SM Energy Company (SM) Q1 2014 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the SM Energy First Quarter 2014 Earnings Conference Call. [Operator Instructions] Please note that today's conference is being recorded. I would now like to hand the conference over to David Copeland, Executive Vice President and General Counsel. Sir, please go ahead.

Thank you, Karen. Good morning to all joining us by phone and online for SM Energy's -- SM Energy Company's First 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 this 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 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 Factor section of our Form 10-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 press release from yesterday. Additionally, we may use the terms probable, possible and 3P reserves and estimated ultimate recovery, or EUR, on this call. You should read the Cautionary Language page in our slide presentation for an important discussion of these terms and the special risks and other considerations associated with these non-proved reserve metrics. Company officials on the call this morning are: Tony Best, Chief Executive Officer; Jay Ottoson, President and Chief Operating Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; Brent Collins, Senior Director of Planning and Investor Relations; and I am the company's Executive Vice President, General Counsel and Corporate Secretary. I'll now turn the call over to Tony.

Thank you, David. Good morning, everyone, and thank you for joining us for the First 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, we had a good start to the year, and we are executing well on our 2014 business plan. In the first quarter, we came in at the top end of our production guidance range and we performed well on most of our guided cost metrics. Our plan for 2014 include a conducting a number of inventory enhancement tests in our core Eagle Ford and Bakken/Three Forks programs, and we are following through with this plan. In the Eagle Ford, we have been drilling wells this year with laterals that are on average almost 25% longer this year than last year, and we've also meaningfully increased our sand loading in our completions there. In the Bakken/Three Forks, we plan to conduct a number of tests beginning in the second quarter that include completions with higher sand and fluid volumes, downspacing tests in East Raven and testing new Bakken intervals at Gooseneck and Stateline. It will take some time to get results from all of these tests, but we expect that they will further improve the economics of both our Eagle Ford and Bakken/Three Forks programs and increase our inventory meaningfully in these plays. As noted in yesterday's press release, we have entered into agreements to acquire additional acreage in the Powder River Basin. These assets complement our existing acreage position, and we're excited by what we are seeing in the Powder River Basin. Jay will share some detail on this in a moment. Lastly, our New Ventures testing in the Permian and East Texas areas is progressing well, and we expect to have more to share on these plays later this year. With that, I'll move to Slide 4 for a quick rundown of our quarterly performance. From a production standpoint, we were at the high end of our guidance range with an average of 138.6 MBOE per day in the quarter. As you'll recall, we closed on our Anadarko Basin assets in the Mid-Continent late in December, which is why our reported production declined slightly on a sequential basis. On a retained properties basis, we grew average daily production 2% in the first quarter. From a cost metrics standpoint, we were within or below our guidance range on almost all of our guided metrics. We reported GAAP net income of $0.96 per diluted share for the quarter and adjusted net income of $1.58 per diluted share. Our quarterly EBITDAX for the quarter was $399 million. 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, where I'll discuss our operated Eagle Ford program. We made 20 completions during the quarter. Our pad drilling program results in some lumpiness in the timing of completions and we didn't make any completions in the month of March. The wells we completed in the quarter were generally drilled in 2013 in areas 2 and 3 and averaged 5,430 feet in length, which was typical of our 2013 program. As Tony mentioned, this year, we generally have been drilling longer laterals in our Eagle Ford program and are increasing the amount of sand that we're using in our completions. Our wells are typically choked back on initial completions, so it does take some time to assess the impact of these types of changes on well economics. I would expect that we'll have some data to share in comparable well performance in the second half of this year. On Slide 7, you can see that APC completed 107 flowing completions in the first quarter, and that we had sequential production growth of 17% after a relatively modest growth in the previous quarter. Our transportation cost in the APC-operated areas were high during the quarter, which drove our corporate number over our guidance. Due to a shift toward a higher percentage of NGL production, which has higher transportation cost associated, and charges for trucking and shipper pay deficiency fees during the quarter. Consistent with our prior capital guidance, we anticipate that the Mitsui carry will end during the second quarter. So from that point forward, we will be paying our own way for drilling and completion activity in the non-op Eagle Ford. Moving to the Bakken/Three Forks play on Slide 8. I think most of the investment community is aware that this winter was pretty rough in the northern Rockies. Some of our activities there, particularly our completion work, were impacted from a schedule standpoint. We completed 12 gross wells during the quarter, but later than we expected, which is the reason our rate in the Bakken was flat sequentially. In general, our assets are performing well and we're optimistic about proving up additional economic drilling inventory in the Bakken/Three Forks this year, as Tony previously discussed. In the Permian on Slide 9, we're still planning to spud our first Wolfcamp D well in our northern Buffalo exploration acreage in the second quarter to be completed in the third. At Sweetie Peck, we completed 3 additional Wolfcamp B wells during the quarter. On Slide 10, we've updated our production plot with some additional data, which indicates that our 5,000-foot lateral wells all appear to be achieving results better than our economic hurdle at this point. As a reminder, our hurdle rate for development drilling is a 1.2 discounted present value to investment ratio calculated at 15% discount rate, which is roughly a 25% forward-looking rate of return for projects like this. The Dorcus 3036 is our first longer lateral test, about 7,500 feet. We don't have 30 days of production on that well yet to report, but to date, it's performing well and certainly in line with our expectations. I'm now on Slide 11, where I'll provide an update on the Powder River Basin. As noted in our press release yesterday and as Tony discussed, we've entered into agreements to add approximately 28,000 net acres or roughly $100 million in cash in some non-core acreage traded in the eastern Powder River Basin. Once we complete these transactions, we'll have 161,000 acres in the Powder River Basin, 122,000 of which will be prospective in the Frontier. A good portion of what we are buying are additional interest in spacing units in which we already have some interest, which will allow us to operate more of our acreage position and control the pace of development and spend. As you can see, our acreage extends over a trend area roughly 30 miles from one end to the other, and I think it's fair to say at this point that we've achieved a dominant position in much of that area. On Slide 12, you can see our most recent cumulative production plots for our long lateral operated wells in the Frontier. The wells are all performing better than our economic threshold. Our most recent long lateral well, the Blackjack, had a 2-stream peak 30-day IP rate of 917 barrels of oil equivalent per day. We're currently flowing back a 5,000-foot lateral well, the [indiscernible], which is also looking good but doesn't have enough producing days yet to calculate a 30-day rate. We're going to be increasing our activity level to accelerate our delineation program in this area. We're currently running 2-operated rigs, and we'll be adding a third rig later this quarter. Our operations folks are focused on improving our drilling performance and refining our completion designs, and picking up a third rig should help us accelerate that process. We now expect to complete 11 wells in the Powder River Basin in 2014 operated wells, up from the 8 we had planned for in our original budget. I should note that several of these wells target the Shannon, which also adds significant potential across our acreage and which we believe has historically been under-stimulated. Our next several Frontier wells will be important ones as they target the area in the center of our acreage position. With continued success, I would expect that we could further increase rig count in 2015. In summary, our Powder program continues to generate encouraging results. The pending acreage transactions we've announced are entirely consistent with our basic organic growth strategy and add to what we believe can be a significant new resource play for our company. I'm now on Slide 13. In East Texas, our focus for 2014 is to roughly determine the economic potential of the acreage we've amassed there, start the build-out of gathering infrastructures to most prospective portions of the prospect areas and determine where we would like to pursue additional leasing. You can see on to slide the exploration wells that we plan to drill in 2014 to enable these early decisions. On Slide 14, we presented the results from the last 2 wells we've completed in the Deep Pines West prospect area. As noted, these well test rates and the duration of our test rates are constrained due to a lack of gas-gathering infrastructure. At this point, we can conclude that the initial productivity of the wells is encouraging after completion and that a good portion of the acreage will produce 42- to 48-degree API oil in addition to high BTU gas. We have intentionally been testing along the down-dip side of our acreage to determine the amount of that acreage which will make significant amounts of liquids. We're moving forward to install gas-gathering infrastructure to several wells at Deep Pines West, so that we can get longer-term production test data. Longer-term tests are needed before we can determine well decline rates, make reserve estimates and generate more accurate estimates of the economics of future drilling. We expect this gathering infrastructure to be in place later this year and hope to reach more definitive conclusions about a good portion of our acreage by year end. With that, I'll turn the call over to Wade.

Thank you, Jay. I'll start on Slide 15. At the end of the first quarter of '14, we had about $236 million of cash on the balance sheet, and our net debt to trailing EBITDAX remained at 0.9x, with our net debt to book cap decreasing slightly this quarter to 42%. Our capital structure remains very straightforward with our debt balances remaining unchanged from the prior period at $1.6 billion. The nearest maturity of our unsecured senior notes is nearly 5 years out. Regarding our secured revolving facility, at the end of the first quarter, our borrowing base was maintained by our bank group at $2.2 billion. Although the borrowing base is unchanged from our last redetermination, it's important to note that we had significant divestitures in the second half of last year, most notably our Anadarko Basin sale at year end. So moving to Slide 16. 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 improved slightly quarter-over-quarter with growing EBITDAX and unchanged debt. It also shows that we are significantly below our peer group median average of 2.3x. Clearly, the balance sheet is in great shape. Finally, we did add some more oil hedges during the quarter. You can see all of our current positions in the appendix of this presentation. So with that, I'll turn the call back over to Tony for his closing remarks.

Thank you, Wade. Before handing the call over for questions, I'd like to spend a few minutes reviewing some key takeaways that are shown on Slide 17. First, we are executing well on our 2014 program. We came in at the high end of our production guidance and performed well against the majority of our guided cost measures. Also during the quarter, we worked diligently to begin testing in our core development programs to enhance the depth and economic strength of our inventory. While we do not have results on all of these tests as of yet, testing and evaluation is underway, and we expect to have results by the end of this year. Third, we are very excited to announce the pending agreements we have entered into in the Powder River Basin to increase our acreage position in that play. Upon closing, we will have acquired a great bolt-on position to our current acreage. And in addition to our new acreage announcement, we've also announced our intention to accelerate our program in the Powder River Basin with additional Frontier and Shannon interval completions in 2014. Lastly, we continue to move ahead in our other New Ventures programs and are encouraged by the results we've seen in the Permian and East Texas thus far. In the Permian Basin, our recent Sweetie Peck Wolfcamp B results have been strong and in line with our previous results in the play. In our northern Midland Basin acreage, we look forward to spudding our first Wolfcamp D well in the second quarter, as Jay mentioned. In our East Texas play, we continue to delineate the large acreage position we have to identify the most productive and economic areas within that position. We will continue to monitor the results of these New Ventures programs throughout the year and share our progress with you as we acquire more data and better understand the potential of these new plays. I would now like to open the call up for your questions.

[Operator Instructions] Our first question comes from the line of Michael Hall from Heikkinen Energy.

I guess back to -- I guess to start in the Powder River Basin, I'm just curious to have some additional color around just kind of thought process there if we ought to view this continued out on acreage in the area as a real indication. Do you see this emerging as a real core piece of the portfolio going forward? And just kind of how scalable you really see this asset if you do continue to see success in '14 as we move out into '15?

Well, this is Jay. I think, as I said, we're not sure about 100% of the acreage at -- we haven't delineated all the acreage. We need to drill a couple of key wells here. But the wells we have drilled, and we didn't show our -- the non-op wells we participated in, but we've had a lot of really good success and been pretty consistent with our results, which is really encouraging. At this point, I think we'd have to say, we're encouraged. We're optimistic. Is it a slam dunk? No, not yet, but certainly, moving in the right direction. As far as the scalability, we talked many times about Powder River Basin. This is a lot of federal acreage. Probably the biggest impediment to speed here is permitting and, to some extent, infrastructure, although it's not -- that's not a huge problem at the pace we're running. We're well ahead on our permitting. We have a great relationship with the BLM in that area and landowners there. We're in -- as we acquire additional acreage, we become a more dominant player and we compete more successfully for permits against other people in terms of there's fewer people submitting permit, so we can have more control over the pace. So I think it can be a material position for us, probably not a '15, '16 rig program, but certainly a significant portion of our business.

Okay, that's helpful. And can you just remind me, I guess, or maybe update me on thoughts around the Shannon and how prospective you think that is? You gave 122,000 net acres prospective for the Frontier. How much do you think is this potentially prospective for the Shannon? And then how do those 2 intervals differ or how are they expected to differ in terms of production mix and productivity? Just any color around that would be helpful.

Well, the Shannon has typically been thought of as sort of a bailout in a way we've looked at it, and I think they're -- we look at the Shannon and believe that it's -- that there's more potential there. There are number of wells drilled in the Shannon up there, but most of them have not been all that economic. And we completed a fairly good Shannon well last year, IP-ed about 500 barrels a day. When we look at the wells that are being completed horizontally, it just appears to us that there could be a bigger effort made, frankly, and put more frac into these wells. And so there's a lot of potential in the Shannon across our acreage. Almost all our acreage has additional either Shannon or Sussex potential. So these are upsides to our Frontier program.

Our next question comes from the line of Joe Allman from JPMorgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: So in terms of the Permian and the Woodbine, what are the recent costs of those wells? And actually, if you can add in the Powder River Basin as well, what are the recent costs and what are your target costs for those 3 plays?

For the long laterals in the Powder, our recent cost had been about $16 million. We think we can drill them for $14 million, assuming we continue with the same frac design that we have. There are some indications that we may need to step up our frac size, which could drive our cost a little higher, but we think would potentially generate better wells as well, so we'll see how that goes. Shorter lateral wells in the Powder are more like $9 million to $11 million. Our last cost for a 5,000-foot lateral was about $11 million. In the Permian, our recent well cost for 5,000-foot lateral have been right at just a little bit over $8 million. $8 million is sort of our target this year. Longer lateral wells are proportionately higher. In the East Texas program, obviously, we're still way into the exploration side of this, drilling a lot of puddle holes and doing science, and those costs have been pretty high, $14 million kind of numbers plus. I think we can drill them for $13 million in the deeper portions once we get on kind of a development pace, but we haven't seen that yet. And then some of the shallower portions of the basin, as you get over to the west, I think you'll see wells more like in the 9s. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Got you. Okay, Jay, and so the target costs that you identified for each of those plays, will they get you adequate economics?

Well, yes. We're showing already -- if you look at the slides we just put together, we show that our economics in the Powder are already exceeding the numbers we need at a $14 million well cost. And I will tell you, those wells are economic at $16 million right now. If you look at the Permian, we're well in excess of our hurdle rates and the wells we're drilling. And in East Texas, we don't know yet. It's just too early to say. Joseph D. Allman - JP Morgan Chase & Co, Research Division: So for example, on your slides, in the Powder, when you showed 850,000 BOE-type curve, what kind of economics do you get assuming a $14 million well there?

That's a 1.2 DPI or about a 25% rate of return is our hurdle rate, and that's what that curve portrays. It's about an 850,000 BOE well at $14 million. Joseph D. Allman - JP Morgan Chase & Co, Research Division: And only a few results so far, but your results seem way above at this point?

Yes, that's accurate. And so what I would say right now is the wells are economic at 16, but our hurdle rate is that 850,000 at $14 million. That's -- we'll continue to show our wells this way until we have enough wells to be able to present a reasonable type curve. As I noted in the presentation earlier, this play is 30 miles from north to south. And there's 3 results on that plot that are 28 miles apart. We got a long way to go here before we can divide this up into type curve areas and really give you a lot of definition about those various areas. The areas are different. At this point, this is the method we're going to use for disclosing these wells because we think it's the best information we can give you. The wells we're drilling are exceeding our hurdle over a big area. And over time, we'll get more -- we'll cut this acreage down and give you more details, but this is the best we can do at this point. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. Is the main goal this year to delineate that acreage because it appears that your current completing well, the Rush [ph] is pretty far to the north, so it appears that you're spreading up these wells, the entire 30 miles or close to that?

That's the intent. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. And then just a quick one on Eagle Ford. I know it's early days since your update at the end of the -- for the fourth quarter results, but any early indications of improved results, particularly in the areas that weren't doing so well?

We won't have any information on that, as I mentioned earlier, until probably the second half. We haven't drilled a well in that area since the earlier completions that we were disappointed with last year.

And our next question comes from the line of Pearce Hammond from Simmons & Co. Pearce W. Hammond - Simmons & Company International, Research Division: I'm trying to better understand the East Texas well results. In the presentation and in the press release, your report restrained 7-day rates with excellent flowing casing pressures. But based on the well cost that you just gave, I think it paints a more incomplete well e-coms picture at this point, but I know we don't have all the pieces of information to make kind of that determination definitively at this time. But how do you internally define whether a well in East Texas is good in order to continue drilling? And are there any rules of thumb that investors should use to judge this program when we get well results like this?

Well, as we indicated, as I indicated in my discussion earlier, what we learned from data we have so far is that the wells appear to have significant productivity after completion. And they're making oil that's about 42 to 48 gravity API, which would indicate to us this is probably a volatile oil type reservoir. That's really what we know. And so -- and I mean, that's encouraging, but it doesn't tell you what your decline rate is going to be. It doesn't tell you what your reserves are going to be. In order to get that, you got to be able to put these wells on a significant long-term production tests and watch their decline. We can't do that at this point. We recognize that the data we're presenting is incomplete. It's all the data we have. We will have more data this year, later this year after we install gas-gathering infrastructure and can put the wells on long-term tests. Pearce W. Hammond - Simmons & Company International, Research Division: Perfect, Jay. And then what are your thoughts on gas lift for Eagle Ford-operated area 1?

We've never been particularly enthusiastic about gas lift because you can't get to it's as low a bottom hole pressure with gas lift. APC uses it. There were some good reasons to use it early on. Our approach has been to go plunger lift and then transition to rod lift. I'm not criticizing APC, there's a -- there are reasons why gas lift could be good in certain times. We just think at some point, most of this reservoir and especially the northern portions, we're going to get a rod lift situation anyway. And in installing gas lift early on, it could be additional cost. So our approach has been to go plunger lift to rod lift. We need to get a lot of electricity in the field in order to be able to do that on a broad basis, and that's part of the reason that we haven't developed early in the very far western portions of the field. Pearce W. Hammond - Simmons & Company International, Research Division: Great. And when do you plan to spud a Spraberry well at Buffalo?

It'll be later this year. In our Buffalo program for the D well that we're spudding in the second quarter, we actually have several partners. We're derisking by using -- by participating with others there. We'll be spudding that well in June. I don't think we'll have it completed until end of the third quarter. We would like to do, again, we would like to do with partners an upper -- or a lower Spraberry test in the same kind of way later this year. We don't have that on the schedule yet, but I think it'll be before year end. Pearce W. Hammond - Simmons & Company International, Research Division: Great. And then last one for me, just quickly, with the big increase in inventories in pad 3, are you seeing any changes in condensate pricing?

Our condensate pricing is essentially -- is disclosed, of course, in our work. We trade and we're going to trade at $17 off LLS. The way our marketing contracts are set up, you're going to see us -- our realizations are going to be LLS less $17. LLS is traded down some from Brent. We're going to trade down with LLS. But if you'd use LLS less $17, you're going to get right to where we're going to be.

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

One quick question, first, CapEx. It didn't look you made any directional change to your budget for 2014 with the acquisition of the Powder River Basin and subsequent increase in activity. Does that change at all or are you just taking dollars from somewhere else?

Scott, we generally do pretty a thorough top-to-bottom capital review between now and mid-July. And we're going to look at all of our capital demands between now -- and there's a number of moving parts here with the Anadarko piece, the carry going away and this new Powder, new Powder program. We're spending more money on completions in the Eagle Ford because we're using more sand and looking at that, so there's a number of moving parts. We'll look at the whole thing in July and make an assessment of where we're at, at that point.

Okay. Were a lot of these -- when you develop a budget, were a lot of these implied into it? Or directionally, it sounds like there's going to be an upward creep, if I'm not mistaken?

I think there is upward pressure, no question. Obviously $100 million we just spent in the Powder was not budgeted. So we would have to accommodate that if we were going to keep our budget flat. I think there is some pressure to go up. At the same time, we're really mindful of the fact that we are outspending cash flow and that we need to be careful about that. We have a lot of big programs coming up that will need our balance sheet to fund, so we're going to be pretty religious about our discipline on this.

Okay. And hitting on East Texas in a different way, it looks like the prospect of your productive wells could be there. When you look at the oil cuts that are -- you're giving currently, do you think that is sufficient to potentially provide an economic play, or is one of the goals as well to identify areas with higher oil cuts, and do you think those exist?

Well, if you look back at the well we completed last year, the Horizon 2H had about a 40% oil cut. These wells we completed south of that are more like 19%, 20%. And we -- as I indicated earlier, we intentionally drilled south to try to figure out what the oil cuts are across the acreage. Part of the early -- part of our delineation here is to figure out where that sweet spot is so we can build to it with our infrastructure. I think the numbers we've gotten on these 2 wells to the south, if the wells aren't strong enough and the decline rates aren't too high, these wells can be economic. We would certainly love to see higher oil cuts. I mean -- and we're going to be moving north with some of our drilling coming up to look for that and certainly, the Horizon had oil cuts. That obviously helps your economics. But I do think that if the wells are strong enough, that these oil cuts can make it. It's just a matter of how good the wells are, and we don't have the test yet on that. Let me -- I would like to come back to your capital question for just a moment. I know that we're running under our capital budget so far this year. So although there is pressure to go up, we're -- so far this year, we're actually under budget. So it doesn't necessarily mean that we're going to have a big capital increase at midyear.

Okay, I appreciate that. And one last thing on East Texas. What type of resource play do you think this could be? Is it going to be a fairly -- based on what you know and what it seems from the well results, is it going to be a little bit more homogenous or heterogeneous-type of play? I mean, what can you see from what you know today?

Well, I think that we -- I think you could characterize the Woodbine as being somewhat more conventional than some of the other plays that we're involved in. And it's not that dissimilar, frankly, in that respect from the Frontier that we're involved in, in the Powder. It is a sandstone. I mean there is some geologic complexity to it as you go across the shelf. But generally, the results we've seen so far is that where you have a decent package of Woodbine, it produces at pretty high rates with -- upon completion. Beyond that, we really can't say at this point. We just don't have enough penetration to be able to say.

Scott, this is Tony. And in terms of scope and scale, I mean, if you just take a look at the acreage position we've got now, it's only 40% of that turned out to be productive. That could be as much as 15-rig program to hold that in the first several years of development.

And our next question comes from the line of Matt Portillo from TPH. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just 2 quick questions from me. In regards to the Permian at Sweetie Peck, I was wondering if you could provide an update on your general thoughts around delineation of additional horizons in the play and how that may progress in 2014?

Yes, this is Jay again. We'll be drilling a lower Spraberry test there sometime later this year. We'll probably test the Wolfcamp D at some point as well. Right now, the lower Spraberry looks like the best target to us and it has significant -- we think it has significant potential in that area. We're doing spacing test right now in the Wolfcamp B to look at how close we can put these wells together. We pretty much finished our profit testing. We're going to be pumping white sand generally in the area, and we've done some work on slick water versus hybrid fracs as well, so we're optimizing our completions. But in terms of other intervals, I think you'll see us test the lower Spraberry later this year. We may do a Wolfcamp D test as well at some point later in the year. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And then in regards to the Shannon, you mentioned you guys saw some initial encouraging results. Could you talk a little bit of it, I guess, relative to the Frontier where the -- well cost up there? And then kind of the EUR threshold or hurdle that you'd be looking at or kind of how those initial results have performed so far?

Well, the well cost will be slightly lower. Again, we haven't drilled very many of them. So I don't have exact number for you, but they'll be lower than the Frontier. Our sense on this is just that if you look at the Shannon horizontal wells that have been drilled is that nobody's really pumped a lot of sand in these wells, so a lot -- haven't pumped a lot of fluid, haven't pumped a lot of sand. The last well we did was a pretty encouraging number, given what we pumped, and I would say it was reasonably economic. Not as exciting as the Frontier to us at this point, but I think there's a lot of potential in the Shannon. And I just -- when I look at them, I just say nobody's really gone out there and pump as good as job as you can possibly pump in this at this point. So I look at it as a significant upside to the Frontier in a lot of potential locations, but it's certainly unproven at this point that it can be as economic as our Frontier program. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And then just my last question in regards the non-op acreage, you guys saw a fairly significant jump in your production profile. Have you changed your thoughts at all around kind of the trajectory of your guidance in regards to production for the APC acreage?

If you look back 1 quarter, they grew 2% from the third to fourth quarter and 17% from the first quarter to the -- third and fourth quarter to the first. And if you look back a couple of quarters beyond that, they were 14% growth the quarter before that. So they -- it bounces around. Our guidance assumes about a 5% per quarter growth. We haven't seen enough yet to tell us if that's wrong or that we should upgrade it. 107 completions in the quarter is certainly an impressive number. If you run that out, that's a lot of completions for the year. We're a little skeptical that they'll maintain that pace. We'll see. I think we -- again, we'll look at it at midyear when we see how the capital is really flowing for the first 6 months, and you can see where we think will be at, but we'll update that in midyear.

And our next question comes from the line of Subash Chandra from Jefferies.

First question, the PRB tuck-in, is that still in that highly overpressured area?

Subash, can you repeat that. I missed one word there. I didn't understand.

Acquisition.

The acquisition?

Sure. Yes, the acquisition.

Yes, it's in -- it's right in the overpressured area. I think if you look at the map, a lot of the acreage is actually acreage -- we're buying additional interest in acreage we already own. So we're moving our working interest up in some play cases like 10% in an area to 70%, which will allow us to operate, drive the permitting process and everything. So it's a direct bolt-on to acreage we had, plus some nice fill-in around what we have.

Okay. Was this [indiscernible] stuff or is there is still acreage available in the overpressured area?

We're not allowed -- we're actually not -- under the terms of our agreement, we're not allowed to say who we bought it from, Subash.

Okay. Okay, understand. Second, I guess, the market wants to I guess shift their attention to the New Ventures stuff as quickly as possible, so I thought maybe if you could review your Eagle Ford inventory? If you could even express it in terms of productive capacity? Maybe if you have that number, what you think production could be ultimately over time? Is that something you've run? And then in terms of your latest thoughts, years of drilling, et cetera, just sort of assess its place in the program?

Well, Subash, that's a pretty big question off the top of my head here. We certainly have considerable more running room in the Eagle Ford and a lot of opportunity. I think it's probably appropriate to see how the inventory testing are working out -- working on right now goes before we make a lot of more statements about Eagle Ford inventory that we didn't have to beat if they're wrong. We're certainly -- we're going to do our homework and present the work in the best way we can. I guess it's easier to say we've got a 5-year drilling plan at 100 wells a year, so we have -- and there's certainly 5 years worth of inventory there. But beyond that, I think we need to get our testing done and give get people a really full update on where we end up.

Okay. And a final one for me. The package is still out there, some of the smaller FSO packages versus the Bakken stuff, is there any update on that or do you expect any proceeds of magnitude from these sales?

Nothing that we have not announced that I'm aware of.

Okay. Is that Bakken thing for sale?

Well, yes.

It's done.

Yes, that deal is done. It was not a material number, but $50 million kind of round numbers.

We'll get that in the second quarter.

We get that in the second quarter. I think it closes in the second quarter.

Your next question comes from the line of David Tameron from Wells Fargo.

Tony, congrats on the retirement. Jay, congrats on the promotion. Best of luck in whatever the next venture is for you, Tony.

I appreciate it.

Looking at the Eagle Ford, you talked and I'm -- I was -- you talked about the transportation costs on that non-op volume and deficiency fees and NGL recoveries being higher. Is NGL recovery higher? Is that a function of propane and taking it in -- Anadarko taking advantage of that market? Or can you just give us a little more detail there? And then maybe give me some color on deficiency fee, exactly what that was?

Well, let's talk about the NGLs first. In general, our NGL percentages have been coming up ever since the [indiscernible] plant started up, so their recoveries higher. With that comes higher costs associated with the processing. So in general, we associate most of that increase in NGL volume and cost to the [indiscernible] plant start-up. On a net-net basis, a good thing. We're happy that our costs are up because those volumes are up. On the other cost, as our -- my understanding is that we had -- that Anadarko had made some commitments to shipper pay that they fell short on. I think I'm not sure whether those were on the oil or gas side, and they also had some trucking costs in the field due to some infrastructure not getting completed on schedule that were beyond what we had expected. We have increased our guidance somewhat to account for all of these things as we go forward. Some of these costs, we think, will come down over time. Certainly, the trucking costs and the deficiency these will come down over time, but we did adjust our guidance somewhat to account for those.

Okay, that's helpful. Back to the PRB, the Rush [ph] well, and maybe you mentioned this, but is that -- what's the target there?

It's a Frontier well. It's a 5,000-foot lateral well.

Okay. And then do you have any HBP commitments out there with this new acquisition with what you have right now with your -- any commitments out there?

It didn't increase our acreage commitments that much in terms of what we have to drill. Again, a lot of it is acreage we already own a piece of it and are now operator of. One point I should make is that, and I don't know that our press release said it, but we didn't -- there was no PET in this deal. What we bought was all acreage.

Okay. And then final question, if I just think back 6 months or ask you to think back 6 months, the way your capital plan kind of would have been for '15, '16. And if you want to give me a number, great. I suspect you won't, but if you want to give me a number, fine. But I was thinking more in terms of allocation, like how does that change if we look at it today versus 6 months ago. Obviously, Powder takes a little more, but I'm just trying to figure how we should think about the allocation going forward?

I would say that if we look back to that period of time, our allocation is almost exactly what we expected it to be. I think Anadarko has probably run forward a little faster than we expected, so we're running through the carry money a little faster than we expected. But I think we were talking about midyear last year, and now it's more like still in the quarter. Other than that, I think our capital program is pretty much where we expect it.

And I mean, if I think forward to '15, should -- best guess right now is it fairly similar as one of the plays in the East Texas -- or has something increased the likelihood that would make it a bigger chunk next year? Could you give me any color there?

I think it depends almost entirely on what happens in East Texas. I think you can see we're moving toward a larger program in the Powder. I think there is potential for us to pick up an additional rig in the Bakken depending on how our inventory build goes. I think our Eagle Ford span will be very consistent. I think the Permian, depending on how our Buffalo testing goes, could be significantly larger. And East Texas is really a wildcard at this point in terms of how that program goes from here to the end of the year. So we're prudent on balance sheet for a reason, is that we know that if East Texas goes, as Tony said, we're going to have to work quickly to hold acreage. Same thing is true on that Permian acreage. If we decided here in the next quarter or so that we've really got something, we're going to have to start driving some rig count on that direction. So we -- I think our base programs next year look pretty similar. Really, it's an issue of how much our New Ventures programs at. With that, I would say that our base programs can generate 15% growth at about the same capital spend we're at right now. That 15% growth number we've talked about for 2015 doesn't include any of these upsides.

So David, I think the way to think about that is, like Jay said, very strong base program providing us really good growth numbers. And then several catalyst in the New Ventures side with success in any one of those they've got the scope and scale to move the needle for us in a rather significant way.

And our next question comes from the line of Mike Scialla from Stifel. Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division: You'd mentioned that you're doing longer laterals and new completion design and it sounded like it was mostly areas 2 and 3 so far. And I'm just wondering could you give a little more detail on that? Is it just the higher sand concentrations or are you changing something else there? And why do that now? Is there something you've seen from competitors that have made you want to try something different because I thought those areas were working pretty well.

Well, there's a couple of questions embedded there. Let me kind of break that down. We are drilling wells this year in Area 1, as well as areas 2, 3 and across the acreage. What I was talking about when I said Area 2, 3 was the wells we completed in the first quarter that were drilled last year. We have drilled wells in Area 1 already this year, and we'll be completing them later this half. In general, the industry is moving to higher sand than concentrations in the Eagle fourth, particularly using a lot of 100 mesh. A lot of people moving toward 100-mesh sand. And in fact, you've seen the cost response. 100-mesh sand is now more expensive than it used to be. And we have seen what we think are some encouraging indications in some of the early tests we've done in upping our sand concentrations in all portions of the Eagle Ford in the Galvan areas as well. Certainly, we've had some great results with our over 500,000-foot lateral wells, with 12,000 pounds per foot kind of numbers or even lower. But we think if we can do better that it's a very cost-effective way to improve reserve -- rate and reserves. Certainly, as we move forward into the portions of the Eagle Ford acreage that are dryer, for example, to the south, that may be more pressure-challenged or whatever, improving our completions is going to be a big part of making that steps, meet our hurdles and be a big part of our inventory. So that's -- we continue to test. We continue to push the technology as far as we can. Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division: Okay, still using sleeves or are you going to plug-and-perf or...?

No, we've never used sleeves in the Eagle Ford. We've always been a cemented plug-and-perf company. We've tested several different -- we tested sleeves, never been successful with them in the Eagle Ford. That's not to say they can't work. I'm sure somebody's probably making it work somewhere. But in our area, cement and plug-and-perf has been proven so far at least to be the best technique.

And Mike, this is Tony. Let me mention one thing relative to the Eagle Ford. I don't know that we've talked about it, but we did present some information at IPAA just a few weeks ago relative to APC's wells west of our Area 1. And I think if you go back and look at that slide in that presentation, it gives us some pretty solid results from their wells. If you take a look at the data we provided. So I mean, like Jay said, we are drilling in Area 1. We're going to directionally be drilling longer laterals, pumping more sand, and certainly, we'll be focused on artificial lift optimization. So we're definitely putting the focus there, but there's some data in that presentation that might be useful for you. Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division: Yes, it's actually where I was going to go next. It does look -- Jay, you had mentioned you're not crazy doing about deciding to do gas lift right away if you're going to rod pump eventually. I was just wondering have any of your wells in Area 1 been put on rod pump at this point? And if not, when would you see that happening? And as Tony mentioned, those wells do look strong. I did see that in the presentation. Is that, you think, a function of geology or is it more to do with the lift mechanism?

Well, in fact, as I understand, those wells are on plunger lift. I think Anadarko did a number of things right on those wells. Those wells are widely spaced, so there are not a lot of frac interference with them. They put good fracs on. They're longer laterals wells, not a lot longer, but a little longer. And they've had plunger -- good effective plunger lift systems in them from the get go. So I think, again, they did a lot of things right. I think it's just an indication that the geology in Area 1 is not the problem necessarily. I mean, I think when you have good wells to our east, good wells to our West, I think our completion is that we just haven't put our best foot forward on getting these wells completed and on onstream and lifted yet. When we do that, I think we'll have much better results. We have -- I think the number right now is we have 5 wells on rod lift up in an area. We'll have 15 more sometime a little later this year. And we're essentially -- eventually, we expect to have almost all the wells in that area on rod lift, but we're putting it -- we have to put it in around our infrastructure because that's where our electricity is. And our infrastructure is really on the east side of the field at this point. So we'll be putting wells on east side on rod lift as we can get the facilities up and running, get our electricity distributed there and then we'll be adding rod lift as we go forward. Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division: Is that a 2014 event, you think, or longer?

So there'll be -- I think we'll have 20 wells or so on rod lift by the end of this year. And probably -- and we got a -- I saw a list the other day, we have another 15 already planned. We've got to get the equipment. We've got to get the electricity in the ground or overhead to be able to do all that. But this year, we should have a number of wells on rod lift.

Our next question comes from the line of John Nelson from Citigroup.

May I call my congratulations to both Tony and Jay, on your retirement and appointment as well.

Thank you, John.

Thank you, John.

Just wanted to check, I know we've sort of historically seen true-ups in the non-op Eagle Ford segment. Are any of the fracs and volumes, is there any noise in there for true-ups at all?

So John, we don't think so. And obviously, we're a non-operator and our net interest are different in different portions of the field. So we grow at different rates than they grow just because of the way our working interest change. We don't believe there's any large out-of-periods or anything like that are influencing the numbers.

Okay. And then I think you answered this earlier, but you still think a 5% sequential growth rate from these levels is the way we should think about for the rest of the year or still how we thought about coming into the year that 5% sequential growth rate will be a better way to model it for the year?

We assumed coming into the year that it would grow about 5% per quarter. So the 14% is clearly over our expectation. But the fourth quarter was probably under that expectation. So again, we're using that 5% growth number in building our current guidance. If we see that, clearly, they're completing a lot more wells than we thought they could get to and that they continue a very high-rate pace, we will modify our guidance later this year. Anadarko is a big company. They move capital around. We hear things all the time about potential capital needs in other portions of their company that may take money from the Eagle Ford or push money to the Eagle Ford. It's real hard to know exactly what they're going to do. Certainly, if they repeat their first quarter performance 3 more times, they're going to complete a lot of wells this year and they will generate significantly higher than a 5% per quarter growth.

Fair enough. I guess just a more high-level question. It's kind of early in the year to already be moving production guidance higher for full year. Just curious if -- is that just better clarity on maybe those non-op Eagle Ford volumes or could this be interpreted as more a reaction to how your sort of stock price moves over the quarter?

John, it's interesting -- I noted this morning that somebody said we moved our guidance up. And I guess, we moved the top end of the guidance range like 1 million barrels is probably it? And that really just reflect the fact that we're ahead a little bit so far this year. It isn't a reflection -- it isn't a change in our thought process about the rest of the year. At this point, we don't know enough to know what Anadarko is going to do. And nothing has really changed in our base plan. The things we're talking about doing in the Powder won't add material rate until very late in the year. So even increasing our activity there doesn't have a big impact on our rate forecast.

Fair enough. And then just last one for me. Do you guys have a rough estimate about your total cost basis in the PRB is at this stage?

I don't know that we've ever disclosed that, and I don't think we probably will here. It's -- I think we did say at one point in time that we paid about $1,500 an acre for the acreage we picked up from QP, so it -- and that was a good portion of it. But we had a lot of that acreage -- some of that acreage was longtime legacy HBP that we held, which is very, very low-cost basis.

And our final question for today comes from the line of Welles Fitzpatrick from Johnson Rice. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: If I remember correctly, you guys had something like an average working interest of like 40% or 45% in the Frontier. What's that number after the acquisition and the swaps?

Well, it's in excess of 50%. I think if you're doing your thought process and you use about a 55% working interest, typically, you're going to get close. As I said, in a lot of the areas we just bought, we picked up from about 10% all the way to 70%. So it certainly helps our average. But 50% -- if you're using 50% to 55% on a typical well, that's not a bad number. Early days, people were non-consenting. And now they don't not consent as much, so it's a little hard to tell exactly what you're working interest is going to be in any given well, but that's not too far from [indiscernible] Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: Perfect. And then one last one, the next Independence well, the Harper, I believe. Is that going to be going further down-dip like the Woodbine's well or did you kind of see the GOR went in with that initial well that you want to seen and maybe go up-dip now?

That well is actually in Lead County, so it's going to be northwest of our current position. We would expect it to be oilier. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: Okay, perfect. And does this 42- to 48-degree oil number that you guys said, does that apply also to Independence or was that really just for the more eastern blocks?

That's really the Deep Pines West prospect specific area, the well results we presented there. Every well we drilled so far in Deep Pines West in the Frontier is tested between 42 to 48.

And that concludes our question-and-answer session for today. I would like to turn the conference back to management for any concluding comments.

This is Tony again. Thank you for joining us for the first quarter call. We look forward to another update with you next quarter. Thanks for calling in.

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program, and you may now disconnect. Everyone, have a good day.