Hello. My name is Joan, and I will be you conference operator. At this time, I would like to welcome everyone to the SM Energy Third Quarter Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator instructions) Thank you. I would now turn the call over to David Copeland. You may begin your conference.

Thank you, Joan. Good morning all of you joining us the phone and online for SM Energy Company’s third quarter 2011 Earnings Conference Call and Operations Update. Before we start, I’d like to advise you that we will be making forward-looking statements during this call about our plans, expectations and assumptions regarding our future performance. These statements involve risk, which may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements. For discussion of these risks, you should refer to the cautionary information about forward-looking statements in our press release from yesterday afternoon, the presentation posted to our website for this call and the risk factor section in our Form 10-K and Form 10-Q that will be filed later today. We will also discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliations of these measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release from yesterday. Additionally, we may use the terms probable, possible, and 3P reserves and estimate ultimate recovery or EUR on this call. You should read the cautionary language that is in our slide presentation for important discussion of these terms and the special risk and other considerations associated with these non-approved reserve metrics. The company officials on the call this morning are, Tony Best, President and Chief Executive Officer, Jay Ottoson, Executive Vice President and Chief Operating Officer, Wade Pursell, Executive Vice President and Chief Financial Officer, Brent Collins, Senior Director of Planning, Investor Relations and myself David Copeland, Senior Vice President and General Counsel. With that I will turn it over to Tony.

Good morning, everyone, and thank you for joining us for SM Energy’s third quarter 2011 earnings and update call. Our comment this morning will reference the slide deck that was posted on our company website last night. I’ll now cover the highlights from the quarter. I’m starting on slide three of the presentation. For the third quarter, we posted a 6% sequential increase and average daily production and achieved a new company quarterly record, by averaging 462 million cubic feet equivalent of production a day. We met or beat all of our guidance metrics for the third quarter, which Wade will provide more detail on in the financial update. Our production growth during the quarter was led by our operated Eagle Ford and Bakken/Three Forks programs, which add quarter-over-quarter increases in production of 32% and 35% respectively. We’re obviously very pleased with these results, especially considering the challenges each of these programs is faced this year with the addition of new infrastructure in Eagle Ford and a severe winter and flooding in North Dakota. Lastly, we recently completed our semi-annual borrowing re-determination process, and our bank group has increased our borrowing base to $1.4 billion from $1.3 billion. It is important to note that our bank group did not consider assets subject to close or pending transactions in this process and that the increase scheme in the face of declining commodity prices. Overall, SM Energy experienced another solid quarter. With that, I’ll turn the call over to Wade and Jay for their respective financial and operational reviews. Wade?

Thanks, Tony. I’m going to start on slide five. As Tony mentioned, the company performed very well in the third quarter. We met or beat all of our guidance metrics we provided. Our production was in line with our guidance with 453 to 481, coming in at 462 million per day. Production mix for the quarter was a little gassier than we expected, and Jay is going to elaborate a little more on this later. On the cost side, we met or beat all of our ranges for the third quarter. I might point out the lower production tax rates as a result of certain production tax incentives associated with tight gas activity on our Eagle Ford and Haynesville Shale programs in Texas. Our GAAP net income was $230.1 million or $3.41 per diluted share. Our adjusted net income per share was $42.4 million or $0.63 per diluted share. The large difference between the GAAP and adjusted income is the result of gains that we recognized this quarter related to the sale of the Eagle Ford Shale properties in La Salle County, Texas and a large unrealized derivative gain due to lower commodity prices at the end of the quarter. Speaking of lower commodity prices, lower natural gas prices at September 30th triggered an impairment of crude James Lime gas properties in the amount of $48.5 million. With regard to cash flow, our operating cash flow for the quarter was $185 million. GAAP cash flow from operating activities was about $120 million. Its difference was driven by large decrease in current liabilities between the second and third quarters of 2011, working capital changes primarily. We’ve included reconciliation of both adjusted net income and operating cash flow to the related GAAP measures in the appendix of the operation. So, I’m now…

Thank you, Wade, and good morning, everyone. I’ll start my remarks on slide nine, with the summary of our production for the quarter. As you can see production average is approximately 462 million cubic feet equivalent, up from 437 million in the second quarter, a 6% percent. Although we were above forecast in most operated areas, our operated Eagle Ford assets produced right at our forecast for the quarter, limited by intermittent constraints on our ability to move higher volumes. In our forecast to the volumes we would book from Anadarko’s Eagle Ford during the quarter was a bit too high. As a non-operating partner, we have found it challenging to accurately estimate production volumes for this largely large and rapidly growing program. Oil production grew 6% sequentially to 21,500 barrels per day driven by growth in the Eagle Ford and our Bakken/Three Forks programs. Natural gas increased to 281.2 million cubic feet per day, which is a 7% increase from the prior quarter. Reported NGL volumes in the third quarter, however, were essentially flat to the second quarter on a sequential basis, which is due to corrections made to previously estimated and reported volumes, largely in our non-op assets. Moving on to slide 10, our operated Eagle Ford program reported a production increase of 32% quarter-over-quarter while running an average of 3.5 drilling rigs. A significant amount of this increase in production was from being able to open up chokes on previously restricted wells. We are currently running four drillings in the play and plans to add a fifth rig in the play by year-end. We have another new build rig coming to us early next year, at which time we could increase our rig count to six. But most likely, we will let one of the non-walking rigs…

Thanks, Jay. Looking at slide 15, as Jay mentioned, we've updated our 2011 and 2012 funding slides to show updated projected cash flow numbers. At the last earnings call, we've presented this slide with estimated cash flow projections that assumes the strip price at the end of July. As you know, the strip price today is significantly lower than it was at that time. As you can see, our new expected 2011 cash flow amount is $795 million down from the $860 million at the second quarter call. And our 2012 projection is now between $1.1 billion and $1.2 billion down from $1.2 billion to $1.3 billion. To reiterate, these changes merely reflect the change in commodity strip today versus the end of July for our last call. As you'll notice, our funding gap for the years 2011 and 2012 have increased to $277 million and $325 million respectively compared to about $200 million per year at the second quarter call. You should recall that $277 million gap in 2011 was funded by the $350 million high-yield bond offering earlier this year. The $325 million gap in 2012, even assuming no further divestitures, is very manageable and can certainly be covered within our revolver. As a result, we are reiterating the production guidance that we laid out last quarter. I'm now on slide 16. We expect to produce around 164 BCF equivalent in 2011 and 225 to 232 BCF equivalent in 2012. That represents 50% production growth in 2011 and 35% to 40% production growth in 2012. So with that, I'll turn the call back to Tony for his final remarks.

Thanks, Wade. Before we open the call up for questions, I'd like to touch on a few key takeaways from our presentation this morning. First and foremost, production growth in our operated programs in the Bakken and Eagle Ford has been very strong, up over 30% in each play quarter-over-quarter. I think these growth numbers are not only a testament to the top tier assets that we hold, but also to the solid execution of our plan by our employees turning these assets into growth engines for our company. During the quarter, we completed our semi-annual borrowing base re-determination. Results of the re-determination included an increase to our overall borrowing base despite a reduction in asset base from properties that was excluded from the process due to announced divestitures and a lower commodity price deck. Lastly, it is worth noting that while a decrease commodity strip price has created a larger projected funding gap than we had assumed at the second quarter, we are still projecting a gap that we feel is very manageable as we have a strong balance sheet including a $1 billion revolver with no borrowings as of the end of the third quarter. The depth and strength of our balance sheet will allow us to grow the company at the rate we had previously guided. As we always do, we will keep an eye on commodity prices and completed well cost. And if warranted, we will adjust our program accordingly. As you've heard us say, we are not interested in growth for growth’s sake. At this point in time, however, we are comfortable reiterating the capital and production forecast that we provided in our last call. With that, I'll open up the call for questions.

(Operator instructions) Your first question comes from the line of Welles Fitzpatrick with Johnson Rice. Welles Fitzpatrick – Johnson Rice: Good morning.

Good morning, Welles.

Hey, Welles. Welles Fitzpatrick – Johnson Rice: There's a little bit of acreage bump in the Bakken, is that at least cleaned up?

Yes. Welles, it is. I didn't even notice it's actually on the slide, but yes. It's just some additional acreage we picked up. Welles Fitzpatrick – Johnson Rice: Okay. And is there any way we can get an update on the Permian leasing efforts?

I don't think we have anything that we can say, really, about our Permian leasing efforts. Welles Fitzpatrick – Johnson Rice: Okay. And one more, if I could, the slight bump in Eagle Ford well costs, it sounds like you guys are optimistic going forward. Can you talk a little bit of it? I'm assuming that's on the completion side. Can you get any more granular? Is it propped in? Is it asset?

No, I think we're just seeing some indication that we're not getting demands for cost increases every time we bid a job. I think that we're starting to see some indications that there's a little bit of excess pumping capacity in the Eagle Ford. It's not huge and we're certainly not seeing cost decreases at this point. But I think it's starting to pressure, starting to come off a little bit. We expected that. Obviously, we're hoping for it. We're maybe a little too hopeful. But I'm fairly comfortable that as we go into next year, you're going to see cost flatten. In addition to that, of course, when we've had drilling, we should cut our cost. Our water handling system is going to cut our cost as well. So, I think in general, we're comfortable that if you forecast our cost in the Eagle Ford forward into 2012 that we're going to be relatively flat. Welles Fitzpatrick – Johnson Rice: Perfect. That's all I've got. Thanks so much, guys.

Well, let me make a comment that some of the reason you’re seeing increases on our well cost is because we're pumping more stages on a lot of these frac job as well. I mentioned it in the call, but we're trying to do a number of jobs in which we pump higher stage counts at closer spacing. And that's driving our well costs as well. Welles Fitzpatrick – Johnson Rice: Thank you.

Your next question comes from the line of Brian Lively with Tudor Pickering Holt. Brian Lively – Tudor Pickering Holt: Last quarter you guys gave some proved estimates for the operated Eagle Ford wells, a handful of wells that I think were around the 7 BCFE range. I'm just wondering how those wells are tracking and can you guys have any more updates on overall how the wells are stacking up versus that estimate?

This is Javan. Brian, I actually haven't looked back at those wells in the last few weeks. I don't have any reason to believe that they’re any different than what we gave you. We obviously gave you numbers we thought were fairly conservative to begin with. And what we indicated when we gave those numbers was that we thought those were consistent with a down-spaced case. I would say, in general, as I mentioned in the call, I think the Galvan entry is likely to be not down-spaced as much as potentially some of our tighter oiler areas. So I think those numbers we gave you are good numbers. In fact, there's probably some upside to those base on what I think the ultimate spacing is likely to be. Brian Lively – Tudor Pickering Holt: And, Jay, do you have a sense of when the two PKs would be for the 7 BCF well?

Brian, I don't think we've given those numbers and I'm not sure that I actually have an estimate of what the two PKs is. It is north of those numbers. That's all we can really say. Brian Lively – Tudor Pickering Holt: Okay. And then, looking at the volumes for Q3, can you guys give an update of what the current corporate-wide production rate is and then maybe what your plant exit is for year-end 2011?

Could you repeat that question, Brian? Brian Lively – Tudor Pickering Holt: Yes, Jay. I'm just looking for a current rate on company-wide production and then the exit for this year?

I don't have a current rate. We typically don't guide on those numbers. I know what our numbers were in October or in September and I know what I think they are in October. But I don't even final October numbers yet. Yes. Brian Lively – Tudor Pickering Holt: Okay. And then just last question for me. You talked about intermittent production volumes in Q3. Any way to quantify how much volumes were curtailed or lost in the quarter in Eagle Ford?

I don’t have an exact number. A lot of the curtailment in both Enterprise and Kinder were up and down. We had some compression issues where we were up and down. I think people should understand we contracted our mid-stream business through Regency back at – it was right at the end of the first quarter, beginning of the second quarter. And in that timeframe between then and now, these guys have done an enormous quantity of work in the field. At one point in time, in the third quarter, we had 600 contractors in the field, building our 16-inch pipeline. And as a result of all that construction activity, there are times when you have to shut in wells, you have to shut in production, you have to curtail production. Just last week, we’ve lost rate because we had to pack the line, the 16-inch line all the way for several days when our production was down. So there’s just a lot of startup related stop where you’re up and down. In fact, I think the fact that we made our operated forecast in the middle of all this is actually a testament to our guys in the field doing an exceptionally good job. I recognize that a lot of people, for one reason or another, believe that we’re always going to out-perform our forecast. But I think we hit our forecast in the Eagle Ford this quarter and I’m actually very proud of that. I’m not so proud of the fact that we overestimated some volumes in other areas, but the operated stuff really worked very well. As of this morning, we were making about 136 million a day of gross wet production capacity and we’re still coming back up after packing that line. And we have a number of additional wells to hook up and put into production. So, that 136 million is a gross wet operated number. Kinder Morgan and Copano is flowing and we’re flowing gas to both enterprise and them and although they had a few startup bubbles, in general, it was a fine performance by all of them.

Brian, if you look at the guidance update in the appendix, we’re showing fourth quarter average daily production of 479 to 509. So, if you’re kind of thinking about fourth quarter production on average, it’d be in that range.

Yes, I think he was looking for December instantaneous rate of the end of the year. And I don’t know that number right now. Brian Lively – Tudor Pickering Holt: All right, guys. Thanks.

Thank you, Brian.

Your next question comes from the line of Jeb Bachmann with Howard Weil.

Morning, guys.

Good morning, Jeb. Jeb Bachmann – Howard Weil, Inc: I had a couple of questions. First, Jave, any early comments on the performance of the 7,000-foot laterals, 20-inch frac stage wells in Eagle Ford?

No, I don’t. In general, what we’re seeing as we brought our frac stages closer together as we’re getting better overlap on our micro sides, we haven’t really seen any interference yet. So, we are moving to hire a frac stage counts and we’re going to be experimenting with Bakken style sleeve type jobs in order to be able to get those jobs to pump quicker. So we have some interesting tests that were going on. But I don’t have really any results to share at this point. Maybe by year-end, I might be able to find – maybe by year-end I might be able to say something additional on that.

Okay. And then, we talked about this in the past. I’m just kind of wondering. On the Permian down-spacing, if you guys are ready to talk about results today, are you still kind of monitoring that program?

Well, we drilled six or eight wells. In general, they’re performing up to our forecast. The big issue we have, I think, in the Permian right now is those Wolfberry wells are over $2 million apiece and it cuts down the number of puds you have as a result. So, the wells we drilled are performing fine. We’re just not that excited about going in and drilling a whole bunch of them right now.

Okay. And last one for me, Tony, any update or comments right now on the Haynesville JV? Are you guys are still looking at doing that at this point?

Yes, Jeb. At this point, we’re moving on. Basically, we went out and work that for some period of time to find an appropriate partner to bring in. Before I transferred, there wasn’t any compelling offer. And now we’ve got to the point where we’ve got about seven wells to drill next year, including one sidetrack, and we expect to have that done by September of next year. So, a pretty modest program, one rig and we expect to have that HBP by September of next year.

Any Bossier well?

The importance of that is not only the Haynesville potential but also we retain rights in the Bossier by completing the well.

No, it’s all right. I have my next question, if you guys had any Bossier wells planned within the next year.

We do have a Bossier test that’ll be drilled right around the first of the year. It’s a block that, in fact, if you drill a Bossier test, you can hold all depths. So, we’re going to take a well that we had completed vertically in the Haynesville and we’re going to turn that around and completed it with a lateral in the Bossier. So that’ll be somewhere around mid-first quarter.

Okay, great. Thanks guys.

Thanks, Jeb.

Your next question comes from the Subash Chandra with Jefferies. Subash Chandra – Jefferies & Company, Inc.: Yeah, I was hoping if you could provide some Eagle Ford numbers on the operated stuff, perhaps, the number of wells producing and/or number of wells in backlog.

Well, I’ll start by saying we don’t have a number of wells in backlog because we don’t drill wells and not complete them. We have about 70 wells drilled and I think the number completed is close to that. But that’s not an exact number. We can get you that and Brent can give it you. Subash Chandra – Jefferies & Company, Inc.: And the 70 was a gross or a net?

Well, our net gross is essentially the same. It’s a 100% working (inaudible). Subash Chandra – Jefferies & Company, Inc.: Okay. Well, I’ll just get it from Brent then. In the dry gas acreage, do you have some drills to hold budget that’s going to kick in anytime in 2012?

We will have to drill a couple of dry gas wells in 2012, but it’s really minimal. They’re very large lease blocks and they’re continuous development clauses. So essentially, we only have to drill one well every 120 days or so and we can generally push those up into the wetted gas portion of that. I would guess we’ll probably drill one or two dry gas wells in – it’s really dry gas well in 2012. Subash Chandra – Jefferies & Company, Inc: Okay.

We’re planning to drill 95 wells next year. Subash Chandra – Jefferies & Company, Inc: All right. And then, finally, you kind of pride this, I guess, in the queue, but hopefully, you have the numbers in front of you, but do you have the production by area breakdown on Mid-Con, ArkLaTex, and so on?

Yes. You’ll have to give us a minute on that to pull it up. Subash Chandra – Jefferies & Company, Inc: Okay, thanks.

You have another question? We’ll come back to that. Subash Chandra – Jefferies & Company, Inc.: Yes, I guess. And this might be more – well, first of all, 136 a day gross wet operated, how does that compare to the 128 net that you reported for the quarter?

Well, the 128 net is about 10%, maybe 11% higher than our gross wet produced. So, take 12 off of that, what do you get, 116?

Yes.

So, we average about 116 for the quarter, somewhere in that range and now we’re at about 136. And I think we’re limited a little bit today, so a significant growth. And what we said and we have said as opposed to – on a total company exit rate, we’ve said repeatedly that we’re going to be at about 170 a day gross wet operated production in December, we believe, on our operated Eagle Ford. So, again add 10% or n15% to that to get to a net MCFD number. Subash Chandra – Jefferies & Company, Inc.: Okay. And finally, again, it might be more of an issue than you want to share, but sort of I’m just taking a mid-point here, but 30 million, 40 million a day sequential growth in Q4. Can you sort of have a sense how that might breakdown Eagle Ford operated, non-operated, the contribution?

Well, in general, I think you can tell from the numbers I just gave you, more than half of that is going to be just operated Eagle Ford growth. The rest of our assets are going to grow some and then also non-ops, I would expect it to grow a lot as well. So, most of the growth is going to be on the Eagle Ford and more than half of that is going to be operated. So, I guess you can kind of say, well, I think you’ll have a little bit of Haynesville growth in the fourth quarter. We completed a couple wells right at the beginning of October. So, I think you’ll see gas growth in the Haynesville that’s not insignificant. Half of it is probably going to be operated Eagle Ford and the rest will be non-op Eagle Ford. Brent has those numbers, I think, for you. Subash Chandra - Jefferies & Company, Inc.: Perfect. Thank you.

Yes. The 462 million a day, that’s put on – 70 is Rocky Mountain, 31 is Permian, 196 is South Texas, Gulf Coast which is the Eagle Ford, 81 is ArkLaTex, 84 is Mid-Continent. Subash Chandra – Jefferies & Company, Inc: Sure. Fantastic. All right. Thanks everybody.

Your next question comes from the line of Mike Scialla with Stifel Nicolaus. Mike Scialla – Stifel Nicolaus & Company: Good morning, guys. I’ll confess. I was one of those guys that I thought you’d always beat the high-end of your guidance. But I wanted to see – you’d mentioned, Jay, that the non-op production of the Eagle Ford was below your forecast. Can you quantify how much that was off?

I’m not sure I know the exact number. It was like 0.7 Bs.

From our forecast, on our internal forecast, it was about 3.5 to 4 Bs light.

Yes, the 0.7 which is NGLs, right? Mike Scialla – Stifel Nicolaus & Company: Okay.

We were just overly optimistic about their ramp and part of that was that we frankly overestimated the second quarter sum, so we got on the wrong – we’re on the wrong trend line, okay? And we had to go back and correct the volumes that we booked in the second quarter, which obviously, made it look even worse.

That was the 0.7 you’re talking about.

That was the 0.7 I was talking about. So, again, it’s not the performance of the asset. They’re doing a lot of really good things. They’re completing a lot of wells. The way they’re going about this is they’re kind of mowing the grass with drilling all these wells. And as a result, they have a lot of well shut in when they’re fracking offset wells. And we didn’t account for that correctly in our forecast. And then we’ve had a lot of trouble on the NGL side, making forecast of their NGL numbers for one reason or another. So, we just blew the forecast on that and hopefully, we got our fourth quarter forecast in line, and we won’t do that again. Mike Scialla – Stifel Nicolaus & Company: Got it. Okay. And on the spacing test that you’re doing on the Eagle Ford, is the 625-foot spacing something that you’re thinking might work now in the wetter portions of Galvan? Or is that the tighter spacing that you’re thinking about for the oiler parts of the plain?

No. It’s still a little early, but I’ll just say it because I’m sensitive about all the folks out there who are trying to understand this. I don’t think you should assume 625s at Galvan. I think it’s probably going to be more like 835-foot type spacing. I think it will get to those lower spacing numbers in the tighter and wetter portions of the reservoir, maybe even lower. But I think in the very best parts of the reservoir, we have more porosity and wells drain larger radiuses. I think something like an 830-type foot spacing is probably a more reasonable assumption. And if I was building a model, that’s what I’d use. I know there’s other people out there talking about tighter spacing, but as an industry we have a tendency to overcapitalize our successes. And we’re not going to do that. Mike Scialla – Stifel Nicolaus & Company: That helps. I appreciate that. And any detail at all you can provide on the Mitsui deal? You mentioned you needed to consent, or the consent that you recently got. Is that from partners? Or can add any color behind that?

Yes, at this point, we basically said what we intend to say as far as the current status. Obviously, that’s work in progress. So it’s best if we don’t provide any more details at this time other than to say we fully expect that to close by year-end and we’re working it hard with our soon-to-be-partner Mitsui. Mike Scialla – Stifel Nicolaus & Company: Okay. And last one for me on your Bakken well cost, what you said continued to creep up a little bit in the 8.5 million to 9 million range now in the Raven area. Can you talk about your latest completion design there, what the 8.5 to 9 translates to? Sort of like the number of stages and…

Well, we’re past 20 on mechanical sleeves now and we’re pumping very large volumes of fluid. You remember the Raven area is pretty deep, so it’s probably the most expensive area, one of the most expensive areas in the Bakken to drill and complete. But I will say the wells look great. I mean, there have been some really good results. I don’t have a bunch of them to show you today, but there’s some really good recent well results in there. Pressure matters and certainly those wells are out-performing our forecast. But they’re still economic. I get concerned about the Bakken because of just the sensitivity of it to price. But right now, these wells are working and we just are hoping that these costs flatten out a little bit for us. Some of the cost increase we have seen is due to us pumping more stages and pumping more fluid, and that’s built into those cost increases. Mike Scialla – Stifel Nicolaus & Company: You’re still using sleeves and sand there?

Yes, we are, but we’ve gone to higher stage now and typically as everybody is moving to a higher sleeve number, higher completion stages even in the sleeves, we’re moving in that direction as well. But we do say probably a $1 million a well by pumping with sleeves. And we still believe that’s the right answer. Mike Scialla – Stifel Nicolaus & Company: So what do you think the threshold prices for an oil price before you think about slowing down there?

Well, again, it all depends on cost. It’s very difficult to give numbers like that. If they went to 70 bucks and cost stays where it is, some of the stuff gets really tight. But I don’t think that happens. If it goes to 70 and stays there, I think costs come down substantially. So it’s a little bit hard to figure.

But right now, we’re bullets on the play and we’re going to be adding rig.

Right. We just committed to a fourth rig there starting in April, a new bill that’s got a two-year contract. So we’re bullish on it and we think it’s great. We have some great asset there. And we’d like to go a little bit faster and we’re going to be picking it up a little bit in 2012. Mike Scialla – Stifel Nicolaus & Company: Pretty good. Thank you.

Thanks.

Your next question comes from the line of Nick Pope with Dahlman Rose. Nick Pope – Dahlman Rose: Hey, good morning, guys.

Hey, Nick.

Good morning, Nick. Nick Pope – Dahlman Rose: A quick question on fourth-quarter guidance. In terms of the non-operated Eagle Ford, is there an expectation of a full quarter of the full interest in the non-operated? Or is it a year-end thing that we’ll expect any guidance?

That is the way we built it, is we looked at our total capital spend and assumed a full quarter in the non-op. As I said, we’re a little bit behind on our spending other places and we think basically it’s a wash both from a capital and a production standpoint versus the forecast that we gave at the second quarter. Nick Pope – Dahlman Rose: Okay, that’s helpful. And then just again in the non-op, I guess when you look at kind of the NGL volumes the total Anardako production it’s providing, it seems like there’s a decent amount of variability in the kind of the percentage of NGL on the total. And is that something to do with the contracts and processing during the quarter? Or is it because of the fluctuations in the wells and completions during the quarter?

There have been some changes in some of the processing to my understanding. However, most of the variation you see between first, second and third quarter is due to just poor estimating on our part during the second quarter. We overestimated their NGL and their liquid numbers in the second quarter and then had to correct them in the third. Now, I should say, none of these changes are material from an overall company financial standpoint. It’s just that’s how – we just booked a little too much on the second, had to take it out in the third. And you can see that specifically in those bar charts where you look at liquid volumes. The percentage of liquids in the second quarter went way up and now it’s come back down. Part of that is over-exaggerated due to the fact that we’ve made corrections. Part of that was second quarter was just too high. Tony Best I think that’s part of the learning process, Nick, in terms of watching their program and trying to understand the impact on the offsetting wells and their pace. But we’ve made those corrections. I think we’re fine going forward.

And again, we’re talking about 0.7 Bs. That’s not a huge number. But your point is, the one point you made was, and they’re drilling a lot of different kinds of wells across the big area and there is a lot of variability. So it’s a big program, growing really fast, with a lot of variability and they have process and contracts, everything, just like we do. And we don’t get timely data, as timely a data on non-op stuff as we do on operating, and that’s not their fault. That’s just the nature of the Bs. So when something is growing 20%, 30% a quarter and your data is two months behind, it’s pretty easy to not get your estimates right. Now that’s not an excuse, but it is what it is. Nick Pope – Dahlman Rose: That’s helpful. And just one more thing, just production kind of breakout, Mid-Con saw a little bit of a dip, I guess, second quarter to third quarter, kind of more line with where the first quarter was. Maybe I’ll expect that Mid-Con is something that you are going to be able to really grow at this point with the number of rigs you have? Or you’re expecting that to just kind of be stable to slightly declining at this point?

Well, if you think about Mid-Con, there’s Woodford which we haven’t been drilling in since year-end last year and the Granite Wash. At the first part of the third quarter we only had one rig in the Wash and we pick up another and really even two rigs in the Granite Wash we only drilled about 12 wells a year, I think. If we want to keep that asset flat, given the underlying decline of our vertical Granite Wash wells are deeper sipped [ph] in the middle of Oklahoma (inaudible) and the Woodford decline, if we’re going to offset all that, we need a higher capital expend in the Mid-Con. We are going to be stepping up some of our Granite Wash program next year, hopefully to a three-rig program. But in general we cannot drill every single region given our current capital expend plan. So I think what you’ll see is that the Mid-Con is going to be essential flat for most of 2012 even though we put a three-rig program in there. And once we get down drilling the Haynesville, that stuff will start the planning as well. So most of the drills going forward is going to be in the Eagle Ford and the Bakken. And then we certainly hope to see some drills in the Permian and Niobrara assets next year as we start to see more money in those oilier areas. Mid-Con is going to be flat or slightly down I think. Nick Pope – Dahlman Rose: Okay. That’s very helpful guys. Thanks for the time.

Thanks Nick.

Your next question comes from the line of Jeff Robertson with Barclays. Jeff Robertson – Barclays: I apologize if I missed this earlier but can you talk it all about the impact of down-spacing on how you all will be booking reserves in the Eagle Ford over the next couple of years and when that might start to show up in year-end bookings?

Well, there’s a number of factors when you started looking at booking puds. I’m not sure down-spacing is necessarily as big a driver as the five-year rule and the rate at which we convert pads will be for us. You really have to look at development at this stage and we’re converting pads at a very high rate. In fact, almost none. So you need to look at what your pad-conversion rate is, your development plan and the five-year rule and ask yourself how many pads do I really be able to drill in a five-year period. I’m not really that the spacing matters that much with respect to that development plan in pad-conversion rates. We’re not going to book a whole bunch of pads and let them sit and have them roll a map at then of five years because we didn’t drill them. So I don’t know that spacing necessarily, I have to think through it a little more about it, but I don’t think the spacing necessarily drives your pad bookings as much as your pad-conversion rate at whatever spacing it is, if you understand what I mean. Jeff Robertson – Barclays: Yes, I do. Do you have a feel for any kind of depth when you book spacing or down-spaced wells yet? In terms of what you booked at down-spaced well at some percentage as well at some percentage of an existing well?

That, we don’t know yet. I think that’s part of what we need to figure out in our spacing test is what would that – it’s essentially an interference number, what would we ascribe to a down-spaced well? Would that interference, at that level of interference, does it make sense to drill the well as opposed to just maintain the current spacing? That’s really what the spacing piles are all about. I would say that we have seen some interference that when we drill the 625s, whether that interference is substantial enough to mean that that incremental capital expend is not worth it or not, I think it’s what we still have to understand. I’ve tried to be conservative and I think appropriately, so especially in the Galvan area on this call and just help people understand that that’s the area you should be most concerned about because it has more porosity and a larger drainage radius. If you’re going to see interference, that’s probably where you’re going to see it. But at this point I think we need to wait until year-end to get a little more data before we get conclusive about what we see there. Jeff Robertson – Barclays: Okay. Thank you very much.

Thanks.

Your next question comes from the line of Ryan Todd with Deutsche Bank. Ryan Todd – Deutsche Bank: Good morning, gentlemen. A couple of quick questions for you. One, what’s the right way to think – I know you have obviously a policy that’s strong, but what’s the right way to think about the potential for divestitures going forward in terms of funding gaps for next year, in 2012?

I would say, Ryan, at this point in time, the major transactions and divestitures are behind us or teed up to close. Having said that, every year we will look at the entire portfolio and identify properties that we think maybe timely to take the market. But right now I would say, we got the major transactions either closing or behind us. Ryan Todd – Deutsche Bank: Great. And then one more. On the realization side on liquids in the Eagle Ford, what are your stand on realization that as you look forward over the next three, six, 12 months these infrastructures improved? And what trend do you expect particularly in crude pricing in the basin?

Well I don’t know that we have a great number for you. I think we said repeatedly that we think people need to be careful about ascribing a large value to the current gap between Gulf Coast and Cushing pricing because we think that’s going to converge over time, which if you believe WTI is going to slow and Gulf comes thwarted, then that would be a decrease in your margins. I think that, but I do think that those numbers are likely to come together over time. Other than that, the Bellevue pricing for NGLs is much better than Conway right now. I think ethane prices are good. I don’t think we see any big changes out there.

Yeah I think our marketing guides tells us that right in South Texas, if you comparing to NYMEX oil, you can take in terms of about $11 and that includes quality, that includes transportation, and that’s improving as Jay just said. Ryan Todd – Deutsche Bank: Okay. So it’s improving relative to WTI but you’d expect the gap to close going forward to some point in…

We have never believed that that big gap between Louisiana pricing and Cushing can be sustainable over time. People will figure out a way to make that go away. So we don’t sit around and thinking that we’re going to give the premium for this oil for the long haul. Ryan Todd – Deutsche Bank: Okay. But if it did stay wider, I mean assuming the gap stayed wider, would you expect to start pricing closer to – I mean and (inaudible) adjusted transport or…

Well, I think, yeah. If it stays wide we would probably get some benefit from that and we just gave you the numbers about where we’re at right now and potentially that could stay there. Again, I’m not suggesting that – I don’t know which way those gaps closed. Does the other move up or does the other move down? But I don’t think it’s reasonable for people to assume that an arbitrage, a potential like and last for year and years and years. Ryan Todd – Deutsche Bank: Right. Okay. All right. I appreciate the help gentlemen.

Thanks. Ryan Todd – Deutsche Bank: Thanks.

Your next question comes from the line of Gil Yang with Bank of America. Gil Yang – Bank of America: Good morning. In answer to your previous question, you talked about the Granite Wash. You’d like to grow but you probably would not really grow. And you talked about growth in Eagle Ford and Bakken. Does that reflect your relative views on what the returns are in the areas? Or are there sort of operational withholding issues that drive those differential growth rates?

Our Granite Wash position is entirely held by production. And so we can do pretty much nothing or anything that we like. In fact the returns on the Granite Wash are very competitive and we’d like to spend more money as we move towards 2013 and we get towards our cash flow, which our goal has been repeatedly, as we said that we wanted to get a double-digit growth within our cash flow in 2013. Certainly as we get to that point, our anticipation is that we will start ramping our Granite Wash program, our Permian and Mississippian programs, other programs, oily program at that point that where we have a little discretion. Right now we have to drill what we pretty much have in the budget and that just means we can’t throw an enormous rig program at the Granite Wash. I would also say the Granite Wash is different and we say this all the time. It’s not one big thing that you can just go drill the sea and wells in, they’re all the same. We’re probably operating in at least six different washes that are stacked on top of each other. Each one of which has individual risks and we need to understand that. So in fact going slowly and playing off other people’s successes and doing some experimentation and experience in ourselves really gets us set-up for a larger rig program and going forward. So I don’t think we’re giving up a lot of value by going on a little slowly. I think we’re actually deep risking the play for ourselves. And it certainly puts us in a position that when we have additional cash flow, we have some place to go with, that’s low-risk and very high returns, which I think is a good start.

Okay. Great. In terms of the Bakken, you’re talked about cost inflation a little bit. Can you maybe comment on – and maybe the answer that what you’re completing and what you’re doing in completions but why the inflation seemingly high in Raven than in Gooseneck?

Well, Gooseneck is much shallower than Raven’s. I’m not going to give the depths exactly right here but it’s significantly shallower play and well cost are much lower, several $2 or $3 million lower. We’re actually pumping a pretty large frack jobs at Gooseneck as well. Not as large probably as Raven’s, but we’ve been stepping up our frack count and volumes in the Gooseneck area up there as we kind of get less worried about water production. But it’s really just the shallow of depths at Gooseneck that allow you to drill at lower cost. Gil Yang – Bank of America: Well I’m not saying why it’s lower in cost, I’m asking if the pick-up in well cost second quarter to third quarter seemingly higher in Raven than in Gooseneck.

Yeah, I think we’ve upped our frack count and fluid volumes in Raven more so than we have in Gooseneck. And that’s the difference in cost increase if you like. There’s also higher pressure so you got higher pumping pressure and the cost of the jobs are higher.

Okay. And proportionally the well cost in Raven is more on the completion side than in Gooseneck?

That’s probably true. Although you have – again, you’re drilling to deeper depths. Drilling is relatively inexpensive part of these wells anymore. The completion is the big ticket. So when your completion cost go up that obviously drives the numbers more.

And then how much of your program, of the inflation that you’re seeing, do you think is because of relative lack of skill in the play? Do you think you need to be bigger to get more cost efficiencies or to be more immunized against the inflation? Or are you large enough to see those efficiencies?

You know I really don’t believe that – I think that operations are running with about three-rig program. We have fracks lined up to all that. We have a frack contractor console our jobs for us, very efficient operation. I really don’t think that doubling that would change our well cost substantially. I think there is a number out there that I think you need to get to. I think if you’re running one rig and you only have a fracture every couple of months, I think that’s one thing. We have a pretty consistent program, at the size we’re at. I don’t think there’s huge cost aim associated with scale beyond what we are right now. I maybe wrong a little bit on that but I don’t think you’d see big cost increases or decrease if we were bigger. Gil Yang – Bank of America: Okay. Fine. Thanks a lot.

Thank you.

I’ll comment. We’re drilling a lot of non-ops up there who are a lot bigger than us and their cost are higher than ours. So I don’t see us drilling more expensive wells than our peers. Gil Yang – Bank of America: Okay. Great. Thanks.

And our final question will come from the line of Andrew Coleman with Raymond James. Andrew Coleman – Raymond James: Good morning, everybody.

Good morning. Andrew Coleman – Raymond James: Got a question for you, just on the kind of what are the different well sizes or the acreage well size or the acreage spacings in Galvan Ranch – so I guess 150 acres of 120 acres, roughly. What do you risk at acreage at kind of for your forecast?

Are you asking how much of the acreage do we think we’ll drill out in Galvan? Is that what you’re asking? Andrew Coleman – Raymond James: Yeah. Yes.

I think a 100% of the acreage in Galvan will drill out. Now the Southern end of it is dry gas and they won’t drill out today. But I think in terms of productivity of the acreage I think it’s all going to drill out. Andrew Coleman – Raymond James: Okay. And across the rest of the play, did you get also similarly high kind of chance of success that you’ll drill it out?

Well I think as you get up into the Northwest you have to start to maybe think, well some of all that won’t. It just depends. We haven’t drilled a lot of wells around the very far west end yet. And I’m not sure I would use 100%. I mean that’s the number for all that. But I think a lot a lot of it is going to drill out. And we’ve said that repeatedly. We think we haven’t drilled a dry hole in the play yet. We drilled some wells we weren’t 100% proud of but I think over time a lot these acres are just going to drill out.

Okay. And then just kind of back to the reserves question that I think was asked earlier, do you think or have you given much thought to what the numbers might look like? I mean should you kind of think about F&D cost planning this year or kind of being on pat what they were last year?

We don’t really guide on F&D. F&D is almost completely a function of puds you book and I just don’t know that yet. And that’s going to just depend on so many things that I don’t we’ll try to guess on that.

Okay. All right.

And we will be taking off our reserve process here shortly. So I mean we differently worked that through December and have the numbers ready for public consumption probably next year. Andrew Coleman – Raymond James: Okay. That sounds fine and I’ll probably use the rough assumption of kind of similar for last year and we’ll get and account the wells at a later date than probably closer what you guys did. And then I guess as look as you’re growing up there in the Bakken, other operators have talked about some of the multiple zones of the Three Forks. Do you have any plans at this point to test those and do you have those on your acreage?

I haven’t had a conversation with our folks recently about multiple Three Forks zones. I think it’s pretty well known that we’re drilling or about to drill Three Forks well down at Stark County. We’ve got permits out there for that. But in terms of multiple zones and like the Raven area, I haven’t had a discussion with the folks about that.

Okay.

I want to go back on the reserves question, just to make sure it’s clear. The reason the banks raised our borrowing base after mid-year at a point with lower pricing than we had before was because our reserves are going up. Okay? I don’t want people to think that we don’t know what our reserves are. But we just don’t guide on that because there’s just too much pud risk in doing that at this point of the year. Andrew Coleman – Raymond James: Right. And typically in the revolver’s what you’re – you’re only or your cap debt is somewhere like 10% of puds that can be used for the revolver’s or essentially PDP kind of case for RBLs?

There’s no cap but as is the case with everyone’s borrowing base, the puds are not given that much value at all in determining the borrowing base. Andrew Coleman – Raymond James: Okay. Thank you very much.

Thank you.

Okay. I’ll now turn the call back over to our speakers. Do you have any closing remarks?

Yes. This is Tony. First of all, thank you all for joining the SM Energy Call this morning. We do appreciate your appreciate your interest in our company. We’re excited about where we are and the plans that we’ve set about that we have in front of us. And we look forward to our next update with you in February. Thank you for calling in.

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