Good day and welcome to the Chesapeake Energy Corporation 2012 Q4 and full year earnings conference call. [Operator instructions.] 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 call today to discuss Chesapeake’s financial and operational results for the 2012 fourth quarter and full year. Hopefully you’ve had a chance to review our press release and updated investor presentation that we have posted to our website. During the course of this call, our commentary will include forward looking statements regarding our beliefs, goals, expectations, objectives, forecasts, projections, and future performance and the assumptions underlying such statements. Please note that there are a number of factors that could cause our actual results to differ materially from such forward looking statements. Additional information concerning these factors is available on our earnings release and the company’s SEC filings. Additionally, we may refer to certain non-GAAP financial measures, so we encourage you to read the full disclosure and GAAP reconciliations located on our website and in this morning’s press release. I would next like to introduce the other members of our management team, who are with me on the call today: Steve Dixon, our chief operating officer Nick Dell’Osso, our chief financial officer; and Gary Clark, our vice president of investor relations and research. Before I turn the conference over to Steve, however, I would like to share with you a few comments on a leadership change at Chesapeake. As you know, Aubrey McClendon, the company’s co-founder and CEO will retire from the company on April 1, 2013, and after leading the company during our first 80 conference calls, he is now stepping aside to Steve and Nick to lead this call. In addition, a search is currently underway for a new CEO, and the board plans to complete this search by that time. Aubrey has had a remarkable career founding and leading Chesapeake, and has created one of the most valuable and innovative companies in the global energy industry. Two of Aubrey’s most important accomplishments are the tremendous asset base that has been amassed by the company and the talented and dedicated organization he built to develop these assets. The culture and capabilities of the company Aubrey created, and the standards of excellence he championed, have been distinctive and inspiring, resulting in a company with extraordinary potential. But his legacy will ultimately be the realization of that potential through the success and value that we all help deliver after his tenure as CEO concludes. With those thoughts in mind, and on behalf of nearly 12,000 employees at Chesapeake, we want to sincerely thank Aubrey for his visionary leadership and for his 24 years of tireless service to the company, the shareholders, the employees, and to the industry. With that, I’m going to turn the call over to Steve Dixon, who is working with Nick Dell’Osso to guide the company through this period. I thank them, and all of my Chesapeake colleagues, for their continued dedication and focus as we work collectively to develop Chesapeake’s world-class asset for our shareholders. Steve?

Thanks, Jeff. I’m pleased to report substantial progress at Chesapeake this quarter, on three key objectives: improving our production mix towards more liquids, reducing per-unit production cost, and achieving our targeted capital budget reductions. Nick will talk more in depth about both the capital budget achievements and our cost discipline in a few minutes, but suffice it to say, I’m proud of what our operational teams have achieved and the path that we are on. Clearly we have amassed an enviable collection of assets across 10 of the top 15 key onshore plays in the U.S., and now the task at hand is to convert a decade of industry-leading new play investments into improved shareholder returns. And we are well-positioned to do this, even more efficiently and effectively than ever before. Over the past three quarters, Chesapeake has demonstrated that we have the people, properties, and processes in place to drive liquids production higher while also containing per-unit expenses. Furthermore, I’m energized by the opportunity to greatly improve our capital efficiency in the quarters ahead. To this end, during the past year, all of our asset teams have been retasked and incentivized to shift their focus from acreage capture mode to meeting budgets and delivering higher returns on capital. Focusing our operations on the core of the core enables our drilling program to increasingly target the best parts of each play, which should translate into better well results and very impactful capital efficiency improvements. Through focused pad drilling, our equipment mobilization times will compress, water handling logistics will be simplified, road and pad construction costs will decline, pipeline connection times will shorten, and many other economies of scale will be realized. We are targeting capital efficiency improvements of at least 15-20% as we transition to pad drilling. Before I get…

[Operator instructions.] We’ll go first to Doug Leggate with Bank of America Merrill Lynch. Doug Leggate – Bank of America Merrill Lynch : I’ll start off with Nick, or whoever wants to take this one, on the asset sales. Nick, it sounds like you’re pretty close to the the Mississippi Lime disposal. Could you share with us any color in terms of whether this is solely an acreage deal or the format in terms of joint venture or whatever? Or particularly, if there’s any production associated with your likely transaction? Nick Dell’Osso: I’m going to hold back on giving you any specifics on the transaction given we’re in the throes of working on it. But I would say that there is some production associated with it, and we have included the impact of that in our outlook. Doug Leggate – Bank of America Merrill Lynch : Maybe a follow on related, then. One of the biggest criticisms, perhaps, of the company is still the outspend, or the overspend. And you highlighted the liquidity position since the beginning of the year, at least the end of last year. However, if you don’t achieve the $5-7 billion of asset sales, it wouldn’t really help you. So can you help, or provide any kind of color, as to how the board is influencing the spending decision versus the potential ultimate scale of disposals, and any comfort you can give us on the line of sight as to how you get to such big numbers, $5-7 billion this year? Nick Dell’Osso: Well, we and the board are very focused on our budget for the year, which as you noted has multiple elements. It has our spend. It also has asset sales and other costs associated with it. We’re focused on the end game of…

We are focusing our capital program on liquids, and drilling our very best locations, and that’s starting to [gin] those results. Probably the Eagle Ford is certainly the biggest driver, where most of our capital is, and where we’ve had the greatest success. And it continues to impress and improve. And hopefully we’ll get some more results quarter over quarter going forward. Doug Leggate – Bank of America Merrill Lynch : No change to the type curve? In the Eagle Ford in particular? Nick Dell’Osso: We haven’t provided the type curve since 2010. Doug Leggate – Bank of America Merrill Lynch : That’s what I mean. It seems to be pretty out of date. Nick Dell’Osso: Our results we think show great growth there, and great performance. [talkover] continue to deliver to you guys out of the Eagle Ford, and out of all our liquids plays.

We’ll go next to Arun Jayaram with Credit Suisse.

Nick, I wanted to ask you, obviously you have a $4 billion outspend this year. Wanted to see how the Marcellus could tie in to the deleveraging of your balance sheet. Obviously you have a big acreage position here. I’d argue it’s probably the highest multiple business in the U.S. E&P. The company’s obviously focused on liquids. Why not think about monetizing a piece of the Marcellus? Nick Dell’Osso: We’re looking at a number of alternatives on the A&D front for this year. We have a pretty good plan in front of us. We have had a couple of non-core acreage packages in the Marcellus out of the market that we had said we were going to do in our third quarter. And we continue to do that across the board, look for the places within our portfolio where we are going to be the most efficient, given the footprint that we have, and where we have the best results, and know that we have acreage that would be more valuable to someone else. Very good acreage that can be drilled for a great return, but within our portfolio, as we’re going to allocate capital, can be delivered to someone else for a better return in up-front cash to Chesapeake. So we’re doing that in the Marcellus, and we’re doing that across all of our plays.

And in terms of what we have line of sight on today, it’s the Mississippi Lime and an acreage package in the Eagle Ford, in terms of upstream asset sales? Is that fair? Nick Dell’Osso: Those are the two biggest that we’ve talked about publicly. That’s correct.

And switching gears a little bit, you guys recently talked about a 10-year agreement on the methanol front. I just wanted to get some details on that, and perhaps are you seeing more industrial customers looking to do similar kinds of things? Nick Dell’Osso: We are seeing a lot of interest from industrial customers. There’s been a really big increase over the last couple of years, but recently it’s been even probably a more concerted effort by industrial customers to talk to us about some creative ideas. And we’ve found the methanol transaction to be very attractive for us. It links our ultimate delivery to a price of a commodity that’s closer tied to crude, so we can take some gas exposure and tie it in a way that correlates it more to a crude price. And it’s something that brings additional demand onto the U.S. market for natural gas. So we think that we have a great price structure locked in there, one that achieves a very favorable price for Chesapeake and still provides us with enough exposure to upside to make it interesting beyond the price at the outset of the deal.

And one quick one for Steve. Where is your Haynesville production today versus at the peak?

I know it was down pretty hard quarter over quarter. Gross, we’re down to 1.3 from 2 Bcf a day.

Down by about a third. Okay, that’s helpful.

We’ll go next to Brian Singer with Goldman Sachs. Brian Singer – Goldman Sachs: First, on the oil mix, can you just talk about how, if at all, you expect your oil mix to evolve and change in three areas: the Mississippi Lime, Eagle Ford, and in Utica? I noticed that the Mississippi Lime, that oil as a percentage of the total ticked up during the quarter. In the Eagle Ford, it ticked down a little bit. And just also wondering when you talk about 5-10 [Bcfe] whereas in Utica, what percentage oil versus NGLs versus gas you would expect?

I’ll start with the Utica. That’s still pretty early and results change pretty quickly across the play. Yields have a pretty wide range, and so that’s why we gave a wide range. So I don’t really have a number to give you on that. Nick Dell’Osso: The Mississippi Lime and the Eagle Ford, we don’t really expect the mix to change there over time. We have pretty good insight now with those basins having pretty material amount of production. So we feel good about that production mix being reasonably constant over time. There will be fluctuations of course, as you bring on different packages of wells, but we don’t expect any material differences. Brian Singer – Goldman Sachs: And those, in places like the Mississippi Lime, would be consistent with the 40-45% that you saw in the third and fourth quarter? Or do you expect some sort of degradation over time as wells decline? Nick Dell’Osso: We had 46% gas in the fourth quarter in the Mississippi Lime, so then 45% oil and the rest being NGLs. And again, we don’t anticipate any trend difference there over time. Brian Singer – Goldman Sachs: And then just strategically, to the degree that gas prices surprise to the down side, can we expect that Chesapeake would sell more assets than it would be presently expected, or reduce capital? Or borrow against the revolver? Nick Dell’Osso: I’m sorry, could you repeat the question? Brian Singer – Goldman Sachs: Yeah, if gas prices surprise to the downside, should we expect that Chesapeake would reduce capex from current guidance, sell more assets than expected, or just utilize the revolver and increase debt? Nick Dell’Osso: You know, the first answer there is that 72% of our revenue is hedged for 2013. So short term impacts to commodity prices won’t have the impact that it did have on us last year. The second answer is that, again, we’re very focused on deleveraging over time. So I’ll just probably leave it at that. We have a lot of leverage we can pull to get there, and we’ll continue to be focused on delivering on asset sales, be focused on staying within our budgets and reducing our leverage.

We’ll go next to Charles Meade with Johnson Rice. Charles Meade – Johnson Rice: I recognize that you guys are still in process on a Mississippian sale, but could you give some parameters on the deals that you’re looking for, both in terms of scope, whether it’s over your whole 2 million acres, or timing?

Charles, I just would really like to not take questions on a pending transaction this morning. Charles Meade – Johnson Rice: That’s certainly understandable. The other thing I wanted to ask you guys about, maybe this is better for Steve. I really liked the slides you guys put together on the takeaway in the Marcellus and Utica. I think you mentioned that the Marcellus takeaway is going to be limited through year end ’13, where there’s going to be incremental capacity come along, but do you view this as more of the last significant hump to get over as far as takeaway, or do you view this as the first of many hurdles that you’re going to have, or that the industry’s going to have in the coming years, as far as takeaway?

You know, there’s a number of projects, as you’re well aware. Some of those projects are more focused on getting us premium market access versus just capacity and then some, of course, do provide important capacity relief. Today, there’s planned a total of additional 3 Bcf of capacity additions, as we’ve noted in that slide. And some of them have just come on pretty recently. There will be periods of time where capacity will get ahead of the deliverability of the basin, and there will be periods of time where the industry catches up with it. It’s going to be an evolving push and pull that will continue over time. But I think pretty quickly here, particularly with gas prices where they are, and rig count where it is, you would get to a point where you wouldn’t have long term capacity constraints before too terribly long in the basin.

We’ll go next to Neal Dingmann with SunTrust. Neal Dingmann – SunTrust: Just wondering, on the Utica that you mentioned, looking at that 5-10 Bcf that you gave, could you give a little bit on what type of type curve you’re expecting there? Or I guess what I’m looking at more specifically is what kind of first-year depletion, or if you can give us any depletion levels around those 45 wells that are producing?

We are constrained there, and really haven’t been able to produce these wells as we would like. So that’s why we gave a big range in Bcfe. So I’m afraid it’s just too early to tell. Neal Dingmann – SunTrust: And the 55,000, is that just for later this year, assuming that you have most of this midstream tied in? Can you maybe walk through it a little bit as far as kind of what you’re expecting on the takeaway there, how to see that progress in the Utica?

Yes, to reach that, we need all three of those plants up and running before year end, which they are on target and expect that to happen. Neal Dingmann – SunTrust: And then just lastly, you mentioned about how good your Eagle Ford results certainly have been. Just wondering, is it just the result of trying to contain the cash flow outspend as far as why cut those rigs there? To go from 34 to 17 rigs on such a great area, just want to hear your comment about if that looks like expectation would be to run kind of run around that going forward?

Fortunately, most of that is in efficiency gains. We are still able to produce the same amount of net wells. And it’s also not to outrun our infrastructure. So this is just the right well count to both hold our acreage and be more efficient with our capital.

We’ll go next to Dave Kistler with Simmons & Company. Dave Kistler – Simmons & Company: Just looking at your ’13 capex, can you kind of break out what percent of that is dedicated to maybe four drilling commitments? Or asked differently, what percentage is fixed obligations, [HBP] drilling, etc., and what percentage is flexible? Nick Dell’Osso: You know, we don’t generally provide that breakout. Suffice it to say, we are focused on holding by production our Eagle Ford and other liquids plays that still have some work to do there. Those also happen to be our highest return plays. So that’s really why we don’t focus on looking at it that way. We’re really more focused on what Steve described a few minutes ago, which is allocating our rigs to make sure that we’re focused on returns, both near term and longer term returns. We don’t want to get in front of infrastructure. We want to focus on the efficiencies that we’re creating. And we want to try to drill the best wells. So there are a couple of places where we’re going to go hold some leases, and take care of some commitments, but that’s really not what’s driving our rig allocation this year as much as it is trying to be most effective and efficient at growing our liquids production and focusing on returns. Dave Kistler – Simmons & Company: And then you mentioned in your comments that you achieved about $12 billion in divestitures in ’12. When I’m looking at the cash flow statement, it’s highlighting about $10 billion. Can you walk me through the disconnect, or what’s rolling over into ’13, just based on announcement dates and closure dates, etc., just so we can get a sense of how that feeds into your guidance of $4-7 billion for ’13? Nick Dell’Osso: Just to reconcile the 2012 number, remember that one of the things we included in that ’12 is the sale of the preferred interest in our Cleveland Tonkawa asset, which shows up in the financing section. So there’s no rollover into ’13 of that ’12, and the ’13 number is focused on new projects that we’ll be talking to you guys about. Dave Kistler – Simmons & Company: And then one last one. If you could kind of give us an update in terms of maybe drilled uncompleted wells or drilled and completed but not tied in in sort of the Marcellus and I guess the Rockies as two potential large growth areas for this next year, that would be great.

In the North Marcellus, there’s still a couple hundred wells to be turned on that we want to get in line this year. Nick Dell’Osso: One of the things I would point you to, Dave, is on page 14 of our release we break out our well costs and we had broken out last year the costs on unproved properties, which would be basically dollars that we had spent on wells that were not yet put into the pool, because they were not yet proven. That becomes effectively a balance over time, and so you’ve seen the last two quarters that’s a negative number. So net-net, we are decreasing the number of inventory wells in the company at this point, and we’ve done that in the Marcellus and we’ll continue to do that across the company with a few instances where we’re adding to it into our plays. But net-net, we’re in a decrease mode.

We’ll go next to David Tameron with Wells Fargo. David Tameron – Wells Fargo: In the Marcellus, can you talk a little about the pipeline? Is that an issue with the specs for the BTU content? Or can you talk a little about that bottleneck there? And then when do you guys expect ATEX to come on? Nick Dell’Osso: We can project a certain amount of ethane, and then at some point we do need that pipeline to alleviate our takeaway from the basin, but at this point, that’s really about capacity as much as it is anything. So we do think that ATEX will come on beginning of ’14. Late ’13, beginning of ’14. David Tameron – Wells Fargo: We’ve just heard from other operators and other interested people that ethane’s going to be a big bottleneck getting out of the Marcellus over the next couple of years, even with additional pipeline capacity. What’s your snapshot of the current situation up there? Nick Dell’Osso: We have taken out a pretty good bit of capacity on ATEX, and so we’re feeling good about our ability to move it out of the basin to the Gulf Coast, which should get us to the best market available for ethane in the U.S. We do also have a small amount of [FT] going up to [Sarnia] as well. David Tameron – Wells Fargo: Jumping over to the Utica, the EURs you put in the press release, that 5-10 Bcf, could you maybe just talk about what production mix is assumed in that number, and then how variable it is across the acreage position? Just an update overall on the Utica?

It is pretty early, and a very limited well set, so that’s why we gave such a big range. And it does vary across the play, so that’s all the guidance we can really provide at this time. David Tameron – Wells Fargo: All right. Last question, Nick, you commented on the condensate oversupply. Can you just expand on that a little bit, and what you’re alluding to there? Nick Dell’Osso: Just pointing to the fact that we are always focused on getting premium pricing for our products, and paying attention to what our product mix is, and what the supply demand dynamics are for the subproducts, if you will, in the marketplace. And given the questions that were raised this week by a number of analysts around condensate pricing, we just wanted to comment on it. In particular, in the Eagle Ford, our average gravity in the basin is about 45 degrees, and then I just wanted to give the color that condensate is less than 10% of our total mix of oil across the company. So we just thought that was helpful color to provide.

We’ll go next to Biju Perincheril with Jefferies. Biju Perincheril – Jefferies: First, on your production guidance, are you assuming less asset sales in the new 2013 guidance? Or is it the same amount of asset sales as previously assumed? Nick Dell’Osso: It’s approximately the same. The mix has changed a little bit here and there, but we always attempt to show our expectations of asset sales into our guidance unless we tell you otherwise. And we had that the last time, and we have it again this time. So we show you, at the top of that page, the expected production impact of what we’ve assumed to be sold in 2013. Biju Perincheril – Jefferies: So the difference in the footnote, then, I assume is the asset sales estimated completed, especially the Permian? Nick Dell’Osso: Right. The last time we gave an outlook, it would have been inclusive of production for the end of 2012 as well as ’13. Biju Perincheril – Jefferies: And then your gas production declined in the fourth quarter. Was there anything special in those numbers, is that an organic decline rate that we saw in the fourth quarter? Nick Dell’Osso: Well, we did have our Permian sale in the fourth quarter, which was significant. There was a lot of gas produced out of the Permian. And we did manage some [FT] commitments in the Barnett as well, which had a minor impact, but was something that was not organic.

We’ll go next to Scott Hanold with RBC. Scott Hanold – RBC Capital Markets: A little bit on Utica again, and I’ll try to skin the cat a different way. When you step back and look at the Utica today versus what you all thought a couple of years back, it seems like it’s a little bit more gassy, and the core is a little bit smaller. Is that a fair statement?

Well, the gassy part may not be bad. Those are higher IPs and can be higher rates of return. And we’re very pleased with the results that we’re getting. So nothing bad to say, and no shrink in the core. It’s just early, and the results are so variable on the product mix, that it’s difficult to give. Nick Dell’Osso: We did give a couple of specific well results in our release today, so you guys can look at that, and probably draw some conclusions from there. There’s a lot to learn about this basin still. Our number of penetrations relative to the number of wells that we’d ultimately drill is very small. And we don’t yet have the processing capacity to flow things at full rate yet, and there’s just a lot to learn. So that’s the reason we’re being a little bit less informative here, just because we feel like we need to learn more before we can say more. But so far, we’re very, very pleased with the play. Scott Hanold – RBC Capital Markets: What if this does turn out to be a little bit gassier? Do you see the economics of Utica being a little bit better than the Marcellus? And would there be a lot of excess gas coming out of the basin? And you did previously, I think, Nick, in your comments, indicate that you all are pretty bullish on gas prices. And certainly when you step back and look at you guys locking in a lot of your hedging and your production in 2013, it kind of sends a different message. Can you kind of square the circle around that one? Nick Dell’Osso: Sure, I’d be happy to. When I say we’re bullish on gas prices from here, I’m thinking not just…

We’ll go next to Joe Magner with Macquarie Capital.

Just maybe one more attempt at Mississippi Lime. I realize you don’t want to discuss the details, but there have been some different structures talked about in the past, through this plan to pursue a lump sum JV. And then that changed to maybe breaking it down into smaller packages. Any direction on where you’re headed with the just kind of overall concept there? Nick Dell’Osso: I think I’m just going to say again, we don’t really want to discuss a pending transaction. But we hope to be able to discuss it in great detail with you guys soon.

Okay. And then in terms of your overall position there, can you provide any breakdown between Kansas and Oklahoma? On the acreage side as well as on the number of wells that have been drilled and the production split between the two states? Nick Dell’Osso: There is a map in our slide deck, so you can see the breakout, at least visually, by acreage in the play. But you can also see that all of our rigs are in Oklahoma at the moment, as we continue to learn more about the Kansas part. Page 28 of our investor deck.

And then any anticipated charges or impacts related to firm midstream transportation and processing agreements that are in place given the sale of your midstream interests? Nick Dell’Osso: We reiterated our guidance around gas differentials, and that takes into account the revised structure of those contracts. Those contracts are basically similar to what we did internally. It’s basically a cost of service approach. So we can work with [Access] to direct and tell them the capacity we need, and there’s a cost of capital approach to setting the fees over time. So we were doing that internally, and that’s really how our contract has been codified with them to do it externally. So based on those fees, we reiterated our guidance. We had planned for that when we set this guidance up initially, and it’s still the same.

Any insight into the search process? Level of interest? Or any expectations on timing of when a candidate might be identified? Nick Dell’Osso: No, I think I’ll have to let the previous comments by the company and the board stand there for now.

And we’ll go next to Bob Brackett with Bernstein Research.

I had a question on asset sales. What are you assuming for the timing of these dispositions in your production guidance? Nick Dell’Osso: They’re layered in throughout the year, as we expect the sales to occur. So they’re all timed as we think the sales will occur, and the impacts will hit our financials.

So you’re assuming half of them are done by the middle of the year? Nick Dell’Osso: I really don’t want to get that specific this morning. Again, we’ve lined them out with the processes that we’re running, some of which are underway now, some of which will be underway soon. And that’s just how we have it layered in. And the Mississippi Lime is, of course, the nearest term, and it is forecasted into our outlook to be the nearest-term impact.

And of the $200 million that you’ve either closed or have PSAs for, what are those? Can you give us basins or packages that those might be? Nick Dell’Osso: Mostly acreage. There’s not a lot of production in that. And it’s just packages and non-core acreage.

Any color on which packages? Nick Dell’Osso: There was a little bit of DJ Basin in there, and a little bit of Marcellus and a few other things. It’s a gathering of a few different ones.

And on the working capital, I noticed it ticked up a bit. What’s your long term plan for that working capital going forward? Nick Dell’Osso: Our working capital tick up, a lot of it was driven by the fact that we used a current tax asset attribute to offset some gains from our midstream sale. That was in excess of $600 million in the quarter. One thing I would point you to is that our payables were down pretty materially. Our working capital is a microcosm of our company, as I’ve noted before. As activity levels come down, our payables will come down. As commodity prices go up, our receivables will go up. We do, of course, have partners in a lot of our wells, and so you have offsetting effects of as commodity prices go up, we have greater revenue payable, and as our activity levels come down, we have less receivables from partners on operating capex. But overall, it’s really actually trending in the right direction when you consider the movements for taxes, etc.

And the Utica 5-10 Bcf equivalent, what’s the well cost and lateral link stages on that sort of well?

Well costs have come down significantly this last year. We’re down to low to mid-$7 billion per well. The lateral links are over 5,000. Don’t have that average with me, but they’re long laterals.

We’ll go next to Matt Portillo with Tudor, Pickering, and Holt.

I was curious if you could provide us with your current rig count and specifically how we should think about your rig averages in the PRB, Haynesville, and Barnett for 2013? Nick Dell’Osso: We detail our current rig count on page eight of our slide deck, and so you can see that we have just about 82 operated rigs. That’s adjusted for Permian. So from there, you asked about which basins again?

The PRB, Barnett, and Haynesville. I’m just looking on slide 15. You guys have that as about 16% of your drilling and completion capex, and I think the PRB was accelerating as of Q3. So I’m curious where the rig count is there. And then just curious on your Haynesville and Barnett rig count. I know you guys were at two rigs. Is that going to pick up in the back half of this year?

No, we’ve got both the Barnett and the Haynesville flat at two rigs, and the Powder River is at 10.

And then just a couple of other quick questions from me. In terms of the Eagle Ford, can you give us an update on the uncompleted well count? Nick Dell’Osso: We don’t have that number with us this morning. It’s a very dynamic count, as we are running a number of rigs there, bringing on a lot of infrastructure every day. But we’ll continue to have a decent number of wells in inventory, in the Eagle Ford, making lumpy but good progress all year. There will be times where we bring on a piece of infrastructure that will allow us to connect a bunch of wells at once, and so again, it’s pretty lumpy, but it will be a challenge throughout this year, one which we think we have forecasted appropriately in our plan.

And my final question, just on the spending side, could you give us any color on a specific number for your spending on OFS midstream and other for 2013? Nick Dell’Osso: It is down a good bit from last year. The only growth on oilfield services that we have in this year is a couple of rigs we had ordered early last year that are being delivered. These are really high-value rigs that are going to be used primarily in the east that are very efficient and great assets for us. And we have our last two frack spreads that I think are both already now delivered. So the vast majority of our COS spending is down. It’s significantly lower than last year.

Is there any color on the magnitude of that reduction? Is it 50%? Is it 75%? Is it 25%? Just trying to get an idea of the magnitude. Nick Dell’Osso: More than 50%.

We’ll go next to Michael Hall with Baird. Michael Hall – Robert W. Baird: Just wanted to dive in a little deeper on the Eagle Ford. Just first on the efficiency gain, cycle time improvements you’ve been seeing, just curious how much further you think you can take that. And then what percentage of activity is currently on pads versus [unintelligible] capture in 2013 versus 2012?

In 2013, we are not able to do a lot of pad drilling, because we’re still in HBP mode. That will be completed really in the second half of the year. So that will change throughout the year, so we may be as little as 15% now, to really by the end of this year, once we’re complete, it will basically be at 100%. And so we do anticipate for 2014 to have pretty significant additional improvements in our efficiency. Michael Hall – Robert W. Baird: And then on the proposed acreage sales in the Eagle Ford, were there any lease-hold expiration issues that might be considered in evaluating that deal?

No, the core part of it can all be easily held by production.

We’ll go next to Marshall Carver with Capital One Southcoast.

On the Utica, you talked about the 5-10 Bcf per well. Across what percentage of your million net acres do you think you can get those recoveries? How much has been derisked at this point?

Were you referring to the Total JV box, which is about 450 net? We think there is a lot of gas, but mostly dry in the remainder of it, and so there’s been very few tests in it, but our geologists think there’s a significant amount of gas in place. But would probably be on the high side of that on a Bcf basis.

On the production mix in the Utica, could you at least give us the production mix for the year-end target that you mentioned? And is that a gross or a net number that you mentioned?

That is a net number. But it’s a function of wells that we get hooked up on, because there’s such a variable on the mix. But you can look at the wells in our press release and get kind of an idea from those IPs what we’re seeing. Nick Dell’Osso: We are attempting to drill as close to infrastructure through the year as we can, and so I’d like to think that the wells that we showed you there are going to be representative of at least a good bit of the wells we drill this year. They won’t be all like that, but there’ll be a lot.

And do you have the expected number of wells to be put on production over the year? Nick Dell’Osso: Don’t have that with us this morning.

We’ll go next to Joe Allman - JPMorgan.

A question on the funding gap. So if you just look at your total spending, not just the items you give guidance for, but total spending, and you compare that to your expected cash flow, what’s your estimate of the funding gap for 2013? Nick Dell’Osso: About $4 billion.

So then, on the low end of what you’re going to sell, you’ll hit your capex, and on the high end, you’ll hit your capex plus you would pay down debt? Nick Dell’Osso: That’s correct.

And is it still the company’s goal to get long term debt down to $9.5 billion? Nick Dell’Osso: Yeah, I think we’re absolutely focused on getting the company deleveraged financially, and we’re very intent on getting to investment grade metrics, getting to a much stronger balance sheet. We picked $9.5 billion a couple of years ago. That’s still a pretty good number when you look at it from an investment grade metrics standpoint. But we’re two years more now from when we set that goal and we’ll always probably look at it on a pretty fluid basis. It could ultimately go lower than that, could be a bit different. But in general, significant deleveraging is absolutely the plan and won’t change.

And the two big assets that you’ve got out there, that you’ve identified, are the Mississippian, which you’re close to, it sounds like, and then the Eagle Ford Shale North. Will those two get you pretty darn close to the $4 billion? Nick Dell’Osso: I’m going to let those deals speak for themselves as they happen, but we have a number of things that we’ll do this year.

Is it your goal, even though you haven’t disclosed it, to sell other significant assets of the size of, say, the Mississippian or Eagle Ford Shale North, that you just simply haven’t disclosed, to enable you to cover your capex plus pay down a significant portion of debt? Nick Dell’Osso: I think it’s fair to say that some of the things we plan to sell are bigger than others, and there’s, again, a number of projects that will get us to that ultimate number.

And is the goal to sell as much non-cash flow generating stuff? Can you get there? Or do you need to really get into some cash flow generating assets to raise the money you want to raise? Nick Dell’Osso: It’s a balance, but of course from a strategic perspective, you always like the idea of selling assets that are not producing cash flow today, and are going to be more valuable to someone else than they are to us, which by definition would mean that they have less cash associated with them.

And what’s the status of the Eagle Ford Shale North sale? Nick Dell’Osso: We’ll be speaking to you guys about that when the time comes, and just don’t really want to discuss pending transactions today.

When I look at your 2013 product guidance, in the note that you have underneath, toward the top of the guidance, now you’re including about 35 Bcfe of asset sales in your current guidance. Previous it was at 140 Bcfe. You kept your guidance the same. So does that mean that the non for sale production is actually lower than what you previously thought? And if so, why would that be?

The prior guidance really reflected the asset sales that we were expecting to complete in the last half of 2012, and reflected the production that those assets would have in 2013. Specifically, the Permian Basin sale. Our current guidance really just reflects the incremental transactions that we have for 2013.

I’m not sure if I fully understand. Is there kind of a reduction in your non for sale assets?

There’s no change. It’s just reflecting that we’ve already closed certain transactions that were part of the production associated with our guidance. There’s no change.

Okay. So I guess you’re referring to the Permian for the most part?

Yes.

So in your prior guidance, the fact that the Permian was going to be gone was already in your prior guidance, right? Schedule B?

That’s correct.

So that difference between the 140 Bcfe and 35, you’re saying that’s Permian?