Greetings, and welcome to the Range Resources Second Quarter 2011 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. This call may include forward-looking statements, which you may find more information about on our website at www.rangeresources.com. It is now my pleasure to introduce your host, Rodney Waller, Senior Vice President for Range Resources. Thank you. Mr. Waller, you may begin.

Thank you, operator. Good morning, and welcome. Range reported outstanding results for the second quarter of 2011, with an increase in production in realized prices and a decrease in unit costs. As our operations continue to become more efficient, we're able to spend capital more efficiently and realize greater returns. Range ended the quarter with the strongest balance sheet and the largest liquidity in its history. I think you'll hear these same things reiterated from each of our speakers today. On the call with me are John Pinkerton, our Chairman and Chief Executive Officer; Jeff Ventura, our President and Chief Operating Officer; and Roger Manny, our Executive Vice President and Chief Financial Officer. Before turning the call over to John, I'd like to cover a few administrative items. First, we did file our 10-Q with the SEC this morning. It's now 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 non-GAAP measures of cash flow, EBITDAX, cash margins and the reconciliation of our adjusted non-GAAP earnings to reported earnings that are discussed on the call today. We've also added tables which will guide you in forecasting our future realized prices for natural gas, crude oil and natural gas liquids. Detailed information of our current hedge position by quarter is also included on the website and will be updated periodically between quarters. Second, we will be participating in several conferences in August. Check our website for a complete listing for the next several months. We'll be at Tuohy Brothers Energy Conference in New York on August 8; Tudor, Pickering Energy Conference on August 10 in Houston and the EnerCom Annual Oil and Gas Conference in Denver on August 15. Now let me turn it over to John.

Thanks, Rodney. Before Roger reviews our second quarter financial results, I'll review the key accomplishments we achieved in the second quarter. On a year-over-year basis, second quarter production rose 8%, exceeding the high end of our guidance. If you adjust for the Barnett sale, second quarter 2011 productions would have been 33% increase year-over-year. Our drilling program was on schedule throughout the quarter as we drilled 91 wells. We continue to be extremely pleased with the drilling results. And despite the low natural gas prices, we're still generating very attractive rates of return. Currently, we have 21 rigs in operation. The 8% increase in production was enhanced by our 14% increase in realized prices. As a result, second quarter oil and gas revenues were 23% higher than the prior year. The combination of higher prices and production combined with lower operating costs and unit costs, cash flow was 30% higher than the previous year. Speaking of costs, we are most pleased on the cost performance side. On unit production basis, we saw a 9% decrease in our 5 largest cost categories combined. The only disappointment was that general and administrative expense came in at $0.59 per m, that's $0.07 higher than last year, due to higher legal fees and public relations expense. On the positive side, our DD&A expense and operating costs both continue to climb on a unit production basis, so we're very pleased with those. With regards to our Marcellus Shale play, significant headway was made in the quarter, as we continued to drill fantastic wells, filling our acreage position and continue to build out our infrastructure. In addition, we continue to add high-quality technical personnel to our Marcellus team, which now includes approximately 400 people. Lastly, we did all this while successfully closing the largest sale in our history with the Barnett sale. The sale allows us to aggressively pursue our other higher-return projects. The sale also puts us in the best financial position in our history, with nearly $290 million of cash on hand at quarter end, no outstandings on our $2 billion credit facility and no bond maturities until 2017. All in all, I'm very pleased with what we accomplished in the second quarter. It's clearly a compliment, and a big shout out to the entire Range team for a job well done. With that, let's turn the call over to Roger, to review our financial results.

Thank you, John. With the Barnett sale closed at the end of April, the second quarter provides a good preview of what may be expected from Range, as it enters its post-Barnett era, namely, strong production growth, lower operating costs, plentiful liquidity and improved capital efficiency. Before I delve into specific financial highlights, please remember that with the Barnett sale, we are again required to report our financial results using discontinued operations accounting. And we filed an 8-K that reflects our historical financial statements without the Barnett, and we've posted supplemental tables on our website and in the press release that reconcile the discontinued operations results with those in our 10-Q that include the Barnett. Now because the second quarter included one month of Barnett asset ownership, the financial results I'll be presenting on this call, unless specifically noted, will include the historical results of the Barnett assets, which will then mask the supplemental non-GAAP figures in the press release. Now since the balance sheet received continued attention in the second quarter, as we prepared the company for further expansion in our key plays, I thought we would begin our discussion there. The first quarter saw the renewal and extension of our 5-year bank credit facility, with a higher commitment amount and borrowing base, lower interest rate and more flexible covenants. The second quarter of this year saw the closing and receipt of proceeds from the Barnett sale, the issuance of $500 million in fixed rate 5 3/4% 10-year senior subordinated notes and the full redemption of our $400 million and 6 3/8% and 7 1/2% notes that were due in 2015 and 2016. Now that all the parts have stopped moving, the end result at 6/30/11 is a balance sheet holding $289 million in cash, a 57-basis point aggregate…

Thanks, Roger. Terrific update. Now let's turn the call over to Jeff to review our operations.

Thanks, John. Range's net production from the Marcellus Shale is currently about 310 million cubic feet equivalent per day. Production performance from Range's wells in the Marcellus continues to improve. The average estimated ultimate recovery from 103 horizontal wells in the southwest portion of the play that were drilled and completed in 2009 and '10 averages 5.7 Bcfe. That's comprised of 4 Bcf of gas and 281,000 barrels of liquids. This has been a great accomplishment by our team. After we drilled the industry's first successful well in the play and later offset it with successful horizontal wells, we estimated that the horizontal wells might be greater than 3 Bcfe per well. We later moved that estimate from a range of 3 to 4 Bcfe, then 3.5 to 4.5 Bcfe, then to 5 Bcfe per well. Now based on 103 wells from our last 2 complete years of drilling, the estimate has increased to 5.7 Bcfe. That's partly the result of our team going up the learning curve regarding how to better drill and complete the wells, and it’s partly due to the rock performing better than we expected. It's important when comparing well results between areas and operators to factor in the completion. Range's 103 wells that averaged 5.7 Bcfe have an average lateral length of 2,802 feet with a non-stage frac. Other operators routinely drill longer laterals and pump more stages. Based on a Goldman Sachs research report dated May 31, the average EUR for the 9 companies that they list is 5.7 Bcfe. However, many of those companies drill significantly longer laterals and pump more stages than Range, yet the average estimated ultimate recovery is the same. That implies that versus the average, the rock quality of what we're drilling is better. It also suggests that if…

Thanks, Jeff. Now let's look forward a bit. Looking to the second half of 2011, we see continued strong operating results. For the third quarter of 2011, we're looking for production to average 515 million to 520 million a day. Factored into the third quarter production guidance is our Barnett sale. In the second quarter, the Barnett production was included for one month. For the third quarter, no Barnett production will be included. Assuming we hit the mid-range of our guidance for the third quarter, it will represent a 3% increase year-over-year. The 3% increase does not adjust for the Barnett sale. If you adjust for the Barnett sale, the year-over-year production growth would be 31%. We made up about half of the sold Barnett production by the end of the second quarter, and we expect to make up the other half by the end of the third quarter. So that's kind of exciting. We're right on track with that, and that's our business plan. Now I'm going to talk a little bit about the fourth quarter. For the fourth quarter, we currently anticipate production to average between 606 million to 611 million a day. Assuming the midpoint, this equates to a 13% increase year-over-year, again including the Barnett. Adjusting for the Barnett sale, this equates to a 43% increase year-over-year. Most of the fourth quarter production increase will come from wells that we've already drilled, and we're currently weighing pipeline connection. When you take this into account in the third -- in the fourth quarter production guidance, you can see we still expect to achieve 10% production growth, including the impact of the Barnett sale. We also still expect to exit 2011 with the Marcellus shale production at 400 million a day net. Looking for -- looking at 2012,…

[Operator Instructions] Gentlemen, our first question is from Ron Mills with Johnson Rice & Company. Ronald Mills - Johnson Rice & Company, L.L.C.: Question on the Mississippian, Jeff. You started talking about the lateral links. I know in your first 7 wells the 2,200-foot lateral's lower than what other operators have been testing, which is roughly double that, yet your recoverabilities in terms of EURs are about the same. What's driving the performance in terms of EURs versus a lower -- a shorter lateral length? And what does that presage if you drill longer laterals, in your opinion?

That's a great question. I think, I said a similar type thing in the Marcellus. If you look at our average complete -- if you look at the average recovery per the Goldman Sachs report, Range is right in the middle of the pack, yet our wells are significantly -- have significantly fewer stages and shorter laterals. Sort of implies that we have higher-quality rock at where we are. And plus it says, we may have upside in terms of well recovery can continue to go up if we decide to move those completions up. And I think the same thing would be true in the horizontal Mississippian play to get a similar recovery from a shorter lateral might imply higher quality rock or higher oil cup. So that would say that there could be upside in terms of if we change our completion design. That being said, I'd like to reemphasize that what we're currently doing in both plays generates greater return, greater than 100%. So I think the good news though is that there's upside beyond where we are today. Ronald Mills - Johnson Rice & Company, L.L.C.: Great. And then a follow-up, just in terms of planned activity, you've drilled 7 wells. How much activity do you think you’ll have over the second half of the year in terms of rig count or well count? And then, are you also staying ahead of the game in terms of saltwater disposal systems to handle the wells once they're ready to be completed?

Yes, let me answer -- let me do it in the order that you said. For the second half of the year, we have no drilling activity planned there, and we're currently putting together, and we will be putting together, now and through the fall, our budget and capital spending plans for 2012. It's very early but, I believe what you'll see, subject to board approval is we'll start program drilling early next year in the Mississippian, where we have at least one rig, and we'll be looking up and we'll pick up the second rig and so on. So you'll start to see program drilling next year. The good news is if you only roll back and answer that question about the saltwater disposal in a 2- or 3-minute answer, if you look at what we did up in that area, we really started there a few years ago. And we started there, and we got into the area, because we thought it was a good stacked-pay area, and we had a really strong technical team, which is sort of the types of things that we look for strategically within the company. So stack-pay area, literally from almost 700 feet down to TD, which there is literally 6,000 feet or a little shallower. Great stack-payer, you have probably more than 20 productive horizons. So we started developing some of the shallow horizons 4 or 5 years ago, in really the Tonkawa section out there, the Tonkawa sands. And with that, we put in our water disposal systems and everything. Probably, about 2 to 3 years ago we shot a 3D over that big field and started drilling deeper targets in the Mississippian and then in the Wilcox, all with good success and continued to expand out to water disposal. And then we moved off structure and started drilling the Mississippian off structure with good success. And then start -- and these were all vertical wells. And then we started, last year, drilling horizontal Mississippian wells, again with good success, 7 wells averaging 485,000 barrels of oil equivalent. And then it's a very liquids-rich area. So we have our water disposal system in there, and we will stay ahead of that. And the good news there is you got a great disposal zone directly below you in the Mississippian and the Arbuckle, very prolific water disposal zones. So I think we're in great shape, strong team. We're building a really exciting acreage position, and you'll see us start continuing drilling, I believe, next year. Ronald Mills - Johnson Rice & Company, L.L.C.: And lastly, just to expand on that last comment, the acreage position has gone from 15,000 to 28,000 to 45,000 acres. And given your size and scale, the question -- last question just on scalability of this play, which has continued to grow in aerial extent and by the higher profile that you're placing on this, is this a scenario that you would look to expend incremental capital?

Yes, we're very judiciously picking up additional acreage, and really, today, our acreage position's probably a little above that. And we're, really, probably approaching about 1,000 potential locations, assuming it all continues to drill out. If you take 1,000 locations and -- it's very early, but those 7 wells average 485,000 barrels of oil equivalent. 1,000 locations if it worked out times 485,000 barrels. That's 485 million barrels of oil. And then when you net that back, just on the acreage position we have really, in hand, we're about close to 400 million barrels net. That's impactful. I think our team is -- we're continuing to acquire additional acreage, and I think we can build that. So can we build 1,000 maybe in the 1,500 locations and beyond? So 400 million barrels might become 600 million barrels and beyond. And we're acquiring that in a very disciplined fashion, in a blocky position, where we've got good infrastructure. So I'm excited about the team there and the play that we have.

Our next question comes from the line of David Kistler with Simmons & Company. David Kistler - Simmons & Company International: On a little bit bigger picture basis, if we reflect on BHP's bid for Petrohawk, where they're certainly putting or willing to pay for resource potential above and beyond proved and kind of look towards your position in the Marcellus. And it’s definitely focused on kind of the Utica and Upper Devonian, where you've done a little testing but not a lot. Given the strong financial position, do you think about accelerating testing there, basically, to prove up resource potential in an effort for a marketplace that might have more consolidation?

Well, let me start out by talking a little bit just about potential, and then I'll turn it over to John to speak to the more global issue. One of the things I want to say, I mentioned in my notes, and we have just a couple of Upper Devonian wells that we’ve tested. But every single Marcellus well that we drill goes through the Upper Devonian. So we have well logs and shells, and in some cases, whole cores or sidewalk cores on those intervals. And a lot of it looks prospective for our southwest portion of the acreage. And just like the Marcellus, a lot of it's wet. So when we talk about having on the order of 500 million barrels net to us of NGLs in the Marcellus with the position we have, leaving the ethanes in the gas, we have a big upside in terms of Upper Devonian. We did drill and complete a couple of wells. I mentioned they’re performing well. And I talked about them on the last call, so you can go back and look at it. But we talked about just a couple of wells, so it's not a valid sample, but we have a lot of data. We've mapped it. And you look at the -- last time, I mentioned a better well looked like it might be on the order of 3.5 Bcf. Since then, the wells producing -- the decline curve really has flattened. And when we look at the reserve estimates today, that initial well looks like it might be a 4.7 B, which is really exciting, considering we only drilled and completed 2. So there's a lot of upside in terms of how we can drill and target, and we'll consider that. The other thing I want…

Yes. I mean, I obviously second what Jeff said. I think, in terms of the -- in specific, Dave, you asked about the BHP-Petrohawk deal. I mean, I think the key takeaway for me on that was, one hail to Floyd Wilson. So I'm going to send Floyd a nice bottle of wine here. But in reality, kidding aside, I think, what it tells you is, is that NAV really matters. And at the end of the day, the companies that can drive up their NAV on a most cost-efficient basis, on a per-share basis, are the ones who are going to be the big winners. And that's all we're focused on. And we’ve found a giant gas field. We're going, I think, relatively fast. In fact, I think even some of those bigger companies, at least in the short term will actually go slower but -- until they get their feet on the ground. But we're going relatively fast. I think, as Jeff mentioned, the good news is there's going to be lots of other Upper Devonian and Utica wells drilled by other people that'll help develop the industry's perception. And of these other plays, just like in the Marcellus, we were the first ones to kind of jump up out of the bunker, running up the hill. And then over time, our friends at Cabot and all the other companies started drilling really good wells. And that's really good for us, because it helps: one, it helps the play in general; and two, it really helps acreage that we have in and around a lot of these other operators. I mean, damn, we own a whole lot of acreage. So when other people drill around us, it really helps us. And we're trading logs between companies now and…

David, that's a really good question, and that's something that Jeff and I and Roger and some of the other guys, when we go out to lunch, we talk about a lot, thinking through. I think we're just now starting to kind of tinker around and look at 2012. Obviously, we’ve got a long-range plan that's got some fences around it. But in terms of the specifics, we're now -- we're just starting to tinker with that. And Jeff and I were just talking about it this morning, in fact. And one, it's pretty exciting, and we've got a lot of opportunity. And it's good to see our costs coming down, because that allows us to do more. But yes, I mean, we expect to generate great growth for 2012. But we're going to be opportunity-driven. And to the extent that the Mississippian or St. Louis plays has those opportunities, we're going to do the best we can to fund those things, to capture those things for our shareholders. So right now, I think it's just a little early. We need to get our numbers finalized. We need to get to our board, which we'll do later in the year. But no, we're going to -- one of the great things that we've done, as you mentioned, is we have great balance sheet. And so it's great to have a great balance sheet. Every once a while, you need to use it, which is what Roger always says. Now Roger's going to be -- make sure that Jeff and I don't go off the reservation but -- so we got a great balance sheet, to the extent that the Mississippian turns out great or the St. Louis. We'll have the -- we have the dry powder to exploit those things…

Our next question comes from the line of Gil Yang with Bank of America Merrill Lynch.

Could you -- John, you said that -- you highlighted again, I think, you said in the first quarter that in the fourth quarter, a lot of the growth was going to come from the backlog of wells that you will complete. Can you just review for us what that backlog is currently, where you think it could be at the end of the year? And what parts of the Marcellus as well as are …

Yes, Gil, this is Jeff Ventura. Let me jump in with that question. When you look at the northeast, we put 5 wells on in the first quarter. We recently brought on 5 more. We have 27 more coming on by the end of November, so that'll be 37 wells up there. And then we talked about 21 wells awaiting connection in the southwest and 51 awaiting completion. Of the 21 awaiting connection, we'll put 14 of those on in the third quarter and one in the fourth. And of the 51, while waiting completion, there are probably 90% of those will be on or 80% to 90% by the end of the year. And that's where the growth -- a lot of the growth that John's talked about is going to come from.

Okay. Great. You made a comment that the 2009, 2010 program is 5.7 Bcf. If you look at the presentation -- your presentation, your 2011 wells are tracking a little under that. Is there anything going on that -- or you’re doing in this areas? Are you doing shorter laterals? Or are you doing anything peculiar?

Yes. Gil, if you actually look at that, it's actually the 2011 wells are higher. They're not lower. If you look on the -- Rodney has the curve, right here. If you look at the 2011 wells -- maybe you're talking about we're early on, on the IP, that's just a function of some constraints and all gathering. But the overall quality of the wells looks good and really is on par, if not, a tick higher when you look at the -- each individual well, individually, and project the math.

Yes. I'm just looking at the aggregate data that you showed in your presentation.

Yes, yes, yes. That's just a function of some constraints early on, sort of like that Upper Devonian well that I mentioned. Early on, on that Upper Devonian, we talked about the first well. Now I'm saying, it looks like it might be 4.7 B that came on under constraint conditions of 2.5 million per day, 1.9 million gas and 91 barrels of liquids you have to have a 4.7 Bcf well. So ultimately at the end of the day, we think it's about rate of return, not about IP. It's the full shape of the curve. Looking at the individual well data that we're looking at, we're excited about our 2011 program.

Right. And it sounds like the 2011 program, you're basically tracking the lateral length and other stages of the previous 2 years of [indiscernible], right?

Yes, that's correct. It's on par, it's very similar. But like I said, we put a number of experiments out there. We frac the well that just probably about a month ago in the southwest that had 20 stages in it. So we're looking at some of those types of things.

Our next question comes from the line of Brian Singer with Goldman Sachs.

Following up on your comments on the Upper Devonian what is the thickness and thickness variability that you're seeing there that you expect versus the Marcellus? And what are you thinking about rates of return from drilling a shale or Upper Devonian zone versus what you're seeing in the deeper Marcellus?

Well, when you look at it, it's a combination and not just thickness. But at the end of the day, it comes down, I believe, to hydrocarbon in place and how much of it can you get out. The Upper Devonian section relative to the -- and really where it's -- we feel it's -- the highest prospectivity is in the southwest, although there's a couple of good Upper Devonian wells, even in the central part of the State, so it has potential in a lot of areas. When you look at the thickest part of the Upper Devonian, in general, say, in the southwest -- it's actually on our website, you can look at it, there's a type log. The section in aggregate is thicker than the Marcellus is but the Marcellus is more organic. When you look at gas in place, it ends up actually being about equal. So where we've got 80 to 120 Bcf a section in the Marcellus, the Upper Devonian is about the same. So basically, you could pick the midpoint. Say it’s 100 Bs a section in the Marcellus. The Upper Devonian doubles that to 200 Bs a section. And to go the other way, it's interesting, the Utica in a lot of cases is a little bit more than that. It's probably like down in that same area, maybe 120 to 140 B, so it can be an aggregate in over 300 Bs per section. And the exciting part is that it's predominantly stacked in the southwest. Specifically, though, going back to the Upper Devonian, I think, 2 wells are just too early. It's really exciting though that on our second well it looks like 4.7 Bs as of today. And every time we look at it, the decline gets a little flatter. What we haven't done is targeted the highest gas in place interval or the highest in -- like I was saying earlier, ends up actually with the hydrocarbon in place is actually in the wet part in the Upper Devonian down there. So we'll be spudding a well right on that bull's eye, but it's a big bull's eye in a big area. The section itself is literally right on top of the Marcellus. So even though it's a little bit shallower, the well costs in reality are going to be pretty much the same. But the exciting part is we'll have an infrastructure in there. We have a team there, and you're going to have roads and well pads and gathering and takeaways, so there's really an exciting upside to it.

Brian, this is John. When -- if you just go and drill your Upper Devonian wells on the same pad site, where you drilled your Marcellus well, when you take into account the road, the pad sites, the gathering systems, if you look at all the costs there, you've already spent -- you already got -- you can cheat off somewhere 25% to 30% of your well costs have already been expended by the Marcellus wells that you've already drilled. So it really, it kind of turbocharges your Upper Devonian returns, if you drill on top, but on the same pad sites where you’ve already drilled your Marcellus wells.

Got it. That's helpful. Going to the Marcellus, you highlighted the higher IPs. One of the reasons for that was better-than-expected rock performance. Are you seeing that in the form of just better IP rates or lower declines? And are you seeing that more in the first-year decline rate or in more of the longer and medium-term decline rate?

Let me better define that. If you look at those curves, in general, every year, we're progressing upward when you look at -- from when we started until now. But it's not just IPs, it’s flatter declines and therefore, higher ultimate recoveries. So what I'm saying when we’re looking at moving the ultimate recovery from 3 to 4 to 5, now it looks like for the last 2 full program years 5.7. I'm saying that in aggregate is a combination of better completion, but a big part of it is just flatter declines.

And is that flatter decline happening in the long-term decline rate, or is it more your wells you thought would decline at a bigger first-year rate and they’re not declining at that rate, they’re declining at a lower rate?

I think it's a combination of that. It's a combination of both. It's that whole curve has probably shifted to a shallower decline.

Okay. Great. And lastly, can you just refresh us on how much further down you think your OpCosts can go, as you ramp up the Marcellus, and as we see more NGLs coming on does that lead to any uptick in costs, in addition to the uptick in realizations?

I mean, when you look at -- the nice part about where we're, at least, for this year, we're putting 86% of our capital into the Marcellus and historic. So one, if you look at the Marcellus wells, they're high rate flowing gas wells. So they're pretty inexpensive to operate initially. And then like John mentioned, we've divested a couple of billion dollars worth of properties, a lot of those in general were higher-cost properties, higher LOEs. So by not drilling in those areas and selling them, coupled by focusing our capital in our highest rate of return, low LOE area, we'll continue drive them down. As far as specific guidance, I don't know. Roger, I think, talked about where we expect to be in fourth quarter. And we haven't given guidance, I don't think beyond that yet.

Yes, Brian. Low 60s, I think, we feel real good about. I mean, getting something with a 5-handle's going to take a lot more work, but we'll see what 2012 holds for us.

This is John. I'll be a little bolder here. Yes, I can do that, I guess. I think Brian, great -- I've got great confidence in our team. And one of the things -- if you think about the fourth quarter, we're going from 515 to 520 in the third quarter. And we're going to 606 to 611 in the fourth quarter. If you think about that, a lot of those -- a lot of that production increase is coming from wells we've already drilled and completed -- in most cases completed, and we’re waiting on pipeline. I mean, it's going to take some more people to operate those wells, but it's not going to be the same, because a lot of the people operate those wells and in those areas, we've already hired and trained and everything else. So I'm really looking to the fourth quarter with a lot of excitement to see where those costs come down. And I don't want to set a bar that drives Roger and Jeff crazy, but I think that's going to be a great snapshot, in terms of the capital efficiency not only on the drilling side, but also on the operating side, as we turn those wells on, and you get that production increase in the fourth quarter. So I think that's going to be a good data point in terms of that whole -- where we can take this thing. But I'm going to be -- -- I'm cautiously optimistic. I think the guys will hit the ball out of the park. But again, we'll stick with Roger's numbers, and then hopefully, we'll over-perform and make everybody happy, including me.

Our next question comes from the line of Leo Mariani with RBC Capital Markets.

Just wanted to jump into Northeast Pennsylvania a little bit more. I guess, talked about 6 Bcf EUR. Just curious as to where the well costs are up there right now?

Yes. Well, let me start with the southwest, and I'll move up there. We said in the development mode in the southwest would be at $4 million. And actually, I'm glad you brought it up, because one of the questions somebody asked earlier today was, where are you today? And when you look at today, off the AFPs that are coming in the Southwest, a lot of the wells are 4 million to 4.2 million. I've seen some straight away wells as low as 3.8. We just got one and some lighter swing outs, 4.4. But a lot of the wells are just a tick over 4 million. So the team's done a excellent job of driving down costs in the development mode. And remembering, we started a lot higher like you typically do. In the northeast ultimately, if we’re at 4 million in the southwest, we'll put some economics and stuff out later on. And in development mode, those wells might be 5.2 million, something like that. And we're probably 200,000 to 400,000 over that for the wells today. But the guys are making great progress quicker, and we're climbing that curve there even quicker than I thought. I still think -- and those are the numbers, I said 3 years ago when we started into the play, and if you go back to -- Ray Walker's in here, and he's looking at me. And Mark Whitley’s just left the room -- and you go back to some of those early wells in the Southwest, our first 3 horizontals in 2006. We never really said what they were, but they were fairly ugly. You were looking at wells of 6 million. And I said, ultimately, I believe, the team could get them to 4 million in development mode. Well,…

Great. I guess, just switching gears a little bit over to the Mississippian. You guys clearly picked up more acreage. You got just over 45,000 net acres there now. Just curious as to how much of that you think is de-risked by your drilling as well as industry? And if you can kind of on a ballpark there?

Yes, it's really interesting. We've had really good success drilling in that area for a few years in multiple horizons including verticals. We drilled a lot of verticals into the section so we have good control. Our horizontals, I think, if you look at the 2 farthest wells apart, they're on the order of 7 miles. But when you really come up to a 50,000-foot level and look at the play, we're having a really good success where we are. If you go off to the west, SandRidge and Chesapeake a long ways away, and a whole way from where we are, they have wells close to us that goes a long ways out. We're having good success, and if you go off to the east, there's some smaller independents that are having good success as well. So I think it's an exciting play. It's a big oilfield. And we've got a good position and it's growing. So I think it's so far so good. Oh, well cost? We're at -- right now, we're around -- we said we'd drill complete costs of $2.9 million, and we allocated a couple hundred thousand of saltwater disposal well to that to account for. We just allocated our saltwater disposal well back on a per-well basis. We're close to that now. We're not too far away from that. And we really haven't put together, hey, if we have literally 1,000 wells to drill, where do we think we'll be on well 100 or 150. But again, we've got a great team up there led by Max Holloway and Bill Coger [ph] and got a great drilling group working for them. I'm sure there will be good things there as well, with time.

Got it. I guess, last quick question for you guys. You talk about potentially accelerating this play in 2012. I guess, you got a couple other wells you're going to drill in the St. Louis line. That looks to me to be your best rate of return well at this point in time? I think, Jeff, you said it’s paid out in a number of weeks. I guess, you got other locations there. I mean, I guess, that would seem to be another play that given the quick payout you would think you could accelerate that potentially. Can you guys comment on that and maybe what you think your inventory might be in the St. Louis line?

Yes. We'll drill 4 more St. Louis wells there this year. We just drilled and set pipe on the first one. In fact, today, we started completion on it. When you look at the St. Louis though, it's a very different play than the Marcellus, obviously, the shale play along with the Upper Devonian and Utica. And the shale plays have a large scope, that's the unconventional part. The Mississippian play is a carbonate. And you've got a chat component and a lime component, but it's more of a conventional play where you have to move a lot of water. When you move to the St. Louis, it's very conventional. You have a really high-permeability, high-quality reservoir there as evidenced by the higher flow rate unlocked with horizontal drilling really. But you've got to find that up on a structure. So you got to have more of a conventional trap, either a closed structure or 3-way closure against the fault or whatever. So they're more distinct -- discrete targets that you're looking at. The good news is our guys have identified a handful of those, and we've leased them. I'm encouraged about future potential for what that can be. But those leases are new, we've got a lot of time. It's high rate of return, we'll drill the next 4 wells and see where we are. And like we talked about, we'll put together our capital spending plan for 2012 into the fall, present it to the board and then typically, we announce it to you guys early next year.

Our next question comes from the line of Marshall Carver with Capital One Southcoast.

Most of my questions were answered but I did have a question. I know at some conferences recently, you've talked about putting together some long-term contracts with ethane users to buy ethane or that you would sell ethane to them primarily for the Appalachian play. Can you update us on any progress there? Any plans for the timing of those contracts?

Marshall, it's John. Yes, great question. We've made a lot of progress. And we're getting really, really close on probably our first ethane contract. And the team, Greg Davis and [indiscernible] also helps out enormously on that team as well along with Chad Stephens [ph]. And so we're making really good headway there. We don't -- from what we see today -- and there's lots of really good things that's happening on the ethane front, in terms of a lot of other people are getting into play. And you probably saw Sunoco with their open season on one of their projects up there that's, obviously, a very good move and shows you some of the progress being made. But everything's going great. We ought to have some time before -- either on or before the third quarter, we ought to have something pretty definite that we can tell you. And so it's going along better and faster than I would have hoped. So it's all good there.

Okay. And one other question, there was that big Marcellus commissioned report for Pennsylvania filed last week. Was there any -- did you all look through it and were there any surprises in there? Or was it mostly straightforward and what you expected?

Well, first of all, we think it was really great leadership by the governor to put the commission together and get all the different stakeholders together, so we could all kind of work on a long-term solution to issues that are out there. So I commend the Governor and the Lieutenant Governor for making it happen. And I also commend all the people who worked on it. We, Ray Walker, who heads up -- who's with us, and obviously, opened up our Marcellus office in Pittsburgh and turned the light on when he was a single employee, and now, we have over 400 people there -- was on the commission and had, obviously, a big role in that. And in all those commissions you have different kinds of people and whatnot. But I think at the end of the day, when you filter through all the recommendations, I think it was an enormous step forward for the state. And now, there's a buffet table there of recommendations. And now, we need to take some real time and effort in smaller groups probably to work on certain of those recommendations that the Governor tells us that are most important and move those forward. At the end of the day, I don't think there were any real surprises to us. A lot of the things that are being recommended, we're already doing in a large way. So from my perspective and I think from Range's perspective, it was really well done, and it's a great step forward. And again, I think it helps to find on both sides expectations from both sides and a lot of different parties involved -- and I think that way -- it's really the first time you got all those constituencies all in one room working together to try to find solutions versus just punching each other in the nose. So I think that's a great step forward, and I think everybody sees the benefit. Clearly, the Governor does and the House and the Senate up in Pennsylvania sees the huge benefit it's already had and will have. So I think it's a great step forward, and I really commend them for the work that was done in a relatively short period of time. But now, the hard work starts. You got to take those recommendations and turn them into something and so -- but I think, again, I think there's a lot of people who really want to make it work so -- including us. So we'll continue to work really hard and dedicate a lot of resource to making sure it's done and quite frankly, done right, which is one of the things that we've always talked about. So pretty excited about it.

Our next question comes from the line of David Tameron with Wells Fargo Advisors.

A lot of questions have been asked, could you guys talk about -- there's -- you have some permanent acreage position, my understanding is you're drilling a client horizontal, either Sterling or Glaska [ph]. Can you talk about what you're doing out there? Is that true? And if so, what you’re doing out there?

I think what you referring to is we've got over 90,000 net acres HBP in our Conger field area. And we have drilled and completed a Penn shale well out there. And we're not going to release results yet. What I can tell you for our very first try, I'm very encouraged by what I've seen so far, and I think the team is as well. But it's early, we need to watch it, and we'll go from there.

Okay, then, could you give us, Jeff, any color on what your next steps are? Is the Penn or its equivalent prospective over your entire acreage position, or can you just -- can you give us anything else?

Yes. I can tell you it's prospective over our entire acreage position, so it would be meaningful if it works. If you -- they're oil wells, so you can envision the spacing there. I like talked about the spacing on Tonkawa for their oil wells, even at drilling 12 wells per section, which is – it’s a squirly number, when you divide it out, it’s 53 acres per well, with 12 wells per section. And the Tonkawa gives you a recovery of no greater than 10% of the oil in place. That's the exciting part, yet we're still generating 100% rate of return either through better technology, better completions, better down spacing, you can get higher recoveries. So if you use that same math in a place like Conger, and you use that same exact spacing, you're talking about, if I just punched it out right, 1,700 wells. So it's impactful, and it could be very meaningful, and it's oil. So that's what we're doing out there.

Yes. And it's relatively shallow and not all that costly per well too.

Okay. So just -- I guess, I'm going to keep pressing here, you have plans for the rest of the year out there?

Yes, for the rest of the year, we're looking at that. We may drill one more well out there, then we'll just watch the production from 1 or 2 wells this year, and then we'll factor in what our program is next year. I think, mainly, we want to understand it, look at the quality and its HBP, and then we'll go from there.

We are at the end of our allotted time for Q&A. Mr. Pinkerton, I'd like to turn the floor back over to you for any closing comments.

Well, thank you, all, for joining us. I know we're a little bit over, and we had lots of great questions. And I appreciate all those that asked questions. Those were terrific questions. And again, we appreciate everybody joining us. As I mentioned, this is really an exciting time at Range, and we got a lot going on. Even David there who -- I don't know how David does it, but he seems to find out lots of things, so I commend him on that. But we've got a lot going on, and we got a great team, but we're clearly focused and disciplined. And you saw that by our capital spending. We're right on trend with where our capital budget was. And we're going to continue to be disciplined. But it's a really exciting time to be at Range and be a Range shareholder and we couldn't be more happy. But obviously, that's behind us now. Now we got to -- the bar's set high, and we've got to perform next quarter as well. So we'll get off the phone here and get back to work and get that production up and those costs down, and hopefully, we'll have equal, if not better, results next quarter. So again, thank you very much, and we'll see you around. Thank you.

Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.