Trend Watcher: Range Resources' CEO Discusses Q1 2011 Results - Earnings Call Transcript

[Operator Instructions] Our first question is from David Heikkinen with Tudor, Pickering, Holt.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

John, given you expect to be free cash positive in 2013, can you walk us through 2 things? First, your capital budget, expectations for '12 and '13? And second, what your commodity price expectations are for that plan?

The price expectations, we were using roughly $4.50 NYMEX for 2011, $5 for -- I mean $4.50 for 2011, $5 for 2012 and $5.25 for 2013. In terms of capital budgets, the next year's budget will be similar to this year. And in 2013, we'll probably spend a couple of hundred million more than what we're spending for the next -- for '11 and '12. And there's some things baked into it, obviously, into those capital budgets. We expect to become more efficient in terms of some of our drilling. We'll be able to spend more on drilling as time goes by versus on things that are nondrilling expenditures. The other thing is as we build out the infrastructure and as you move through 2011, '12 and '13, a great -- a number of wells we're drilling this year won't get hooked up until next year. But as we get bigger and the pipelines get big -- become more -- we get more outreach of our pipeline system, we'll be able to connect more wells faster. So you'll see some production growth, more efficiency in terms of that than you're seeing, let's say, for the past 2 or 3 years. So all that's kind of baked in there. We've done a lot of work on it, and we're pretty confident that we can make all that work.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Just thinking about activity level. So you've got CapEx flat as rig count goes up by roughly 4 rigs. Is that all efficiency? Do you expect capital cost to come in as you go into development mode and get more concentrated? Can you, Jeff, maybe walk through some specifics around well cost or something along those lines?

We think well cost will come down with time. As we get -- we've got -- we're a little over a couple of hundred wells into the program of what could be, 5,000 to 10,000 wells. As we continue to drill wells, and it becomes more and more manufacturing, I think it's not unreasonable to think that within time, if we keep the same design, that we may be able to knock maybe $500,000 a well off. It may take us 2 or 3 years to get there, but we can move towards that as we get more into that mode. Of course, the other thing we'll do is continue to look at how to optimize completions and rate of return. And there's a variety of things. It may be that we tweak lateral length, stages, where we land them and all those things, it could lead to efficiencies. If we go -- it may be that if we stick with the same design, $500,000 per well comes off. Or it could mean with a more optimum design, it costs a little more, but the rate of return is higher, and we're more capital efficient. Either way, I think we'll get better with time.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

And then just one specific question on your NGL hedges, you locked in C5+. Can you talk about realizations or expectations -- or realizations of production volumes for the C4- side that you haven't hedged?

Well we believe that the C5 is a good proxy for the C2s and lighters. So what we'll simply do is we're hedging that into a very liquid market, but we will modify the amount that we hedged to account for the difference and a dollar change in those commodity prices as we go forward.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

So out of your total NGL barrel, how much is C5+ and how isn't then? Just trying to get the split.

Well if you look at -- if you look at the slide in the flip book on 33 for the Marcellus, your C5s are going to run about 6% of that barrel. And it will be a little bit less than that in the midcontinent area. But if you look at the correlation, David, those C5s and C4s all correlate within $0.50 of each other.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

I'm still thinking that normal kind of 50-ish percent of total PI on everything else on the blend.

I'm sorry, I didn't hear the...

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Your Page 33 still is guiding to a 51% of WTI realization, you just locked in the C5+?

That's right.

The next question is from David Kistler with Simmons & Company.

Real quickly following up on the CapEx before we get to '12 and '13. Looking at '11, Drillbit was $267 million this quarter with a target of about 1.38 for the year. Can you walk us through the ramp up? I think it's significantly heavier in 3Q and 4Q, but if you could just help us through that, that would be great.

I mean when you look at production, it's clearly going to follow that way in completions. But it's definitely going to be a little more weighted towards the third and fourth quarters.

Can you give us a breakdown of how that -- in terms of percentage wise, we should be modeling that out?

We can -- maybe what we can do, the best thing is to talk to Rodney and Laith and David and they can just give you a little more granularity. We don't have that right in front of us, but they can give it to you after the call.

No problem. And then speaking a little bit to the wells that were drilled and waiting on completion or tie in, there were about 51 this quarter on a gross basis. When we start thinking about that and comparing it to previous quarters or kind of what target rates are going forward, could you give some sort of sequential comparison so we know what you're going to be anticipating to flow through over time?

Part of the issue there is we're doing drilling now up in the northeast and in the southwest. To give you a little clarity there, once we get Phase -- the rest of Phase 1 on and Phase 2, we're looking at bringing 29 wells online towards the end of the third quarter in Lycoming County and additional 11 in the fourth quarter. So what is that -- 40 of those wells are going to be skewed towards the late third quarter and fourth quarter. So we feel comfortable. We entered the year at about 200 million per day net. We'll exit the year at about 400 million per day net. But it's going to be skewed towards the third and fourth quarters.

And what should we anticipate is just sort of a typical backlog that you'd have of drilled uncompleted wells? Just so we get a sense of what's being held up by infrastructure or just service constraints at this point?

Well, in terms of service constraints, there isn't. Because what we tend to do is lock in. We have our rigs locked in, we have frac crews locked in. We're not waiting for a frac crew to pop open from another company in order to complete our wells. What you do have a little bit though, is like I said you have the -- we're waiting on phase -- the rest of Phase 1 and Phase 2 in Lycoming County and there's different events that I mentioned in terms of Majorsville and Houston 3 and all those different things coming on. We have a number of wells waiting on completion, and that should get better with time as we continue to build out infrastructure. Like John said, ultimately, once we plan, we delineate and have what we have. I have all that stuff in place. It'll come down. In terms of real specific guidance, I don't have that in front of me. That's another thing we can look at with time. But that's why we're trying -- rather than trying to give you rigs and when they come on, we're trying to give you the rigs that we currently have and what the rigs look like going forward in terms of the Marcellus. But we're also trying to give you the exact -- we're giving you production guidance for this year at 10%, next year at 25% to 30%. Exit this year or -- enter this year at 200 in the Marcellus, exit the year at 400, exit 2012 at 600. So we're giving you the production numbers that go with it. I think that's a lot simpler thing to do rather than you guys trying to time when the wells are going to come on. And I think if you follow the guidance, it's a better way to do it.

I appreciate that clarification. And then as we just jump over to one last thing, the ethylene agreements that you or John mentioned on the call in the ops update, can you give us any kind of color on size of those, timing? Because obviously, those will kind of add a different hedge in place at some point.

We're under confidentially agreements. And I think Dow has given you more information than what we were allowed to give earlier until you get to these long-term agreements in place. We have 2 Memorandums of Understanding that will be going to 2 different directions, regionally. We have more proposals than we think that we could actually satisfy with us and the other producers there. But that will just simply come out over time. But once we have the fractionator in place in late 2011, then we'll be able to get our extractions as to where we want them. All the ethylene and the ethane production is going to be governed by, probably, a Sunoco line going to Sarnia. And the producer, the petrochemical companies in Ontario will have to retrofit. So that will probably be third or fourth quarter of 2012 at the earliest that we can actually start production.

That clarification is very helpful, Rodney. I appreciate it.

And David, in terms of some of those detailed questions in terms of wells and things [ph], just holler at Rodney, and he'll be able to put some clarity around those for you.

The next question is from Gil Yang with Bank of America Merrill Lynch.

A couple of questions. Just to be clear, John, your comment that you'll be internally funded by 2013. So that sort of eliminates the need in your view with those assumptions for any equity going forward. Is that fair?

Gil, as you know, our view on equity has been and will continue to be for years and years and years is that we will issue equity if we have a clear use of proceeds. And that is still our view of equity. Right now, there is clearly not a clear use of proceeds. And we try to make that perfectly clear that with the Barnett, we don't have the need. But I'm not going to promise you that we'll never issue equity again. There's certainly opportunities out there that we look at from time to time. And to the extent that we choose to seize on one of those opportunities and believe it's clearly accretive on a per share value, then we'll try to seize that opportunity. And if that generates a clear use of proceeds, then we will issue equity. That being said, obviously, from our perspective, it's pretty clear to us what we need to be working on. We've got a huge opportunity in the Marcellus and in some of the other projects like Jeff talked about in terms of some of the things that we're doing up in the Texas Panhandle, in Mississippian Lime project, up in Northern Oklahoma and some of the projects we have in the Permian, we got a huge opportunity base. And so we'll continue to do that. We do also have a scout team that's out looking at other opportunities. And there's some exciting things that we're looking at. Nothing, I think, that's on the horizon that would qualify us to rush out and do anything. But again, I think the key, and I said and I'll say it again, is I think the Barnett sale does a number things. But it really puts us in the position of strength, and that we don't have to do anything in terms of that or equity in terms of the pace we're on. Again, that being said, if there's an opportunity presents itself that we think is in our shareholders' best interest, what you pay us to do is to seize that opportunity, and we'll be disciplined in terms of the balance sheet, how we raise to the extent that we issue equities. So still, same game plan, same theories, same strategy, nothing's changed in terms of that.

Okay, great. Thanks for that complete answer. In terms of the commodity price forecast for that, do you assume any ability for you to strategically lock in, let's say, $5.25 over the next -- going forward, beginning 2013, do you assume any ability to lock in hedges at a slight premium to that price?

Absolutely, absolutely.

So that's sort of built into your expectation of cash flow?

No. It's not built into our expectations, I sure as hell hope it happens though.

Just to be clear, and it's on our website, the numbers John gave you for gas price, I think it was the February 3 script, and that's what that's based on. That's the point in time that we put that slide out.

And let me tell you at least the way I look at it and I think we look at it, is that to the extent -- we got now, we'll have in a week or so, we'll have a balance sheet where we got a bunch of cash. And we have nothing outstanding on the $1.5 billion credit facility where we have the borrowing capacity to take that up to $2 billion if we choose to. And our friends at the banks, I think, are perfectly happy to do that assuming we pay them the appropriate fees. We've got enormous liquidity. So really, the lever here -- the leverage here is that to the extent the prices move up and we can lock them in, and we will do that. You've seen with the, quite frankly, with the little issue in Japan, we saw gas prices move up in '12 and '13. We took advantage of that and locked in some '13 gas, I think, at pretty good prices. So we'll be very opportunistic there. So to the extent that we can lock those in, that's great and everything else. But at the end of the day, if gas prices move down a little bit, we've got this balance sheet and this credit facility that we can draw down on to the extent that we need it. So again, I think, it puts us in a position of strength. We got a great balance sheet. Like Roger always says, we've worked really hard and he's done a fantastic job of being CFO of creating this really strong balance sheet. And to the extent that -- there's no use in creating it if you're never going to use it. So to the extent that we need to use it, if gas prices are a little lower than we need, then we'll take advantage of it. To the extent that it's not, then we'll be able to obviously increase our capital a little bit more or do some other things with it that we didn't anticipate either. So it gives us lots of leverage that we can pull. But I think, the thing that's important for the shareholders is that to the extent, and I obviously talk and Jeff and I and Roger, Rodney and the rest, we talked to a lot of shareholders and I think one of the things that's really important is it puts real clarity into between now and 2013. And it really focuses us, the management, to really just get after it, drill the wells, get them on, focus, focus, focus, be disciplined, disciplined and just continue to drive it up. As Jeff said, we're looking at 25% to 30% growth next year, given what we're doing. And our team is doing a great job. And so, I think they'll hit the ball out of the park and if they do, we'll hopefully exceed those numbers and proverbially kick some butt. So again, it just puts us in a position of strength. And I think it's really important, and it gives clarity to all the shareholders. I think that's other important thing.

The next question is from Mike Scialla with Stifel Nicholas.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

So you've talked in the past about drilling 2,500-foot, 3,000-foot laterals with 8-frac stages, which is not optimal but that's the recipe you're going to use to hold acreage. And, Jeff, you talked about the results you got from this 3,500-foot lateral with 12 fracs. I'm just wondering, is there any thoughts of doing a pilot where you try to get more aggressive and really optimize good development to just see what that might look like. Would that change your plans going forward or is that not a concern right now?

Well, let me take -- I'm going to take some time to answer that question. It's a good question. First of all, what we're doing this year, like I said is we're going to drill in that, call it, 2,500-foot, 2,700-foot usable lateral with roughly 8 stages for almost all of our wells. And what we know is, to date, the average of 139 wells primarily in all that are in production in the southwest part of the play, the average of all of them, the good, the bad and the ugly is 5 Bcfe. So in the development mode, that design well cost about $4 million. And today, we're not far from that. We're $4.1 million, $4.2 million, so we're very close to it. So spending, with that design, spending $4 million to get 5 Bcfe under -- and strip pricing right now, I think the 10-year strip is somewhere $5 to $5.50. But if you take a $5 flat gas price forever at 5 Bcfe, that's a 99% rate of return. So that may or may not be optimal, but it's pretty darn good. So we're happy with that, and we know if we stay today, keep that same design and go to fewer wells per pad. We can drill more wells, we can hold more acreage and still generate really strong rates of return. That being said, we've also done a number of experiments in the past, and we'll continue to do some going forward. And that's everything from longer laterals and more stages to where we land the well, we think is really important whether you're high, low or in the middle of the section. And that varies depending on where you are in the play, even where you are within a county, we believe. So there's a lot of different things that go into optimally developing it. And plus at this point in time in the play, early on when we started, back to Range pioneering the play and carrying 100% of the science, we're not doing that anymore. And early on, it was very competitive and for different reasons, companies didn't share a lot of information as everybody was building their acreage position. At this point in time, I think companies are more cooperative than they were competitive. So not only that Range doing experiments but we have other companies out there that are drilling laterals up to 9,000 feet and put a bunch of stages in them. So we can learn not only from our wells but from other people, and we'll look at optimizing going forward. So where we are today is we think we've got, like John said, one of the best plays out there, even at $4 flat gas forever, it's a 74% rate of return. At $5, it's 99% and it can go beyond. So we'll look at, can we get better than where we are today? And I believe we can. The way to get better by drilling and completing the wells better, which I think will happen or we're going to drive the cost down. Either of those are really significant upsides for the play. The other thing that I think is important to look at is, not only does it vary, Northeast, Southwest, or vary within a county, I think, whether you're wet or dry is important too. If you look at the liquids-rich part, which we really dominate and have the tremendous position in, and like I said, the wells are, that 5 Bcfe is 3.6 feet of gas and 239,000 barrels of liquids. We did experiment in one of the wetter areas and we've got a lot of wet area to continue to drill in. And it so happens that, that one well that had a 3,500-foot lateral and a 12-stage frac made 6.7 Bcfe, which is up 4.1 Bs and 425,000 barrels of liquids. So that's a big increase going from 239,000 to 425,000, maybe by more optimally landing it or completing it or some of those things that I've said we're going to test, maybe we can turn that into 500,000 barrels a well with gas, with the associated gas. So that would really drive economics and it really drive rate of return particularly where oil prices are relative to gas prices. If you look at our potential, John talked about, in aggregate, we have 35 to 52 Tcf of upside. We're a 4.1 Tcf company. Out of that, 20 to 31 Ts is in the Marcellus and 15 to 23 Tcf of that is in the Southwest part of the play. But again, if you break it down, you're looking at 13.5 to 20.5 Tcf of gas, that's 307 million to 463 million barrels of liquids, net to Range. In my mind, if you look at our performance year after year after year, and we put all of our horizontal wells in there in terms of 0 time plots, you can see the performance climbing with time. So I would expect the performance could continue to climb with time as we get better and better about what we're doing. So it's not unreasonable to think we'll reach the high end of those reserves, which is a 20.5 Ts just in the Southwest with 463 million barrels of liquids. The other key part of that is that's leaving all the ethane and the gas. Once we start extracting ethane, it's going to double our liquid yields. So the 463 million barrels becomes 926 million barrels net the range. And then, if we can get better about where we land and how we drill and complete, really, you're approaching 1 billion barrels of liquids, net to Range. So we think it's really exciting upside. We've got a dominant position in it and a great team working on it. That was a really long answer. But I think it's important to look at, I think, where we were, where we are today and where we might be going in the future.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

I appreciate that. I wanted to ask you too on the Upper Devonian. Did I hear you right, you said the gas in place is similar to the Marcellus?

Yes. If you think -- and predominantly, we think the Upper Devonian is most perspective in that west to really the southwest part of the play. It doesn't exist over all the areas. But it does stack in the southwest part of the play. If in a particular area, gas in place is 100 Bcf per section, in the Marcellus, the gas in place in the Upper Devonian in aggregate would be 100 Bcf. So it about doubles what you have in that area.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

And how is the rock quality between the 2 compare?

It's really early. I mean, and that's something we need to look at and that's why I try to put in perspective, after a couple of wells in the Marcellus, where were we? After a couple of wells in the Upper Devonian, where were we? We need more data. But the neat part is we know we have hydrocarbon. We know we have wet gas. We know it can produce commercial rates even after our first 2 tries. It's highly unlikely that we landed it right in the optimal intervals on our first 2 tries. I can give you examples in the Marcellus, we're right next to each other, and it's easy to take our first few tries in the Marcellus. We're in a particularly, we landed our first well low in the section, the second one in the middle and the third one is the top. Progressively, as we got higher, the wells got higher. I mean, it went from 20 Mcf a day to about 1 million. And then we just moved it a little bit above the section and got 36. And now in that same area, we're getting 10 to 15, our best well was 26 million per day. And that's just moving where you land the well in the section and has nothing to do with lateral length or frac stages. So I think the same thing will be true of Upper Devonian. Understanding the rock and the quality of the rock and how to optimally land it that's really important but we're off to a better start really in the Upper Devonian than we were in the Marcellus.

Our next question is from Ron Mills with Johnson Rice.

Ronald Mills - Johnson Rice & Company, L.L.C.

Just one clarification on Utica and Upper Devonian. It looks like one of your Upper Devonian was more dry gas, one had liquids component. Would you expect though on an average, the Upper Devonian, where you're in a more liquids portion of the Marcellus that you would also have liquids in the Upper Devonian?

Yes, the wet dry area for the Upper Devonian more or less is exactly or approximately mirror the Marcellus.

Ronald Mills - Johnson Rice & Company, L.L.C.

You mentioned your acreage up in Northwest Pennsylvania. You start testing potentially later this year with horizontal wells. Do you think at that point that to the extent the Utica is present in Northwest Pennsylvania that you may actually bring some of the Utica into the liquids portion of the window as well?

It's possible. The difference is -- when you look at the different horizons, there is now thousands of wells that are drilled in the Marcellus. And each Marcellus well have to drill through the Upper Devonian because it's right on top of it. But if you go down to the Utica, very few wells in the basin penetrate the Utica. So, yes, it could be that a portion of that acreage is perspective for the Utica as well. And we have great Utica potential on our acreage, and big reserve outside. But you're right, a lot of it is going to be dry. To the extent that stuff in the northwest works in the Utica, then it would be, could be wet. One other thing, the other neat part of where our acreage is predominantly in the Southwest, you can stack Upper Devonian, Marcellus and Utica. If you go way to the east, you're going to the Utica, if you go away to the west, you'll lose the Marcellus and Upper Devonian. They aren't sort of like, think of, concentric circles and working and you line them all up, that's the one part where you can line up those play. So a lot of our acreage in the Southwest could have stack pay potential in all 3 horizons.

Ronald Mills - Johnson Rice & Company, L.L.C.

Okay. Just any update or any more information, you had mentioned, I think, on one of your latest calls, you'll test the Pennsylvania shale in the Permian. What's the timing of that and have there been any other test of that formation in the Permian to date?

Yes, on our Conger field area out in the Permian basin, we've got about 91,000 to 92,000 net acres. We drilled a couple of vertical wells into it a few years back and they made on the order of 15 to 20 barrels of oil per day out of the vertical well. So we've got a nice big shale section that's full of oil and we know there's oil in it because we had a couple of vertical wells in them on our acreage and we know it will flow oil. It's not very good for a vertical well but the question is, if you drill that horizontally, what will it do? To my knowledge, there's only one well in the entire Permian Basin that's drilled horizontally into that section, and it's probably 15 miles, 10 to 15 miles away from our acreage. And that well had an IP of 350 barrels per day and fell off pretty steeply. But the question is, it's a first well and it's a ways away on our acreage. We know we got a big, big section full of oil, can we make it commercial with horizontal drilling? And we've drilled and cased our first well, we'll probably frac it sometime this summer and test it and probably have results in the fall. So we have a nice big block, the HPC position. Conger has been a great area for us. It's typical of what Range likes. It's stack pays. It produces -- it's hydrocarbon rich, hydrocarbon charged, a good technical team working it. So it fits the model of things we like to work on.

Ronald Mills - Johnson Rice & Company, L.L.C.

Okay. In the Mississippian Lime, it sounds like since you first talked about it, you almost doubled your acreage position. You've drilled fewer wells than what operators to the west have drilled. But comparing your thoughts or how would you compare your expectations for the play versus what the operators to the West have outlined in terms of well cost and/or EURs as you accelerate your activity there?

We've gone from 14,000 acres to 28,000. And we're continuing to pick up acreage, and we'll continue to update that number. It's been a good play for us. It's a field we started redeveloping a while back. So we're looking at we think well cost there, 2.1 million EURs of 300,000 to 500,000 barrels. 140 locations on the acreage we have and like I said, that will grow. So it's a nice play for us. To the west of us, predominantly is SandRidge and Chesapeake and they're having good success in the play. At IPAA, fortunately, there were a lot of people that wanted to meet with us, so we were in one-on-ones and breakout rooms and such, running around New York. So I didn't get to sit through their presentation but from what I hear, I think they're claiming the similar range of reserves, 300,000 to 500,000 barrels is I think what they're claiming. I think the well cost they're claiming are similar. But I would encourage you to ask Chesapeake and SandRidge. But it's a good play and it's oil. It's worked real well for us and we like it.

Ronald Mills - Johnson Rice & Company, L.L.C.

And then just if you can say anything else on the MOUs, on the ethane sales, there have been discussions not just of taking it to Sardinia but you -- there was also been discussions of pipeline reversals to the Gulf Coast, and/or getting the ethane out to Philly, which then becomes a world commodity. These MOUs that you're going to be working towards getting agreements in place over the next coming months, I'm assuming all those different options are in the mix in terms of leveraging your position and/or ethane pricing?

Yes. When you look at kind of going up to 100,000 feet, when we first look at the play, the ethane, we thought long term was going to be a gain item in terms of being able to ramp up our production. We put a team on it several years ago to work on this. And they've done a great job. Greg Davis and Kurt Tipkin [ph] and the other guys, who have just done a fabulous job, and along with Rodney Phelps [ph] is a big player in that team as well. And where we've really gotten to is, a couple things: One, pretty early on, we've made the conclusion that instead of us just working it alone, it made sense to team up with the other wet gas producers. So we've kind of cubbied up, create our own little ethane group. And so, we're really -- while the teams -- the companies are working it individually, we're also working on a collective basis, so we can use our collective purchasing power, if you want to call it that, to leverage what we're doing with the users of the ethane. And I think that was really strategic and really well thought out. And that's really helped us, all of us, all the ethane producers. The other thing that what's happened is the confidence that the ethane users are starting to have that this is going to be a hell of a lot of ethane. And that what relative value they have of having that ethane produced in the U.S. and the relative value that creates in terms of them being able to take that ethane and make the products they want to produce, that most of those products are used in the U.S. So to the extent that now, they can create those -- buy the ethane in the U.S., create the projects in the U.S. and sell it in the U.S., things like transportation cost and all the other things that they had to deal with get taken off the table. So I think it's one of those things where, I think, they're getting more comfortable clearly, the Dow Chemical press release was pretty bullish on their view of that. And I think it's just taking time for those users of the ethane to really get their arms around how much we are going to have and whatnot, and getting confidence in what they are being told by the producers made sense and that's something they could "hang their hat on" and whatnot. And that's part of what -- they're going to continue to have to get comfortable on as we go from the MOU stage to the definitive agreement stage, which is a natural progression. But the good news is, I think, overall, the good news is that the number of potential customers for the ethane continues to go up almost daily. And so, it's probably a very competitive situation. At the end of the day, we'll get gas plus for the ethane, which is something that never thought of that was going to happen 2 years ago. We we're hoping it was. But now, it's clearly going to happen. And as Jeff mentioned, once you start stripping that out, and that's a huge impact in terms of our liquids volumes, and it will have a big impact on our realizations and our margins and it will obviously, just enhance the intrinsic rate of return of the project.

The next question is from Leo Mariani with RBC Capital Markets.

A couple of questions for you on the Upper Devonian, trying to get a sense of the lateral length on those first couple of wells and a number of frac stages you guys have drilled.

Yes, they were the standard 2,500 foot effective lateral with 8-stage fracs. It could be that there's more optimum place to land them, I'm absolutely convinced there is. And it could be that longer laterals and more stages could make a difference than we'll see with time but encouraged by where we are so far.

Okay. and you guys made a comment that you thought the second well is going to have a better EUR. That's just based on kind of what you're seeing in production history there I imagine and did you do something different with the second well?

Yes, the second well was constrained when we brought it on. But just looking at the production history that we have so far, it hasn't flat or declined, so it projects out a higher recovery. And again, we'll continue to look at those numbers with time. And it's interesting, if you look at our reserves with time over the last few years, they tend to come up with time, which has been very positive too. So we'll continue to watch and look at that. In terms of completions, they were the same. There's -- and I'll just leave it at that.

Okay. How far apart were those first 2 wells that you guys drilled?

They were a long ways apart. I don't have the exact distance but probably it's going to be at least on the order of 5 miles or more, 5 to 8 miles, something like that. And we really haven't put a well into the real wet area, the Upper Devonian either yet.

Okay. I guess just in terms of your acreage in Southwest PA, you've got 550,000 acres there. Just trying to get a sense of how much of that you think is potentially in the dry gas area?

I'll use a simple cut off. If you use something like 1,000 BTU and, say, anything over 1,000 BTU is a plus because we get paid for that. And eventually, it grades up to where it's over 1,400 BTU. So you probably have roughly on the order of about 2/3 of the acreage would be greater than 1,000 BTUs. And again, you're looking at not just the Marcellus but the Upper Devonian. So you've got 2 horizons there, so you'll get a 2:1, a little bit like the men's warehouse there. It's a twofer.

We are nearing the end of today's conference, we will go to Dan McSpirit from BMO Capital Markets for our last question.