SM Energy Company (SM) Q1 2012 Earnings Report, Transcript and Summary

Good morning. My name is Terry, and I will be your conference operator. At this time, I would like to welcome everyone to the SM Energy 1Q 2012 Earnings Call. [Operator Instructions] I will now turn the call over to Mr. David Copeland, Senior Vice President and General Counsel. Sir, please go ahead.

Thank you, Terry. Good morning to all of you joining us by phone and online for SM Energy Company's First Quarter 2012 Earnings Conference Call and Operations Update. Before we start, I would like to advise you that we would 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 on 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 to our website for this call, and the Risk Factors section in our Form 10-K filed earlier this year, and the Form 10-Q that was filed earlier this morning. 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 in 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 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. 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 and Investor Relations; and myself, David Copeland, 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 today for our first quarter 2012 earnings call. I'll briefly cover a few highlights and then turn the call over to Wade and Jay for their respective financial and operational reviews. We'll be referring to slides this morning from the presentation that was posted to our website last evening, and my comments will begin with Slide 3. As I reflect on this quarter, the theme that comes to mind is confident growth. We are hitting the mark with continued strong performance across the board in executing our 2012 business plan. SM Energy had another strong quarter to start the year. We came within guidance -- came in within guidance on production and met or beat all of our cost guidance. Our development programs remain focused on high-return projects. In fact, approximately 95% of our drilling and completion capital is dedicated to oily and NGL-rich projects, with the bulk of that being deployed in our Eagle Ford and Bakken/Three Forks programs. Our financial position remains strong and our liquidity position was recently enhanced with the increase in our borrowing base by our bank group, which Wade will talk about shortly. This increase is being driven by the growth in our higher value oil and NGL assets. Finally, we are on track to post-significant production growth in 2012, which will exceed 30% year-over-year, again, driven by our high-return liquid rich projects. With that, I'll turn the call over to Wade for his financial review.

Thank you, Tony, and good morning, everyone. I'll be pretty brief this morning. The first quarter was solid, and frankly, very clean. I'll begin with a brief recap of how we performed versus our guidance on Slide 5. Production for the quarter came in at 50.7 Bcf equivalent or 8.4 million barrels of oil equivalent, which is right in the middle of our range that we provided for the quarter. Jay is going to discuss production in more detail during his operations review. Cost for the quarter in essentially all areas were better than our guidance and there were no transactions or unusual items during the quarter. GAAP net income came in at $26.3 million or $0.39 per diluted share. Adjusted net income for the quarter was $32.8 million or $0.48 per share. EBITDAX for the quarter was $259 million. For those of you who follow us regularly, you'll note that we changed from operating cash flow to EBITDAX this quarter. We made this change because we use EBITDAX internally as a performance metric and it is more commonly used in the investment community. Moving to Slide 6, I'll discuss our financial position. Our long-term debt at the end of the quarter stood at roughly $1 billion. This translates to total debt to trailing 12 month EBITDAX at the end of the first quarter of essentially 1 turn, exactly 1.04x. Our debt-to-book cap at the end of the quarter was 40%. We're in good shape with respect to debt maturities. We did call for redemption our convertible notes on April 2, and for those holders who are converting, we intend to net share settle those notes. Cash portion will be funded using our credit facility, with the balance being settled in equity. We are still in the valuation window, so we won't know the precise number of shares we will need to issue for a few more days. As a reminder, these shares have been included in diluted EPS for a while now as the stock has traded above $54.42. I'm now on Slide 7 where I'll discuss our credit facility. Our bank group recently increased the borrowing base from $1.3 billion to $1.5 billion and that was despite oil and gas prices. As Tony alluded to, this reflects the growth of oil and NGL-rich properties in our asset base. We have currently elected to leave our bank commitments at $1 billion. At quarter end, we only had $24 million drawn on the credit facility so we clearly have ample liquidity available to us to fund our capital program and corporate needs going forward. A summary of our current hedge position is included in the Appendix of the slide deck, and detailed hedging information is included in our Form 10-Q, which was filed earlier this morning. So with that, I'll turn the call over to Jay.

Thank you, Wade. I'll begin my remarks starting on Slide 9. As Wade said, production for the quarter came in at 50.7 BCFE. On a sequential basis, this was a slight decrease from the record production we had in the fourth quarter of 2011. However, as a reminder, we divested a portion of our nonoperating Eagle Ford program in December of 2011, which resulted in our working interest being reduced from approximately 27% to 14.5% in the joint venture. Adjusted for divestitures, the company grew production 4% sequentially. Our production mix in the first quarter was 56% natural gas, 14% NGLs and 30% oil, very consistent with our production mix in the fourth quarter. We've received several inquiries regarding our production mix lately, so I want to spend a couple of moments discussing that. I'm currently on Slide 10. As Tony mentioned earlier, 95% of our drilling and completion capital for this year is focused on oil and NGL-rich programs. We expect our production mix in 2012 to average about 55% natural gas and 45% liquids by volume. By 2014, we project that mix, given our current slate of projects, will be about 50-50. I should also note that most of our operated productions in the Rocky Mountains, Mid-Continent and Permian regions is still reported on a 2-stream basis, that is oil and rich gas, which explains why our gas realizations continue to be somewhat higher than NYMEX. Another general point I'd like to make is that although our overall price realizations have fallen as a result of lower gas and NGL pricing, our percentage operating margin has stayed relatively flat due to our improving cost structure. Part of this of course is spreading our costs over more volume as we have grown. But our continuing process of selling older, high lift cost assets, our conversion to company operations versus contract on all our significant assets and our people's diligent effort in improving efficiency and cost are really paying dividends. On Slide 11, we show our expected rig count for the year, which is heavily weighted again toward liquids-rich projects. As you can see, a significant portion of our operated rigs will be deployed in the Eagle Ford and Bakken/Three Forks programs, which I will now move on to discuss. I'm now on Slide 12. In our operated Eagle Ford program, production for the quarter averaged 178.3 million cubic feet equivalent per day. The first quarter of 2012 was really the first quarter where pad drilling had an impact on the timing of our well completions. The way the schedule worked out, we completed 0 wells in the month of February, and 2/3 of the wells we completed for the quarter were actually completed in the month of March. Our guidance anticipated these issues, and volumes ended up right on our plan for the quarter. On the cost front, based on our current contracts, we now believe our frac cost per stage in 2012 will average about 20% lower than we were running in the last half of 2011. My expectation is that we'll leverage those savings by increasing our frac density on our planned wells, which appears to us to have benefits from a per well production capacity and EUR standpoint. I should note that we currently have 3 frac spreads working in the play versus 2 in the last half of 2011. We currently have 6 operated rigs running in the play. Our plan is to cut that number to 5 rigs later this year, as the efficiencies we expect from pad drilling start to kick in. On Slide 13, we show an overview of our non-operated Eagle Ford program, which is performing very well. Despite our sale of a 12.5% stake in this project to Mitsui in December, we saw production grow approximately 9% quarter-over-quarter, in average 12,900 barrels of oil equivalent per day net. This production growth was generated by a large number of wells completed by the operator very late in 2011 and early in '12. We still believe that the operator will run around 10 rigs in this program in 2012, and we'll be carried for essentially 100% of our drilling and completion activity in the non-op program for the next 3 to 4 years. Moving to Slide 14, in the Bakken/Three Forks, production averaged 10,300 barrels of oil equivalent per day net for the quarter. We operated 3 rigs in the program during the first quarter and still plan to add a fourth rig here late in the second quarter. We've also been participating in a number of non-operated wells. As you can see from the plot, our program is producing a nice ramp in production rate. We're also improving our drilling and completion efficiencies in the Williston. Recently, we did a 3 well sequential frac in our Gooseneck development area, completing 3 wells with 60 frac stages in 6 days, including some slight delays for microseismic. I think that's just an indication of how much more efficient our work will become as we move into our infill program in all areas in the Williston over the next year. On Slide 15, we show our other development areas. We're running 3 rigs in the Granite Wash, focusing on Marmaton and Missourian oily targets. In the Permian Basin, we have a rig operating in our oily Mississippian Lime play in Borden County, and finally in the Southern Rockies, we have a rig running focused on various other oily and reservoir targets, including the Niobrara and Frontier. Moving to Slide 16, we show a graph of our projected growth for 2012. Using the midpoint of our guidance, we project to grow production by approximately 32% in 2012, much of that growth of course will occur in the second half. With that, I'll turn the call back over to Tony on Slide 17.

Thanks, Jay. As you just heard, we're off to a great start to the year and we're executing with confidence on our 2012 business plan. We're focused on oily and NGL-rich projects which will continue to drive us towards higher liquids production going forward. Our financial position and liquidity remains strong, and we're poised to deliver another year of significant, profitable growth to our shareholders. With that, we'll turn the call over for your questions.

[Operator Instructions] Your first question comes from the line of Subash Chandra with Jefferies. Subash Chandra - Jefferies & Company, Inc., Research Division: First, a commentary if you could on the trend in NGL prices here very recently. If you have any particular thoughts, propane, ethane, et cetera. And then I have some asset-specific questions if I could.

Well, this is Javan. Obviously, ethane, propane prices are down. I think there's a lot of good writing out there on the reasons for that. We've done our own work and I would say we think it's -- they're going to be weak for a while. We don't have as much exposure to the Conway hub as a lot of other people do, so typically, our liquids are all at Belvieu and we're trading versus Belvieu. So I've heard some commentary from some operators about how they think prices are going to improve over the next few months, particularly in Conway and that probably won't be as big an impact on us. In general, I think if you look at the strip for propane, it's really pretty strong, solid. I mean, it's lower than it was, but it's not going down. And over time, we think those product prices will improve. But certainly, there needs to be more demand.

As a reminder also, Subash -- this is Tony. We've said in the past, based on the evaluations that we've done, that even if ethane prices continued to drop and went to rejection, we would still see only 4%, 5% of reduction in our rate of return on our projects so I mean, even in kind of that worst case scenario, our project is still very resilient. Subash Chandra - Jefferies & Company, Inc., Research Division: Okay, that's right. You did say that. I'm just curious where do you think the Belvieu ethane rejection occurs? Is it what price does ethane need to be?

No, Subash. I don't know that we can claim to be experts on that topic. And I'll probably refer you to a whole bunch of people who are writing on that that probably understand the market better than we do. We're just committed to the idea that -- we've run the lowest side cases as Tony indicated and we really think we can stand a pretty low price. Trying to project exactly what that's going to be month by month or quarter by quarter is really not in our wheelhouse of expertise. Subash Chandra - Jefferies & Company, Inc., Research Division: All right. Okay, good enough. And then on to more asset-specific questions. How much production was, if you will, curtailed or off-line because of completion activities operated Eagle Ford? And could you address why transportation costs -- how you got them lower on a per unit basis sequentially?

Well, as far as exact volumes and what was off and what's not off, no, I don't have those numbers for you. I think we indicated that the real difference between fourth quarter and first quarter was the result of a lack of well completions in the first quarter. I don't remember the second question again... Subash Chandra - Jefferies & Company, Inc., Research Division: Oh, sorry. The reduction in transportation cost per unit, how that was achieved?

In a general sense, transportation costs follow our operated Eagle Ford production. So the dip -- a little bit of dip in production has been a big driver on our overall transportation cost numbers. The numbers move around a little bit quarter-to-quarter, obviously these are accrual type numbers and it depends on when we pay the bills and how they get accrued. But in general, our transportation costs will move with operated Eagle Ford production. Subash Chandra - Jefferies & Company, Inc., Research Division: Okay, and one final one for me, if I -- do you have the production mix in operated Eagle Ford versus non-op Eagle Ford?

Well, I think if you look at what we showed in the fourth quarter for operated Eagle Ford, we were right at 56% gas in the operated Eagle Ford, which is one of the reasons -- it's probably a little unusual to us that people keep talking about our gas percentage going up when our dominant production is 56% gas. I mean, it is 56%. That's where our growth is. So nominally, I mean, you can't really be producing a lot more than 56% gas. So I'm not sure where some of these people come up with all this stuff about gas percentages going up and stuff. But in general... Subash Chandra - Jefferies & Company, Inc., Research Division: I'm not one of those people.

Yes, I understand but I'm saying that because we get this question all the time, and I think we try to guide on this, but people don't listen apparently. I think it's pretty clear from our fourth quarter numbers, the first quarter in general, our operating Eagle Ford is about 56% gas. Our non-op is oilier. And so as that production grows, the mix gets oilier. And of course all our other investments essentially are on the oil side at this point. Subash Chandra - Jefferies & Company, Inc., Research Division: Is it safe to say that I can -- I think in Q4 for non-op we were 46% oil, 29% gas. Is that a good number to assume going forward?

I don't see why you'd use a different number, to be honest. I mean, if it's -- it's going to move around some depending on where our operator over there is completing wells. But generally it's not going to change that much quarter-to-quarter.

Your next question comes from the line of Scott Hanold with RBC Capital Markets.

Can I have a follow-up question on the NGL pricing? I mean, what percentage of your NGL basket is ethane?

It's about 48%.

Okay, and then propane would be about what?

It's about a 1/4, I believe, is the number. That's a ballpark number, right at 1/4. Actually, NGL -- total ethane 46% on the -- no, that's operated Eagle Ford total. You know what? Let me give you the numbers for the operated Eagle Ford. It's 46% ethane; 24.9% propane, okay? And that's -- we sell NGLs in other places, but not a lot of other places. So those are generally good numbers for the company as a whole. The number on ethane has come up some over time for us in the Eagle Ford and I personally attribute that to higher plant recoveries but that's just -- that's where we are right now.

Okay, that does make you a little higher than most but that you think that's plant more specific?

Well, about 60% now of the non-methane molecules that we produce in our NGL stream. The non-methane molecules in the gas stream in the Eagle Ford are ethane. And then the amount you actually produce in your -- you actually sell is dependent on your recoveries, all right? So you can calculate that recovery, but that's going to be 75%, 80% recovery, which is up a little bit from where we were.

Okay, understood. Looking at the Bakken, I had a question in terms of your activity. Where is that fourth rig going to be targeted mostly?

Well, I don't know that we've said, hey it's going to this place. It were going to be spread around. Most of the activity is going to be in the Bear Den area up on the anticline. I think generally we're going to get to our infill program which is what we've been hoping to do. We expect that rig now to be probably in late June.

Okay, and you know, when I look at your acreage position, obviously, your focused acreage is, call it, a little bit less than half of your total acreage position. Is most or the rest of it HBP? I guess the Elm Coulee would be but is everything else HBP or do you need to put a rig to work out there to hold some of that?

It's almost all HBP.

Okay, and in terms of the step up in the Gooseneck area, what does some of your results look like recently? I've seen some improved industry results up there. Have you kind of been seeing some similar things as well?

Well, our results in Gooseneck, they have continued to improve as we've upped our frac volumes. But I think in general, they're very, very economic wells. We don't really quote IPs the way other people do because we don't manage our way around IPs but we're getting some really strong wells and in general, they've been very good. Most of the people I've talked to who have looked at the public data are telling me that they're surprised by how good the wells are. We're not surprised by that. But they're good strong wells. And they're not -- and they're cheaper, $1.5 million to $2 million, probably cheaper than drilling in the main part of the Bakken to the south so...

The way we kind of think about it is -- this is Tony, if you take a look at returns on both projects, they're very comparable, which kind of supports what Jay just said. You got good producing wells in the Divide area. And yet they're cheaper wells. So your return is a comparable to the Bakken's. So we like both programs. They're doing well.

All right, great. And one last question, just on terms, you talked about pad drilling and the impact ahead during the first quarter. How should we think about that when we look at the rest of the year? Is it going to be fairly lumpy, and does that smooth out as we get into 2013 or is that just something we need to adjust for?

Well, I think it does move out. There's a little of a -- as we started up our rigs, when we brought our pad drilling rigs on in the fourth quarter, third, fourth quarter last year, we really kind of warmed those rigs up on individual wells. And then really right at the end of the fourth quarter we really transitioned them into pad drilling with all of essentially at the -- with all our 3-pad driller or moving rigs at the same time. We're even pad drilling some with our other rigs. And so it is lumpy here at the front. As the schedules start to -- as some things accelerate or slip and they start to get a little bit less in rhythm, it'll still be lumpy, but it won't be as lumpy. I think the real impact, as you move forward in the next couple of quarters, April, during the month of April, the industry down there had several significant pipeline interruptions. Kinder Morgan was down for several weeks due to a fire in one of their gas plants and that will impact a number of people, not just us. Regency had a fire in a dehydration unit which had them down for essentially the entire month of April. So April is going to be kind of a tough month from a production standpoint. So unfortunately we brought on a bunch of wells right at the end of March or in March, and then had a bunch of production downtime in April. And that's why our production guidance for the second quarter, the low end of that is a little lower than some people might be expecting. I think we can recover from that during the quarter and that's why we guided to where we guided. We left our guidance alone for the year because we really do believe we can make that up. But I think you're going to see some industry-wide impact in the month of April, due to some of this downtime. Now as we go forward, again, I think the lumpiness will spread out, and you'll start to see less impact, in a given month, for example, from that. But it's always going to be a little lumpy and you always have to account for the fact that you'll have some base downtime as a result of completing wells around these pad drilled wells. And of course, we need to improve our efficiency in pad drilling. We'll, over time, we'll get better with the schedule -- it takes us a little longer now to get a complete pad completed than we hope it will over time. So I think it'll improve. I guess that's the long story.

Your next question comes from the line of Pearce Hammond with Simmons & Company. Pearce W. Hammond - Simmons & Company International, Research Division: A very strong Bakken production growth quarter-to-quarter. What accounted for that? Was that just better weather?

Well, certainly better weather has had a big impact on the industry as a whole up there over the last quarter. Last year, we completed almost all the wells we completed for the year in the second half. And part of that I think is flush productions from that. Part of it is just a good steady continuous program. We had a number of really nice wells. As one of the earlier callers asked, Gooseneck has continued to outperform our expectation. There's several really nice completions there. And it's just a -- it's a great program for us and I think we're really running on all cylinders with the rigs we have there, and we're looking forward to our next rig coming as I mentioned in late June. Pearce W. Hammond - Simmons & Company International, Research Division: And then can you provide some more color on the Permian and do you potentially have some prospectivity to the cline?

Well, any more it seems like anybody who owns acreage in the midland basin's got prospectivity in one shale or another. So I would say the answer to that is that we have prospectivity in shale. The cline is a specific shale, but there's a lot of other ones too. And I guess other than that, I won't comment on anything related to exploration. Pearce W. Hammond - Simmons & Company International, Research Division: And then lastly, what is your -- what would you estimate to your base decline is for the company? Base production decline?

We did that number at the end of the year, and the number is a little over 40%. Pearce W. Hammond - Simmons & Company International, Research Division: 40%?

40% for the first year annual number, and that's a result of us -- it's come up over time as a result of us participating in a lot of these resource plays and selling a lot of our legacy low production rate -- or low decline production. So we have a pretty steep initial decline this year. Over time, as we build a bigger base under us of these assets that have lower declines, that will start to come back down. But right now it's in that -- a little over 40%.

Pearce, this is Tony. If you think back about when a lot of these plays got their start it was all about the same time. So certainly, as these plays come on with high initial decline rates, that's what drives that early on.

Your next question comes from the line of Welles Fitzpatrick with Johnson Rice. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: In the Bakken, it sounds like there are no near term plans to drill outside of the 3 main areas, and combine that with kind of mid-Billings being a little bit of a hotspot on the lease sale on Tuesday flirting with $5,000 an acre. Would you guys ever look to sell the Bakken acreage outside of the 87,000?

Well, in fact, I think a lot of people know we have a non-op Bakken package that's being marketed right now by The Bank of Montreal, and we would expect bids on that later on this summer. So we're looking at our non-op position specifically as we do always to try to have more control of our capital spending. So we will be selling some acreage this year. As far as selling HBP, operated HBP, we don't have any plans to do that. No compelling reason to do it. I understand that some of that might be worth, some real money but right at the moment we're focused on getting our existing acreage that needs to be HBP'd tied up. Once we get that done then we'll look at broadening that program. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: Okay, and you guys have mentioned in the past that Briscoe might be able to go tighter than 625s. Have you seen anything more on that? And then as far as the IPAA where you last updated and when do you think you all will know where you stand on that?

Well we haven't released any results on it. We don't have any to talk about today. I would expect that we'll talk again about spacing probably at the end of the year. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: Perfect, and one last one if I could, on the 2014 50-50 plant, how do you envision that oil-NGL split?

No, I don't know that I know that number off the top of my head. It's going to get oilier. I can say that because of basically Bakken, Permian, Granite Wash. But I don't know the exact number.

We'll go to the next question, David Tameron from Wells Fargo.

And just -- Jay, just following up on the last question, that 50-50 split. Can you give us any guidance as far as what percentage would be Eagle Ford, what percentage would be Bakken, Granite Wash? I mean do you guys anticipate -- you're going to 4 rigs in the Bakken now, do you anticipate taking that higher in the next couple of years or can you give us any color around that?

Well, that number is coming out of our long range plan model and which assumes about a 5 rig Eagle Ford program, and 4 rig Bakken program going forward. Most of the growth beyond that is really in the real oily Granite Wash piece. And then we have some Niobrara/Permian rig count growth involved in that based on what we're seeing right now. So in general, it's pretty much a flat operated Eagle Ford program, and that's what's built into the model that we're using to do that.

Okay, that's helpful...

When I say flat, I don't mean flat rate. I mean flat rig count, okay?

Yes. And when I think about the -- you're adding the rig now, but then it sounds like you're going to exit at your 5 rather than 6. Is that -- are you retiring the rig? Is it just pad drilling? And can you talk about the reduction in rig count?

Yes, really the idea of going to 5 rigs is if we think that with pad drilling that we can get to where we need to get to on a rate curve without having to run that sixth rig. It's an efficiency issue. It's not that we're trying to slow down. We actually think with pad drilling that we can get to where we were drilling, our original plan was 6 rigs, was 5. And that's just part of what we hope to gain from the efficiencies of the pad drilling.

Okay and just to confirm you just said that Bakken non-op sale, that's included in the guidance, correct?

Can you repeat the question?

I'm sorry, the Bakken non-op, is that in-guidance or is that not in-guidance, production from that?

It is. There's a little rate in there that we would have to -- if we sell it, would have to come out. It's not a big number.

And back to the Eagle Ford, along with some of the other overreaction out there, I guess, I would call it on the gas side, there's been talk about decline rates in Eagle Ford. Have you seen any change in your Eagle Ford op -- operated productions as far as decline rates?

I wouldn't say we've seen a change. I mean, these wells do decline obviously. And they have pretty healthy normal-looking resource play decline rates. But I haven't seen anything that would indicate they're going faster. I would say if you look at some of -- I've had people ask me about public data on some of the wells we completed in the fourth quarter. When we did that down those down spacing tests late last year, some of those wells did have higher declines than the base wells, and I think some people had picked up on some of that. A lot of what we've seen, and you got to be really careful with the Railroad Commission data because there's so many things going on internal to the field in terms of shut-ins, restricted rates for periods of time associated with hooking up facilities. We're swapping out compression. We had these just in the last month a lot of downtime associated with gas offtake infrastructure. Those guys are still starting up their facilities too. I think people assume that these gas pipelines come on, and they just, they're just there. And it really didn't work that way. There's a lot of up and down and we're bringing on new wells all the time, and now we're bringing them on, sometimes 3 wells at a time, and we got to handle all that. So there's a lot of up and down in that public data, very difficult to explain from month-to-month exactly well by well, rate by rate. I'm not even capable of doing it, to be honest. So I think it's hard -- when you look at that data and say well, that it looks like declines are up, it's a little hard to really tell that. Unless you know exactly what the choke setting was on the wells and what we were doing at the time. But in a general sense, I don't see anything that looks like deterioration in well performance in the base well for drilling. In fact, in general, I think our wells are getting better as we learn to frac them. As we move our frac stage spacing closer together. So I don't see that.

All right. And then one final one, Nevada, Noble has made noise about it. Plains is making noise this morning. And you guys have according to the K anyway, a couple of hundred thousand acres out there. Have you -- anything you can give us on that? Any color there or anything you guys have tested or looked at? I guess you haven't tested it yet, but anything you've looked at as far as that acreage is concerned?

Well, I guess I'll continue with a standard comment that we don't comment on our exploration efforts.

But we do have a position there, David. We've had it for sometime but other than that, we're not saying much about it.

Your next question comes from the line of Matt Portillo with Tudor, Pickering, Holt. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just 2 quick questions for me. To start off on I guess the operating efficiencies that you're starting to see in the Eagle Ford and the Bakken, could you give us an update on I guess where well costs are currently running for you guys and maybe where you see those trends moving forward?

You know, we gave a lot of data on well costs at year-end and I would say those numbers really have not substantially changed. And I'll just refer you to the presentation. It has all that data -- because it gives a whole bunch of data on well costs. In a general sense, as I mentioned earlier, we think we see our Eagle Ford frac costs coming down about -- we're thinking about 20% average for the year. In general, I think our well costs however are going to stay about flat. We're going to use most of that cost savings and putting more frac stages into these wells. So we're going to say about 20% per frac stage. We're going to put about 20% more frac into them. That's kind of like when you buy a high mileage car, you tend to drive more. That's what we're doing here with our frac work. Other than that though, I think the best thing for you is to go look at that data we've already provided on area by area. Well costs, it's still I think it's very, very close to the right numbers. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just wanted to check on the update there. And then on the Eagle Ford, I just wanted to clarify again. I think I missed the response in the prepared remarks, but could you just remind me how many wells you completed in your operated acreage in January, February, March?

We didn't actually give the exact number, but I'll be happy to do it. We completed 6 wells in January, 0 in February and 12 in March. So again, 2/3 of our completions were in the month of March. And then of course, we got those done and stumbled right into a pipeline interruption in April. So that's just the nature of the beast.

That wasn't our pipeline there. That was a third party offtake.

But that 0 in February obviously, that's a result of all these pad drilled wells getting completed essentially together and not in the month of February. That's the way it works.

Your next question comes from the line of Dan Guffey with Stifel, Nicolaus. Daniel Guffey - Stifel, Nicolaus & Co., Inc., Research Division: You're still moving rigs around Galvan and throughout Briscoe. At what point do you think you'll have the acreage held and not where you'll focus primarily on pad drilling?

Well, let me back up and talk about leases in these areas. You don't ever get this held in the sense that you're thinking. These are paid up leases, we're under continuous development clauses on all of this acreage. So the obligation is to keep drilling. So you'll never have a situation where you get a well drilled at some spacing and then you got it all held. You hold essentially 600, 640 acres every time you drill a well. But in order to hold it all, you essentially have to drill it all over a period of time. So it's not going to be that we can get to a point and then we go to development. We are in development. And as we pad drill wells, we hold the acreage that those wells drill and we fulfill our continuous development obligation to keep moving in those leases. The smallest lease we have down there is something like 5,500 acres and we hold quite a bit with a single rig as it works. But we will have to drill around the acreage in all of the leases over time in order to hold this entire position together. So you'll continue to see us that -- we got 3 rigs that move very easily -- they'll be pad drilling essentially all the time. And then the other 2 we'll be moving around some Then we'll be pad drilling some and that we're moving to drill these holding wells or continuous development wells over time. We don't have to drill very many wells in the dry gas portion of the reservoir, hardly at all based on the way the leases look. And we won't be but we will have to drill a couple a year a few a year in order to hold them all together. Daniel Guffey - Stifel, Nicolaus & Co., Inc., Research Division: Okay, great. And can you talk about the cost savings between the 3 rigs that are drilling on pads and 2 that are moving around?

Well, I think the number we've always said is $500,000, $600,000 per well cost savings for pad drilling. Now, I want to be frank about this. From a stewardship standpoint, we've got to pad drill. We can't go down there and put a pad out there for every well we're going to drill. It would be an enormous impact on the surface anyway and we're not going to do that. So pad drilling is a necessity of development here. But we do think we save $500,000 or $600,000 per well for the 3 wells that we put next to each other.

I think as Jay mentioned earlier, we're very early in the pad drilling cycle, so I mean those efficiencies will improve. But we got to get up to speed and we're just now getting our walking rigs in place with our pad drilling program. So we got a ways to go. We're off to a reasonable start.

Your next question comes from the line of Nicholas Pope with Dahlman Rose. Nicholas P. Pope - Dahlman Rose & Company, LLC, Research Division: A quick question, just on the Eagle Ford capacity, the Take Aways slide that you have in the slide deck, I noticed there was a change in the net volumes versus gross volumes. They looked like it dipped from like a 14% uplift to a 7% uplift. And I was trying to figure out what caused that and if we should expect that going forward or if it was just near term kind of issues with the Eagle Ford production?

Well, that's just -- those are just our 1Q volumes. And so they change it every quarter. I don't think -- the number that I always use in my head is about a 10% uplift. So I think this seems a little low to me but if you're using a 10% uplift, that's probably a reasonable number over time. At one time it was a little higher, it was more like almost 20% in one quarter early last year. But I think a 10% number is probably a good average. Nicholas P. Pope - Dahlman Rose & Company, LLC, Research Division: Got it. I just wanted to clarify that.

I appreciate you pointed it out. I'm embarrassed, I actually didn't notice that on the slide. Nicholas P. Pope - Dahlman Rose & Company, LLC, Research Division: But I just -- it sounds like it's just -- it bounces around that 10% number which is just what I was trying to -- I wanted to make sure I was correct about that.

Yes it goes up and I think if you were really out there to build the models, I would use the 10% number. Nicholas P. Pope - Dahlman Rose & Company, LLC, Research Division: And then the Mid-Con, you guys are talking about a lot of activity. What was -- do you have the production rate for the Mid-Con in the first quarter?

It's in the Q.

It's in the Q. They're in the Q. I don't have them right here.

I'm showing no further questions. Thank you.

All right, well again, thank you very much for your focus and attention on SM Energy this morning. Stay tuned for our next quarterly report. Thank you all for dialing in.

Thank you for participating. This does conclude today's call. You may now disconnect.