Welcome to the Range Resources First Quarter 2014 Earnings Conference Call. This call is being recorded. [Operator Instructions] Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. [Operator Instructions] At this time, I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, operator. Good morning, and welcome. Range reported outstanding results for the first quarter, with record production and continuing decrease in unit costs over the prior year. The order of our speakers on the call today are: Jeff Ventura, President and Chief Executive Officer; Ray Walker, Executive Vice President, Chief Operating Officer; and Roger Manny, Executive Vice President, Chief Financial Officer. In addition, Chad Stephens, our Senior Vice President in Charge of Marketing, will be available to answer questions after our prepared remarks. Range did file our 10-Q with the SEC yesterday. It should be available on the homepage of our website, or you can access it using the SEC's EDGAR system. In addition, we've posted on our website supplemental tables which will guide you in the calculation of the non-GAAP measures of cash flow, EBITDAX, cash margins and the reconciliation of reported earnings to our adjusted non-GAAP earnings that are discussed on the call. Now let me turn the call over to Jeff.

Thank you, Rodney. Range is continuing to successfully execute its plan and we're currently on track to grow our production volumes at 20% to 25% for this year and beyond. For the first quarter, production grew 21% over the prior year quarter. Cash flow reached $262 million, which is an increase of 20%. Unit costs decreased 6% compared to the prior year quarter, and net income was $33 million. On the operations side, it's fun to announce that we drilled our best Marcellus well ever, in what we believe is the best Marcellus well ever drilled by the industry in the southwest portion of the play. The well tested at a 24-hour rate of 6,357 Boes per day, or 38.1 million cubic feet equivalent per day from a 7,065 foot lateral with 36 stages in the Marcellus. Our team continues to demonstrate its ability to consistently improve and raise the bar. This speaks both to the quality of our acreage and also to the quality of our team. The Midcontinent team also set a new record by drilling our highest oil-rate Mississippian Chat well to date. This well came online at a rate of 1,263 BOEs per day. Of this total, the oil-only rate was 1,062 barrels per day. As I discussed in detail on our last call, I believe that there are 3 key items this year that will distinguish performance between companies in our industry: one -- the first one is owning a sizable acreage position in the core area of the key -- of a key play such as the Marcellus; the second is the ability to consistently execute well; and the third is having a strong forward-thinking marketing team. In regards to item one, we have a huge position in the quarter to Marcellus, which is…

Thanks, Jeff. I'll focus my remarks this morning on operational results, production guidance and marketing, and as always, there's specific detail in our earnings release and in our updated presentation and we can certainly cover any of that in the Q&A. I'll start with our southern Marcellus division in Southwest Pennsylvania with an example of improving capital efficiency, combined with improving well performance. We recently drilled 2 new wells on an existing Marcellus pad in our wet area. That pad had 5 existing wells that had been producing for a little over 2 years. One is the new well with a 700 foot spaced well and the other one was a 900 foot spaced well. That new wells averaged 3,776 foot laterals and 19 stages as compared against 2,500 feet and 9 stages on the 5 existing wells. And the new wells utilized our newer targeting technology, reduced cluster spacing, or what we call RCS completions, and our newer frac-ing science. These new wells point out some very important and significant value adds going forward. First, these 2 new wells, on average, cost approximately $850,000 less per well than like-kind wells drilled on a newly constructed pad today. In other words, an apples-to-apples comparison with today's cost and processes. The reason for the significant savings is the already existing infrastructure, in essence, the pad, road, water and some of the production facilities were already paid for, along with the gathering infrastructure. Secondly, the average initial production rate, or IP, of these 2 wells was $18.9 million a day each, as compared to $4.9 million a day each for the existing wells completed over 2 years ago. That's nearly 4x better. This is a tangible example of improving completion designs and technologies combined with reservoir modeling, and this example confirms our…

Thank you, Ray. Building upon the strength of our 2013 results, the first quarter of 2014 saw strong production-driven top line revenue growth, building significantly higher earnings and cash flow than last year. First quarter revenue from natural gas, oil and NGL sales, including cash-settled derivatives, was $467 million, 17% higher than last year. Cash margin for the quarter was $2.73 per mcfe, roughly the same as last year's $2.75 figure, but higher sequentially than the $2.68 per mcfe figure from the fourth quarter. Cash flow for the first quarter was $262 million, which was 20% higher than cash flow from a year ago. Cash flow per fully diluted share was $1.62, 19% higher than last year. EBITDAX for the first quarter was $305 million, 18% higher than last year. Net income for the first quarter came in at $33 million compared to a net loss last year of $76 million. Earnings derived from methods used by most analysts, which excludes asset sales, derivative mark-to-market entries and various nonrecurring items, was $74 million or $0.46 per fully diluted share. As Rodney mentioned, please remember that all our non-GAAP measures are fully reconciled to GAAP on the various supplemental tables found on the Range website. Moving down the income statement to the expense categories and keeping with our current practice of only commenting on expense items that were significantly different from guidance, most of the unit costs came in as expected or better. Cash direct operating expense for the first quarter at $0.41 per mcfe was $0.02 over guidance due to nonrecurring workover expense and higher field-level overhead expense, mainly due to costs associated with managing production to a record cold Marcellus winter and higher water disposal costs. We expect second quarter cash operating expense to return to trend at $0.36…

Operator, let's open it up for Q&A.

[Operator Instructions] The first question comes from the line of Dave Kistler with Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: I appreciate the breakout of the corporate differentials historically, and it looks like, obviously, in this quarter, due to favorable pricing up in the Northeast and kind of unfettered access to those markets is what drove that 88% -- or excuse me, $0.88 premium in the Marcellus. Can you guys talk about, I know you've got hedges in place, but what your expectations are for kind of expected run rate, both short term and long term, on those basis differentials at this juncture?

Yes, Dave, this is Chad. Thanks for the question. First off, if you look in our earnings press release on Page 5, there's a table that talks about the corporate basis differentials and the breakout of our Marcellus, which was the specific Marcellus was $0.88 positive. But we also -- there's a little paragraph there that talks about going forward with our existing basis hedges, the impact of them are and they're relatively immaterial going forward. But to give you a little bit more color, let's briefly review some of the main points that we talked about in our last earnings call and then I'll talk a little bit more specific about new information that we have released since then. First, one of the most important factors regarding our differentials is determining what pipelines a producer has access to, and we talked about in Southwest PA, the multiple pipelines we have access to. When we began accumulating our Marcellus acreage position in 2006, not only did we want the best location based on gas in place and we have some gas in place maps in our presentations, as evidenced by the maps, we also wanted the best location based on accessible infrastructure. The bulk of our Marcellus acreage is located in Southwest PA near several large existing pipelines that give us access to multiple markets and pricing points. This diversity reduces the risk associated with all the recent basis volatility in the Appalachia indices that we've seen over the past 4 or 5 months. One of Range's unique qualities is our disciplined approach of finding multiple options. So you can see this in our selection of stacked pay acreage positions, the multiple NGL marketing ranges we have with our ethane, extensive customer base that we talked about and we're expanding…

Again, it was -- the first quarter was this unforeseen winter vortex and prices, all of the indices really spiked. And that was really what drove the loss in the basis hedges. We used all of our tools available to us. We accessed multiple indices through the multiple firm transportation pipe projects that we have, but we also use other tools such as basis hedging. As we entered this particular winter back in late summer and early fall, we were anticipating these basis blowouts, which were occurring as we entered the winter, and we were hedging to protect against continued blowouts. And unfortunately, this winter vortex hit, the basis narrowed. And we caught -- we got caught with these basis hedges. But we're going to always continue to use all of the tools at our disposal to protect against this basis risk going forward. So I hope that gave you some perspective of how we approach. I think going forward, relative to fourth quarter 2013 and first quarter 2014, when you look at where the indices were and where our corporate differential resulted, I think you can pretty much project similar differentials going forward, absent a winter vortex. David W. Kistler - Simmons & Company International, Research Division: Okay, I appreciate that color. And then just one other question. As you guys highlighted, you'll be moving from 6 horizontal rigs down to 3 horizontal rigs in Southwest PA through the balance of this year. Obviously, it highlights tremendous drilling efficiency and completion efficiency gains, but it didn't look like there's any change to forward CapEx. So with that in mind, does that mean that more capital is going to the individual wells, specifically through more stage completions, the tighter frac clusters, et cetera? Or is there potential that your full year CapEx actually could come in below expectation?

Well, that's a great question, Dave. Our CapEx budget is still going to remain at the $1.52 billion and we're not going to change that. We are -- you hit on a couple of points. We are definitely becoming more and more efficient. We're also drilling longer laterals. We have an extra rig in there for the, of course, the Utica test. It's really just a matter of timing and everything else that is the reason, the fluctuation of rig count, but it's really what we're seeing is capital efficiency, more RCS completions, longer laterals and it's just all a matter of fact of the timing. But our CapEx budget will remain at the $1.52 billion. David W. Kistler - Simmons & Company International, Research Division: Okay. Last question, at 3 horizontal rigs at year end, is that where you plan to be running in 2015? Or do you need to ramp that back up to kind of maintain similar wells drilled as you did in '14? Just trying to get a handle on how that's swinging up and down.

Yes, it will swing up and down throughout the year, but definitely there will probably be on average more rigs running in '15 than there is in '14 just simply because we're going to keep our production growth guidance in the 20% to 25% range. So of course, 20% to 25% of '14's volume is a lot bigger than 20% to 25% of '13's volumes were.

Our next question comes from the line of Jeffrey Campbell with Tuohy Brothers Investment Research.

I've got -- I've sort of several kind of quick answer-type questions. The first one is the Utica test that you're currently drilling, is that being drilled on an existing production pad? Or is that a stand-alone well?

Yes, that is being drilled on an existing producing Marcellus pad. And we're actually offsetting one of the Trenton-Black River tests that was done years ago, have a high-quality 3D seismic that we shot across the position for the Marcellus, which also enables us to image the Point Pleasant interval in the Utica. And then we've got the ability to actually put this well into sales fairly quickly towards the end of the year. So we're pretty excited about the test.

Okay. I noticed that the NGL production had a pretty significant uptick quarter-over-quarter. Is there any special color to that?

Yes, let me address that one. What you saw, as we have, as we mentioned in the press release, both of our ethane projects, Mariner West and ATEX, up and running. Next year, we'll add the third one that we have, Mariner East. And as we mentioned in the release and Ray did as well, once all 3 are up, it's actually a 25% uplift of taking the ethane out, that's net of all fees versus leaving it in the gas. To put a little more color, on an annual basis, that will be about a $45 million to $50 million increase in cash flow.

Okay, great. And the last question that I'll ask today is, when do you plan to start to -- now that you've got the Utica going, when do you plan to start undertaking some liquids-rich exploration or development, whatever you want to call it, for the Pennsylvania Upper Devonian?

Well, we've, in the past, have drilled, I think, 4 or 5 Upper Devonian tests, and every time we drill a Marcellus well, we get a good look at the Upper Devonian. So we've mapped it out. There's now enough industry tests that have been done around our position in Southwest PA, as well as all across the play, actually. And we've got a few slides in our presentation that refer to that. I think Slide #24. So -- and when you look at all that data, that, to us, is something that's been unlocked. We had a really, really great well, the last well we tested. So we're basically holding that right now, focusing on the Marcellus. As we drill the Marcellus, we hold rights to all of the formations from surface to the center of the earth. So it's really a matter of focus for us today. And we have, as I talked about, really good examples of going back on the existing producing pads and wells that are a whole lot cheaper and a whole lot better performers. And we believe there's lots of potential to figure out the Marcellus. And I think you'll see the Upper Devonian layer into that plan as the years come forward.

Our next question comes from the line of Ron Mills with Johnson Rice & Company. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Ray, on the super-rich wells that you -- the 5 well pads you talked about in the longer laterals, those are 20-plus percent longer than what you expect for the average this year. Are you still sticking to the 5,300 foot lateral average for the year? What drove the longer laterals? And was there anything special or different about where you drilled that pad to result in that kind of deliverability?

Well, that is a great question, Ron. We -- the pad was actually not a special pick geographically per se as much as it was fitting into an area that we needed to HBP some acreage and also fill in the infrastructure. So it was probably more governed by that and was probably a location that was planned 2 or 3 years ago when we picked that location. So I think what you're seeing is a couple of things. We are producing or completing wells significantly differently than we did 2 or 3 years ago. We're using better frac designs, RCS completions, different profit mixes and all sorts of things that the completion team, the technical team up there are doing. They're also working a lot on targeting the laterals and figuring out exactly how to place these things in the Marcellus and it's making a huge difference, as you can tell, by this monster pad -- monster well that's on the pad. So this has been a really impressive pad for us. As far as lateral lengths, we're always trying to drill the longest lateral that we potentially can on a site. When we put out the average lateral lengths planned for the year at the last call, those were basically based on our plans at that time. Our hope is that we will basically get to drill a little bit longer when we actually get the rig on that pad because we'll be able to add leases at the last minute and things like that, that go forward. So all of those things being said, I think our average lateral length will probably end up being a little bit longer. But again, it is, on average, over 100-and-some odd wells. Some of those will be pretty long. Some of them are over 7,000 feet, and some, of course, will be shorter. So hopefully, we'll always be able to push that lateral length a little bit further as time goes on.

Let me add a little color, Ron, before you add your second question. And top of what Ray said, if you look at Slide 19, we show in the Southwest, dry, wet and super-rich, and importantly, that second line is EURs per thousand foot of lateral. And with the exception of what Cabot has up in the northeast, I think our EURs per thousand foot of lateral were probably second highest of anyone there. Really, what it speaks to is the quality of the lot. Now what you're seeing is we're taking high-quality rock and we're drilling longer laterals. So we drill a 7,000 foot lateral and we got a well that's 38.1 million per day. It speaks to longer laterals and more stages and all those efficiency Ray said can do, that was in the super-rich. In the dry, we went back and drilled some wells with little bit longer laterals and the wells are constrained, and just opening one up and it's still constrained, it was 30 million per day. So it shows when you got high-quality rock in the core of the play, and as we continually optimize completions, it speaks to, as we continue to migrate longer, what those wells might look like. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Great. And then, I guess, somewhat as a follow-up to Dave's question earlier. If you look at the success here in the super-rich and the 3 dry gas wells, you talked Marcellus, as well as you talked about in -- or earlier on the call, plus the Utica. When you think about capital allocation over 2015 and beyond, and also with the rig count that you talk about, how do you full strength your plays given the strong results in each of these plays, albeit with the Utica still drilling the first well?

Well, I think the key is on that same Slide 19. I just talked about EURs per thousand foot of lateral. If you look on the same slide, it looks at the rates of return. And you can see the rates of return, whether they're dry, wet or super-rich, are really strong in all 3 areas. So we intend to develop that entire position. And again, remembering that position is about 530,000 net acres on the slide before it. On 80 acre spacing just in the Marcellus, there's over 6,000 locations to drill. And as Ray mentioned, it looks like we can go tighter, we have hole pilots in some of these new wells that he referred to -- were really exciting because it shows going back in earlier, jumping back to last summer, so when you infill, we thought maybe those infill wells might be 80% of the offset. Now with some of these other tighter spaced wells going in with newer completions in older areas, it shows, hey, maybe we can do a lot better than that. So we've got the Marcellus to develop on top of it. The Upper Devonian looks derisked and a great opportunity and we'll find out. And hopefully, on our call in October, we'll be able to talk about the results in the Utica and we have high hopes for that. Again, we're offsetting old Trenton-Black River wells. So we've already seen the formation and seen what it can do and it correlates really well to the high-rate wells that are marching eastward towards us. In fact, one of them is within a mile of the edge of our acreage. So we plan to develop all of it. So really, what we think we're going to end up with is a cube of Upper Devonian, Marcellus and Point Pleasant below us with stacked pay potential and then you're going to have dry, wet and super-rich and really that whole thing looks good, which gives us the confidence to say that we think we can grow at 20% to 25% for many years with improving capital efficiencies as we go forward into a better gas pricing environment.

Ron, I was just going to add a little color to that. I don't know if I told you about these 2 wet wells we drilled. One of them, just to illustrate Jeff's point with a tangible current example, is we went back on this pad that has 5 existing producing wells that we completed a little over 2 years ago. So they've been on sales for 2 years and one of these new wells was placed between laterals that were 1,400 feet apart, so it's a 700 foot infill well instead of maybe a 500 foot, but that's pretty close. And the other well was between 1,800 foot, 2 laterals that were existing 1,800 feet apart so we put one in that's 900 feet spaced, in other words. Those 2 wells IP-ed at almost 20 million a day as compared to 5 million a day from the original wells. And what's more important than all of that, they're $850,000 cheaper per well on an apples-to-apples comparison. When we look at those kind of economics, what we show you on Page 19 doesn't even get close to what potential we could see going forward. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Which gets to the last point in terms of capital efficiency. I mean, obviously, significantly higher EURs at even the lower cost. You've made a lot of changes as you can -- as that highlights just on the 2 years on that 1 pad. How close are we getting in terms of getting to -- not maximum, but where do you think you are in the continuum of increasing capital efficiency, given the amount of changes that you made just over the past 2 years? Because I don't think they're driving potential significant value growth in -- when you look at your future inventory.

Yes, that's a great question, and I think we still got a long ways to go and it's an impact of several things or an effect of several things. One, we've got a really top-notch technical team that's doing tons of PVT analysis and reservoir modeling and analysis of targeting and all of these different things that they're doing. And we're in the core position in the play, which has better perm, better porosity, more hydrocarbon in place. And when you combine all of those things, I really think, as fast as things are changing, that we're still only in the third inning, maybe the top of the fourth of a baseball game trying to figure out what the potential could be going forward. We're only several hundred wells into what, like Jeff referred to earlier, could be 6,000-plus wells going -- when it's all said and done. So when you get a team that's that sharp, that's got the kind of track record that we've got and kind of improvements that we've seen just in the last few years, I think the potential is really, really big for what we're going to see in improvements going forward.

Our next question comes from the line of Bob Brackett with Bernstein. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Yes, a couple of quick ones, please, if I could. On that Utica test well, are you drilling a vertical pilot hole? And has that already been TD-ed?

We have not TD-ed the pilot hole yet. We will drill down and actually get some logs and so forth and then we'll kick it off and drill a horizontal in it. So I could -- you could say a pilot hole from the standpoint of just getting some logs and so forth, but we have an offset well fairly close but we will confirm that and actually match it up to our seismic and all of that going forward. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Okay. And then the other, back to the Marcellus, on these new RCS wells you've been talking about, especially the infills, what do you think the effective frac half-widths of these things are?

That is the age-old question. And if you ask 20 different engineers, you'll probably get 20 different responses. There's -- to me, as a guy that's done a lot of frac jobs over the years, it depends. When you talk about effective fracture length, if we're talking about where we effectively place the proppant in the fracture, that could be quite long, in some cases, maybe 500, 600, 700 feet half-lengths. But I think what we now understand in today's world is that these fractures are very, very complicated and very complex near the wellbore. And actually, what we're learning is we want more of that to take place near the wellbore. So I would tell you today that in an effective -- from an effective production standpoint, that you're probably 100 to 150 feet away from a wellbore at the best because all of the really good production that we're seeing is coming from pretty near wellbore. When you do history matching of pressures and different things over the years, you're going to see that, that -- that's what's happening. And you've seen that evidence in some of the fields that have a lot of history like the Barnett, where they've actually been able to put laterals as close as 125 feet in some cases. But clearly, they did it at 250 feet in a lot of areas in the sweet spot. Now will this go that far? It's way too early to tell that at this point. But we clearly, as the examples we've talked about this morning, clearly believe we can get to 500 foot spacing in the wet and super-rich area. I think there will be areas where you can go closer than that in some instances. I think the Upper Devonian may act the same…

Well, I think, when we look at all our numbers today, we think we're in the high 30s of recovery of gas in place. Now as time goes on, we'll probably be able to calculate that there's more gas in place than we thought there was, but we'll also get better at frac jobs. We'll also get better at initiation of fractures near the wellbore in making more complexity, and there may be stress shadowing and different things like that, that we can do to help create that complexity. But there's no doubt we will drive recovery of hydrocarbons in place up as time goes on. But today, I think we're still pretty solid in the 35%, 40%. Alan Farquharson can talk a little bit more about that.

Yes, Bob, we're still in that range in terms of where we think we're going to be. And as Jeff said a little bit earlier, we think we're going to be able to drive it up to over 50%. As you look at each individual layer, I think it gets very complex to try to say in the first 100 feet, we're going to be x percent and then we're going to get y after that. So I think, really, of all the numbers we continue to provide you is on what the resource opportunity is looking at specifically, our acreage block [indiscernible] over the years. In those numbers, there is variability depending upon where the acreage is and the hydrocarbon in place in those numbers. So obviously, in the cores, maybe a little bit higher than that. But in the aggregate, we're thinking that we're in the 35% to 40% type recovery range and that we think we should be able to exceed up to 50%, depending upon what spacing is going to be at end of the day, commodity pricing, et cetera. That is what's going to continue to drive recovery factors higher.

Yes, if I can just add on, if you go back to Slide 13, we have a gas in place now for the Marcellus Shale, and of course, behind that, the other horizons. And I really believe, and I think we believe as a team, where you're going to get the high recoveries, by high recoveries I mean maybe exceeding 50%, is in the core of the play. And there's clearly 2 cores, one in the Northeast, one in the Southwest. If you're in non-core, the recoveries are going to be lower, the stuff may never be drilled. So it's where your acreage is located. And again, going back to those original infills that we released last summer, we've shown that you can drill as tight as 500 foot between wells successfully. So how tight that ultimately gets, we'll see. But I think driving the recovery factors up will be a combination of tighter spacing, which may be the 500 foot, coupled with more efficient completions.

We are nearing the end of today's conference. We will go to Doug Leggate of Bank of America Merrill Lynch for our final question.

Can I ask a question about your -- you said that the limitations on how much further you can go with the lateral lengths on the wells that you drilled to date. I guess, what I'm really trying to get at is you're sticking with the 5,300 feet but -- and I think the expression you used in the press release is you continue to experiment. But are there any limitations as to why you couldn't move to the longer length as a more standard well design? And I've got a quick follow-up, please.

Yes. No, there's no limitations to our lease position or anything like that. I mean, so what -- I think what's really important, if you go to Slide 18, the fact that just -- we're just now -- we have roughly 1 million net acres in Pennsylvania, the biggest position, I think, in Pennsylvania than any company, and importantly, with big parts of that in the core, in the stacked pay areas where the infrastructure is and all that type of thing. But if you go to 18, even on 1,000 foot between wells, we've drilled 8% of our wells to date. And I think, ultimately, we'll be drilling on 500 foot in that core area. So you could argue we've drilled 4% of them. No, there's no limitation and what you've seen us do is progressively go longer. I mean, if you go back every single year, we're progressively -- we've gone longer, and you're seeing us now step out and try some 7,000 foot wells and all and, hey, with great results, 38.1 million a day, the best well ever by any company in the whole southwest part of the play in the Marcellus. In fact, if you look at liquids-rich, it's better than any of the Utica wells, if you want to look at it that way. So no, there's no limitation. So I think as good as the results have been, we can, like Ray said, we're probably bottom of the third, top of the fourth. We can continue to go longer. If we haven't optimized the first 4% to 8% of our wells, we'll get better on the remaining 90%, so we're working on it.

Okay. My follow-up, Jeff, I guess, nobody has really asked about the mix on the call. I just wanted to get your updated thoughts on that. And what's behind my question is, if you look at the well results, the most recent well results, I guess, after you changed your well design last year, you changed back again to, I guess, the longer laterals you're doing again now. But it seems that the well results are coming in a little lighter in terms of volumes, the 30-day volumes, compared to what you were getting in the wells last year. So I'm just wondering, what was your updated level of enthusiasm, I guess, in the overall quality of the play and in terms of how you think about future capital commitment and so on? I'll leave it there.

Yes, Doug, that's a good question. And I think in the last earnings release, we reported some 30-day rates on a group of these newer design completions, and that 30-day rate is a little bit higher than the 7-day rate we reported in this release. That's not unusual. These wells tend to start out and they don't, a lot of times, don't reach their maximum production rates for a week or 2, sometimes a little longer out. So I would expect that -- I wouldn't put too much weight in the 30 day versus 7. I mean, we certainly don't. I mean, we look a lot more at 30 days, we just don't happen to have 30 days on those wells yet. So we're still cautiously optimistic about it. We're very pleased of what the team's doing. They, as evidenced by, they just hit a record well. It's our biggest oil rate from any well to date. So I think we're doing much better at delineating the acreage and learning from our 3D seismic that we're getting in. We're -- the bigger stimulations, we're still tweaking some things in that. And I really think by the end of the year, we'll have a much better picture of how those wells are going to hold up. It's simply -- we simply need to see 6 to 9 months of production out of some of these wells and it's going to unfortunately take 6 to 9 months to see that. So we can't speed it up. So once we've got that data towards the end of this year, I think we'll be able to get a lot more color on how we see that play emerging from this point.

Thank you. This concludes today's question-and-answer session. I would like to turn the call back over to Mr. Ventura for his concluding remarks.

Yes, I'd like to start by saying I think there's roughly 10 more people that were in the queue for questions, so please -- I apologize we don't have more time. Please follow up with the IR team, and we hope to answer all your questions. But the concluding comments, we're on track to grow production 20% to 25% in 2014. I think cash flow will grow in line with that or perhaps better, we'll see. But given our approximately 1 million net acre position in Pennsylvania, focused in the southwest portion of the state where there's good historical infrastructure and where there's great stacked pay potential and because we have a great portfolio of dry, wet and super-rich wells, coupled with our approximately 325,000 acre footprint in the southern Appalachia basin and our 360,000 acre net footprint in the Midcontinent, we believe we can grow 20% to 25% for many years. As always, we'll stay focused on safely executing our plan and being good stewards of the environment. Thanks for participating on the call.

Thank you for your participation in today's conference. You may disconnect at this time.