Good day, ladies and gentlemen, and welcome to the SM Energy Second Quarter 2014 Earnings Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference, David Copeland, Executive Vice President and General Counsel. Sir, you may begin.

Thank you, Sam. Good morning to all joining us by phone and online for SM Energy Company's Second Quarter 2014 Earnings Conference Call and Operations Update. Before we start, I'd like to advise you that we will be making forward-looking statements during the call about our plans, expectations, pending acquisitions 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 to our website for this call and the Risk Factors section of our Form K filed earlier this year and our Form 10-Q 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 important discussion of these terms and the special risks and other considerations associated with these non-proved reserve metrics. Other 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; and Brent Collins, Senior Director of Planning and Investor Relations. I'll now turn the call back over to Tony.

Thank you, David. Good morning, everyone, and thank you for joining us for the Second Quarter 2014 SM Energy Earnings Call. We will be referencing slides this morning that we posted on our website yesterday. I'll begin on Slide 3 and share a few key messages. First, I'd like to highlight that we had another very strong quarter. We reported record quarterly production of 147,000 BOE per day, led by our Eagle Ford assets, which had significant growth in the quarter. Along with record production for the quarter, we also reported record quarterly adjusted EBITDAX in the second quarter of $423 million. Second, we recently signed an agreement to acquire a significant block of acreage in Divide and Williams Counties, adjacent to our Gooseneck acreage, where we have been operating a very successful Three Forks program. This pending acquisition is the largest in the company's history on a dollar basis, and is expected to add a significant amount of oily inventory to our Williston Basin program, adding 61,000 net acres to our existing position. So we're very excited about that. Third, in the last quarterly call, we indicated that we were working on testing various completion designs and longer laterals in our development programs. We have been rigorously testing these completion designs to optimize our development programs in the Eagle Ford and the Bakken/Three Forks. During the second quarter, we started to receive a sufficient amount of data from these alternative completion tests to make some initial conclusions on the improved frac designs. We can now comfortably say that we are seeing improved results that are significantly increasing the value of these core development programs. Jay will provide more details on these improvements in his operational review. Moving to Slide 4. I will walk through some key financial and performance metrics for the second quarter. As I stated in the previous slide, in the second quarter, we reported record quarterly production and adjusted EBITDAX. From a performance standpoint, we were above the high end of our production guidance range and within or below the range for all of our guided cost metrics. As you can see, execution on our 2014 business plan has gone extremely well, and positions us for continued success in the second half of the year. With that, I'll turn the call over to Jay for his operational review.

Thank you, Tony, and good morning, everyone. As Tony indicated, operationally, we had a great quarter, meeting or beating all our guidance numbers. But we're really very pleased with the progress we've also made in improving and expanding our drilling inventory. I'll start on Slide 6, where I'll discuss our operated Eagle Ford program. We made 23 completions during the quarter, and production increased 9% to an average of 83,000 BOEs per day. We currently have 5 rigs running in this program. As many of you know, we've been moving to longer lateral drilling and testing the use of more sand in our Eagle Ford completions. Our average well drilled in 2014 will be about 30% longer than in 2013. With respect to using more sand, we now have some high confidence results which demonstrate compelling economic value for this particular change in our completion program. One of the first places we tried the increased sand technique was in what we call Area 2 of our operated acreage, essentially right in the middle of our position. Slide 7 shows the location of Area 2 and summarizes what we tested. We had 26 older wells in the immediate area, with an average lateral length of approximately 5,000 feet. And we drilled 7 new wells late last year with the same lateral length and completed them with almost twice as much sand per lateral foot, from around 1,100 pounds per lateral foot to a little more than 2,000 pounds per lateral foot. Again, the lateral lengths for both the older and newer wells are essentially the same. We generally restrict chokes on our new completions in the operated area for some period of time in order to minimize any potential damage to the completion during early flow-back. So the best way to…

Thank you, Jay. I'll start on Slide 20. So at the end of the second quarter, we had about $164 million of cash on the balance sheet, and our debt to trailing EBITDAX was 1x. That amount of debt equates to 48% of our total booked capitalization. So our total amount of long-term debt remains unchanged from the prior period at $1.6 billion, and we have no maturities on that debt within the next 5 years. We have an undrawn revolving credit facility with $1.3 billion in lender commitments, with a borrowing base securing it -- amounting to $2.2 billion. We intend to fund the acquisition in the Rockies, that Jay talked about earlier, with cash on hand and the borrowing -- and some borrowing on the revolver. Moving to the next slide, Slide 21. We show our debt to trailing 12-month EBITDAX against a group of peer companies that we track internally. As you can see from the slide, this leverage metric was also unchanged compared to last quarter. It also shows that we are well below our peer group median average of 2.2x, and I might add that even on a pro forma basis after the Gooseneck acquisition, the ratio would be 1.1x. One final comment from me. We added some oil hedges during the quarter, and with the additional oil coming from the Gooseneck acquisition, we've been adding more during July. The details can be found in the appendix of this slide deck or in the 10-Q, which was filed this morning. With that, I'll turn the call back to Tony for his closing remarks.

Thank you, Wade. Before handing the call over for your questions, I'll highlight what we think are the key takeaways from this call on Slide 23 (sic) [22]. First, we had another really strong second quarter. We came in above our production guidance and performed well against all of our guided cost measures. We also set new quarterly production and adjusted EBITDAX records in the quarter. Next, I'm very excited about the pending acquisition that we announced last night, which is a fantastic fit with our existing Gooseneck acreage. We have the potential to add a significant amount of really valuable, oily inventory in a core area of the company. These new assets are a great addition to the SM portfolio. Lastly, we've provided some data today on enhancements that we've been making in our Eagle Ford and Three Forks programs that are resulting in significant improvements to the economics of those programs, and we'll have more updates on our well optimization as the data comes in during the upcoming quarters. I'd now like to open up the call for your questions.

[Operator Instructions] Our first question comes from Mike Kelly of Global Hunter Securities.

A couple of questions for me. One, I just wanted to clarify, with the improvements you're seeing in the Eagle Ford here and the 40% improvement, is that 40 percentage points? If I look back at the Q4 presentation from -- you had $90 oil on Area 2, you're about a 30% rate of return. We're now talking about potential 70% IRRs here? And basically, I just wanted some clarity on that.

Yes, Mike, this is Javan. Yes, it's 40 percentage points increase.

Okay. Outstanding. And then, over in the Bakken, this Baytex acquisition. Looks like the acreage there is a little bit north of your position, it's a direct offset. But is there anything from a geological standpoint of -- is there any differences there, I guess, from a geological standpoint? Because it does look like, on the rates we pulled, you guys have about 40% higher initial IP rates. And do you expect to see a little bit of less productive wells as you move further north?

Mike, it's Javan again. It's actually -- we have 2 areas in Gooseneck. The North Gooseneck area and the South. A lot of this acreage is right -- lays right in between it and a little bit to the east. So we would say the acreage is right in between us. We know it's going to perform very similarly to our acreage position. The acreage to the east, obviously, is a little farther away. We did risk the acreage a little bit when we bought it. One thing I think we should say, and I'm glad you brought up Gooseneck. We hear this all the time. If you go back and look at just general industry data in that particular -- in Divide County over a long period of time, there are a number of wells there that weren't great. A lot of shorter lateral wells drilled early on, and a number of other operators have drilled wells that, frankly, we wouldn't be proud of. If you look at our results in Gooseneck, I think we stick out as an outstanding operator in that area, and there's a number of good reasons for that, including the way we complete the wells and the way we operate them. We're very proud of our operations staff there. We fully believe that we can develop a lot of this acreage to the kind of standards that we've been demonstrating on our other acreage.

Okay, great. Maybe if I could slip one more quick one in here. You hinted at the end of your prepared remarks that the subsequent update we're going to get with CapEx is going to be -- should be positive and bode well for production growth rates going forward. And I'm kind of thinking of you guys as a 15% grower going into '15. Is it, now with some bolt-on acreage here in different positions, higher rate of returns in the Eagle Ford, is that a meaningful impact to the 15% growth rate? Should we start thinking about upward of 20%? How should we think about that?

Well, this is Javan again. Again, we need to sit down with our board and get our capital program completely worked through. But I think it's safe to say that our growth rate in '15 is going to be up, certainly between 15% and 20%. We'll see where it ends up.

Our next question comes from Matt Portillo of TPH. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just a few quick questions for me in regards to the Bakken. I guess just a quick follow-up on the acquisition acreage. I was curious if you could comment a bit maybe on the difference in the completion techniques or some of the opportunities you see to enhance kind of the EURs. I think Baytex previously had kind of a 390 EUR published here, and I think you guys are -- kind of the analysis we've done would suggest that your Three Forks wells have materially outperformed that on your acreage. And then, I guess the second quick follow-up question. Just could you remind us where you're rates of return are currently kind of on the older completions in Divide? And kind of with the new completions you've seen so far, where those could be headed to?

This is Javan again. In terms of completion styles, I mean, we typically pump a sliding sleeve, say, the 26- to 30-stage completion, the sand loadings, as we've indicated there. Again, I think our well costs are typically lower than most of our competitors in the area. We're very aggressive about our artificial lift installations. We've run a lot of long-stroke units there, which are performing very well for us. In general, I think we have very good uptime on our assets. We're very pleased that the -- in the particular area we're buying here, that all their gas is essentially connected to pipeline. So a lot of good -- a lot of great opportunities here, we think, to make good wells. Earlier this year, we disclosed our own Gooseneck numbers. I think that the number we disclosed was a little under 400,000 barrels of oil equivalent per day, from an EUR standpoint. We did risk that a little bit on this acreage, just because there's a little bit of unknown as you go south. But in general, that's probably not a bad number. We think there's significant opportunities here with increased sand loading and some additional things we can do that we haven't talked about yet, but kind of some interesting completion techniques we think we can use to improve on that. In general, I think if you look back at that release that we sent out at the end of the fourth quarter, at about $90 oil, we were showing about 45% or 44% returns per well in Gooseneck. And again, we think those numbers are getting better over time. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And then one quick follow-up. I know that you guys had also mentioned, I think, previously, you were starting to test upsized fracs in the Bear Den and Raven area. And I guess specifically to Bear Den, you've kind of moved, I think, north of 4 million pounds on the wells. I was curious, given the kind of industry or early industry success with some of the 9 million- to 10 million-pound completions in the basin, if you guys may be looking to potentially upsize further, given the quality of that asset base, but I just wanted some, maybe, some context on how you're thinking about the completion changes in that area of your acreage.

It's Javan again. I think no question, we're looking at higher sand volumes across the acreage position. Most of our testing of that will be in the Raven, say, East -- Middle to Eastern or Western McKenzie County. We don't have a lot of immediate drilling inventory in the Bear Den area, but we do have a few wells later this year. We'll certainly be testing higher-sand loadings in our Stateline area later this year as we move there. So far, we haven't seen a big breakover. As we continue to pump more sand, it appears the wells get better. Everybody is moving in that direction. That's the direction we're moving as well.

Our next question comes from Pearce Hammond of Simmons & Company. Pearce W. Hammond - Simmons & Company International, Research Division: I was just curious, would you consider any divestitures to fund the Bakken acquisition, as well as the $100 million PRB bolt-on acquisition earlier this year?

Pearce, it's Wade. We always look at divestitures. I would tell you that just specifically looking through a divestiture to fund those acquisitions, that's clearly not necessary with the balance sheet. As I mentioned, we're -- going into the end of this quarter, we still had cash on the balance sheet and we're using that, and the draw on the revolver to fund the Baytex deal. So no imminent desire to do a divestiture just for that purpose, but we always look. Pearce W. Hammond - Simmons & Company International, Research Division: And then my follow-up would be, do you plan to apply for a private letter ruling with the Commerce Department to export condensate? And then currently, how much of your condensate is stabilized?

Pearce, this is Javan. Great question, thank you for asking it. We sell all of our condensate to middlemen. We don't export crude ourselves. We don't have any facilities to do that. We don't own firm transportation to the coast. So all our -- almost all our crude that comes out of the Eagle Ford is stabilized. We run it through a stabilizer that Plains operates. So from that standpoint, we don't see any material difference between the product we're selling and the product that some people who've talked about this are selling. At this point, given our situation, we're not applying for letter rulings, but it could very well be that our downstream purchasers will.

Our next question comes from Mike Scialla of Stifel. Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division: On your new completion technique, what you outlined in the presentation, if I'm understanding correctly, is just the additional sand. You really haven't given us anything yet on the longer lateral lengths. Is that correct? And then how applicable do you think the new technique is to those other areas? You kind of alluded to the oilier areas may take a combination of both those things.

Yes, Mike, great question. First of all, let me reemphasize that the testing we just talked about was on wells with similar lateral lengths. We drilled those wells late last year before we started lengthening laterals. So we had an opportunity to get a straight-up test between higher sand loadings and lower sand loadings, and that's why we showed -- we did that test and why we showed the data the way we did. We don't have that kind of result yet on longer lateral wells. I will tell you that we fully expect longer lateral wells to outperform short lateral wells. I think it's a no-brainer to some extent. We guided most of the work we did this year when we put out our results at the end of the year on longer-lateral type completions. I will emphasize that the guidance we provided at the end of the fourth quarter did not include increased sand volumes, so we would expect to improve on that. In terms of how it applies to other Eagle Ford areas, I think from a modeling standpoint, we think it's going to work in any area where you have sufficient Eagle Ford thickness. There is, in general, sufficient Eagle Ford thickness on almost all our acreage. Certainly, as you go north on our acreage, into the oilier parts of our acreage position, our position actually thickens from Area 2. So I think all the indications we have would be that it should be very successful on the thicker, oilier parts of the reservoir. And I can tell you, from looking at APC's results, that when they pump higher sand volumes on their wells, which are north of ours, they get better wells. So there's no reason to believe that as we move north and into the oilier portions of our acreage that this should not be affected. Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division: And that -- so Area 1, we may get some news before the end of this year on the new techniques there?

Yes, I think you will. Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division: Okay. Great. And then switching over to Powder. You're going to a fourth rig there a little earlier than, I think, you anticipated. Is that any read-through on the permitting process? Getting any better up there?

We have more than sufficient permits to run a 4-rig program. Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division: Okay. And last one for me on the Powder. What are you budgeting for a well cost for your Shannon wells?

I think the current [indiscernible] is between $10 million and $11 million.

Yes, let us -- Mike, if you don't mind, call Brent back and we'll make sure you get a good number on that. I'm sure Tony's right. I just want to make sure that we get it exactly right for you.

Our next question comes from Subash Chandra of Jefferies.

So on the Baytex acquisition, how's the infrastructure there? Is it in good shape? Or do you think most of the dollars incrementally could be for drilling? Or will there be some infrastructure work required? And then also on the acreage, just a question on the limits of sand loading up here versus, of course, deeper parts of the basin. I imagine, it's -- you're closer to a max here, potentially. And also, I think you guys have, in the past, limited the amount of water you've experienced in these wells versus other operators, and if you could sort of refresh me on your successes to date and how that might translate into the new acquisition.

Subash, okay, let me start, infrastructure first. Let's talk about, Baytex has done, I think, a terrific job on the gas side infrastructure. 90% of their operated wells right now are hooked up to gas sales and the other 10% are coming. So they have a great gas architecture in terms of not having to clear a bunch of gas we -- as we get in here. We're very pleased with that. Their oil is generally being trucked at this point. We think there's an opportunity there to hook up oil sales, which we've done in most of our acreage. We think there's a positive associated with that in terms of our economics, which we frankly have rolled into our acquisition economics. The water side, now this kind of gets back to completions. Generally, we have pumped larger jobs up here than most of our competitors over time. We think there's a strong relationship to well performance and water volumes, up to a point. And as I said, we typically pump 26- to now 30-stage jobs up here. I don't necessarily see that we're up against a limit on sand loading. We'll, frankly, we will be testing higher sand loadings in subsequent wells, probably almost twice the sand loading we have here, or significantly higher, I should say. Again, thickness does have something to do with that. The typical integrals that would be here are a little thinner, we -- this is a long answer to a short question, but we used to be concerned that if you frac these wells too much, that you'd get into the Bakken, which we thought might be wet. Our recent testing in the Bakken and log and core work, would suggest that it's not going to produce high water cuts. So in fact, we may be able to be more aggressive with our frac designs.

Okay. That's good to know. As far as the water infrastructure up there, is that also being trucked? And any opportunities to address that? Or is water up there not as much as maybe the popular perception might be?

Well, we do pay for some water up there and we do truck some. We've also been able to use, in many cases, some surface waters. If you've been in Divide County, it's kind of a pothole area. There's a number of natural surface waters there that we've been able to use. So at this point, no big issue on water use.

Or water disposal?

We have our own water disposal system. We will probably have to spend some money on water disposal on the Baytex side, but we rolled that into the acquisition economics.

Our next question comes from Jeb Bachmann of Howard Weil.

Just had a couple of quick questions on the graphs you guys provided for the Eagle Ford and the Bakken. Just wondering how many wells were in that sample set.

Yes, this is Javan. As I mentioned in the script, there are 33 total wells in the Area 2 data set, 7 of which were completed with high sand loadings. In the Bakken data set, that -- again, and I don't know, 7 is the perfect number, I guess, but there were about 7 -- there were 7 wells, I believe, in the higher sand loading test there as well.

And Jay, with -- in those tests, I mean, were some of those or were all of those on restricted chokes? Or were you playing around with that early on in that process?

Typically, in the Eagle Ford, we produce all these wells back on a restricted choke for some period of time, just to protect the completion. That's just good practice. In the Bakken, we do bring the -- we flow the wells back. They get on artificial lift fairly early. So choke management is not as big an issue there.

Okay. I'm just trying to get a sense with this program, as it continues to move forward, should we see improvement in that? And I guess you talked about optimization, but should we expect that to continue going forward here in the curves, and kind of what you're seeing on the flow-backs?

So Jeb, let's make sure I'm talking about the right asset. Are you talking about the Eagle Ford now or Gooseneck?

Yes, no, I'm sorry. I'm talking about the Eagle Ford.

Eagle Ford. Well, clearly, we think we're going to do better over time. We're continuing to test other techniques, which we think have the opportunity to improve even on these results.

Our next question comes from Welles Fitzpatrick of Johnson Rice. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: On these higher sand loadings in both areas, is it safe to assume that, that does not affect your spacing assumptions in those 2 spots?

Great question. I think, given the outperformance of these wells, spacing is something we need to revisit. Not -- we don't have an answer for you yet, but clearly, when the wells are performing this much better, I think you got to go back and look at whether you can push them a little closer together. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: Okay, perfect. And then, just one last one. The royalty rate on the new acreage, is that also around 20%?

Welles, I have to look -- it is, but I need to -- again, would you call Brent back and get an exact number for that? Because we want to make sure we give you the correct number. It's in the 82% kind of range, I think, but I want to make sure I check. Going back -- I'm sorry to interrupt you, but going back to a question that was asked earlier, the current AFE dollar amount on the Shannon well we're currently drilling is $11.3 million. But I think, over time, our expectation is we can get those well cost down, so... Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: Okay. Perfect. And did you guys state the lateral length on the Dynamite well, by any chance?

It's a long lateral well. It's about a 10,000-footer.

Our next question comes from David Tameron of Wells Fargo.

I know, Jay, you said you'd address CapEx in mid-August. But just as we think about capital allocation, I mean obviously, Eagle Ford and Bakken, I guess, would be 1 and 2. How should we think about all the other, I guess, new venture plays or East Texas, Permian, Powder? How would you rank those? Or how should we think about what stands the best chance of getting the most capital of those plays?

David, that's a great question and something we'll be working very hard on as we go into the budget cycle this fall. Really, we, as you know, we rank things based on the returns and the NPVs they generate, and we will allocate capital the best -- in absolutely the best way we can, based on the highest return wells. I think the Powder will get money. And certainly, we're drilling some great wells in the Permian right now, which will get in that queue as well. But how that allocation actually works, we'll just have to see after we look at our fall process.

David, I think it's -- this is Tony. I think it's safe to say that, obviously, the lion share of capital is certainly going to be focused on our key development areas in both the Eagle Ford and the Bakken, and we don't see that changing anytime soon. But we have some work to do as we do our capital update.

Thanks, Tony. That's right.

Okay. And just one more question on that. Is -- I know it sounds like I'm fishing for a number, and I know you won't give it to me, but just directionally for 2015, you had, I guess, philosophically put out some framework around that before as far as if you maintain a flat budget, you grow x. I mean, how should we think about -- I know the balance sheet is in good shape, but how should we think about your desire to overspend, outspend, accelerate growth, et cetera? What -- can you give us some framework around that?

David, I will defer that question. But what I can say is that we're going to drill economic wells, okay? And we have never been afraid to outspend, to drill highly economic opportunities, and we're not afraid to do it now. With that said, we're also going to be prudent in the way we manage our balance sheet.

Our next question comes from Scott Hanold of RBC Capital Markets.

Just wondering on the PRB, you certainly have shown a pretty good appetite to increase activity and your results sort of warrant that. Permits sound like they're okay. What would -- remind me of the infrastructure situation out there. Is that going to -- should we temper growth expectations out there until some key pieces get put in there? Where are we at with that?

This is Javan, Scott. In general, we're in good shape. We've dedicated the northern area and the southern areas of our position to gas gathering, and we're actually connecting the wells before we complete them. On the oil side, there's plenty of infrastructure, there's some new rail facilities going into that area. Typically, you're going to see Bakken-like differentials on the oil. So in general, we don't believe infrastructure's a real issue. Obviously, the Powder River Basin is a relatively new basin, and there's fewer competitors for some services. We think that'll improve over time as well.

Okay. I appreciate that. And on this acquisition in the Williston Basin. I guess my question is do you think there's more opportunity in this specific area? I mean, obviously, it's been highlighted quite a bit that you all have had some pretty good performance. Is that an advantage for you guys to go out there and be a little bit more acquisitive?

Well, this is Javan again. Yes, our intention is to build position in our core areas. So certainly something we're interested in doing.

Our next question comes from Joe Magner of Macquarie.

I guess following on that last question, over the last year or 2, there's been a lot of focus on expanding some new resource opportunities organically with this bolt-on acquisition. Just how should we think about allocation capital going forward between those organic opportunities and more acquisitions? I appreciate you just answered that you're interested in coring up some of your growth areas, but is there a bit more of a shift towards acquisitions? Or is this just it was an opportunity to bolt on in a core area? And that's how it's kind of a not necessarily a one-off, but not a specific change to your strategy going forward.

Yes, Joe. This is Tony. Good question. I would say, at this point, we see our highest potential for growing inventory with our current core development areas. And I think, as you can see from the results that we've shared this morning and last night, we certainly believe that, and we're seeing some great results in growing inventory from these core areas. As Jay just mentioned, another key part of our growth strategy is to see where we can continue to add acreage in and around these core areas. Because if we have success there, then we hope to extend that into some additional new acreage. Regarding new ventures, I think at this point, we have a pretty compelling portfolio of opportunities. So we'll continue to look out there, but I think we've got a very compelling set of assets right now, and our focus is on continuing to exploit what we've captured already. I think it is safe to say that in addition to true exploration and looking at new ventures, you are going to see more emphasis from us on key acquisitions like we've announced this morning.

Well, before we take the next question, let me note that Baytex NRI in 126 spacing units ranges between 81.6% and 82.1%. So right at 82%.

That range.

[Operator Instructions] Our next question comes from John Nelson of Citigroup.

Could you just remind me is $100 million still the right way to think about the annual CapEx level to run a PRB rig?

I haven't looked back at the numbers. It depends entirely on the working interest. I think on a gross basis, $100 million is probably not far off for 100% working interest, but I'd have to look and see. Our average working interest in these wells is in the 55% range.

Yes, fair enough. And then, just on the comment that you see permits that have sufficient to run a 4-rig program. Can you just talk to what sort of the framework around that statement is? Does that mean kind of over the next 12 months you have sufficient sort of visibility? Or how do you get to sort of that statement?

Well, we've been adding rigs one at a time here as we build inventory and permits. We currently have something like 36 permits approved, which is probably 6-rig years' worth of activity or 5-rig years' worth of activity. We have a number of permits in the queue and a number more in preparation. So I think in general, we feel very comfortable that we have enough permits to stand up and run a consistent 4-rig program, and potentially more rigs into 2015, depending on how our capital situation looks.

That's really helpful. And then just last one for me. In the Permian, obviously, industry activity has heated up. And relatively, you guys have a smaller position. Are you seeing any pressure in sort of operating in the Permian? Cost pressure, could it be?

Clearly -- this is Javan again. In terms of pressure, I'm going to assume that what you mean is cost pressure or ability to get things done. Certainly. I mean, rig count in the Permian is very high. Activity levels are very high and going higher. There is some cost pressure, although not a lot. I mean, I'd probably call it a 5% kind of annual cost increase rate at this point. We share frac spread there with some other parties, so we're able to get our fracs done when we need to. We'd love to get our activity level a little higher. With some success, we might be able to do that and get our own frac spread, which should be good. But it is a very busy area. It's a bubbly kind of environment out there right now. And that happens in all these basins at some period of time, we just have to get used to it.

John, I would point you to the latest Spears & Associates report. They kind of give a basin-by-basin cost update. And most of the basins are relatively flat, maybe 1% or 2% expected for the year, but nothing dramatic. And kind of the one exception there is kind of on the Permian. It's probably more in the 3% to 5% range. But to date, we haven't had difficulty acquiring the goods and services we need to go ahead and execute on our program.

That's very helpful. And then just last one for me. What should we be expecting, sort of result-wise, out of East Texas, either in 3Q or 4Q? And any update sort of when we should expect to see those wells?

Well, as I indicated earlier, we're currently installing infrastructure to be able to do long-term production tests on a number of our wells. The key piece of data that we need is how do these wells decline over time. We already know we have good pressures. We've got -- they look very productive initially, and we think they're going to have acceptable liquid levels, liquid loading levels. Really, the big issue is what's that decline rate look like. We're working on the infrastructure now. We hope to have some results. Obviously, it takes time to get a long-term production test. We hope to have results by year end.

Our next question comes from Joe Allman of JPMorgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: So in the Eagle Ford, in Area 2, with the new completion designs, so how does that impact the EURs? So what's the new EUR associated with those, that increasing rates of return and NPV that you cited?

Well, Joe, we haven't estimated EUR yet. Clearly, it's going to go up in proportion to the productivity of the well. We haven't -- I haven't got a new EUR number for you, but clearly up. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. Got you. And then, in terms of -- besides just changing the profit loading, do you expect to make some other changes going forward? So for example, are you going to try shorter frac stage lengths and closer -- perf closer your spacing and things like that?

This is Javan again. Yes, we're testing all those things. We're also looking at using more 100 mesh in these jobs, which is both a cost savings, and we think a potential for some interesting improvement opportunity there. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Got you. And Jay, similar to the way you did this testing by basically changing one variable, do you plan on changing just one variable at a time just to see how each variable has an impact?

Well, certainly, we try. You want to move quickly as well and you can't wait a year to test everything. So there are cases where we'll change more than one thing, where we think we can kind of suss out how those impact things. But generally, yes, you should try to change one variable at a time. The whole theme here is that we're going bigger, stronger, faster. We got a great asset. If you go back 4 or 5 years, this company didn't have these big, chunky assets that you could really work on. This is a huge opportunity for us, to go in and just make the stuff better and more valuable. I think we've accomplished that, as we talked this quarter. I think you're seeing higher values. I think you'll continue to see a more valuable development as we go forward. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Got you. And then, in terms of the Bakken. You talked about using sliding sleeves. So have you tried plug-and-perf in the Bakken? And if so, how has that worked?

We have just started doing some plug-perf completions, and we don't have results on them yet. We just started pumping some here in the last couple of quarters. And we're optimistic about it, but I don't have results back yet. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. And in the Eagle Ford, what kind of completion design are you using there?

That's a cemented plug-perf designs. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Got you. Okay. And then a couple of quick ones. So Scott Hanold may have asked this one, but in the Frontier -- but I missed the answer if he did. The Frontier play, what does the infrastructure look like? And are you constrained in any way from ramping that up pretty quick if you wanted to?

Again, the gas side infrastructure, we're in good shape. We've got dedicated areas to 2 different gas gatherers who are working well with us, and we're getting our wells hooked up before we complete them. On the oil side, the oil generally -- there's new infrastructure out there, some rail facilities going in. We truck some of it today. I think there's opportunity over time to hook most of that up to pipe as well. So no real delays there. These are long -- I need to be clear, these are long-cycle wells. It takes time -- from the time you drill a long lateral well, you get it hooked up, you get it completed, it probably takes 120 days from spud to production. And that's another opportunity for us here, is to try to squeeze that time down over time. We certainly were able to do that in Eagle Ford over time. We think we'll be able to do that in the Powder as well. Joseph D. Allman - JP Morgan Chase & Co, Research Division: And 2 real quick ones. With the Baytex acquisition, how many drilling locations do you think you add with that acquisition?

Thanks for asking that. I figured that would be a question today. Let me put it this way. My math would suggest that given the value of the PDP, we only need to drill one good well per spacing unit to pay for this. Now we're drilling our other Gooseneck acreage at 4 Three Forks wells per spacing unit, and we haven't even gotten to the Bakken yet. So we're not going to put out a number today on how many wells we're going to drill, but I think you can assume that we think there's a ton of upside in this asset. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay, great. And then, earlier in the call, I think you talked about how many - how much of your acreage in the Frontier is -- how much of that acreage is prospective for the Frontier in the Powder. Did you say 127,000?

Yes, that's the number I gave, yes.

And our final question comes from Michael Hall of Heikkinen Energy Advisors.

A number of mine have been answered, but I guess just some housekeeping on that Divide acreage block now. What's the average working interest across the ownership after the deal?

It will be somewhere between 37.5% and 50% on a typical well drill. It depends on where -- whether it's in an existing spacing unit or where some people may have not consented, or on the base acreage, where we basically own 37.5% of an AMI.

Okay. And then you alluded to...

Before we move on from that, let me just say that I personally view that as an opportunity. I think over time, we'll be able to pick up additional acreage in this, so...

Yes, point taken. And then, you made some commentary around kind of seeing some improved results or optimistic results from the Bakken in the area. Any additional elaboration on what you're seeing? And kind of some timeframes on additional data?

Well, we're running a number of different completion tests in the Bakken, including the plug-perf test I referred to. We're running some higher sand loading tests and we're doing some downspacing work. Most of our Bakken work will get -- is getting done now, and we probably won't have results until late this year. We also have a Stateline test that we've mentioned earlier that we're doing.

And is the hurdle in the Bakken kind of water handling and dealing with water from the reservoir? Or is there...?

Are you speaking specifically to Gooseneck now? Or just the Bakken?

Yes, yes, sorry. Just no, no -- up in Gooseneck.

Well, we don't see that as particularly a hurdle. These wells produce at higher water cuts than typical Bakken wells, but not at super-high water cuts. That was one of the concerns early on, but it has not proved to be the case.

Okay, helpful. And then in the Eagle Ford, I believe you have some Upper Eagle Ford tests in the hopper. Any updated commentary around that? Or just a reminder on timing and when we might hear about them?

We do have some planned Upper Eagle Ford tests. Haven't released results on those yet, probably won't until sometime later this year.

Thank you. And at this time, I'd like to turn the call back to management for any closing comments.

This is Tony Best. Thank you so much for joining us for the second quarter call. We look forward to updating the SM story again next quarter. Thank you for calling in.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude today's program. You may all disconnect. Everyone, have a wonderful day.