SM Energy Company (SM) Q3 2013 Earnings Report, Transcript and Summary

David W. Copeland - Executive Vice President, General Counsel and Corporate Secretary Anthony J. Best - Chief Executive Officer, Director and Member of Executive Committee Javan D. Ottoson - President and Chief Operating Officer A. Wade Pursell - Chief Financial Officer and Executive Vice President

Pearce W. Hammond - Simmons & Company International, Research Division Joseph Bachmann - Howard Weil Incorporated, Research Division Michael Hall Joseph Patrick Magner - Macquarie Research Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division David R. Tameron - Wells Fargo Securities, LLC, Research Division Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division Scott Hanold - RBC Capital Markets, LLC, Research Division Brian T. Velie - Capital One Securities, Inc., Research Division James Spicer - Wells Fargo Securities, LLC, Research Division John C. Nelson - Citigroup Inc, Research Division

Good morning, my name is Cathy. And I will be your conference operator today. At this time, I would like to welcome everyone to the SM Energy Third Quarter 2013 Earnings Conference Call. [Operator Instructions] Thank you. I would now like to turn the conference over to David Copeland, Executive Vice President and General Counsel. Please go ahead, sir.

Thank you, Cathy. Good morning to all joining us by phone and online for SM Energy Company's third quarter 2013 earnings conference 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 of our Form 10-K that was filed on February 21, 2013. We will 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 estimate and ultimate recovery, or EUR, on this call. You should read the Cautionary Language page in our slide presentation for any important -- 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.

Thank you, David. Good morning, everyone, and thank you for joining us for the third quarter 2013 SM Energy earnings call. We'll be referencing slides this morning that we posted on our website yesterday. I'll start on Slide 3 and go through a few key messages for the quarter. SM Energy had a very strong quarter with record quarterly production of 12.8 million barrels of oil equivalent with 50% of this production being oil condensate or NGLs. Along with our record production, we reported record quarterly EBITDAX, which was greater than our quarterly capital expenditures. Over the past few months, there's been a lot of attention on the Permian Basin and a fair number of questions about our Permian program, which up until now, is something that we haven't talked much about due to our ongoing leasing efforts in the basin. We feel that we have now reached a point where we can talk about our position and program plans in more detail. As many of you already know, we drilled and completed our first horizontal Wolfcamp B well in our Sweetie Peck field and are seeing very strong results to date. From an acreage standpoint, we've have been working hard to add acreage in the play, and I'm pleased to say that our efforts have been successful as we've added significant acreage to our Midland Basin position, which Jay will cover in detail during his operational update. Lastly, I'd like to point out that although a lot of attention in investor meetings and calls is directed at our new venture programs, it is important to note that it is the successful execution of our core development programs that is driving the growth of our company today. With that, I'll move to Slide 4 to do a quick rundown of our quarterly performance. From our production standpoint, we were at the high end of our guidance range with an average 139,000 barrels of oil equivalent per day during the quarter. From a cost standpoint, we were within or below our guidance range on all guided metrics. A few of the costs which came in below our range were cash G&A, which was less than expected due to lower compensation-related expenses and our DD&A rate, which came in 14% below the midpoint of our guidance range. The decrease in DD&A is a result of lower finding and development cost in our core development plays as we continue to gain efficiencies and drive costs down. We reported GAAP net income of $1.04 per diluted share for the quarter and adjusted net income of $1.54 per diluted share. Our quarterly EBITDAX for the quarter was $410 million, which as I mentioned before, is a company record. I'll now turn the call over to Jay for his operational review.

Thank you, Tony. Good morning, everyone. I'll start on Slide 6 with a quick discussion of our production for the quarter. As Tony mentioned in his introduction, our average daily production for the quarter was approximately 139,000 barrels of oil equivalent per day, which is a 5% sequential increase from the second quarter of 2013 and a 34% increase from the third quarter of 2012. Year-over-year, liquids production grew by 48%. Our product mix for the quarter was 50% liquids, which we had indicated was our expectation to achieve by year end. We got to that number a little earlier than expected because we had a number of lower liquid yield wells in the operated Eagle Ford shut in during the quarter for extended periods due to offset drilling and completion operations. As indicated on Slide 7, our operated Eagle Ford program total volume grew 3% sequentially this quarter and 68% year-over-year. You can see the impact of the simultaneous operations related shut-ins I just referred to in the reduction in gas rate from the second to the third quarter. We do expect that trend to reverse in the fourth quarter. We brought on 25 completed wells during the quarter, 22 of which were in what we refer to as area 1 or Briscoe Ranch. Year-to-date, we have completed 75 wells. From an infrastructure standpoint, everything is staying on schedule. There are now 12 central gathering facilities operating on our acreage and our gathering system buildout is keeping pace with our development plans. On Slide 8. The non-operated Eagle Ford program continues to provide solid steady production growth. Volumes grew 14% sequentially from the prior period. Anadarko has run a consistent program for the past several quarters and has recently added a 10th rig. They've also told us that they will be adding additional frac capacity to help bring down the inventory of drilled, but uncompleted wells. We continue to be very pleased with the operators' development of this asset. Moving to Slide 9. Our Bakken/Three Forks program had 9% sequential production growth. We maintained a 3-rig program and made 13 gross completions. We are participating with others in down spacing pilots, the results of which we will incorporate into our drilling plans and estimations of economic inventory at year end. We're also evaluating all the claims being made for revised completion designs in the basin, and will make adjustments to our completion plans if we see merit in doing so. At this point, our typical long lateral completion is a 26 stage sliding-sleeve frac job using about 80,000 barrels of fluid. As shown on Slide 10, our Permian production grew 3% sequentially. We brought on 5 new wells in the Permian this quarter, 2 in the Tredway Mississippian prospect area, 2 in the Bone Springs intervals on our acreage position in Southeast New Mexico and 1 in the Wolfcamp B shale. I would like to spend some extra time today going over our Permian acreage position, recent results and plans. Slide 11 is a locator map of our acreage position in the Permian Basin. In total, we have roughly 130,000 net acres. This count excludes about 14,000 acres we are currently marketing located on the western edge of the Midland Basin in Andrews County. You may recall that we drilled several Leonard Shale test wells on that acreage prior to starting our sale process. Our assets in Southeast New Mexico are currently producing about 1,500 barrels of oil equivalent per day net to SM and consist of 2 water flood units: the Parkway Delaware unit and East Shugart Delaware Unit and associated acreage. We operate both units and have a 33% working interest in Parkway and a 73% working interest in East Shugart. We have recently been drilling some water flood infill wells at East Shugart and have completed a number of Bone Spring horizontal wells in the last year or so on our Parkway acreage. As I indicated earlier, we completed 2 of those Bone Spring wells during the third quarter. We have a few more Bone Spring locations left to drill and continue to look for additional upside on the acreage. Our Tredway Mississippian prospect acreage position currently stands at 54,500 acres and our wells there produce about 1,800 barrels of oil equivalent per day net to SM. You may recall from previous discussions that we had subdivided the prospect into a northern area, a central area, which we call Roy and a southern area. We have previously indicated that wells in the Roy area generally -- generate fairly consistent results, but at the North and South areas, were relatively unproven. The 2 wells we completed in the third quarter were in the northern area. We are taking a hiatus on Tredway drilling during the fourth quarter to evaluate all our results to date and determine our best forward path with the asset. The remainder of our acreage position, 72,500 acres, is Midland Basin acreage that we believe is highly prospective for a number of shale targets. Our operated Sweetie Peck and non-operated Halff East assets, which total about 19,000 net acres, currently generate the remainder of our current Permian production. We've previously drilled these legacy assets vertically and completed them in multiple non-shale rock layers within the Spraberry and Wolfcamp intervals. The industry refers to these as Wolfberry wells. What we're all finding now is that shales source rock throughout these intervals appears to have been largely undrained by our previous vertical completions and can generate prolific production in horizontal wells. The remainder of our perspective shale acreage, roughly 53,500 acres, is a new acreage position that we have been building over the last year in the Northern Midland Basin, which we call, Buffalo. I will discuss that position in more detail a little later in the presentation. I'm now on Slide 12, which shows the location of our Midland Basin shale acreage positions and a number of reported Wolfcamp shale horizontal well results. Our first operated well on the play, the Dorcus 3035H at Sweetie Peck had a 30 day IP rate of 1,226 barrels of oil equivalent per day, which we believe compares quite favorably to what our peers had been reporting in the basin for Wolfcamp shale wells. On Slide 13, we're showing several decline curves and how the early time data for the Dorcus well compares to those curves. The lower curve is the curve, which we've been using for initial AFE economics. The front end of this lower curve was developed based on average reported public data for similar lateral length wells in the southern portion of the Midland Basin. We then projected the average oil rate forward using a hyperbolic exponent of 1.3 and an 8% terminal decline and applied an average gas oil ratio to convert the oil curve to a barrels of oil equivalent curve. This resulting curve generates an estimated ultimate recovery of 430,000 barrels of oil equivalent. The upper red curve is a more optimistic estimate and uses a higher initial oil production rate, a steeper initial decline, a 1.6 B factor and a 6% terminal decline and generates an estimated ultimate recovery of 660,000 barrels of oil equivalent. This 660,000 barrels of oil equivalent number is fairly similar to numbers some of our peers are quoting for wells in our general neighborhood. At this point, our Dorcus well is outperforming both of these curves. We have another well at Sweetie Peck, the Britain 3133H flowing back right now, and a third well, the CVX 4134H drilled, but not yet completed. We will use data from these 3 wells and develop an average or so-called, projected-type curve over the next few months for future Wolfcamp B drilling at Sweetie Peck. In the upper right portion of Slide 13, are some completion details for the Dorcus well. You will note that we put a lot of sand and fluid into this completion. On Slide 14, we're showing what the potential horizontal development of the Wolfcamp B interval could look like at Sweetie Peck. We have identified the 3 wells that we have completed or are currently completing, the Dorcus, the Britain and the CVX. We estimate that there are approximately 65 potential Wolfcamp B locations assuming 107 acre spacing. Lateral lengths will vary from 5,000 to 7,600 feet in length depending on lease limitations. As the map indicates, there are a couple of areas in Sweetie Peck where we drilled Wolfberry wells down to 20 acre spacing, where we are currently assuming that we may not be able to bid in as many wells as in other areas. Of course, we'll do everything we can over time to increase our economic well count. Slide 15 shows a log of a vertical well in the eastern portion of the Sweetie Peck field. Our first few wells are all targeting the Wolfcamp B interval, but there are other good looking intervals here that are already being tested in other locations by industry participants. We believe there is substantial upside at Sweetie Peck beyond just the Wolfcamp B and expect to test that potential during early 2014. Our Halff East acreage position is operated by Concho. They're in the process of drilling and completing several Wolfcamp wells on that acreage and we'll do them the courtesy of allowing them to discuss their operated wells when they have results. Moving to the Northern Midland Basin, I am now on Slide 16. I mentioned earlier that we have built an acreage position we call the Buffalo Prospect. This position was built at relatively low cost around a vertical science well named Tatonka that we drilled earlier this year. The acreage is primarily in Southern Gaines and Dawson Counties. In general, the core and log data we took from the science well look very similar to data we gathered from core and logs at Sweetie Peck, which encouraged us to increase our land acquisition effort. We will be reentering the Tatonka well and completing it horizontally in the Wolfcamp B in December. I'm now on Slide 17 where I'll summarize our shale drilling plans for the remainder of this year in the Midland Basin. At Sweetie Peck, we plan to flow back the Britain well, complete the CVX well and drill 2 additional horizontal wells. At Buffalo, we will complete the Tatonka horizontal leg in December. We will give information about our 2014 plans when we announce our budget for next year, also in December. That concludes our survey of Permian Basin acreage and activity. Regarding our New Ventures program, we have a quick update on Slide 18. In the Powder River Basin Frontier play, we did not have a rig running on the third quarter, but have recently picked 1 up in October. We've been pushing ahead with our permitting effort and have 10 permits in hand with an additional 22 applications submitted. As a reminder, these wells currently take 80 days or so to drill, so approximately 5 permits can support a rig line for a year. We firmly believe that we'll be able to obtain the permits we need to support our contemplated levels of activity over time. Lastly, in East Texas, we recently leased or committed to acquire approximately an additional 20,000 net acres in the play bringing our total to about 215,000 net acres. We drilled at Eagle Ford tests on the Western end of our acreage position in the third quarter, which we plan to have completed shortly. We currently have 2 rigs running in the area, and we'll be drilling a series of additional test wells in the coming months. Before turning the call over to Wade for his elaboration on our strong financial position, I'll make a quick comment on our Anadarko Basin divestiture process. We had great participation in our sales process. It was very well run, and we're very proud of our employees, who put the sale process together and the information. We received bids late last week and are in the process of evaluating those. We are still targeting a closing date sometime around year end. Given where we are in the process, we won't be able to give anymore color on that today. With that, I'll turn the call over to Wade for his financial update.

Thank you, Jay. I'll start on Slide 20. First thing I'll mention this morning is during the third quarter, our net cash from operations exceeded our capital expenditures resulting in an unchanged long-term debt balance for the quarter. Our capital structure remains very straight forward and transparent with 4 pieces of long-term debt and a revolving credit facility, which we currently have only $28 million drawn against. As a reminder, our borrowing base increased in the third quarter to $2.2 billion, up from $1.8 billion at the end of the second quarter. And our current revolver commitment is $1.3 billion. The increase to our borrowing base was driven by our increasing reserve base at mid-year. So moving to Slide 21, we are showing our debt maturity timeline for our unsecured bonds and secured credit facility. As you can see the earliest maturity of the bonds is over 5 years out. Turning to Slide 22, which is my last slide. We have a graph, which shows our debt to trailing 12 months EBITDAX against a group of peer companies, which we track internally. As you can see the slide, our leverage metric improved quarter-over-quarter with growing EBITDAX and unchanged debt. It also shows that we are significantly below our peer group average of 2.5x debt to trailing 12 months EBITDAX. Finally, we did add a lot of hedges during the quarter, and you can see those details in the 10-Q which we filed this morning. So with that, I'll turn the call over to Tony for his closing remarks.

Thank you, Wade. Before handing the call over for your questions, I'd like to spend a few minutes reviewing what we think are the key takeaways from this morning's call. First, we had an excellent quarter, with record production at the top end of our guidance range and record quarterly EBITDAX of $410 million, which grew 57% from this time last year and which exceeded our CapEx spending for the quarter. Second, our balance sheet remains strong, as Wade just pointed out. Our outstanding debt was unchanged from the prior quarter and we have approximately $1.3 billion available under our revolver. As our EBITDAX continues to grow, our preferred leverage metric, debt-to-trailing 12 month EBITDAX has improved during the quarter, and we are now at 1.2x, which is half of the peer group average. Lastly, we continue to grow our oily inventory. We've been working hard in the Permian putting together an expanded position in the basin. And I'm happy that we're now at a point to be able to share more about our success and our plans for that program in today's call. Our first Wolfcamp B horizontal well looks very encouraging thus far, and we'll be drilling wells in this interval for the remainder of the year. We are anxious to test our newly acquired acreage in the Northern Midland basin as we move towards year end. In 2013, we have significantly increased the amount of oily inventory in the company. We have expanded our position in the Permian, have obtained a substantial and still growing position in East Texas and a significant position in the Powder River basin. All 3 of these emerging plays are oily, and our success here will continue to shift our production mix towards the liquid side as well as contribute to SM Energy's long-term growth with continued success. I'd now like to open the call up for your questions.

[Operator Instructions] Your first question comes from the line of Pearce Hammond with Simmons & Company. Pearce W. Hammond - Simmons & Company International, Research Division: Tony and Jay, can you provide a bit of a broad outline on your thinkings for the '14 capital budget. I know you're going to give the guidance in December, but any kind of general thoughts. I know the Mitsui agreement will roll off at some point next year, the carry will, so just some general thoughts.

Yes, Pearce. As we talked about earlier, we're going through the budgeting process right now and expect to provide 2014 capital guidance in December. But directionally, what I would say at this point is, you should expect a capital program that's similarly sized and focused like 2013. The additional change to that would be the Mitsui carry, which we would expect to be completed sometime during the first half of next year. And we've kind of said, if you think about that as kind of $250 to $260 million a year, maybe somewhere around $150 million might be something reasonable to add to kind of the size of our CapEx this year. But again, that's directional we're going on through the specific budget plans for next year. I should mention, too, that the success that we're seeing right now is baked into the 15% growth target for next year. Pearce W. Hammond - Simmons & Company International, Research Division: Great. And then my follow-up would be some producers have talked about upper and then lower a Eagle Ford, Do you see that same sort of horizons on your acreage in the Eagle Ford?

Let me mention one thing -- one correction on my last comment. I should mention when I talked about our kind of directional guidance on CapEx next year, that minimal success from our New Ventures plays is baked into that plan for next year at this point.

I'd like to address the question on the Upper Eagle Ford. We are aware that Rosetta is doing some pilot testing in the Upper Eagle Ford, and we look forward to seeing their results. We have always believed that there's hydrocarbon storage in the upper Eagle Ford and to some extent in the Austin Chalk. However, we've also believed that the fracs we're doing are already draining that rock. So if they proved something up there, we will be happy to follow up on it.

And your next question comes from the line of Jeb Bachmann, Howard Weil.

Jay, I had a couple of questions on the Wolfcamp. I noticed you didn't include any cost assumptions for those wells and understanding you're putting a lot of science into these early wells. Can you give us any kind of commentary on that at this point?

Well, you're right, Jeb. We are putting a lot of science in here and experimenting with different proppants and some pretty expensive proppants on the early wells. The direction we're taking here is to leave it all in the field and make good wells early on. I do think we'll see some substantial cost reduction over time. The Dorcus well cost was about $8.5 million, but you can see we put a lot of effort into it. We're getting faster drilling them. I think we can get our cost down over time. We are going to spend some more money on premium proppants on some of the early wells to I just see what the impact of that is. We're going to make wells here early on and then we'll optimize costs through the future.

Okay. Then looking up into Gaines and Dawson County, is Tatonka the only vertical well control that you have on that acreage at this point?

There's a lot of vertical wells up there, Tatonka is the only well where we have core end logs that we can really compare to. And as I indicated earlier, the core end logs look very similar to our Sweetie Peck core end logs, which we have an identical set of logs and core from Sweetie Peck. So we really built the position based on the science that we saw, and we're very hopeful that we'll get some more results.

In that core analysis, that includes the maturity of the rock up there, you're saying is similar to Sweetie Peck?

Yes. And I will say if you get much farther north than our position in Gaines and Dawson, it will get immature. So I mean the rest as you go north, there is immaturity, there is different rest as you go East and West. We tried -- we built this position at a very specific location for a very specific reason, and we certainly hope that we're right, but the core end logs are very encouraging.

And you mentioned the Bone Spring wells, do you have any rates on those yet or are those flowing back at this time.

Generally, they're making our AFE numbers. We drilled a number of wells. They're going to have EURs between 300,000 to 400,000 barrels,. Typically they will IP somewhere around 500. They're nice wells, they're not huge in the context of our overall program, just because we just don't have that many locations.

Okay. And just 2 quick ones, if I may. Any update on the Andrews County sale. I know you gave us an Anadarko basin update.

Jeb, we're in the process, and we have some bids. And we're moving forward, and that's really all I can say.

Okay. And then last one from me. Tony, with the strong balance sheet and asset sale proceeds likely coming in the door here shortly, any kind of commentary as to what you guys plan to do going forward in terms of ramping up activity or looking for adding new acreage in some of your stronger areas?

Yes, I would say we certainly have the dry powder to execute the program that we've laid out. But also we've got the strength of the balance sheet to pursue additional opportunities as we see them. As I mentioned, our capital plans for next year, which includes 15% production growth on a higher base for this year include very little success in our new venture areas. So we've got tremendous opportunities. We continue to see success, and we certainly could ramp those programs, especially in East Texas, if we see success there. So we've got a lot of running room and we've got the strong balance sheet to support that.

Your next question comes from the line of Michael Hall with Heikkinen Energy.

First just a couple of quick ones in the Permian program. Just trying to think through, I guess, as that progresses into next year, assuming success in the North, does that eventually -- does that looked like a 2-rig program with one running in their Southern Sweetie Peck and one up at Buffalo, or would you initially be kind of hopping rig back between the 2 areas. And then is that an additive how this added the program to 2013 spending or how should we think about that going forward?

This is Javan. It's just too early to tell. I think we could clearly support a several rig program in the Sweetie Peck area alone and then if we're successful in Tatonka, which unfortunately we won't really know until mid December, which is after really when we'll put our budget together, we could support a multi-rig program there as well. So as Tony said, we're positioning ourselves from a capital standpoint, from a debt standpoint and from bringing in some proceeds to be able to ramp during 2014 in the Permian or in East Texas. And we honestly expect that we will be doing that to some extent, but I think our initial shot at a budget will probably be fairly conservative in the sense that we won't budget a lot for success we haven't seen yet. But clearly, there's an opportunity here both in East Texas and in the Permian to ramp into some really nice oily success next year. And that's why we're selling assets, that's why we're building our war chest here essentially to be able to go out and do that.

Okay. That's helpful. I appreciate the color. I guess, along with [ph] East Texas, if could you remind me on what to expect from a data flow standpoint on that asset and what you all are testing and when we should expect to hear more about it and kind of go forward there?

You bet. Sure. Yes, great question. I'm glad you brought it up. As we indicated, we're completing an Eagle Ford test during the fourth quarter on the Western end of our position. We have 2 rigs running drilling Woodbine tests right now farther East over in the San Jacinto County area, generally. And we've got several more tests to come there. I don't think you'll hear much from us about results until sometime next year, probably early in the year on the Eagle Ford test, a little later perhaps on some of the Woodbine tests. These are fairly long wells to drill and test. Obviously, you're looking forward to getting our wells drilled and seeing how this plays out. As I said, we're going to release our 2014 budget mid-December, and you should assume that we're not going to budget for success in that program. And with success, we would need to revisit our production and capital forecast some time next year.

Okay. Great. And are you looking at any other targets on that asset outside of the Woodbine and Eagle Ford at this point? Obviously, [indiscernible] putting any capital work on any other targets.

Well, there are several other intervals of interest. The Austin Chalk is going to get some focus, I can tell you, during next year. I haven't seen any specific plans to drill any other targets other than those 3 yet, but I wouldn't be surprised if we're successful in some of these that we will find some other ways to spend some exploration capital during next year.

Great. The last one of mine, just housekeeping. On the new Permian acreage in Buffalo, what was roughly the working interest there?

We're going to be 100% essentially on all of it.

Your next question comes from the line of Joe Magner with Macquarie.

I just want to -- sorry, to go back to the CapEx question. I just want to clarify. Tony, you mentioned that next year's program initially will be sort of similar to '13 levels, with the additional of the Mitsui carry for a portion of the year, and that there is some amount of New Ventures spending in there. There are a lot of -- I guess a lot of comments being thrown around regarding what's being considered with the 2014 guidance that we'll get in December versus what we might see later in the year as you get more information. So is that -- am I understanding that correct? Initially, it would be similar but there could be upside with more detail and more information from these newer opportunities?

Yes, I would say that's reasonable and keep in mind, too, that each year, we have a component of our budget that's focused on New Ventures. And it's generally been running somewhere around $125 million or so per year. But again, that varies a little bit, but that's kind of what we had in mind for -- that's what we had in our budget for this year. So I would expect something comparable next year. But again, as Jay mentioned, we're certainly poised for ramp-up if we have success with some of these emerging plays.

Okay. And I just wanted -- I guess, a follow up on a comment that was made briefly about what is and is not included in your 15% production growth target for next year. I think in the past you've said that there's a small amount of New Ventures built into that primarily associated with the Powder River Basin. Is there much in there for the Wolfcamp at this point?

No. This is Javan. No, there isn't. And really, the statement you just made is accurate. There's a little bit of Powder River Basin upside in there. We basically baked that in, assuming we're going run a rig or 2 up there. But we're not budgeting, and we haven't -- in our modeling, we have not assumed success in East Texas or in the Permian Wolfcamp Shale in our 15% numbers. So I think what you'll see, as Tony indicated, when we come out with our budget, it's a little too early to tell on both those plays in terms of how big we go. We may very well, given our success at Sweetie Peck, go ahead and budget a little more activity there, but that might be offset in some other areas. But I think the 15% number is a good number to start with, and we'll see what happens in Tatonka and in East Texas, and we'll make adjustments later in the year as we need to.

Okay. And then just last one. You mentioned that the production mix shift in the third quarter was due to some gas flows that were shut in, and maybe we would see that revert in the fourth quarter. How much impact could that have, and I guess what the -- how much more could it shift back to the gas side of the equation with those wells being brought back on line?

Great question. I think what we always have said is that we'd be running at about 50% by year end. That was our target. I still think that's a correct assumption. When we exit the-year, we will be running at about 50%. That number will be helped by the fact that when we sell the Anadarko Basin assets, that actually shifts us to a more oily mix as well. I would expect to see, with gas rates coming back, some in the Eagle Ford in the fourth quarter, I would expect us to have a slightly gassier year mix in the fourth quarter. I haven't calculated an exact number for that, but I'm guessing it's going to be somewhere around 52%. But that's a really detailed number. And I'm guessing a little bit. But a couple percent shift back toward gas wouldn't surprise me at all.

The next question comes from the line of Welles Fitzpatrick with Johnson Rice. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: On the quarter-over-quarter growth in the Eagle Ford, obviously that slowed a little bit due to the shut-ins. But have you guys had any or do you see any issues with regard to interruptible capacity until you hit that next bump in your contracts?

We have never had problems shipping gas on an interruptible basis. At this point, we have all the firm we need for the volumes we've been shipping, but we believe that there's interruptible available until we need -- until we hit our next firm tranche. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: Okay, perfect. And then am I remembering correctly that the Roy area is around 21,000 of the 55,000 in Tredway?

That's about right. Yes. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: And any commentary -- and you hit on it a little bit earlier, and I suppose it's easy enough to follow the money that you guys are permitting [ph] a lot around that initial San Jacinto well. But any commentary on how that, I believe 2,500 footer, held up in the longer dated rate?

We haven't had a lot of opportunity to flow the well, but in general, the wells we've drilled, although they had some mechanical troubles, have looked pretty good to us. I think really it's way too early, and we're going to get some wells drilled with decent length laterals and get good completions on them. And at this point, I would say everything is still really up in the air.

And your next question comes from the line of David Tameron with Wells Fargo.

Most of the questions have been asked, but just going back to the DD&A rate, a pretty substantial drop both for the third quarter and the full year. And I know you mentioned this when you did your mid-year revolver redetermination, that you had an increase in reserves. But is it the right read from my end that the reserve growth is greater than you anticipated or is there something else going on in that calculation?

I mean, you're reading it correctly. It's a combination of the reserves that we did at mid-year, not only adding reserves but the cost improvements that we have been seeing getting baked in there as well.

And David, I think a lot of people don't recognize it, but we've been -- over the last 3 years, we're in the top quartile of our peers for F&D, following F&D and that number is rolling into our numbers as we go forward, and it's approaching -- our DD&A rate is approaching that number, which has been in the $14 range of over the last 3 year average.

It's coming down.

So it's coming down and moved a little more than we expected this quarter. But clearly, we're moving toward our long-term F&D average.

I would say, too, that it's also a function of the improving quality of the portfolio, which we've continued to core up over the last few years.

Your next question comes from the line of Matt Portillo with TPH. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just a few quick questions for me. In terms of the Bakken, can you give us an update on some of the downspacing that you're testing and maybe when we could expect some results there? And then I guess the second question alongside that, as inventory increases, how do guys think about capitalizing this asset from an acceleration perspective? And does this kind of still fit in the core part of your portfolio with the emergence of the Permian as kind of another play that may ultimately garner additional capital?

Well, good question. We're in several -- frankly we're in some of Kodiak's wells. So we're in a number of several different spacing tests, and we're monitoring all those. Yes, I think it's an interesting question about acceleration. If you think about what's happening in the Bakken right now with what some people refer to as a kind of a technical renaissance in fracturing and all the things that are going on there, I think it's actually a very powerful argument for not going too fast. We really believe that the potential for adding value through this type of technological betterment through downspacing and better frac technique is one of the best reasons for moderation in your pace of development, and we've maintained a pretty constant 3-rig program there, which we think is consistent with the kind of inventory we have. We're going to be able now to take advantage of spacing, downspacing and better technical work as we go forward. I don't think that, I had a supervisor at one time that said, "You know, you can PV yourself to death." It's appropriate we think to maintain a moderate pace where we can take advantage of these great assets getting better over time. So we think the Bakken and Three Forks is a big part of our portfolio. We love the area. We have no intention of exiting it. We have cored it up a little bit, where we've sold some non-op assets that we didn't think were performing as well. And we will continue to do that as appropriate. But our operated acreage looks really good to us, and we're looking forward to applying new techniques and additional spacing learnings that we get to that acreage as we go forward.

I think a good way to think about our development portfolio today is kind of that 3-legged stool. It's an overused cliché, but in our case it's true. Certainly, you've got the Eagle Ford. The Bakken remains a very strong leg on that stool. And now you're seeing the Permian forming another strong leg with our core development plan. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And then just a quick question in regards to the type curves presented on the Wolfcamp B. You mentioned that came from public data. Just curious on the 430,000 EUR. Could you mention which counties you guys included in that, just to make sure that we're thinking of like-to-like kind of asset analysis there?

This is Jay. I'm going to pick words just a little bit. I never used the words that those are type curves, and they're not -- we're not using them as type curves because a type curve to me means an average of a bunch of our wells that applied to our data. What those are, the low curve we took the front-end oil rates from a bunch of Southern Midland Basin wells, a lot of this would be the far south areas where people have more data, the EOG areas, all those other areas, we took the front-end oil rates for that, and then we projected them forward using what we think is actually a pretty reasonable number for the long-term B factor, the 1.3 and an 8% terminal decline, which generally is going to be how we would book wells early on, with a fairly conservative B and a higher terminal decline than some people use. The higher curve on that's on that sheet really is just an upper -- it's a higher estimate for us. We used a higher decline rate early on, kind of set the initial production rate up based on the fact that Dorcas [ph] looked like it was going to do that. We used what we hear from a lot of industry participants. It's a little more standard 1.6 B and a 6% demin [ph], which again those are yet to be proven in any well. B factors in these types of plays tend to come down over time, unfortunately. But we are not representing any curve on there as a type curve for Sweetie Peck development. Until we get 3 or 4 wells behind us and get some run time on them so we can build a good average, we won't represent anything as a type curve. Those are just decline curves that we put on there so people could see, hey, this is kind of what the thing is looking like. We should have something that looks like an average type curve here in a few months after we get a couple more wells and get some more data. But I think that the 6 60 number that's on there is very similar to some numbers that some of our other industry participants are throwing out in some of their investor presentations, and that curve shape is not too far from some of the curve shapes that you'll see people showing in investor presentations. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And this is my last question. You guys mentioned that Anadarko is picking up incremental frac crews in your non-operated acreage to blow down some of the wells. I was wondering if you could provide a little bit of color on how many wells are kind of in inventory today. And then does this change your kind of growth rate assumptions on your non-operated acreage over the next 6 to 12 months?

I don't have that number at my fingertips here, so I'm not going to quote a number that might be wrong. And it doesn't change our perceptions of the growth rate. I think we've always maintained that this thing would grow at an average of about 5% growth rate per quarter. Sometimes it's a little lumpy. Our views on that haven't changed.

Your next question comes from the line of Mike Scialla with Stifel. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Jay, you'd said that in your Buffalo area to the north, there's the risk of immature rock, and you mentioned some risk to the East and West. Can I infer that even if you do have success with your Tatonka well that you probably don't grow that position from the 53,000 acres that you have now?

Mike, there's still some more acreage in our buy area, but we probably won't be moving north and we won't be moving a long way east or west either. We think we're basically kind of at the end of the prospective rock up there at least at this point. And we may learn something that tells us that we are being overly conservative about that. We have a little bit bigger buy area than what we actually bought, and we'd like to pick up some additional acreage still, but it's going to be pretty close to where we are now. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And then looking at your cross-section for Sweetie Peck, you show 7, I think, potential intervals that are prospective. Have you heard of any other companies testing any of those, or have you tested any work -- while I guess you obviously haven't at this point, but where do you think you're going next with the horizontal well beyond the Wolfcamp B?

I'm pretty sure our next test will be in the Cline, and the reason for that is largely because it's the deepest and it would hold the most acreage to do that, so if the Cline works we'd drill. We would probably focus on Cline drilling for some period of time in order to get all depths held. We're enthusiastic about the lower Spraberry Shale there. I think that's another pretty good target. If you read some investor stuff, there's people targeting the [indiscernible] and other things and other areas, but Wolfcamp A looks like a good target. But I think right now, we're probably more focused on the Cline than anything else. And I think you'll see us drill a test in the Cline early next year. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And when I look at that, I mean, it just looks -- you've got so many different intervals that are prospective vertically. Didn't -- wouldn't that argue for tighter vertical spacing or why does horizontal take preference over vertical development here?

If you go back to the way these wells were completed, what they did -- what we did is we would drill a vertical well, and then we would essentially complete the -- and I'm going to call them carbonates, but they're kind of dirty carbonates intervals, all in between, you say, make like a 12-stage frac completion. In which you're completing 12 different intervals through here. That wouldn't work in a shale. I mean, if you want to target shale, you can't make a completion where you target 12 little fracs in a shale because that won't add up to one big well. So what you need in a shale is you need to get it long laterals, you need to get a long opportunity to put a bunch of fracs into that individual shale. Putting a hole at one single frac into a shale is not going to make it into 5 different shales, isn't the same as having a 5,000 foot lateral with 26 stages of frac in it. So I don't think vertical's the right way to go here. I think what we'll be doing is targeting specific shales as long a lateral as we can drill within our lease limits, and we'll go as -- we will try to start at the deep end and get the acreage held if we can -- to the extent we can do that. Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division: And one last one from me. The 22 wells you brought on in the Area 1, do you have enough production history on those to say how they're performing versus your type curve?

Not really. We've had a lot of up-and-down time. We tubed up a bunch of the wells. We've tried some different techniques, where we're leaving some of the wells -- leaving them on restricted chokes for long periods of time. So some of the wells that I've looked at look pretty good, in general, on some of the yields. But other than that, I really can't say a whole lot. It's just too early. We'll update that during our reserve process and probably give more information sometime next year on it.

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

I'd like to dig into the DD&A rate that changed, a little bit more. You've obviously indicated that had to do with kind of the updated reserve report was the big reason for that. Can you give us a sense on from a little bit of a mix shift and component shift that you saw on that, specifically is there a lot more Eagle Ford PUDs in there? And what were the assumptions on well costs and EURs versus what old reserve report had previously indicated and whether or not the assets you have up for sale in Anadarko Basin would have been included in that number as well?

A lot of questions there. We probably can't answer that much detail on our midyear reserve report, Scott, but I will say that PUDs didn't have much to do with it -- I heard you mention PUDs. But beyond that, we really can't say much more about the midyear reserve report.

Anadarko, that would have been held for sale.

Yes, that's an asset held for sale now, so the Anadarko Basin is not in there.

Okay. So the Anadarko is out. And implicitly there are some improved EURs and lower well costs in the Eagle Ford PUDs, but you're not going to quantify that at this point, is that right?

This is Javan. I'd just say in general our reserves are -- our reserve report looked good and our costs have been coming down. And that's consistent with the trend -- a long-term trend here of improving our portfolio, as Tony indicated.

Okay. Fair enough. And then moving to the Permian. Just a question on the Sweetie Peck area. Obviously there was a very strong result from Dorcus. When you look at where that asset is positioned relative to, I guess, the basin over there in Midland, it's more toward the central basin platform. Did some of your acreage start to come out of the basin a little bit? Does it tend to be a little bit shallower than some of the other industry activity you're seeing today? Or can you give us a little bit of color on that?

Well, I think that, that was the big risk, really at Sweetie Peck, because you are more towards the shelf edge. And I think it's a really interesting result from an industry standpoint because I think it tells you that you can get closer to that shelf edge than maybe people thought. I don't know that, that means there is going to a lot of acquisition opportunity for anybody because a lot of this acreage is already held, but it is probably the closest well to that western edge that's really made a good result. And that was where the risk was I think. So anyway, I'm -- it's a good first result. We're excited about it. It's obviously very encouraging. It's still early days.

Absolutely. And to that point, with some of the vertical wells that you have done that are -- in looking at your map, Dorcus was somewhere in the central part of your asset base. If you go a little bit further to the west, do you see any, like, significant changes in the geology and depths or composition in some of the vertical wells?

Well, our mapping would show that some of the shales are more prospective on the east side of the block than they are on the west side of the block. That's not just the Wolfcamp B. It relates to other intervals as well. I think the farther west you go, the more risk you run as these things thin. And certainly, we saw that up in Andrews County when we got up there. So basin center is great. I think all we proved here was that you don't have to be dead basin center to make one of these wells work really well.

Okay, okay. And then one last question. With respect to trying to hold this acreage, you referred to looking at the Cline. When you drilled the vertical wells, did you pretty much just go down to the Wolfcamp as the deepest zone? Or are any of those -- are any a bit deeper -- so when you're looking at potential Cline over this acreage position, does a good chunk of this still need to be held to that lower formation?

I don't want to get into a whole bunch of specific land details because, frankly, I just don't know them as well as I should for a question like that. There's no question that some of the vertical, early vertical wells didn't go quite as deep the way that play worked out. People kept taking them deeper and deeper over time, so some of the early wells didn't go quite as deep. In general, we want to -- we're going to drill the Cline early because we think it gives us our best shot at -- A, it's a good thing to do; B, it will help us solve any issues we have like that.

Your next question comes from the line of Brian Velie with Capital One Security.

A couple of quick questions. In the Buffalo area, is there any reason to believe that costs per well there would be any different than what you're seeing or what you saw on the Dorcus well? Or can we assume that kind of $8.5 million with heavy science trending downward over time is a safe assumption for that area as well?

At this point, I really don't have any way to give you a number that's better than that. We don't expect well costs to be significantly different.

Okay. That's helpful. And then one other quick question, and I'm not sure if you can comment or not. But you mentioned that the Buffalo acreage was acquired at a relatively low cost. Can you put a number on that? Or is there an average that you think we could use?

We're still closing and acquiring a little bit, so I don't think we'll use a number. What I can say is it was low cost compared to some of the numbers you'll see in the more established areas of the basin.

Your next question comes from the line of James Spicer with Wells Fargo.

Just going back to the balance sheet for a minute, you guys are clearly in a very strong financial position here. Spending is roughly in line with cash flow. You're going to be building up a pretty substantial war chest with the proceeds from the Anadarko Basin sale and then some of your other smaller asset sales. It sounds like the intention here is to use the proceeds from these sales to support and potentially accelerate the CapEx program. I'm just wondering whether there are any other uses of proceeds that you're contemplating, be it further debt reduction, share repurchases, dividends, anything else.

Yes, James. This is Wade. I mean, just to tag along to what Tony said, we'll be reviewing all those capital allocation decisions over the next few months before we come out with our '14 plan. And it really does depend on the success of the New Ventures areas. I mean, those could add a lot of capital for very good reasons. So right now that's really all we're saying on it. But as we always do, we'll review all of our options and consider our balance sheet as we go along.

Okay. And then a related question. The 1.2x leverage where you guys are today, is that something you view as a good long-term level that you feel is optimal for running the business? Or do you think that could move up materially higher or lower given your view on capital spending?

Yes, this is Wade again, James. Yes, the 1.2x is a very, very comfortable level, obviously. You've heard me say in the past the we would be comfortable going up to around a 2x level, so that's still the case. That hasn't changed. It's a very enviable position to be in where we are right now, but we would move that up for the right reasons.

Your last question comes from the line of John Nelson with Citigroup.

First, just a housekeeping item. Can you confirm the Dorcus well rate was a 2-stream rate and what an approximate number might be on a 3-stream basis?

John, I have to apologize but I could not hear your question. Could you speak up just a little bit?

Is this better?

Yes, just talk loud, okay?

Sorry about that. Just the question was on the Dorcus well and whether that reported number was a 2-stream rate and if there was an approximate number you could provide or what a 3-stream level equivalent might be.

That was a 2-stream number. It's wet gas and oil. And it is rich gas, but I don't know the exact -- I don't know what the 3-stream number would be because, again, we -- our gas contracts don't provide us with a liquid volume, but it's pretty rich gas.

Fair enough. And then in your prepared comments, you talked about putting a lot of sand and fluid relative to peers. And you also I think had tighter frac stage spacing. Jay, sort of peer-leading well results have [ph] sort of normalized on that basis. I'm just curious your thoughts on if we've sort of run as far as we can as sort of increasing the intensity of the wells, or whether there'd be sort of diminishing returns from continuing that trend.

Well, our focus here early on was we wanted to put everything into this as we could, so we went about as tight and about as big as we thought we could and probably one of the biggest fracs we've ever pumped. And that was our focus was to really make these wells work early on, and they are economic the way we're pumping them. I think most of our optimization, we're going to look at some different profit types. We've pumped this well with all white sand, the Britain well, where we're actually using a premium resin coated product, and we're going to pump ceramic on one of these jobs here pretty quickly. As far as stage spacing and fluid volumes, I think we're probably at the top end of where we would be, and we'd probably start working our way. So we'll get this stuff done, this testing done, then we'll probably start working our way down as opposed to up, and that was really our focus was let's do the big stuff first and not kind of sneak our way into it over time. We wanted to do the testing early. So I guess that's an answer to that question.

That's great color. Last question I've got to ask, it's obviously very exciting sort of news coming from the Permian, and the bounce on your stock today is encouraging. But there's still what I would consider a pretty staggering valuation discrepancy between sort of where you guys trade and either where more Permian pure plays are trading or sort of are buying assets at. Given that you guys have been proactive in reshaping the portfolio historically, I'm wondering if you would evaluate monetizing the Permian here or if there might not be tax efficient way of sort of capitalizing that arbitrage.

Well, I'll take the first stab at it. Obviously, we see the multiple as well and it has been -- we have been encouraged recently by the stock performance clearly outperforming all of our peers in EPX at a significant level this year. As I said before, over the next few months we'll be looking at our capital allocation decisions and we factor everything in, and that's not going to change. Regarding your specific question about monetizing the Permian, we always look at our assets as part of that process, and that's why we're selling the Anadarko Basin. Permian is part of our 3-legged stool, as Tony said earlier. But beyond that, I'm not sure I would say any more.

I would say that part of why we spend so much time on the Permian today is so that people could understand what we believe is a really compelling portfolio there, and we certainly hope to see that result and some value accretion to the company for doing that.

At this time, there are no questions.

Thank you, operator, and thank all of you for joining us for the third quarter call. Again, I would like to certainly compliment our organization for putting up some great numbers and for their execution and exploration efforts. We look forward to talking to you at our fourth quarter call as well as year end. Thanks so much.

Thank you. This concludes today's conference call. You may now disconnect.