SM Energy Company (SM) Q2 2013 Earnings Report, Transcript and Summary

Good morning. My name is Melinda, and I will be your conference operator today. At this time, I would like to welcome everyone to the SM Energy Second Quarter 2013 Earnings Conference Call. [Operator Instructions] Thank you. Mr. David Copeland, Executive Vice President and General Counsel, you may begin your conference.

Thank you, Melinda. Good morning to all joining us by phone and online for SM Energy Company's second quarter 2013 earnings call and operations update. Before we start, I'd like to advise you that we'll be making forward-looking statements during this call about our plans, expectations, pending divestitures 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 that was filed on February 21, 2013. We'll also discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliation of these measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release from yesterday. Additionally, we may use the terms probable, possible and 3P reserves and 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. Company officials on the call this morning are Tony Best, Chief Executive Officer; Jay Ottoson, President and Chief Operating Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; Brent Collins, Senior Director of Planning and Investor Relations; and I am the company's Executive Vice President, General Counsel and Corporate Secretary. I'll now turn the call over to Tony.

Good morning, everyone, and thank you for joining us for the second quarter 2013 SM Energy earnings call. We will be referencing slides this morning that we'd posted on our website yesterday. I will begin on Slide 3. The company had an excellent second quarter. I know most of you have already reviewed our press release from yesterday, so I'm not going to go over that in detail. However, we had a very strong quarter on the production front, driven by our growth from all of our development programs led by our operated Eagle Ford. In fact, we set a new quarterly production record for the company in the second quarter. Guided costs in aggregate came in at the lower end of guidance. Adjusted net income was $51.8 million or $0.76 per diluted share, and EBITDAX setting new quarterly record at $342.5 million. I'm now on Slide 4. As we press released yesterday, we are increasing our production forecast for 2013 by approximately 10% to a range of 47.3 million to 48.6 million barrels of oil equivalent, with only a corresponding 3% increase in development capital. The operated Eagle Ford program is the largest driver of this increase in production. In that program, we're going to be able to drill, complete and flow to production roughly 20 more wells, at a total cost close to our original budget for the year. We are benefiting from a number of efficiencies in both the operated and non-operated programs in the Eagle Ford that Jay will talk about in a little bit in his review. I will also point out that there is essentially no contribution assumed in our 2013 production guidance from our new play areas in East Texas and the Powder River Basin. Yesterday, we also reiterated our 15% per annum production growth targets for 2014 and 2015 on retained properties. Given that we are increasing 2013 production by 10%, the production numbers in 2014 and 2015 are expected to be 10% higher as well. These targets assume that we'll close our previously announced planned divestiture of Anadarko Basin assets on January 1, 2014, and that these assets will contribute approximately 3 million barrels of oil equivalent of production this year. These growth targets assume modest success in our Frontier program in the Powder River Basin and minimal success in East Texas. So with the tests, these growth targets could improve perhaps significantly. I'm now on Slide 5. With respect to our revised capital forecast, we are increasing our capital program for 2013 to approximately $1.65 billion, which is a 10% increase over what we had originally budgeted. As I mentioned earlier, our development capital increased slightly to $1.24 billion. Our development program remains focused on the Eagle Ford and Bakken/Three Forks, with 75% of our development capital being allocated to just those 2 plays. The biggest portion of the capital increase relates to our non-development capital that will provide inventory to drive our future growth. The $65 million acquisition of Powder River Basin acreage that we previously announced wasn't budgeted, so that is part of this increase. Our revised capital guidance also includes an increase in non-development investment in our new ventures effort where we continue to test and delineate our emerging East Texas and Powder River Basin plays. Moving to Slide 6. I'd now like to take a minute to talk about a key element of our business strategy. Because we intend to be a long-term business enterprise, we know that we need to replace inventory, and you can do that in 1 of 2 ways. You can grow organically, through self-development, or you can buy it through acquisitions. Our first preference is self-development because it generally allows for higher returns and the downside risk is less impacting. I know that when I talk with many of you in the investment community at conferences or during one-on-ones, we talk about ideas and projects being worked in our new ventures program. But today I want to explain why we have such a program. On this slide, you can see the phases of our new venture process. I'm not going to go through all the steps in detail, but the general idea is that we distill a number of geologic concepts down to a couple of potentially impactful prospects that, if successful, will ultimately compete in our development portfolio going forward. That is not to say we will never do acquisitions. We think that acquisitions have a place in our business strategy, particularly when we believe that we may know something differential about an asset. We have and will continue to evaluate a broad range of acquisition opportunities. Moving to Slide 7. You can see how new ventures fits into our overall business strategy. As a resource play company, you must restock your project inventory so you can continually high-grade your portfolio going forward. Remember that the key plays growing our company today, and I'm speaking primarily of the Eagle Ford and the Bakken/Three Forks, were sourced as new venture efforts 4 or 5 years ago. As you can see, core development remains our primary focus as we work to concentrate our capital on our highest rate of return projects. We intend to operate our projects so we can control the pace of investment and the quality of development, which allows us to improve our returns. We focus on debt-adjusted per share metrics because we believe that is the right way to gauge our performance. When it is clear that project or asset will no longer compete within our portfolio, we look to monetize it and redirect the proceeds to higher-return projects or to enhance our balance sheet. With that, I'm going to turn the call over to Jay for his operational review.

Thank you, Tony, and good morning, everyone. As indicated on Slide 9, we grew our corporate production volumes by 15% quarter-over-quarter and we're up 42% from a year ago. All of our development areas had nice production gains for the quarter led by our operated Eagle Ford asset. Moving to Slide 10, I'll discuss the operated Eagle Ford. Obviously, we had a really strong quarter. We grew 28% on a sequential basis and 92% year-over-year. We benefited in the quarter from a large number of new wells being connected to sales and added capacity in our gathering system. Our swap drilling program resulted in nearly all the wells brought on in the first half of 2013 being in lower condensate-yield Galvan and Apache Ranch areas of the field. We also had a number of oilier producing wells shut-in due to simultaneous operations associated with completing new wells. As a result, the production mix is gassier both for the Eagle Ford program and the company in total for the quarter. As we move into the third quarter, our oil rate will pick up as most of our new wells being currently brought on production are in higher yield areas on the north side of the field. In fact, I can say that our oil volumes are already up strongly in July. On the infrastructure front, our gathering infrastructure will be significantly expanded in the second half with the addition of 8 new field gathering centers to our existing 10. Our guidance assumes that tie-in of these new facilities may curb our production growth for periods of time later this year, but these new facilities will allow us to continue to increase rate and reduce field separator pressures in 2014. I should note that we use interruptible downstream wet gas transportation on a daily basis all quarter in addition to our contracted firm transportation. Our firm gross wet gas transportation level rose again in July by 80 million standard cubic feet a day to 380 million standard cubic feet per day. However, we do anticipate utilizing interruptible transportation again by year end and in the first half of next year and don't foresee any problems with space being available. The biggest story in our Eagle Ford program, however, is really in our increasing development efficiency. Our last 15 wells in the Bristol area averaged $5.4 million per well, a 13% decrease in the cost per foot of well over the last year. Because of these cost savings, we expect to now be able to bring on 95 wells in 2013, a 20-well increase over our original plan, while spending little more than our original budget. In summary, at this point of the year, our operated Eagle Ford production is ahead of where we expect it to be, and our improved capital efficiency in the play is the major reason we can increase our corporate production guidance with very little additional spending on rate-generating projects. In a non-operated Eagle Ford, I'm now on Slide 11, production was up 9% quarter-over-quarter and is up 83% since last year at this time. Anadarko accomplished a lot of facility tie-in and new plant startup work during the quarter, so it was a very busy time for them. We are encouraged by the decreases we're seeing in Anadarko's well costs and some of the experimentation they're doing to further reduce costs and do longer laterals and revised frac designs. We learn a great deal from our partnership with APC, which is an additional benefit to us beyond the opportunity to participate in a very economic development. We believe the operator will be running at least 9 rigs for the remainder of this year. As you know, we're being carried by Mitsui on essentially all our share of drilling and completion costs into 2014. Moving to Slide 12. During the quarter, in our Bakken/Three Forks development area, we swapped out 2 older rigs for a more efficient pad drilling rig. And we're now operating 3 rigs in the program, which we plan to do for the remainder of this year. During the quarter, we brought on 12 new operated wells and saw sequential daily production growth of 12%. In our current primary drilling areas, Raven and Gooseneck, we have seen operational efficiencies from the implementation of pad drilling. Our Gooseneck well costs are down about 8% from the numbers we quoted at year end 2012 to about $6.5 million. We're participating with others in Bakken downspacing tests in the Raven area and a lower bench test in the Three Forks. There've also been some interesting industry results recently in the Bakken interval, near our Gooseneck acreage, where we've been drilling only Three Forks wells previously. So we believe there are continued opportunities for adding economic resource in our Bakken/Three Forks play area. I'm now on Slide 13. In the Permian Basin, we grew production 25% on a sequential basis to 6.6 thousand BOEs per day. This is largely being driven by increased contribution from our Mississippian Lime play as we completed several more wells there in the quarter. We also drilled a Wolfcamp shale well in the southern Midland Basin that is currently flowing back after completion. We hold about 20,000 net acres in the southern basin, of which about 2/3 is operated. Of the 3 rig program we plan to run in the Permian in the second half, we now intend to maintain a single-rig program focused on shale wells. We'll also be participating in wells on our non-operated acreage targeting shales. On Slide 14, we have included the synopsis of new ventures activity for the quarter. During the quarter, we closed on our previously announced acquisition of approximately 40,000 net acres in the Powder River Basin. Our objectives in stack pay basin are the Frontier, the Shannon and the Sussex. We have a total of 110,000 net acres in the Powder River Basin. We'll be picking up a rig to start our development there during the second half of the year. In East Texas, we continue to build our acreage position. During the quarter, we added another 45,000 net acres to our position, bringing our total committed acreage to 195,000 net acres. We just started up a rig there and are planning to add a second rig later this quarter. We hope to have some additional well tests to share with you by late this year or early 2014. We'll be testing both the Eagle Ford and the Woodbine, and there are some other intervals of interest as well. In other business, as Tony mentioned, we've already announced that we're moving forward to sell our assets in the Anadarko Basin, including our position in the Granite Wash. We expect the data room for that package to be opened in September. We also have several smaller, largely non-op packages that are being marketed right now. We hope to have all these deals closed before year end. With that, I'll hand the call over to Wade for his financial review.

Thank you, Jay. Good morning. I'm on Slide 16. During the second quarter, we issued $500 million of high-yield notes with a 5% coupon rate and the 10.5-year maturity. We used the proceeds to pay off our revolver. To be frank, the issuance was mostly opportunistic as a 5% long-term unsecured coupon was too good to pass up. As you can see from the left side of the slide, our capital structure remains very straightforward, with 4 pieces of senior debt and a revolver. Debt to trailing 12 months EBITDAX actually fell slightly in the second quarter, and our debt to book capital remained flat at 52% from the first quarter of 2013. On the right side of the slide, you'll see that the earliest debt maturity is not until 2018. With respect to liquidity, our revolver, which was nearly undrawn at the end of the second quarter -- full [ph] commitment amount of $1.3 billion and a total borrowing base of $1.8 billion, so we have plenty of dry powder. Moving to Slide 17, I'd like to discuss how we look at leverage. We believe debt to trailing 12 month EBITDAX is an important metric, and one we use to manage the balance sheet. By the way, it's the only financial covenant in our loan agreements other than to maintain positive working capital liquidity. Our current debt to EBITDAX multiple is well below the peer average of 2.5x. In fact it decreased slightly in the second quarter to 1.3x. We now expect to be below the previously guided 1.6x at year end 2013, despite the increasing CapEx that Tony discussed. We're trying to manage our leverage to a point where we can invest in projects that provide superior returns and grow EBITDAX, production and reserves on a debt-adjusted per share basis. Lastly, with respect to hedging, we did add some hedges in the second quarter. We actually now have the highest percentage of PDP hedged that we've had in recent history. As most of you know, we sell most of our operated Eagle Ford condensate in prices linked to LLS prices, so we added some basis swaps to help protect our Eagle Ford pricing. We also layered in some more natural gas hedges when we saw prices up around $4. Details of our hedging position can be found in the Appendix to this presentation and in the 10-Q filed this morning. So with that, I'll turn the call back over to Tony for his closing remarks.

Thank you, Wade. Before we turn the call over for questions, I want to touch on a few closing key messages. First, we had a strong second quarter, with reported production well above our guidance range. We also performed well in our total cash cost, coming in at the lower end of our guidance. Second, we have increased our full year production guidance by 10% with a range of 47.3 to 48.6 million barrels of oil equivalent. And we're also increasing our production outlook for 2014 and 2015. Our development programs, as Jay mentioned, are performing well. And with success in our new ventures program, there is upside potential to our production outlook. And these programs could fuel our growth for years to come. Lastly, as Wade mentioned, our balance sheet remains strong, and we expect to end the year with debt to trailing EBITDAX below 1.6x even with our capital guidance increase for 2013. With that, I'll turn the call over for your questions.

[Operator Instructions] Your first question comes from Nicholas Pope with Cowen and Company.

Just looking at the big bump you had kind of in the softer guidance for 2014 and '15 production numbers. I know you'd spoken previously about trying to get CapEx and cash flows fairly close to one another within the next year. I was wondering what the thought process is now with that increased production profile, if that's going to change kind of the viewpoint of CapEx spending over that same time frame.

Yes, Nick, this is Wade. Obviously, we'll give much more specific guidance later this year on next year. I think the comment I would make is that we feel very confident in reaffirming that 15% growth even on the higher production number. And I would say that from a standpoint of what's assumed in there, I think earlier we said it was based on our current programs, I would say there's no East Texas assumed in that projection. And with respect to PRB, there's a modest contribution from PRB. I think that should help you in your thinking from a standpoint of what's included in the general assumptions in that growth. I think the answer to are we going to exit the year with EBITDAX in excess of CapEx? I think the answer -- I would answer that as saying, we could. I would also tell you that if we don't, it'll be due to good reasons like spending in East Texas, PRB and maybe some success in Permian shales. But again, we'll give much more specific guidance on that later this year.

All right, that's great. I appreciate it. And then just kind of a housekeeping. On the drilling carry from Mitsui, do you know where we are -- I guess, where we stand right now, how much is remaining and I guess where, with kind of their increased pace, where that might kind of switch back to kind of everybody paying equal costs?

Yes, our thinking now is sometime around the middle of 2014 probably late 2Q, early 3Q. We just, obviously, we'll be watching it closely and it will depend on the pace of capital from Anadarko.

Your next question comes from Jeb Bachmann with Howard Weil.

A few questions. I just wanted to dig a little deeper into the improving well costs in the upper Eagle Ford. Jay, if you can give a little more detail as to where you saw those improvements, were they on completion design or efficient rigs, just if you could?

Yes, thanks, Jeb, for the question. I think it really is an important one. And I would have to say we're seeing improvements in all areas. A lot of it is days-to-depth, we're just drilling faster, and I give the guys in our drilling department a lot of credit for that. I think if you look at us from an industry standpoint, I think we're one of the quickest drillers in the basin down there now. And our completion efficiency is getting better. Our pumps are ready when we need to pump, we're just getting better everyday at getting these wells completed. So I'd say it's pretty much across the board. There's obviously some benefit associated with our pad and swap drilling as well that's incorporated.

And Jay, do you think the trajectory of that will continue to move down going forward? I mean, how much additional improvements do you think you could realize?

Well, obviously, that's a more difficult projection. We've made so many strides, it's hard to say, it's not going to continue forever, obviously. I think there is some room to continue. I think we're also going to be focusing on drilling maybe some longer lateral wells and experimenting additionally with our completion. So those things may work against cost reduction, but may help us on the EUR front.

Is this primarily in area 1 or is this also area 2 and 3 where you're seeing these improvements?

Well, we have seen improvements in area -- in the Galvan area, area 3 before. We really haven't drilled much in area 1 since last year. So the last 15 wells we drilled are largely area 1 wells, and so that's why you see the big decrease versus last year. We've already seen these kinds of reductions in our drilling program in Galvan, the area 3, earlier this year. So just a continuation of a trend.

Okay, great. And then just a couple of quick ones. One, you mentioned the production mix should improve on the oil side going into 3Q. Are we looking back towards 1Q levels or maybe even a little bit north of that?

I should say -- this is Jay, and I forgot to mention this is me. The numbers are strongly up. We fully anticipate getting to that 50% gas production split by year end. I don't know that I actually even know where we are relative to the first quarter right now, but we're up strongly from the second quarter.

Okay. And then on the asset sales, how much of that is going to eliminate the MPPs [ph] on your income statement?

I think it's going to be similar, around $9 million or $10 million, Jeff.

Okay. So you'll still have some leftover even with those asset sales?

That's true. I believe the -- on the balance sheet that we just released, it's around $70 million so, yes, down to 60-ish.

Okay, and then just one quick one on -- Jay, you mentioned on the interruptible takeaway end of this year into next year. Do you have a percentage of how much you're going to be shipping on interruptible takeaway?

The last time we looked at it, the number was about 7% in total. But that depends very much on what our actual production -- how our actual production lays out. So that was sort of on a guided basis.

Your next question comes from Subash Chandra with Jefferies.

So on Briscoe, curious how you're sort of looking at second half drilling as far as EUR expectations go to get closer to that 600,000 BOE type curve. I think on the last call we spent some time on pretty valid reasons to why you weren't quite seeing the numbers that you thought, maybe refresh those thoughts. The impact of RCS, have you tried it there and if you can try it there? And that downtime that you referred to on oil, if there's a way to quantify that for the quarter? Then I have a follow-up.

Well, I think I heard 3 different questions there, and I'll try to answer the first one first. Briscoe, the new wells are just starting production, so I don't really have any comments on EURs relative to those. We did talk about that on our last call. In fact, if you look at our type curves in area 1, all our type curves are driven based on gas production and then we apply a yield. If you look at the type curves that we put out for area 1, the gas forecast that we put out play right through the middle of the historical data if you adjust for downtime. Really, the issue is yield. And as we mentioned on the call, last call, we were drilling in the higher yield areas of the field today. And those are the wells we'll be bringing on. So what we'll really be looking at over the next 6 months is how does that yield look versus our expectation. You made a comment about some specific technology, RCS, and right at the moment, that's escaping me as to what you mean by that. I think maybe that rate transient analysis...

I'm sorry, I meant what your spacing is, your frac spacing is, and if there's a way of trying to replicate maybe some of the other parts of the Eagle Ford and other liquids-rich plays to get those -- get them through frac spacing?

Definitely. We're looking at a number of different things, and I will say APC is as well, longer laterals, different frac spacing to, try to improve our performance in the oilier areas. The issue you have to deal with in a lot of our northern areas, especially in the northwestern part of our acreage, is you have a lot lower pressures as well. So I think we need to do more work there. We frankly just have not drilled that many wells in that area of the field, and we need to continue to experiment to try to drive improved performance. And then I'm forgetting the third part of your question, if you could repeat that.

The Briscoe oil downtime?

Oh, I don't think I can actually quantify that for you. But I can tell you that by looking at the morning reports that I see, we've had a large percentage of oil shut-in -- a larger percentage of oil shut-in during the second quarter. The way our swap drilling program works is we actually drill and complete the wells all in one area, and we have a lot of wells shut-in before we bring them on. So if you look at this year's schedule, we drilled and completed a lot of Galvan area wells way back in the first quarter and then brought them on, on the second. We've been drilling and completing in the Briscoe area basically in the second quarter, and we'll be bringing them on in the third. Because our wells in the Briscoe area are higher-yield, typically, those simultaneous operations differentially impact oil production. As I said, earlier, we're seeing strongly higher oil rates already in July. So we think essentially, we'll get back on what I suppose most people would have regarded as a normal trend for oil. We anticipate oil rated being down a little bit this quarter.

Okay. And a final one for me. How are you thinking about PRB repeatability versus Eagle Ford? I know it's early, but if you have any thoughts there.

Well, I think your comment, it is just really early. So far, so good. Everything we drilled is confirming what our type curves to date. We don't have any reason to doubt our type curves, but it's very, very early.

As you think about is it -- do you see more of, say, a distribution curve similar to conventional play, or do you think there is some type of shale repeatability here based on some of those subsurface work you might have done?

Well, what we've seen so far is we think that -- well, we will call it a P10/P90 range is really how you measure this on EURs. What we've seen so far is that we think that range is not going to be super real, real wide. It looks more like a shale play from that standpoint. But again, it's very early.

Your next question comes from Matt Portillo with Tudor, Pickering, Holt. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just on the operated Eagle Ford, just have 2 quick questions for you. Firstly, as we look at the completion count, pretty similar to the first quarter but obviously saw a pretty dramatic uptick on the wells, kind of look like 2x productivity on the wells. I was just curious if that was a function of -- purely a function of where you were drilling those wells or that is also a function of improving IPs and EURs in the play? And then the second question I just wanted to ask you, if you could just give us a little bit more detail in terms of the spud-to-spud times for you guys and how that has changed over the last year or so? And then ultimately, where you think kind of the technical limitations may be on drilling times.

Well, I'll comment first on why the production seems a lot higher in the second quarter. A large part of it is really capacity availability in our gathering system. We added compression during the quarter and did some additional facility work, had some excellent performance by our gathering system provider, Regency, which allowed us to bring on a whole bunch of new wells at pretty high rates. We were drilling frankly in the best area of the field in the first quarter, and brought on a lot of those wells in the second quarter. Too early to say whether the EURs are better but certainly a lot of really strong wells in the Galvan area, which frankly is what we anticipated. And we were able to take advantage of that during the quarter. As far as exact spud to spud numbers, frankly, I just don't have the data in front of me. And I don't want to misquote the number. The numbers are down, and they've been down all year, and we have seen significant cost reductions. As far as technical limits, we're very close, at this point, I would say, when you start to look at that kind of perfect well process and how fast can you drill each section, we're pretty close to where we thought we could get. Now that doesn't mean that we can't do better, I think we can do better over time. But certainly they're diminishing returns. Once you're drilling these wells in 9 or 10 days, it gets harder to get it a lot faster. And frankly, another day doesn't save you that much money because you still got to complete the well. So I think a lot of what we need to focus on now is really okay, our drilling machine is really running well, we really need to focus on how do we make better wells. Particularly in some of the oilier areas of the field that are lower pressures where we actually have thicker reservoir, how do we make better wells, sort of the question I've talked about earlier. And we're going to put some significant effort into that. Anadarko is a good friend to us in this sense in that they're doing a lot of experimentation with that as well, so we learn a lot from them. That's really going to be the focus I think of our technology effort over the next year or 2. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And then just one quick follow-up. In terms of the Permian, we've seen some interesting results for you guys in the Miss [Mississippian limestone] and you're drilling your first Upton well now. But I think offset industry data looks very encouraging. Could you talk a little bit about the scalability of the asset, how material this could be for you over time and maybe a little bit about how you think about the long-term plans in the play if you kind of ultimately prove up the commerciality potential there?

Well, we mentioned earlier that we have about 20,000 acres in the Southern Midland Basin. There's multiple potential pay zones in the Wolfcamp section, for example, on most of that acreage. And it's a really good area. I mean, a lot of our acreage is not very far away from some of the bigger wells that have been announced in the Southern Basin. We also have additional acreage in the Northern Midland Basin. And so I think we still need to test that. There's still some industry testing in the Northern Midland Basin that we're looking at. But it can add up to a lot of locations. If it works, and especially if you can pursue multiple benches, it's a material addition to our resource. And I really believe, I think the Wolfcamp shale, if you look at all the shales that people are chasing in the Permian, I really think the Wolfcamp is the place to be, both on the Midland Basin side and on the Delaware Basin side. I just think it's the shale I think that's got the most, okay. So we think it's material. We're obviously attempting to build position where we can. It's expensive, but we want to build more position there.

Your next question comes from Scott Hanold with RBC.

Just want to go through a couple of things. Obviously, you had a very strong production coming from the Eagle Ford. The transportation cost in that region were quite a bit higher than, I guess, I had expected. Is utilizing interruptible part of that dynamic where interruptible will inherently carry a higher transportation cost, is that a true statement or not?

Scott, that's actually not true. But let me explain transportation cost for you. It's a really good question and needs to be answered. It's not really the interruptible that's driving the higher cost. There's several things. First of all, the unbudgeted volumes that we produced are all being produced to our last pipe, the last pipe in our firm transportation kind of the pile of bricks that we've built with firm transportation, and we're also using that pipe for the interruptible, so it's going to the same place. That last pipe has the highest per MCF transportation cost. It also has the highest NGL recoveries so the economics are very similar to the rest of our pipes, but it has the highest incremental transportation cost, the stuff that actually shows up as transportation cost. So as we increase volumes to that pipe, our transportation cost go up disproportionately. During the quarter, we also started -- during the first half, we also started up additional compression in the field, which we pay additional fees to our gatherer for that. And we have to pay for the fuel for that. And I know it doesn't seem like it, but gas prices were actually a little higher in the second quarter so our fuel costs were up some. So those are the major things that have been driving and are driving our transportation costs up. The lion's share of our company transportation costs really relate to Eagle Ford wet gas transportation, both operated and non-operated. And so as those volumes go up, the corporate numbers go up, but the Eagle Ford operated numbers have been going up for the 2 reasons that I have given you.

Okay, okay. Now, that's very good, that's very helpful. And the other thing is your goal to get 50-50 gas to liquids by year end, what assumptions are built into ethane rejection to that? Is there any improvement on that by the end of the year?

Scott, we -- I think we've talked about this before. There's about 2 to 3 BCF impact associated with ethane rejection that's baked into our numbers. So obviously, if we weren't rejecting, we'd get there quicker. It's not a huge a material impact. We think we'll get there anyway. We are still rejecting ethane under contracts in the Eagle Ford where we can do that or where we have that election.

Okay, okay, fair enough. And then one other question, on the Eagle Ford wells that you'll be bringing online in the back half of the year, more oily than some of the average mix right now. So if you look at your Eagle Ford operated, roughly 63% gas in 2Q, can you talk about some of those new wells coming online, what percentage oil versus gas those are going to have?

Scott, I don't have those numbers directly in front of me. It's going to go very much in an oilier direction. And so if that percentage is going to move, what you're seeing, what you're going to see is our gas rates aren't going to go up as much but we're going to become oilier over the next couple of quarters.

Okay. And as far as the Eagle Ford itself, I mean, what would you -- 50-50, the total company, what could the Eagle Ford be around the end of the year in terms of oil-gas mix?

Scott, I don't think we've ever guided that. And I really don't know the exact number. I know how it mix up in the total overall corporate number, and obviously it drives a lot of our corporate performance, so it's going to get oilier, but I don't have the exact number for you.

Your next question comes from Welles Fitzpatrick with Johnson Rice. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: Looking at the public data, it doesn't seem like you guys have had any significant issues getting permits up in the PRB, is that an accurate statement?

This is Javan again. We haven't had trouble getting permits for the activity we currently have planned. I think what we've try to do, we're going to pick up a rig in the second half, we have a plan, our tentative plans for '14 are to pick up additional rigs. We're certainly trying to stack up permits, enough permits to keep a multi-rig program going for a number of years. Typically, I think we've tried to guide people to a relatively modest rig count in Powder just because Federal permitting is slow and arduous. And we don't want to give people the impression that we're just going to run in there and throw a huge rig count at it. But so far, and we have good relationship with the BLM. We're working hard to make sure that when we submit permits, that they are complete and accurate, which is very important to them and to us. And we haven't had trouble of getting permits at this point. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: Okay, and then if I remember correctly, your next Frontier well is going to be on sometime around midyear. And obviously, you don't have the results for us today. But is that far along enough to comment on the cost relative to the $14 million to $15 million for the first batch?

Well, our costs are still higher than the $14 million, $15 million ultimate cost that we think we'll be at. I think that well probably is going to run almost $16 million by the time we're said and done. But...

That's a lot of science, I mean...

Yes, the well there is -- that particular well didn't have a lot of science with it, but it's new and it's deep and clearly, it was a little more expensive than where we expect it to be. The $14 million, $15 million range assumes that we're going to optimize somewhat. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: Okay, and then one last one. As far as the Eagle Ford and East Texas, it seems like there are a couple of schools of thought, Clayton Williams having success just below the Chalk, and Halcon finding success just above the Buda. Do you guys -- is it just too early to say where you think you are going to be landing these within the Eagle Ford zone?

Well, yes, I think it is. There's a lot to learn. It's a very large acreage position. We've only announced 1 well, I think, in that oil play so far. There's a lot of things going on, there's a lot of people drilling, and we're obviously going to learn as much as we can from other people.

Your next question comes from Ryan Todd with Deutsche Bank.

A couple of questions. First of all, I guess in the Permian Miss. Last quarter, you had released the results of your first longer lateral well there, and I know you turned on some additional wells in the quarter. Any additional thoughts on the longer lateral well program there, it's potential? And then how should we think about -- we've heard quite a bit about the Permian Wolfcamp. What are your current thoughts on the Permian Miss and at what point do you think you might be willing to give it a thumb's up or thumb's down going forward?

Well, we completed a couple of additional wells in the Miss during the quarter and nothing really -- not really any new news there. I think in general, we said at the last call that we think the central and northern areas probably look better to us and I think that's still true after the completions we have made. We had some issues getting these wells lined out, but -- so we didn't talk about rates this quarter. I do think the longer laterals helped. There's still a wider 10/90 range on the Miss program than generally we're comfortable with for -- to really put our foot on the gas. So we're still -- we have an argument going on whether we're still delineating or whether we're really developing at this point. And I guess I would say we'll probably lean a little bit towards still being a little bit in delineation mode. As far as the Wolfcamp shale goes, there's some great wells in the basin. We're watching that with great interest and we're picking up rigs, so it tells you how we feel about it.

That's great. And then, I guess just one final follow-up on the operated Eagle Ford. I mean, how should we think about -- I guess, in finalizing your numbers next year, how should we think about activity levels from a well count point of view? Is this year's well count a decent way to think about it or should we see some upward pressure on that?

So your question was specific to the Eagle Ford, is that right?

Yes.

I think in general, you should expect that our well counts will be similar. We've got a lot to do, we've got a nice program going. We are drilling great parts of the field, and I think our rig count, our well count, completed well count will be very similar to this year's.

Your next question comes from Mike Scialla with Stifel Nicolaus. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Question is for Wade. That other expense item this quarter, $35 million, can you say what was included in there? I think you had the royalty adjustment of $10 million, but beyond that, what else was in that $35 million number?

Wade, do you know the detail of that?

I do. So that's GAAP marketing expense, Mike. So if you opt in [ph] revenues, other revenue, and this is GAAP marketing, so those net down to essentially 0. Which they typically do every quarter. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Got it. Okay. And then Jay, you mentioned in the Gooseneck area that there's some interesting developments going on in the Bakken. I thought the water cut in that area was very high, which have been preventing development of that in the past. Can you talk about what has changed there?

Well, they've been some completions on the eastern end of our acreage that are interesting. The logs look wet, and so it's a little surprising to us, frankly, that the wells are performing as well as they are. It's still very early and it may turn out not to be great. But it is interesting. It's definitely an upside to our acreage. Mike, I know you're interested in the Powder as well. I want to go back to the question I was asked earlier about well costs down there, and just make it clear, what we're drilling in the last well we drilled, that I mentioned cost $16 million, is in one of the very deepest parts of the Powder River Basin. It has a very long lateral on it. So it's going to be on the higher end of our cost range. I do think we're going to get our well cost down there over time. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Okay. While you're talking about longer laterals, you alluded to that in the maybe in the Briscoe area as well. Can you talk about what length you're looking at? What have you seen Anadarko do in that area?

Well, they're talking -- and I can't tell you what are they drilling, but they're talking about going up to 7,000 feet or more, and I think that's typically where we need to go. We haven't drilled one at that length yet. Frankly, we've been waiting for some of our gathering facilities to be put in place there before we spend a lot more money in those areas and the more remote areas of Briscoe. But I think over time we need to test longer laterals, tie their frac stage spacing and potentially even with that, maybe downspacing again. So there is some additional work to do. There's a lot of acreage out there, and we have quite a bit of time. But I think we need to test the longer laterals and we'll be doing that and Anadarko will be doing that. So we'll learn a lot from both sides. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Okay, and then one last one for me. On East Texas, you alluded to some other intervals that looked interesting. I know you drilled the Chalk well in the past, which I think was pretty much dry gas. Can you talk at all about what other intervals you might be contemplating there?

Well certainly the Chalk. I didn't mention the Chalk specifically, and that was the one that was really at the top of my mind. There are some great areas in the Chalk. As you go east there, we think we have some opportunities in that. There's some other intervals as well, but I don't think we're ready to really discuss those yet. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Can I assume that where you're looking at the Chalk, it would not be a dry gas area?

Well, that was our intent originally. Yes.

Your next question comes from Brian Velie with Capital One Southcoast.

A quick question on one of the slides in the new presentation, I noticed there's a footnote about Anadarko Basin proceeds for guidance purposes being assumed to happen at the start of next year. I wondered if those proceeds figure into the 15% growth in '14 and '15 or that would be additional powder that you could put towards faster growth?

Correct. They did not factor in to that growth estimate.

Okay. And then kind of along the same lines, for the debt-to-EBITDA (sic) [debt-to-EBITDAX] multiples, being inside of 1.6x, does that also not include any proceeds from those sales?

Correct. It does not include.

All right. Great. And for CapEx spending this year, after the increase this quarter, it looked like about $1.25 million of the $1.65 million is going to be, call it, developmental and drilling. Do you think that same ratio will hold in '14 or '15 or do you feel like you might pull back a little bit on the new venture spending?

Yes, I think it's probably too soon to tell. Clearly, it depends on how much success we have, and we hope to be successful. I think the debt-to-EBITDAX metrics that you're talking, that's the metric that really matters if we want to maintain a good, healthy balance sheet. But certainly, we have success, we have the capacity to develop our successes. And selling some assets and trimming our portfolio certainly contributes to that.

Your next question comes from Pearce Hammond with Simmons & Company. Pearce W. Hammond - Simmons & Company International, Research Division: Regarding your non-operated Eagle Ford asset, which has performed exceptionally well, would you consider divesting this asset to help fund the development of your high-impact emerging areas like East Texas, Powder River Basin and Permian?

Yes, Pearce, I would say -- this is Tony. Obviously, we continue to look at our portfolio every year. And certainly, this year, our focus has been on the Anadarko Basin. Plus don't forget, we still got our Mitsui carry taking us through mid next year, as Wade talked about earlier. So I mean, there's issues there that certainly we would have to address if we were to seriously consider a divestiture. But right now, I would say that program is working extremely well. Jay talked about our ability to learn from the Anadarko operation, as well as our own operated. So I would say right now, we like the positions we're in, in both the operated and non-operated. But going forward, we'll continue to look at our portfolio and see if it ever makes sense for us to consider that as a candidate.

And then, I know you all do not guide realizations. But given the compression in the LLS WTI spread in the past month, can you provide any broad guidelines on how to think about oil differentials for the second half of the year?

Well, I think as Wade mentioned, our Eagle Ford production trades off LLS. So you need to focus on the LLS number, and we're going to trade relative to that number. So as LLS moves up and down, those differentials move up and down. It's about half our crude production, rough numbers I believe, forgive me if I'm a little off on that, but that really is what drives Eagle Ford nets. We haven't really seen any real degradation and the, I would call the gap between LLS and our pricing, but LLS does move around.

And then last one for me. Service costs in the Eagle Ford and the Bakken, how do you see those for the remainder of this year. And then as you start doing some planning for '14, do you think that's flattened out or maybe some potential further declines?

In general, we're assuming flat. And I think that's consistent with the kind of numbers that we're seeing.

Your next question comes from Michael Hall with Heikkinen Energy.

Michael Hall, Heikkinen Energy. A lot of mine have been touched on. I guess I just wanted to circle back a little bit on the kind of quarterly progression around oil growth. Can you quantify by any chance how much oil volumes roughly were shut-in, in the second quarter?

I can't give you an exact number because I haven't added it up. I just noticed as I looked through the reports, if you look back over the last couple of quarters, we had a larger volume shut in, in the second quarter, and that was one of the rationales for oil rate being down. As I said, our oil rates were up substantially already in July as we begin to bring these wells on, and I think you'll see a reversal in that trend.

Great. Fair enough. And in terms of the kind of remaining wells to be completed throughout the course of the year, if by chance that splits on how many will be in, let's say, area 1, areas 3 or area 2, is the vast majority going to be in area 1 at this point or -- I'm just trying to show it in my model.

Well, I think what you'll see in the third quarter, the majority of the wells coming on are going to be area 1 wells. They're going to be pretty oily. The fourth quarter, we're going to move back, we'll be moving back into some of the leaner areas of the field, so I think what you'll see over time here is oil rates will come up nicely, I think, in the third quarter and then will get back to sort of a normal progression in the fourth.

Okay, makes sense. And on the incremental 20 wells for $5 million, I'm trying to understand that a little better just in terms of how much of those incremental 20 wells were maybe already had some drilling costs associated with them that have been accounted for previously. Are full D&C costs associated with all 20 of those wells or some of that just kind of fall out of backlog and so there's only the completion costs associated with it? And then of those 20 incremental wells, are those predominantly in Briscoe or is that spread throughout area 1 and 3. Few questions, sorry.

Great questions. I'm not sure I have the level of detail to really answer it well for you. The number we gave I think was $5.4 million. I want to make sure that we're not talking about in the Briscoe area. And in general, when we're talking about our budget, we have carry ins and carry outs every year. I don't think there'll be a substantially different level of carry in versus carry out in terms of money or wells. Our well costs is not just down in Briscoe, it's down across the board. We've talked about our Galvan well cost coming down earlier, so we're saving money on all our wells essentially and we're able to spend it by making a few -- making, drilling and then completing a few additional wells or 20 additional wells. So in general though, I don't think I can give you specifics on exactly where every well is being drilled. As I said, as we go into the third quarter, a lot of wells coming on are going to be in the oilier area 1 areas of the field. And then as we go back into the fourth quarter, we move a little more back into some of the lower yield areas.

And then last one on my end is just around kind of base PDP declines on your legacy assets, let's say or just the nonactive assets outside of Eagle Ford, Bakken, whatnot. You have kind of what the oil declines are looking like there and the gas declines, the PDP?

Well, I don't have a specific oil decline number. I can tell you that our overall corporate decline, if you stop drilling today and just look at 12 months, is about 40%.

Your next question comes from Mike Kelly with Global Hunter Securities.

A lot of the focus of this call has been kind of the allocation of capital in wells being drilled in the Eagle Ford between area 1, which is more oily, versus area 2 and 3. I was just hoping if you could refresh us on the differences of returns between the 2 areas, as you see right now the current commodity environment?

Thank you for that question, it's a good one. And what you'll see, I believe, your wells in area 1, in the area that we are drilling in area 1, in the higher yield areas, have very similar returns to our best wells in the leaner portions of the field in area 3, which is the Galvan area. So when you look at it from a return standpoint, it's really not much of a trade-off. It's really just a function of how did the wells lay out in the schedule and how do we move forward. But the returns are actually very similar in the higher yield areas of the North portion versus the lower yield areas that we've been drilling in the Southern area, which have higher EURs and better returns.

And you guys provided what I thought was some great color on the strategic rationale for having a focused new ventures program. And wanted to ask you just a couple of follow-ups on that front. The Woodbine and Powder River Basin are obviously the 2 concepts that are being tested this year. And I really want to get a sense of how long or short of a leash you're willing to give both of those programs in terms of doing the science work and doing the testing and really what you want to see out of both of those plays in order for it to kind of make the cut move into the development mode?

This is Tony. Let me address that one. With both plays, what we've endeavored to do and I think we're accomplishing is putting together a significant position such that if we have success with either or both of those plays, they will be material and will certainly fuel our growth longer term. So if you look at the acreage numbers that we provided at present time, you'll notice that in both cases, over 100,000 acres. What we like to do is to go in, do early testing, have a position that we can leverage longer term. And if we have success with either or both plays, it really provides us with a lot of opportunity. We had the potential to self-developed, we could also take that with success we wanted to and potentially bring in a JV partner just like we have done in the Eagle Ford. So it gives us a lot of optionality if we continue to have success. I would say right now, you're right, we are in the very early stages in both plays. We're certainly looking to complete some near-term testing, as Jay talked about earlier in both. That's why we're moving some rigs and adding some modest capital this year. And then if we have continued success, we move into more of a delineation phase and then we continue to like what we see, we can go to full development. But I think the way to think about that is it is a gradual process. You don't immediately jump to full development, and that allows us to obviously manage our capital program and maintain, certainly, a strong balance sheet in the meantime.

Let me add one comment. I think Tony's comment here about the distillation of ideas is really important. By the time we get to the point where we're talking about this plays and we built a material position, we're at the point where we're fairly convinced that they're going to work and we're going to put substantial amounts of money on the table to test them. So we come from a conceptual level, all the way down to the point where we drill wells and build position, at this point, these are meaningful things, we are going to spend real money. And as Tony mentioned earlier in the talk, these are the things that are going to drive our growth a couple of years out. And we need to source of these things because our capital program needs to grow over time and we need to find new things. So I thought his talk earlier was really good from that standpoint.

Yes, that's good color. Maybe ask one more on that front, in terms of trying to get an understanding of what you guys do have going on behind the scenes in terms of putting additional plays together. Maybe just if you could give us a sense of when we could expect to hear about more concepts that you're bringing to the floor here?

Well, we typically don't talk about them until we have -- until we built positions. So I don't think I'll comment on specifics of what we're going to say or when we're going to say it. I think you will see new ideas moving forward. We have a lot of money right now to spend on ideas that we've distilled, so we've got a lot on our plate. But there will be some things that will come forward over time.

Your last question comes from Jeff Robertson with Barclays.

Just a follow-up on new ventures. Can you talk, Jay or Tony, about how many wells you think you'll have in East Texas that will go into the planning process for the 2014 capital program?

I think it's a little early to say that. I mean, I think going into the year, we're going to be running 2 rigs, I can say that. I haven't got an exact well count. And whether our rig count goes up in a year or not is going to depend to some extent on how much success we have.

And then just to follow-up. Jay, would you anticipate that the $170 million on new ventures then goes up by some amount in 2014 or would -- is that kind of the -- for the pace you're on in those plays, is that about the right spend level?

That's almost a question about our budgeting process. In fact, what'll happen in East Texas as we move forward is more of that money is going to move into the development side. We really reserve new venture spending for those truly new things where we have not drilled a proved well yet. And so our East Texas stuff, as we are successful, will move actually into our development portion of our budget. So I don't see new ventures necessarily getting larger, that line item getting larger. What would happen is we would start carrying a development wedge, a capital wedge for East Texas.

We have reached the allotted time for questions. I will now turn it back to Tony Best, CEO.

Thank you all for joining us for the second quarter call. We look forward to talking to you again next quarter.

This does conclude today's SM Energy Second Quarter 2013 Earnings Call. You may now disconnect.