital as you’re unable to react to all that real-time to those efficiency gains?

We would simply reduce rig count. I mean the focus is on what’s the right level of capital and the course that we can do that, with fewer rigs then obviously that’s the best outcome for our shareholders. So, we and others in the industry are continuing to try to get more efficient and to the extent we can use fewer rigs to develop our properties over time, that will be a very good thing for all of us. Michael Hall – Robert W. Baird: Got it, great. Thanks, I appreciate it.

Okay. Thanks, everybody. We appreciate your participation today. If you have any follow-up questions, Jeff and the rest of his team are available for you. So, thanks again.