Good morning. My name is Tina, and I will be your conference operator today. At this time, I would like to welcome everyone to the SM Energy second quarter earnings conference call. [Operator Instructions] Mr. David Copeland, you may begin your conference.

Thank you, Tina. Good morning to all of you joining us by phone and online for SM Energy Company's Second Quarter 2012 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 risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements. For a 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 on our website for this call and the Risk Factors section in our Form 10-K filed earlier this year and our Form 10-Q that will be filed later today. We'll also discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliation of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described on our earnings press release from yesterday. Additionally, we may use the terms probable, possible and 3P reserves and estimated ultimate recovery or EUR on this call. You should read the Cautionary Language slide page in our slide presentation for an important discussion of these terms and the special risks and other considerations associated with these non-proved reserve metrics. 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 Executive (sic) [Financial] Officer; Brent Collins, Senior Director of Planning and Investor Relations; and myself, the company's Senior Vice President and General Counsel. With that, I'll turn the call over to Tony.

Good morning, everyone, and thank you for joining us this morning for our second quarter 2012 earnings call. I'll make a few introductory remarks, and then Wade and Jay will provide their respective financial and operational reviews. We'll be referring to slides this morning from the presentation that was posted on our website last evening. And my comments will begin with Slide 3. The second quarter of 2012 continued on pace with our business plans for the year, although we saw adverse financial impacts from lower natural gas pricing and production curtailments in our operated Eagle Ford Shale Program due to equipment delays in our third-party gathering system buildout. As a result of this constraint, we will defer several Eagle Ford well completion in the 2013 and redirect the associated capital into oil-focused projects in the Permian. Jay will talk more about our Permian progress in a few minutes, but as a preface, let me say that I'm very pleased with our progress in our Mississippian Limestone play as well as our acreage build in this oily province. In regard to our balance sheet, it was also an important quarter for SM with the redemption of our convertible bonds and the issuance of $400 million in new high-yield bonds at an attractive 6.5% coupon. I'll now turn the second quarter update over to Wade.

Thank you, Tony, and good morning. I'll begin with a brief recap of how the company performed compared to our guidance for the quarter starting on Slide 5. Production came in at 50.6 Bcf equivalent or 556 million per day, which was towards the low end of the range that we provided for the quarter. Jay will discuss production in more detail in his review. Costs for the quarter were generally in line or better than what we have guided for the quarter. Transportation came in meaningfully below our guidance. This is primarily a function of lower-than-expected Eagle Ford volumes in the quarter. Production taxes also came in below our guidance as a result of tax incentives that we recognized in the quarter related to drilling in the state of Oklahoma. On LOE, absolute dollars came in essentially in line with what we expected for the quarter, however, lower-than-anticipated production volumes pushed LOE per Mcfe slightly above our guidance range. All the other costs that we guide on came in within actually at the low end of our guidance ranges. We had a couple of unusual items this quarter. First, we recorded $38 million of impairment on proved properties related to our Haynesville shale asset. This impairment was driven by weak natural gas prices. We also recorded a loss on divestiture activity of $24 million in the second quarter. During the quarter, we ended the marketing process for package of DJ Basin assets, and we didn't receive offers on what we thought was sufficient value for the assets. When these properties were reclassified from assets held for sale to held and used, we were required to recognize a noncash write-down of about $28 million to state the assets at market value for accounting purposes. Lastly, we had a roughly $11…

Thank you, Wade. Good morning, everybody. I'll begin my remarks on Slide 9. Production for the second quarter came in at 50.6 Bcfe, which is essentially flat with the first quarter on a reported basis. Production on retained properties did grow slightly sequentially. Our liquids production percentage for the quarter was a little higher than in the first quarter, but still rounded to the same 44% liquids as we reported in the first quarter. In general, production in our dry gas producing areas is declining, and we were unable to grow our overall rate within the quarter due to the timing of well completions and infrastructure-related issues, which I will discuss. I'm now on Slide 10. Production in the operated Eagle Ford grew 16% from the first quarter to the second quarter to a record quarterly average of 207 million cubic feet equivalent per day. We had actually expected to grow more in the operated Eagle Ford, but our production for the quarter was impacted in April by the downstream pipeline curtailments that we mentioned at our last call and further impacted by midstream facility issues during the quarter. As others have disclosed recently, equipment shortages and fabrication delays are a real problem in South Texas right now. In our particular case, we have seen several months of slipping schedules for delivery of tanks and vessels required for assembly of new tank batteries and other required facilities. Limited midstream capacity is creating high back pressures and reducing rates on our existing wells and sharply limits the amount of actual incremental field production we can generate from new completions. We're working hard with our midstream provider to resolve these issues, and we are making good progress. However, in the meantime, we have delayed some completions until we can realize more economic…

Thanks, Jay. Our company continues to deliver strong performance in 2012 in the midst of a very volatile market and challenging construction issues in the country's most active basin. We remain focused on the successful execution of our significant resource play projects and pursuit of our key business objectives for 2012. Although we have had service constraints in the operated Eagle Ford program, we're still expecting corporate production growth to be approximately 25% for the year. In our Permian Basin region, we are pleased with the recent successes that have led the company to accelerate activity in the region. Lastly, we have maintained the strength of our balance sheet and have ample liquidity to fund our ongoing program. I would now like to turn the call over for your questions.

[Operator Instructions] Your first question comes from Brian Lively, Tudor, Pickering, Holt. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Jay, on the non-op Eagle Ford volumes, do you have a sense of what the -- or a best estimate of what the second quarter volumes were actually were as opposed to the adjusted volumes for the prior quarters?

I can tell you what the adjustment was. The true-up to the first quarter, Brian, was about 1.4 thousand BOE (sic) [1.4 MBOE], so you could -- that should directionally be able to help you. And as Jay said, that number is at 1.5% of our total production, but it does make the chart look a little confusing. So if you just add the 1.4 back and take it out of the first quarter, you get a smoother line. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Right. Right. That's what I was looking for. And then just more bigger picture on the operated side. Just trying to get a sense of when you guys think that you'll have some of these surface -- or most of these surface issues behind you? And specifically, what are you guys forecasting as you get into later this year and into 2013? Are we -- should we expect to see sort of a big uplift as you will be able to start bringing on these pads that you've completed but unable to maximize at this point?

Well, Brian, we haven't guided -- this is Javan. We haven't guided '13 yet partly because we want to understand how all this is going to ripple into '13. In general, I think it's probably accurate to say we're just a couple of months behind where we expected be in terms of our ramp. '13 gets a little complicated because, as you may remember, we were expecting to kind of run into our firm pipeline capacity in the first half there. We kind of have a flat spot in our firm -- in our pipeline offtake capacity in the first half of '13. So it's kind of a question of when we hit that in the early part of '13. So we need to do some more work on our forecasting as we see some of these facilities showing up to see when we think that'll be before we'll have a really good sense of '13. But I think it's fair to say right now, we're about 2 months behind where we expected to be in our ramp. And what that does then is it pushes that rate we had expected to add. As we move forward, the fourth quarter was going to be a very big quarter. So you basically shift that out a couple of months and that's where the impact in production really comes from. We made good progress in the last month. We have a number of facilities that are going to be installed in August. And then we have a number that are coming right at the end or right at the beginning of the fourth quarter, and we really need to see how that goes. So far, most of the facilities have been delayed by 1 month or 2 versus what we expected. And I -- but we have tried to build a forecast here that we think we can make based on the -- based on assuming some delays, and that's how we laid out the schedule. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I know it's early on 2013, so I'm not going to push on that, but can you maybe just give a sense of, if things play out as you see them now, where do you think your exit rate would be for the Eagle Ford for 2012?

We typically -- we haven't guided that number, and I'd rather not give it because again it's a moving number. It depends on our facilities in the fourth quarter. Now, if you look at our firm capacity, we were originally thinking we would be there up against it in the fourth quarter. I think now that's going to happen sometime probably in the first. But if you look to that firm capacity number on our pipeline numbers, that's probably not far from where I think I'll be -- we'll be maybe a quarter later than we thought. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. That's helpful. Then, just lastly for me, on the Permian, it seems like that the Mississippian results are sort of a bright spot here, especially considering where you think that costs are going. And so my question is, just given all the Eagle Ford surface issues that you guys are facing, it sounds like this asset is going to start ramping up faster in terms of being kind of the next big area that you allocate capital. Is that a fair statement? And then, what should we expect to see as we go into late 2012, 2013 in terms of adding rigs to this area?

Well, we're excited about several different areas in the Permian. And I mentioned the Leonard Shale earlier. We have some activity there as well. I think there's some really exciting things coming forward for us in the Permian with the work we've done. It's taken us quite some time to get to this point. But we are going to be accelerating. We've added another rig here. I think if our results continue to prove up, we could potentially add another rig in 2013, and then we've got other exploratory activities going on as well. So I think we have some exciting stuff coming down the road. I'm really very proud of the guys in the Permian. We've stuck to this limestone play for quite some time to try to understand it, figure it out, and our results are starting to really show. And certainly we -- on a lot of that stuff in the Permian, now you're into 3-year term leases, and we are going to have to accelerate activity to hold all the acreage. So I think you can expect that over the next year or so, we'll be -- as soon as -- as long our results hold up, we will be accelerating some of this activity, yes. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And if you just -- just off on that one -- looking at the rates on these wells, the higher oil cut in them and then the cost side. Where do you think that -- or where do you expect the returns to stack up on both the Leonard and the lime relative to, say, the average Eagle Ford at this point?

Well, average Eagle Ford is a tough number. I mean, obviously the dry gas portions of the Eagle Ford don't work right now, and the economic line in the Eagle Ford has moved north. Let me take -- divert just for a second to say part of the reason the infrastructure issues are tough is because we were focusing our activity more and more to the north, which wasn't our original plan. So some of our infrastructure issues are created by our own drilling schedule changes. But these wells in the Permian meet our hurdles. I think there's some opportunity to drill longer laterals. There are still some significant frac benefits. I think we can drive our costs here. The early wells had a lot of science in them. We're still learning a lot. The first few wells we drilled at -- in the Tredway prospect area probably had too small a rig on the well. We've now got a bigger rig in the play with a top drive on it, so we can drive cost there, saving a lot of money on directional. There's a lot of things we can do, I think, to improve these economics. And they meet our hurdles and they're very competitive right now. So we're excited about it. I don't want to get too nuts. I mean, we don't have that many wells drilled yet, but I think it's an exciting thing, and certainly we're getting to a material acreage position in these plays.

Your next question comes from Subash Chandra with Jefferies. Subash Chandra - Jefferies & Company, Inc., Research Division: A couple of ratio questions here. What do you think about the gas ratio to year-end? And if you sort of can put your 2013 hat on, and again without being specific, apologize for asking 2013 questions, but do you think you can make a negligible -- a meaningful change to the oil ratio next year?

Well, Subash, we guided for out to '14 already, I think, on our -- what we thought our oil rig mix would be. We did that in the last call. I don't think that we would say anything has materially changed. I think by the end of this year, we'll be at something like 55%. What we said, I think, is we were going to be at 55% gas by year-end. And I think in '14, we said we'd be roughly 50-50, isn't that right? And I don't think we know anything right now that would cause us to change that guidance. Clearly, we're going to be get oilier. It's just that it may go -- we -- that's the pace that we think we're on based on our long-range plan. Honestly, if oil prices stay where they are and gas prices stay where they are, we may get there a little quicker because I think it would tend to drive your economics that way, but that's currently our plan. Subash Chandra - Jefferies & Company, Inc., Research Division: Okay, understood. Could you remind me again the firm capacity number by year-end and sort of the status of that firm capacity if it's on schedule or not?

Hold on, we're going to pull the number and make sure we did it right. The firm capacity is going to be there. It's already essentially there for us. There, it goes back one more page. So if you look at year-end, let's say, first quarter '13, we should have -- our firm capacity line is right at 300 million cubic feet a day of gross takeaway capacity. 299 million is my number here, but okay. So -- and then in mid-'13, it pops up to 382 million for a gross takeaway -- this is gross operated gas now. And if you remember, to get to a net number from that, you multiply that by 10% or so. So if we were producing 300 million a day of gross wet production, we would be producing about 330 million cubic feet a day net out of the Eagle Ford. So again, I would say that it's going to -- we thought we were going to hit that number right at the end of this year. We may be a quarter late. Subash Chandra - Jefferies & Company, Inc., Research Division: Okay. It's a big number.

Subash, I think it's a good point. It is a big, big number. And I think that's part of the issue. As you -- there is a significant production ramp built in here. So when you delay it a month or 2, it results in -- when you look within the calendar year of 2012, it has a significant impact. Overall, it doesn't really impact the value of the assets, the wells are fine. It's just -- it's a temporary infrastructure issue, and we'll push it out a little bit. Subash Chandra - Jefferies & Company, Inc., Research Division: And so let's say Q1, everything works out and you can get to that 330 million. I assume that it means that you would complete your backlog as well?

Well, we would. And catching up the backlog will take some time, that's why I think when I say, "Well, it will be a quarter out," I think we're probably talking -- that's part of the issue is we'll have to get back to complete backlog of wells, get caught back up. And so that's why I would say, "If you push our entire calendar out of the quarter, that's probably not an unreasonable way to look at things." Subash Chandra - Jefferies & Company, Inc., Research Division: Okay. And one final one for me. What is the rig count required for Permian lease retention at this point, and are you there?

That's a really good question, and I'm going to defer the question maybe for a quarter until I can get in and really dig around on that. Right now, we're fine. The question, I think, is really over the next 2 years, what do we have to get to, and I don't know that number well enough yet to be able to give it to you. It's going to be up a little bit, but it will depend on some negotiations we have going on about how we can pool up some of these leases. So I think -- but right now, we're fine, and -- but I do think, given good results, we will try to accelerate the program somewhat.

Your next question comes from William (sic) [Welles] Fitzpatrick, Johnson Rice. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: On the 48,000 or roughly 48,000 acres in the Permian that's not in the Northern Midland, can you give us a rough breakout of where that lands in the other 2 areas?

Well, we kind of did that on purpose, so that we wouldn't have to do that. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: Fair enough. We can move onto firm transport then. Do you think with 3 rigs going to 5 there are going to be any issues in the Permian with firm transport? And you guys looking to lock up any midstream there?

Yes, that's another great question. It's a problem we haven't had to deal with much because our volumes haven't been growing that much, but it is something to think about. In general, I think basis differentials have come in a little bit in the Permian recently. What we've seen in terms of the Northern areas that we're working, there is some pipeline -- gas pipeline infrastructure that we need to work through. We think we can do that at the pace we're working. Oil is essentially getting trucked. We haven't seen any big issues with that yet. I don't foresee this growing so fast that we create our own problem. And in general, most of the stuff I've seen would say that Permian differentials were forecast to stay fairly tight. So at this point, we don't see a problem with it, but we probably need to do some work on it. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: Okay. And you guys have talked about completion costs coming in around 20% in the Eagle Ford. Can we get an update on costs there? And I understand that, that might be getting offset by some more expensive fracs. But if you have an update, I'd appreciate it.

I think on a stage count basis, we're probably down between 20% and 25% now on a first stage number. We're being pretty -- part of the reason you see that lower CapEx number in the Eagle Ford is cost savings, it's not all -- just deferring completions. There are cost savings built into that. And we're pretty -- been pretty cautious about -- we're not just going out and adding a whole bunch of stages to wells yet. We're not at a point yet where we can really talk about how much stage count impacts rate and reserves. I'm think it's probably another 6 months or so before we'll really be able to talk about that much. I think there are some logical places we're adding stage count helps, it should make sense. But at this point, we are seeing about a 20% to 25% stage count reduction. We are spending a little more money on stage count, but not a ton. And so we have seen some cost reduction. On the drilling side, drilling costs in the Eagle Ford are pretty firm, but we are saving some money on the completions. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: Okay. And just one last one. Any ethane or how much, if any, ethane were you guys rejecting in South Texas in the second quarter?

Well, we didn't reject any ethane in South Texas, to my knowledge, in the second quarter. And it's not really, right now, it's not really close to that decision. We do have the ability to reject, if we want to, on several of our contracts, though we haven't been doing it.

Your next question comes from Scott Hanold, RBC Capital Markets.

Going to the Permian. It looks like you've built a nice position up there in the Northern Midland basin. Is there a room to expand that further, or is it pretty competitive or already locked down up there?

Well, I think there is some potential in the play. And I will say this just to try to scare people away from it, it's not an easy play. And there is some technology here that needs to be applied to really understand this reservoir, and if you don't apply it correctly, you won't get very good results. So we think there is some potential running room. Right now, we've got a big chunk bit off and we're going to work on it for a while. But I think over time there may be some opportunity to run. This is sort of out of the really shaley -- the intervals where people are most -- people are chasing shales, so it's little less heated maybe than some of the shale play areas. So I hope we can build some more position, I guess, that's the easiest way to say it.

Okay. Okay. And so the way it sounds, you're not looking right now, but you could opportunistically. Do you think this as a fairly expansive play or is it really a little bit more regionally tight?

I would say it's very -- I'd say it's -- I don't know the word regionally tight. It is a geologically constrained play in a sense, okay? And I don't want to get too much into the geology because -- could give a lot away here, but it's not a -- it's not like, playable over huge areas of the Permian basin. You need to be in a certain place to make it work and you need certain technologies, certain data to really be able to play it. And we think we understand that and hopefully a lot of other people don't. I didn't -- And I didn't say that we weren't looking for acreage yet and I didn't say we were either, so...

Okay. Understood. And I guess my next logical question I think I can guess a response is, what technically is more challenging or different about this reservoir?

Yes, I don't think I'll address that question.

Your next question comes from Michael Scialla, Stifel, Nicolaus. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: I think my questions were kind of on the same lines as Scott's, so probably I'm going to get some limited answers here, but I'll try anyway. The improvements you made on these more recent wells in the Permian, was that due to geology and location or is that more due to the way you drilled and completed the wells?

It's a combination of them, Mike. I think we've disclosed in the past that we drilled some vertical wells in the play, and we had some early success in vertical wells here and kind of thought that was where we're going to go with it. And then some subsequent vertical wells showed us that, well, we really need to drill these horizontally. And so we reworked our program, we redid a lot of our geologic interpretation and started drilling horizontal wells. And these wells, we're showing here results from our horizontal wells. And that's really what made the difference for us. And there's a lot of science associated with the direction we're drilling those and how we're completing them, but I'm not going to get into that too much. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Is seismic one of those tools that's important features of success in play?

Now, you're asking me questions that I won't answer. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Okay. Maybe in terms of the 68,000 net acres that you mentioned, do you feel like that area has kind of been de-risked or is that just where you think this play might work?

I would say more of the latter than -- it certainly hasn't all been de-risked, and I would want you to think it has been. We have some good indications. We have some technology we think can help us some, but it's still very early days. And it's still in what I would call a delineation stage development play. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And then you mentioned you are spending some dollars on acreage in some other, it sounds like, maybe unproven plays or those exploratory-type plays?

Yes, I would call them exploratory. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Can you give us any idea of how many acres you might have there?

Well, I think we indicated how much we added in the last -- in the first 6 months. Oh, outside of Permian or... Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Yes, outside -- sorry, outside Permian though.

Oh, no, we're not going to address how much acreage we've had outside. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Okay. Then one last one for Wade, you mentioned you're in your comfort zone now in terms of debt cap. The budget has gone up a little bit from the beginning of the year and cash flow, I guess, with the production being down, is going to be a little less. As you look out to year-end and into 2013, do you still -- does it still look like you're going to be within that comfort range? Or if not, any thoughts on other noncore asset sales or anything like that to get you back in that range?

Now we still feel very comfortable with the balance sheet and where we're headed in the foreseeable future. We'll use the revolver to fund the gap the remainder of this year just like we said we would and lots of capacity there. And looking ahead at 2013, still feel very comfortable working within the debt metrics that I have laid out in the past. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: I think you've said 1.5x debt to EBITDA your -- by your projections, you're going to be under that?

No, I think what we've said in the past is we want stay below 2x, and we would go to 2.5x for the right transaction or right opportunity but we're, I think, we're headed to -- my numbers show 1.5x, 1.6x by the end of this year, which is very comfortable.

Your next question comes from Nick Pope, Dahlman Rose. Nicholas P. Pope - Dahlman Rose & Company, LLC, Research Division: I think in the last call, you guys talked a little bit about some of the hiccups that you had in March and April in the operated Eagle Ford. And just kind of looking at the number that you put up in the second quarter, I was kind of curious what the profile looked like over the quarter itself, because it seems like April was a little slow. What, I guess, what -- I was wondering what June rates were, if you were able to give those kind of numbers, and maybe current rates in the operated Eagle Ford?

Well, we typically don't give month-by-month numbers like that. I will say April was low because of pipeline issues, and then we ran smack into these other midstream issues that kept our rate -- we were up from April, but kept our rate pretty flat for the rest of the quarter. We have made considerable progress already in July in resolving those, and we're up quite a bit, but I don't think we'll give specific numbers. And the reason for that is because on any given day that numbers are up and down, I think it's real hard to -- I don't want to give a number and then find out we got an interruption next week to take it down 20 million a day. But we are making progress. I think if you profile though the second quarter, what you see at April was low. And then we got up some and then we were basically flat through June. And that's when we really started to see -- we expected to grow in June, and we really didn't, and that was when that some of the impact of this midstream infrastructure really came into place. One point I should make, there are a lot of people out there who look at individual well data on the Texas Railroad Commission website, and we've gotten a lot of questions from people about, "why is this well falling off," et cetera, et cetera. And that really does -- these constraints really do ripple back to individual well rates. And we've put on a new completion, and it literally knocked a lot of our other wells back. And so you can't see on that website what the wellhead pressures are that are causing these things, but as the pressures go up, a lot of our older wells lose production. So if you're out there using state data trying to figure out what's going on, you really can't do it. It's just not amenable to that. But in general, I think the last couple of months of that quarter were pretty flat. Nicholas P. Pope - Dahlman Rose & Company, LLC, Research Division: Okay. That's helpful. And I was just hoping to -- sticking with the operated Eagle Ford, I was hoping to kind of get these numbers correct. I think at year-end, in terms of like the producing wells or completed wells, I think you had 84 at year-end and you've completed 26 wells in the first half of the year, is that right?

26 is right. I'm not -- we need to check the 84 number. I don't remember that number off the top of my head.

Your next question comes from David Tameron, Wells Fargo.

Just a few follow-ups. Jay, I don't know if you've said this and I missed it, but can you talk about in the horizontal Permian, the Mississippian Lime, did you give us oil cut, oil percentage on that well?

Yes, it's about 85% oil, and they make some NGLs too. So if you look at total liquid, it's actually higher than 90%.

Okay. Second, Granite Wash, you guys talked about you're going to go down to 2 rigs once you're done HBP'ing. And can you talk about the thought process though, rather than may be move those rigs to the Permian, or you guys are going to Eagle Ford to the Permian on some of those issues you talked about. Can you just talk about the thought that keeps you on that Granite Wash acreage?

Sure. Let me correct one thing you said, our acreage in the Granite Wash is already HBP'ed. So we're not -- that's done, it's been that way. Clearly, if you look at the Granite Wash recently, the NGL prices up there are poor. And what we've done is we've looked at it, but we really want to -- we need to continue to high-grade this program to make sure that we're making the kind of returns that we want to make. And the guys there in our Tulsa region said, "Look, if you let us cut a rig, we'll be better off. We can manage at a higher -- manage to a better quality prospect." So that's what we decided to do. And we're not laying down a rig early, we're just laying down a rig at end of September, which is -- that contract expires anyway. I think it's -- could very well be that after couple of months, we pick up another rig in the Permian and end up essentially moving from one place to another, but probably not within 2012. I think if our Permian rig count goes up, it'll probably go up in '13 after we rework our capital program. And we're pretty committed to trying to get ourselves back closer to cash flow during '13.

Okay. And are you still -- since you went there, can you give us any magnitude -- what does pretty close mean, plus or minus?

Well, what we've said is that we want -- we thought we'd be back to cash flow by 2014, so that assumes our capital is relatively flattish. But other than that, it's just too early to say much about '13.

No, I hear you. All right. And just Granite Wash, are you still drilling the same targets, where before I know it's Marmaton, Missouri, and whatever name it happens to be at the moment. But do you still chase those same formations?

Yes. During the quarter -- I think so far this year we completed 7 wells in the Granite Wash. I believe 5 of those were Marmaton completions. It was either 5 or 4. We had a -- we did complete a couple 3 Hogshooter wells, and frankly, they were disappointing. Now all these wells were in Oklahoma, not in the -- we don't own much acreage in the panhandle of Texas. And we just haven't been real successful in offsetting anybody's successes in Oklahoma and the Hogshooter, and focused most of our activity then in the Marmaton, where we have been successful in a number of areas, particularly in the Mayfield area, which is in far Western Oklahoma. I think what we have a good list of prospects at this point. We're just going to high-grade that list and get ourselves into the best 2-rig program we can. Those wells look good to us. It runs strong economics. But we think, given that we're HBP'ed, that's the right thing to do right now.

Okay. And last question, just back to the Eagle Ford. The non-op, I mean, some of those issues with the production estimates and the deferrals and some of the accounting issues, is there anything you guys can do to on your end to address that? Or how do you manage -- I know you mentioned it's a relatively small portion, but as you know the Street likes to focus on ops versus non-op. It just creates some confusion and volatility in the stock. Can you talk about anything you can do to address that from your end?

Well, we're trying. Believe me, David, we're trying really hard. We get actuals on like a 3-month lag, so literally we are just seeing now data from April, okay? So we're seeing the beginning of the second quarter actuals now at the beginning of the third quarter. And given the transactions that occurred, the fact that there's a lot of wells in the non-op that get shut in for one reason or another during the quarter, the fact that our interests are different in a lot of the different areas of the non-op, and it is actually very difficult. And I know it seems like it ought to be easy and you just call up somebody and ask them what their production is, it just doesn't work that way. I think we are getting better. Clearly, we kind of understand what their underlying trend is, which looks like high-single-digit growth to us, quarter-to-quarter. And that's going to help us as we go forward. But I am sorry, in the sense that I -- it's very frustrating for me as well, but I think we're doing the best we can.

We also have infrastructure issues as well [indiscernible]...

Well, sure we do. Yes, there's a lot of complications. And so I appreciate the frustration, and we certainly share it, and we're trying really hard to get a better number.

Well, yes, I didn't assume you want -- not trying to get better number, just wanted to see what -- where you are on the process and that explanation is -- I think to add some color is helpful, so appreciate it.

It is frustrating. And we're frustrated too, and we want to get the numbers right and get them, I shouldn't say right, these are all estimates, okay? And from a corporate perspective, they're not material, but we understand that people look at these numbers and focus on that.

Another reason we want to be operator.

Another reason we -- why we sold this thing down.

No, you're not alone. And, I mean, other E&P companies had similar issues in same basins, different basins. So just trying to figure out where the process was. But that, again, the color was helpful so I appreciate it.

Your next question comes from Pearce Hammond, Simmons. Pearce W. Hammond - Simmons & Company International, Research Division: I noticed that the NGL hedging realizations on the outyear NGL hedges were around $27 a barrel, which seems a little bit low. I was just curious, are those ethane hedges? Just trying to get a better sense on those prices.

Yes, the comments you made, because they're ethane, that is exactly correct. Our outyear hedges are almost all ethane. We typically didn't hedge a lot of the heavier products out that far, and that's why when you look at those numbers, the numbers look low always because they're mostly ethane or almost all ethane. That's it. Pearce W. Hammond - Simmons & Company International, Research Division: And does your production mix, specifically NGLs and condensate, make you a bit more exposed to surface constraint issues in the operated Eagle Ford?

Well, I think people may not really fully understand the difference between running a gas condensate project and running, say, something in the Bakken, okay? In the Bakken, where we complete a well. We -- if we need to, we flare a little bit of gas, we haul the oil away in a truck. You can pretty much just add well after well and you just add up your well, right? Here, every well we put into this gas handling system creates back pressure on all the other wells. And it is a -- all this stuff is tied together, and it is essentially a gas production field that makes a lot of liquids. And frankly, handling a lot of liquids, up tubing in these wells makes it complicated. And so it's not as simple as well you just add a well and you add rate. It's actually a fairly complicated, multi-phased hydraulic problem when you start to design these facilities and try to optimize of them. So I do think that it's not necessarily the NGLs that create that issue, it's really more the fact that this, for us, is a largely gas-driven production mechanism here. And that creates all these issues associated with back pressure and facilities and need for --we may need compression as we move to the higher liquids end of this thing, compression can become more important. We hadn't planned for that this early. We may need to accelerate that. It's a more complex problem. And I think there's a lot of people out there who just want to build a simple spreadsheet where you just add well after well after well and sum up the answer. It doesn't work that way. Pearce W. Hammond - Simmons & Company International, Research Division: And then lastly for me, can you elaborate on the lower service cost you are experiencing in the Eagle Ford?

Well, really, most of the service cost reduction we've said is in the frac side, and we negotiated about a 20% discount to our frac cost from last fourth quarter, and then we've seen some additional benefits during the year. So about -- between 20% and 25% reduction in per stage frac cost. Other costs down there are not going down much, and you're still seeing most of the other components of LOE and CapEx are pretty firm and that's just -- we haven't seen a lot of that reduction yet there.

Your next question comes from Michael Hall, Robert W. Baird. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: I think a lot of mine have been answered. But I guess first in the operated Eagle Ford, any reason to think, once you get some of these infrastructure enhancements delivered that some of -- and the line pressure issues resolved, any reason to think any of that production won't come back on? So is it more just deferred as opposed to lost?

I think that's been -- yes. No, we don't -- there's really no issues with the wells. It's just a matter of -- right now, if you add a new completion, you really don't add as much incremental rate as you think you'd add, so it's not really economic to add incremental wells when you can't really add the incremental rate. Now, again, we've made good progress in resolving that. Our rates are up some, and I think we're moving in the right direction. But no, there's no real issue with respect to reserves here long term. There's no real issue with respect to the well performance. It's just a matter of getting the facilities in place, getting our pressures down to where they need to be and being able to get back to normal well work. Right now, we've been spending almost all our time trying to work the facilities piece. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: And as you've commented, you're kind of shifting some of the activity to the more oily spots on the block, any emerging kind of sweet spots or variance relative to what you've laid out earlier?

No, I think the sweet spots are what we've said. Typically, the northern portion of Galvan and the eastern portion of the Briscoe acreage. That area there is where we're going to focus most of our activity over the next couple of years. And I think it is important to note that our original development plan was more broad based, and part of the reason that the infrastructure gets tougher is because you're moving into more confined areas to do this. And that creates differences in the schedule versus when we were going to -- where we were going to install things and when we're going to install them. The higher liquid loading in our wells also creates -- most wells that have higher liquid loading are more sensitive to back pressures, and that creates even a little bit of a compounding effect in that. So I think our people are actually doing a really good job of managing through this. And then, of course, schedule delays and just the delivery of equipment have created an issue as well. But we're responding to what is a fairly dynamic economic environment down there, and we're going to get through this. It's just going to be a little delayed.

And, Michael, the changes that Jay talks about are all for the right reasons. Obviously, our economics are stronger in the liquid windows, and that's why we're making those changes, but it does create challenges with the infrastructure build. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Yes, that makes sense. I appreciate the color. And I guess on the downstream component, any lingering issues there? Anything else to say on that end, or is that pretty well all been resolved...

No, we really haven't had, in terms of the downstream pipes, we really haven't had much trouble since that April time period, and that was -- those were 2 very distinct plant-related problems that got resolved by the end, pretty much by the end of April. I want to embellish on what Tony said. He's absolutely right. The changes we're making, we're making because it's the economically right thing to do. We're deferring completions because there's no value in making completions that you can't produce the product. As we move farther north into the oilier parts of the reservoir, what it means is you may defer some gas production frankly from the southern portion of the play and push the capital that you're going to spend on that to places like the Permian where our economics are strong because it's liquids. Now every decision we're making here is driven by the value creation. Obviously, we didn't wish for our equipment to be delayed, but we're dealing with that in a way that we think creates the most value for shareholders. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: It makes sense. Any way to quantify -- I mean, is it meaningful enough, the kind of move away from the gas component and the more liquids rich, which I'm assuming is somewhat a lower rate. Any impact -- or any way to quantify that impact on guidance, if any?

Well, we have plenty of locations in the oilier portions of the reservoir. And I think we can -- we'll still be able to get to essentially where we thought we'd get to in terms of our firm capacity, just a little later than we expected. And in the shift to oilier stuff in the Permian does impact rate some because that frankly we're getting a fairly late start in the year. A lot of those wells won't come on until later in the year and into '13. So the benefit associated with that oilier -- shifting to oilier happens later. And so that's part of the rate impact that we're looking. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Okay. And then I guess on the Permian, did you or can you disclose what you paid for that 27,000 acres?

I don't think we will. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: All right. It's worth trying. And then last one for me, you highlighted gas declines in the operations update section of the release. Are those outpacing expectations to the downside, or kind of what's that base decline rate look like?

Actually, I think our base decline rate is coming back a little bit from where it was. The areas we're declining is largely the Mid-Con, and it's the older -- the gas assets, the Haynesville, in particular, where we didn't -- where we've stopped drilling, our Woodford assets, which -- where we haven't drilled for a while. Those assets are on decline and they're going to be on decline. Our expectation was that with Eagle Ford growth that we could more than offset that decline. And when we ran into our infrastructure problems, we just weren't able to do that. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Can you put a number on kind of what the base decline is, let's say, on your PDP stream?

Well, I think we said at our last call that our number is 40%. It's still in that range. It hasn't changed that much a quarter from that.

Your last question comes from Joe Manger [ph], Macquarie Capital.

I think you've sort of addressed that earlier concerns of -- considerations around infrastructure and midstream issues in the Permian, but I guess based on the what you've learned, what your Eagle Ford experience, what can we anticipate, I guess, going forward in terms of hurdles, or how might you, I guess, look to be more proactive around some of those types of challenges down the road? And it's a little bit early, but as you move and shift more capital into this new area, just trying to anticipate what kind of growing pains we might expect going forward.

Well, I think that -- I'll just comment, the stuff we're working on in the Permian is very, very different than what we're doing in the Eagle Ford, and the infrastructure issues are significantly less complex. Basically, we can truck the oil out of there, that's 90% of the production. So really it's more an issue of getting your -- just getting your gas offtake hooked up. And in that area, that Lynn, Garza area, it's a little lean up there. There are some -- there is competition between providers that we'll certainly be working on. If we need to install some of our own equipment, we will. At this point, we don't see that being a big issue. And I think the -- we have been, I believe, very proactive in our Eagle Ford program. Frankly, I can't completely control what happens to tank delivery or vessel delivery in this environment that we're in. And that's just something we estimated that we'd get it quicker than we would. But I don't think the Permian is the same kind of problem now. Overall, in the Permian, in terms of differentials -- or basis differentials in the Permian, they have come back in some. I do think with the amount of activity out there, it is something we do need to keep an eye on. But the wells have strong enough economics at this point, we think we're okay.

Okay. And not to, I guess, try to pick on or get you to talk much about 2013 plans, but it seems like activity levels generally are going up in all existing areas and new areas going forward. How should we think about, I guess, your capital spending plans and considerations around cash flow, balance sheet constraints, liquidity. Not to, I guess, get you to speak specifically about 2013, but it seems like that outspend will persist for the foreseeable future?

What we've -- this is Tony. What we have said is basically by year-end 2013, we expect to be in a position where we'll be within cash flow. And I think what that infers is basically a CapEx program that's relatively flat year-to-year. And obviously, we haven't guided yet on 2013, but we'll take a look at that. And obviously, the opportunity slate can impact that going forward, but right now, that's kind of the way we're thinking about next year, is more of on a flattish capital program.

But Tony promised me that if I had good enough returns he wouldn't make me shut things down.

We -- and a lot of that certainly will depend on some of our new ventures work as well some of the new areas that we're now talking about Permian specific.

And I guess with that, what areas might slow down? Permian is expanding and Eagle Ford is continuing -- you've got some completion that's going...

Jay talked about the fact that we're going to be laying a rig down later on this year in the Granite Wash, and also that, that's already HBP. So we do have a lot of flexibility with that program. We've been very deliberate with our approach in the Granite Wash, and we like the position we're in, but that's one where we're got a lot of flexibility, so I like that.

And if you're comparing year-over-year, we certainly won't be drilling Haynesville wells next year.

That's right. And I think our infrastructure spend will be down some in non-op. So there are some knobs to turn. Part of the reason we have not guided '13 is because this is one of those things we really got to scratch our head about, trying to understand, where are the best economics, how we want to do this, but we are going to try to get back closer to our cash flow.

All right. With that, thank you all for joining us this morning. We'll talk to you again next quarter.

This concludes today's SM Energy second quarter earnings conference call. You may now disconnect your lines.