Welcome to the Range Resources’ Third Quarter Earnings Conference Call. This call is being recorded. All lines have been placed on mute to prevent any background noise. 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. After the speakers’ remarks, there will be a question-and-answer period. 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 afternoon, and welcome. Range reported results for the third quarter of 2009 with record production, leading the consensus number and clearly, continuing to execute our business plan for 2009. The third quarter marked our 27th consecutive quarter of sequential production growth. Range is within our focus now of being able to achieve seven years of quarterly sequential production growth. Although we’re encouraged with this ability to grow production, we’re more focused on achieving those targets at an optimum cost structure on per share basis to maximize shareholder values. I think you will hear those same principles 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 home page of our website, or you can access it using the SEC’s EDGAR system. In addition, we posted on our website supplemental tables, which will guide you in the calculation of the non-GAAP measures of cash flow, EBITDA, cash margins, and the reconciliation of our non-GAAP earnings to reported earnings that are discussed on the call. Tables are also posted on the website that will give the detailed information of our current hedge position by quarter. Also posted on home page of our website is a short video showing one of our Walking Rigs in Pennsylvania in operation. You might find it interesting if you’ve not been able to visit our operations in Pennsylvania in person. Second, we will be participating in several conferences and roadshows in the upcoming weeks. Check our website for a complete listing for the next several months. Jeff Ventura just spoke at the Oil and Gas Investor’s DUG conference in Pittsburgh earlier this week. This presentation is posted on the website, and includes several new technical slides covering our Marcellus development, if you missed it. We will be at Pritchard’s Appalachian conference in Boston on November 16, the Bank of America-Merrill Lynch energy conference in New York on November 17, the Friedman Billings energy conference December 2 in New York, and the Wells Fargo Conference in New York on December 8, and Capital One Southcoast’s conference in New Orleans on December 9. Now, let me turn the call over to John.

Thanks, Rodney. Before Roger reviews our second quarter financial results. I’ll spend a little bit of time reviewing some of the accomplishments for the quarter. On a year-over-year basis, third quarter production rose 13%, beating the high end of the guidance. The 13% increase includes the impact of selling our Fuhrman-Mascho field effective June 30, 2009. If we hadn’t sold Fuhrman-Mascho, production would have been a 17% increase, this marks the 27th consecutive quarter of sequential production growth. The driver for this was a higher than anticipated production from exceptional drilling in the Barnett and Marcellus shale plays. Second, our drilling program was on schedule throughout the quarter, as we built 128 wells. We continue to be extremely pleased with the drilling results, and despite the lower prices, are generating attractive rates of return. We currently have 15 rigs running, versus 23 this time last year. The 13% increase in production was more than offset by a 30% decrease in realized prices as a result, third quarter ‘09 financial results were lower than the prior year. We are most pleased on the cost side, as our cash costs were well below the prior year. I’m particularly pleased with the unit lease offering costs, as they’re averaging $0.75 per mcf; this was a whopping 25% lower than last year. With regards to our Marcellus Shale play, significant headway was made, as we continue to drill some terrific wells, build and high-grade our acreage position, build out infrastructure, and bring down our well cost. In addition, we continue to add high-quality personnel to our Marcellus team, which Jeff will talk about. In summary, our third quarter results were the best in our company’s history from an operating perspective, and particularly, we did this while at the same time, keeping our capital expenditures within cash flow. All in all, I couldn’t be more pleased on how much we’ve accomplished so far this year. It’s a real testimony to the entire Range team. With that, I’ll turn the call over to Roger, who will review our financial results

Thank you, John. The third quarter of 2009 is in many ways a reprint of the second quarter of 2009, except for our Herculean effort on production. Oil and gas production set a new record high, despite significant asset sales. And direct operating costs were down even more significantly than last quarter. Importantly, like the second quarter, our liquidity and balance sheet remain just as strong at the end of the quarter as the beginning. Oil and gas sales for the third quarter, including cash-settled derivatives, totaled 255 million down 21% from the 322 million in revenues last year. As John mentioned, the 13% increase in production just could not offset the 30% decrease in oil and gas prices. Sales and production were both higher than in the second quarter of this year, which as John also mentioned is a noteworthy achievement given our June 30 sale of the Fuhrman assets, which were producing approximately 15 million a day. Cash flow for the third quarter of ‘09 was 171 million, 25% below the third quarter of ‘08, but up 15 million from the second quarter of this year. Cash flow per share for the quarter totaled $1.08, $0.04 per share higher than the analyst consensus estimate of $1.04. Quarterly EBITDAX of 198 million was 22% lower than the 254 million earned in the third quarter of ‘08. The cash margins for the third quarter were $4.14 per mcfe. That’s higher than the $3.93 per mcfe last quarter, but 35% below last year due to lower oil and gas prices. So, the real story on margins for the quarter is a 15% reduction in cash expenses. We shaved $0.40 per mcfe in cash costs off of last year’s third quarter figures, with lease operating expense down 25% year-over-year. Like last quarter,…

Thanks, Roger. Now, let’s hear from Jeff on the operations.

Thanks, John. I’ll begin my reviewing productions. For the third quarter, production averaged 437 million per day, a 13% increase over the third quarter of 2008. This represents the highest quarterly production rate in the company’s history and the 27th consecutive quarter sequential production growth. This is a great accomplishment by the team, given that we closed on the sale of Fuhrman right at the end of the second quarter, which reduced production by about 15 million per day. Also, we dropped rigs in the Southwest and Midcontinent Divisions throughout the second and third quarters. To overcome all of that is outstanding. I’ll begin with the operations update with the Marcellus Shale. To date, Range has drilling completed 60 horizontal Marcellus Shale wells. 54 of the wells are currently on-line, and today, we’re producing over 80 million per day net. Our current cost to drill and complete one of these wells in the Southwest Pennsylvania from a multi-well pad is about $3.5 million. Based on the zero time slot we released earlier, which includes 24 wells, our expected ultimate gross recovery is 4.4 Bcfe. Factoring in the production profile, which is shown on our website, our average royalty and current gas price adjustments and assuming a $5 per Mmbtu gas price resulted a 46% rate of return and cost to sign and develop of $0.95 per Mmcfe. At a $7 gas price, the rate of return increases to 75%. We believe this is the best rate of return in finding any new development cost of any large-scale, repeatable play in the United States. In the past, I’ve stated that the average reserve expectation across all of our acreage position is in the three to four Bcfe range. To-date, our average well has been about 4.4 Bcfe, which is above the…

Thanks, Jeff. Terrific report. Looking to the fourth quarter of 2009, we see continued strong operating results. For the fourth quarter, we’re looking for production to average 455 to 460 million per day, representing roughly a 14% increase year-over-year, and approximately a 5% increase over the third quarter of ‘09. Taking account both the asset sales and the drilling results today, we have increased our full year 2009 production growth target from 10% to 13%. Given our reduced capital program, we focus about roughly 90% of our CapEx on the Marcellus, Nora, and Barnett plays. These plays generate attractive returns, even at low prices, as Jeff discussed. We’re fortunate that the remaining properties we have a shallow decline curve, in particular, our tight gas sand properties in Appalachia and West Texas on a decline of roughly 10%. One of the key elements that we have talked about from time-to-time that’s having a very key impact on us is our capital efficiency. As Jeff mentioned, in the last several years we’ve spent considerable capital in the Marcellus play without getting to see much of a return on that. Beginning on October of ‘08, this all changed as the first phase of the infrastructure was completed, and production began to ramp up. As our Marcellus production continues to ramp up, we’re seeing this capital efficiency impact having an ever increasing impact on our company. This is allowing us to do more with less. In the third quarter, our CapEx totaled $171 million, including the $4 million of the Marcellus acreage we acquired in exchange for Range common stock. So, our cash CapEx total was $167 million, which was fully funded by $171 million of operating cash flow. For the full year 2009, our cash flow and completed asset sales should be more…

Thank you, Mr. Pinkerton. (Operator Instructions) Our first question comes from Mr. Tom Gardner with Simmons & Company. Please proceed with your question. Thomas Gardner – Simmons & Company: Thank you, operator. John, just circling back on what you just said with regard to the rigs moving into the northeast portion of the Marcellus. I believe Jeff mentioned on the last call that those rigs were moving in there in August. Just wanted to see if you had any sort of results to date and perhaps get an update on the development timing in northeast portion of the play?

This is Jeff. Let me take and crack at that. Yeah, Tom, I did say that on the last call, the rigs we’re getting are the special built rigs, and they were slow to be delivered, so that got delayed a little bit. But we’re currently drilling simultaneously two wells in the northeast. One offsets our best vertical well made over 6 million per day from a vertical well, so we have high hopes for that and the other one’s offsetting also an excellent vertical well that made over 2 million per day. They’re drilling simultaneously, they’re already at significant depth. So I feel comfortable we’ll have results by the end of the year. We’re already preplanning, once we drilled the good vertical wells, we shot 3D to cover it, so we’re drilling the horizontal wells off the 3D directly offsetting the vertical, we’ve already acquired pipeline right away, we’ve already acquired our caps. So, I think that area high I have good hopes for, high hopes for and I expect it will come online towards the end of the next year, with good results for these two wells. You’ll see us doing some drilling in the northeast next year, primarily focused in the southwest, ramping up production, continuing to drill in the northeast and then we’ll have our pipeline on there by the end of next year, it’s all going to be dry gas, with significant development in 2010 in that area. Thomas Gardner – Simmons & Company: Thanks Jeff. Just staying with the northeast portion of the play. How much acreage do you currently have in New York? And can you give us an update on these regulatory initiatives, and the ultimate impact perhaps on drilling in the state?

Yeah, well, we have roughly 2 million acres in the basin. When we talk about 1.4 million acres for the Marcellus that’s prospective. Let me talk about that that 1.4 million acres basically is almost all in Pennsylvania, a little bit in the West Virginia panhandle, right adjacent to Pennsylvania. We’re not counting any New York acreage at all as being prospective for the Marcellus. And when we talked about our high-graded acreage, the 900,000 that’s basically again, almost all in Pennsylvania, a little bit in the West Virginia panhandle. And the difference, that other 500,000 acres has potential for the Marcellus, but it’s behind pipe and existing wells that we have. There, we’ll be looking at it as a recompletion potential, or later on, but it’s on HBP oil and HBP acreage. So, when we originally went back and targeted the Marcellus, when we started the play several years back, we targeted different areas predominantly in southwest Pennsylvania and northeast Pennsylvania, we did not target New York. I’m not saying New York doesn’t have potential, it just wasn’t within our originally targeted areas, and as we’ve continued to refine our model, our model actually has held up very well, and it’s been very robust. And we continue to target basically those same areas.

Yeah, Tom, and this is John, I think that’s Jeff’s perspective is more, let’s say, from a geological perspective. The other perspective is kind of the business perspective. And as, and maybe some people don’t, we’ve been operating up in Appalachia for over 25 years now. And we are one of the largest producers in natural gas in the State of New York. That didn’t mean a lot, but we’re still the largest producers in New York. So, we know firsthand how difficult, on a relative basis, is New York versus PA versus West Virginia versus Ohio versus Virginia, and we take all of that into account when we look at this play. And there is no doubt in our mind that New York, was going to be more challenging from a regulatory perspective. It always has been, and in my view, always will. I don’t want to go into why we believe that, but I think most people can just see that for themselves. I’m not bringing up something that I think is all that earth-shattering here. So again, I think in all these plays, whether it’s the Barnett, or whether you want to be drilling wells in downtown Fort Worth, or whether it’s the Marcellus or all the other plays. You got to take your technical work, and overlay with what you think the business risks are. And quite frankly, when we did that, New York was not one of the ones that, that popped out, where we ought to be buying acreage. So, that in a nutshell is why we don’t own any material Marcellus potential in New York. Again, just want to reiterate what Jeff said is that, it’s not that we don’t think that it’s bad, we just think Pennsylvania is better. Thomas Gardner – Simmons & Company: Got you and thank you, guys. I’ll let someone else hop on. I always have more questions [though] but I’ll let someone else take a crack at it.

Thank you. Our next question comes from the line of Ron Mills with Johnson Rice. Please proceed with your question. Ronald Mills – Johnson & Rice: Good morning. Just to follow up on the northeast PA, and somewhat what you were just speaking of, John. From a permitting standpoint, can you walk through some of the differences in terms of the northeast Pennsylvania permitting process and timeframe versus what you’re experiencing currently in the southwestern portion of the state?

Well go ahead.

John and I are battling on who’s going to answer, we can both chime in. I guess I’ll go first. When you talk about the southwest, the process has become good. It’s significantly improved. I think we routinely get permits in 30 days, or in some cases, significantly less, so that’s going well. In the northeast, again, it’s easy when we talk about areas, these are large areas, you’re talking about a state. Whether you’re in the Delaware River Basin or Susquehanna River Basin, it all makes a difference. Where we are is in the farther east you go, the more difficult that gets, and we don’t have any acreage out in the far east either, which is again, where we start with the technical analysis of where we want to be, and then overlay the business aspects to that as well. So, we’ve been able to get our permits and to move forward. John, do you want to add on to that, or?

Yeah, I think and again, I think the key here is that clearly, over the next year or two, the major driver is going to be the southwest for us. I mean, we’re going to drill some wells in the northeast. We’re excited about the potential, but in terms of delivering the gas in the pipeline, and ramping up the production, it’s going to come from the southwest or the great majority of that’s going to come from the southwest. In that area, as Jeff mentioned, the permitting process has gotten very routine, 30 days. I heard recently we got one permit in eight days, to give you an example. We’ve got a program there, and we’ve got a fairly blocky acreage position, so it’s going quite well, just like it does in the Barnett or Woodford, or any other plays that we’re in terms of horizontal drilling. So, it’s become like clockwork. The northeast, as you move away and again, you got to think about how the oil and gas in Pennsylvania was first developed. Most of the oil and gas in Pennsylvania was developed in the southwest part of the play. In fact, our Renz well, our first well drilled in the Marcellus isn’t too far away from the first oil drilled in United States by Colonel Drake, which was exactly 150 years ago on August 27, which also happens to be my anniversary date, that’s why I remember it. So, because of that, you got all the infrastructure and all the other things down in the southwest. The northeast, there’s just less infrastructure, there’s been less drilling up there, there’s less service, blah blah blah blah. So again that over time, that will solve itself, just like it has in the southwest. The southwest now, in terms…

Yeah. We think a significant portion of our acreage is prospective for the Utica, particularly the acreage that’s in the southwest. And again, we have 550,000 acres there; we have a big position. Same with the upper Devonian Shale, we think it’s more prospective on the western side, and a lot of our acreage, we think, has potential for that. So, the combined, they offer really significant upsides. So, be interesting test we’ll drill both of them this year, complete them this year. It may go a little into next year. So, by the time we have some results, it should be first quarter of next year. Ronald Mills – Johnson & Rice: Okay, great. I’ll let someone else jump in. Thank you, guys.

Thank you. Our next question comes from the line Mr. Joe Allman with J.P. Morgan. Please proceed with your question. Joseph Allman – JPMorgan: Thank you. Good afternoon, everybody.

Hi, Joe.

Good afternoon. Joseph Allman – JPMorgan: Hey, Jeff, could you quantify the operating cost savings you get from recycling the water and using the retention facilities? And how much of that savings have you seen already?

Yeah. It’s a very significant, because when you have to truck water, it’s expensive. Truck it, and then pay for the disposal facility. You’re looking at savings per well, literally, on the order of a couple hundred thousand dollars per well. So, it’s very impactful. So, it’s clearly economically, the right thing to do. But I really want to stress environmentally, it’s really the right thing to do. Because it really reduces the amount of water you need on the front end, and then you get the zero discharge. So, when you’re in a development area with pad drilling it’s really exciting and again, I really want to stop and talk about that point, because a year ago, most people said you couldn’t do it. Even earlier this year, there were a lot of people very skeptical that it could even be done. And then it moved into what would it do to the wells, and okay, we can do it, but what about the quality of wells? Well, none of them have been able to do it. But the quality of the wells, we’ve seen no difference at all. So, that’s really important. So, I think that, when you look at water recycling, coupled with we’re also doing a lot of experimenting with disposal wells now. So, if you can couple those two things together, that’s basically taking care all of the water issues. Joseph Allman – JPMorgan: Okay, that’s helpful. And then, in terms of the operating costs on an mcfe basis, I mean, because of this savings, should we see that, and all other things being equal, come down fairly decently?

Yeah, when you looked at, let me talk about the Marcellus in general. You have two things going on: one, you have high rate flowing gas wells, which are relatively inexpensive to operate. And then, if you can eliminate the trucking, you’re looking at LOEs for Marcellus, really of less than a dime per mcfe. So as we continue to ramp and build Marcellus, and you add that into the rest of the company, it’s going to continue to drive down our LOEs, coupled with the fact that part of our strategy is building high-grading inventory. So, we’re focusing on our more efficient projects that not only have a lower LOE, but lower F&D, and then you’re going to couple that with selling things like Fuhrman that have high LOE. And that’s part of the reason that you’re starting to see really significant impact in driving down LOE, but it’s going to like I talked about on the last call, when you look at capital efficiency, you’re going to see us, even though as good as Range has been, I think you’re going to see even better improvements, really, going forward.

And Jeff, this is, hey sorry Joe, let me interrupt you. Jeff, let me ask a question: then why the hell that our DD&A rate go up?

Well…

Let me answer that, Jeff.

[No way] let me chime after you’re done, but go ahead.

And let me give some, Roger, I think, went through the technical accounting, and probably think mumbo-jumbo if you want to call it that. But let me give you a big picture, and kind of some business man’s perspective is that: if you think one is, we’re on successful effort, so, we don’t do things, when we calculate DD&A, we do it by property pool. So, all the Marcellus is a pool by itself. I mean we don’t just take everything and throw it together like the full cost guys get to do. So, we do pool-by-pool, and we’ve got a number of pools in the company. So, as things change within those pools, it changes the DD&A rates, and as you change production rates between those pools, your overall DD&A rate can change. And so what happened was, is that we bought Fuhrman, the good news, Chad and his team were able to buy Fuhrman at a very low price, our guys did a great job of developing Fuhrman at a low cost. And I think we bought Fuhrman for $212 million, and sold it for 180-something million. So, that’s an A+ check-the-box for all that, but when we sold it, it was still, was a relatively low, even though it had a really high operating cost, over $2 bucks an m, it had a low DD&A rate. So you take that out, and you replace it. And we replaced it with Barnett and to a large degree, with Marcellus. Now let’s talk about that for a bit, and let me just zero in on the Marcellus, is that you think about what the Marcellus is that since October of 2004, we’ve spent a whole bunch of dough, almost $1 million in the Marcellus. And we spent enormous amount…

Yeah, I mean, just looking water-hauling disposal cost was dead even at $0.11 this year over last, so that was not a huge change. I think in answer to your other question, we really haven’t seen the P&L benefit of the recycling yet flow through for the Marcellus, since that’s relatively new. Joseph Allman – JPMorgan: Okay, all right, and then a separate item. In northeast Pennsylvania, when you finish those two horizontal wells, will you place them onto production right away?

No, the – like I mentioned earlier, just clarify, the pipeline for that won’t be up and running till the end of 2010. So, we’ll drill them, we’ll test them, and then we’ll shut ‘em in and you’ll see us do some drilling around them. But that won’t come on to the batch around the end of 2010. And then, 2011, you’ll see a significant ramp-up up in that area. Joseph Allman – JPMorgan: Okay. Very helpful. Thank you.

Thank you. Our next question comes from the line of Monroe Helm with CM Energy Partners. Please proceed with your question. Monroe Helm – CM Energy Partners: I think my questions have been answered, but just a quick one on the Marcellus. If you had better infrastructure there, could you accelerate the pace of drilling over the next two years? Is that kind of the limiting factor?

What you’ll see us do is basically it’s early, we’re building our budget now, we present it to the Board in December for approval, and typically, talk about it in January, February, but roughly speaking, at this point in time, you’ll see is double the number of wells next year versus what we drilled this year. And like we said, basically double our exit rate from next year to this year. We understand, like I said, within that de-risk box, we think we have the potential to drill significant number of wells and develop, really over a 11.6 Tcfe, just on what we’ve proven up so far. So you’re going to see significant growth, but the important part I think we understand, clearly understand the concept of NPV. That is not new to us, we understand that, and that it drives value. We’ve run a number of scenarios looking at the whole play through depletion, how fast we should drill, how does that relate to our balance sheet, and the pipelines, and everything else. But I think when you start, we have a graph on our presentation that shows the trajectory of our growth. And to develop what we think is a multiple Tcf play, there is a lot of upside, and we think ultimately, when you get to full development, you’re going to see a large number of rigs, and potentially, you’re going to be probably looking at 50 rigs or so out in the future. So, we’ll be developing, we’ll be driving up production, but we’re also, remember our story is not just about growth, it’s about growth at low cost. And we think the pace we’re going at is a good pace, and it’s impressive growth. But we want to be sensitive to the balance sheet, and to funding and all those types of things as well.

Yeah, and great question Monroe, and I think this year we really and probably made it a large degree, and I’ll let Jeff take it. But we really wanted to focus on our ability to drive down cost per well, and our guys have done a great job at that, and we’ve achieved the goals that we’ve set for them. So, now, we feel comfortable. So, we’re going to exit the year at twice the deep rigs that we started the year with, and I think you’ll see that kind of expansion of the rig. Just you’ll see that as we go out kind of year-after-year, and so that wouldn’t be a surprise to me in terms of three rigs, six rigs, and then in the next year, as you look into 2011, more likely we’ll be at 12 rigs. And then you can probably double again after that. And to get to the number that Jeff talked about. So, and then if you run that through, and volumes and what-not, that’s what it’s going to take. Again, that’s from the technical perspective, but we run a bunch of modeling in terms of what does that do to the balance sheet. How do you fund that and what-not? And we’re really focused on, it’s not to me, it’s not how many rigs you run, or how much of your production, it’s what you deliver on a per share basis. So, we can run real fast. We can run a lot faster when we’re running, but we got to issue a bunch of equity, like some other companies that have done that are in shale plays, and we’ve run those, and we’ve modeled it out, and your NPV just comes out less. So, one of the things I’ve learned is that…

Yup

190 people out there. This whole thing with the recycling came out of all that. There was a lot of testing. A lot of people worked on that, did really a good job from that group. So, we’re really building the infrastructure, these custom-built rigs we’ve got. As Rodney said, go out and look at the website and see how they walk around the pads, that’s really remarkable. So, all that is in preparation of getting the 40 or 50 rigs here in three or four, five years. So, when you take that, you got to couple it over, what’s going to be, how can we make our shareholders the biggest winners? And so that we tweak with that all the time, and in terms of how fast we should go. And the good news is, from all this modeling, is we believe and again, a lot of it has to do with gas prices, that between asset sales if you just look over the next five years, if you take asset sales that we think we can accomplish and the saving except to do any acquisitions, we won’t have to issue any equity. That we can do this with our existing equity base, and the good news is, for the shareholders is, is that all the upside that Jeff’s talking about, it’ll accrue to all of us. And when I say all of us, I’m still the largest individual shareholder, and I’m a pig, and I want it all for myself. I don’t want to share it, quite frankly, with a bunch of foreign company joint venture partners, or I don’t want to share with a bunch of new shareholders, unless I absolutely have to. So, and that’s as about as blunt as I can say it, okay? Monroe Helm – CM Energy Partners: Well, I appreciate the answer. And I think that’s what could shovel off from some of the other unconventional players, and the sell-side hasn’t figured out yet that there’s a lot of dilution that still has to occur for some of these shale plays to get done. But your measured pace is going to keep you from doing that. If you don’t mind, I’ve got a question for, I guess, maybe for Rodney any of you all. But it really has to do with the change in the way reserves can be reported at the end of this year, and whether or not you all have decided to report 2P and 3P reserves. And if not, why you would not?

Monroe, I’ll take a shot at that. Range Resources and the rest of the industry are all kind of running around with chickens with their heads cut off is the best way and trying to figure out what to do. A couple of things I think are important to note is that while the rules have, quote, changed there’s a lot of unknowns in those rules that people are trying to figure out. And if you go to the SEC and ask them questions, they don’t even know. So, Alan Farquharson, who is our Senior Vice President of Reservoir Engineering, and is just brilliant when it comes to this kind of stuff, has talked to a lot of the chief reservoir engineers in these other companies. And they’re all trying to figure out how to do all this within the context and there’s a lot of questions being asked to the SEC and we’re getting a lot of shrugs there. So, all I can tell you is, we don’t know yet. And quite frankly, I think it’s a pretty material thing, and we’ll answer that question in December, and we’re going to go to our Board, and get whatever we do, it’s going to be discussed and fully vetted at the Board. We’re just not going to make that decision ourselves. More than likely, just to give you at least my view of it is, the Range way is to take it is to go slower versus faster in all this. And we’re going to continue to be very disciplined in terms of how we look at reserves, irrespective of some of the new rules and the vagaries that go along with that. And my hope is, is that the rest of the industry takes a very disciplined approach at it. I’m a little concerned that they’re not for reasons that people can speculate of, but my hope is that the industry takes a very disciplined approach. If you look what happened in Canada, when they did this a moon or two ago, it was a little bit of a chaotic event. So we’re a little concerned there, but and we’ve looked at that, and so hopefully, that answers your question, but the blunt answer is, we don’t know yet. Monroe Helm – CM Energy Partners: Okay, just as a follow-on, not to dominate this. But from your understanding of the rules, would you have to demonstrate that you had the cash flow to be able to develop these 2 and 3P reserves, or some way to finance them, before you could put ‘em on the books?

Well, again, the rules are vague. I can tell you one damn thing, that at Range Resources, we’re not going to put things on the books unless we have a very good idea that we’re going to drill. Because I’m the one and Roger and I have to sign these little forms that, if you screw up, you go to jail, so I don’t care what, quote, the engineers tell me, but we’re only going to put things in the engineering report that we are pretty damn convinced that we’re going to drill up in a reasonable period of time. Monroe Helm – CM Energy Partners: Okay, thanks for the answers, and great results.

Thanks.

Thanks.

Our next question comes from the line of David Heikkinen with Tudor Pickering Holt. Please proceed with your question. David Heikkinen – Tudor Pickering Holt: Good afternoon, Joe pretty well and our team does too just can’t agree more with the good hire there. As you think about, just one quick question on third quarter and then fourth quarter kind of realizations in the Marcellus for gas and liquids, and as the MarkWest processing ramps up, I mean, how does that change, what was it currently, and then how does that change?

David, there’s, as you can imagine, there’s a whole lot of moving parts there. And let me give you a little bit of perspective in that. Right now, a fair amount of our gas is being processed in the southwest through a refrigeration plant, which is, it doesn’t have the ability to strip out as much of the liquid that the cryogenic plant does. So, once the cryogenic plant comes on-line, we will be able to receive a lot more money for those liquids than we have previously, which will be an uptick in the realizations that we’re going to get from the Marcellus. So, that’s kind of the big picture. If you think about what happens is, let me just kind of go through it again the way I think through it, which is pretty simple, is that when we take the gas through the plant, they’re going to strip the liquids out, not at the cryogenic plant. We’ll strip a bigger piece of out, and be able to get more money for that. And obviously, liquids today are, on a relative value, much more valuable than nat gas. So, the more liquids you can take out, you get paid for them. So it’s a relative, it’s a huge high grade given the difference in what you’re getting paid per btu for gas versus liquids. So, that’s the first thing, the second thing is, is once the gas, so once you strip out the liquids, the gas still has a relatively high btu factor, and under our gas contracts, and the way we sell our gas, we will get credit. We have been, and we’ll continue to get credit for the btus. We’re selling btus, not just selling mcfs, so that’s the other thing. So, basically three things: one, you get your raw gas, then you get your btu uplift, and then you get your liquid uplift. David Heikkinen – Tudor Pickering Holt: So with a 40 barrels per million yield kind of declines off the 10 barrels per million be a reasonable assumption, and kind of 40 to 50% of crude oil price realizations be good long term?

Well, to give you a rough idea, the gas that goes through the plant, through the cryogenic plant, once it gets up and running, it will be about 75 to a dollar relative increase, versus Henry Hub. David Heikkinen – Tudor Pickering Holt: Okay. Yeah, I was just trying to model out liquids separately, so as we change oil and gas prices, we get that real uplift in the higher oil well. But we can talk about it off-line, if I want to try to break that out.

Sure. David Heikkinen – Tudor Pickering Holt: The other question, talking about acquisition opportunities, it seems like there’s going to be some assets for sale in the Nora area. Is there any interest at all in adding acreage, or adding producing assets around Nora?

Great question. We have an interest in acquiring assets, and Chad his team continue to look at things all the time. Life’s become a little bit more difficult for them, because obviously, they’re challenged in terms of, now we got the little turbo charger from the Marcellus, and the returns from that. So, that makes it a little tougher in terms of buying things that we think are going to be NAV-accretive on a per share basis. That being said, if we can find high quality assets in our core areas, and clearly, Nora’s one of our core areas, we’re going to take a hard look at. The other question is, can we buy it at a price that we think is accretive to our shareholders. And what I mean there is, is that, if we go out buy something like we have over the last five or six years, now, we’ll fund the equity piece of that. I mean, the equity piece of that, through issuing equity, more than likely to the market. So, then it has to survive that rigorous analysis. So, therefore, it’s a challenge, but the way we look at it, if it’s in our core area, and we think we can acquire it a reasonable price, and we feel like it’s accretive to shareholders, sure, I think that’s what you pay us for to do, is to do those types of things. And then the question is, can we buy it a price that works for us, given all the vagaries, and people, future year gas prices and what-not. But as those assets come on the market, we’ll take hard look at it. David Heikkinen – Tudor Pickering Holt: Okay.

I mean, we’re looking at things in the Barnett now, and we’re looking at things and in the Marcellus right now. So, but yeah, I think that being said, we haven’t done an acquisition for nearly 10 years. So, again, I think, to gives you a little bit of an idea, we’re going to be really disciplined. And again, it all gets backs to what really matters to us, is that that’s really the per share or the stock price, and being the biggest producer, or having the most rigs, or having the biggest acreage position, all of that kind of gobbledygook just absolutely means nothing to us. David Heikkinen – Tudor Pickering Holt: Okay. And as you think about the leasing decision for equity, it’s small dollar amounts but how do you think about using your equity? Or what’s the, I guess, the seller of the acreage, are they asking for equity as opposed to cash? Or how are you thinking about issuing equity for acreage in the Marcellus?

Yeah, it’s a great question. In most cases, the sellers are asking for it, and so that’s why we’ve done it. And in each of the cases, let me just back up in the Marcellus, we’re not buying what I call any trend acreage in the Marcellus, haven’t been for almost two years now. Everything we’re buying is very targeted, it’s in something that we have a very clear view geologically on what we’re doing. And it’s stuff that we think is very promising in terms of the potential. And we don’t own all of the acreage in all the areas that we think are highly prospective, and we don’t have enough money to acquire all that acreage, quite frankly, and we never will acquire it all. But in and around some of our very, very, very key areas, that’s where we’re spending our money. And the good news is, with this, the one good thing about the recession has been is that prices, acreage prices have cooled off quite a bit, and we’ve been able to pick up a fair amount of acreage, again, right in between a bunch of key leases, and what-not, and picking up the acreage. And so that’s been one good part about it. And the other thing about Appalachia that is different than, let’s say, the Barnett Shale play in particular, is that, there aren’t 20,000-acre ranches in Pennsylvania. These are relatively small farms, in most cases. So, the leasing is very, very tedious, takes a lot of land people. And that’s why our acreage position and we’ve built this acreage position over a 25-year period. We were fortunate to have some acreage in the beginning of the play that just happened to be in the middle of it where we’ve built on extensively in that, and we’ll continue to do that. The other thing we’re doing is that we’re discussing with a number of different Marcellus players out there about trading acreage and they try to block up. They block up their positions, we block up ours, because clearly, that’s beneficial from a drilling and operating expense perspective. So, we’re doing some of those, we’ve done two or three so far, and we’ve got two or three more in the works that we’re working on. David Heikkinen – Tudor Pickering Holt: All right. Thanks, all.

Thank you. We are nearing the end of today’s conference. We’ll go to Marshall Carver of Capital One Southcoast for our final question. Marshall Carver – Capital One Southcoast: Yes. Thank you. One question, you added 40 million to the acreage budget, and haven’t changed your 900,000-acre position in a while. Is that $40 million increase going mostly to the Marcellus, or are you adding some in the Barnett too, or just trying to get feel for where that increase in acreage is going?

Most of it’s going in the Marcellus, but some of it’s going in the Barnett. More than 50% of it’s going in the Marcellus. So, in terms of updating the numbers, we haven’t updated the numbers in a while, and no real reason other than and I think the key thing is that, in some cases, we’re trading acreage. We end up with a few more acres, and they end up with a few less acres, depending on the relative quality of the acreage. The other thing is, as we continue to drill wells, we continue to high-grade it. I think we actually, just last week or a week before, actually sold off , I don’t know 10 or 20,000 acres in an area that we just didn’t think we’d get to for 10-plus years. So, we actually sold that off and that money will be recycled into some of our, what we consider our A-areas too. So the acreage number’s going to go up and down could go down, could go up, could go sideways for a while, unless we do something that’s pretty material. And we do from time to time have people with large blocks of acreage that have come to us and because we are the pioneer of the play and they see our results, and how well we’ve done it, they’ve asked us to be their partner. And that’s challenging, because again, if you think through it, I’d rather be spending our talent on acreage, where we get 100% benefit versus acreage where we’re getting, let’s say, half benefit or 60% benefit. Not that we don’t look at those, but we evaluate those as well, so it’s just all that kind of gobbledygook together. Marshall Carver – Capital One Southcoast: Okay, thank you. And are you adding sort of equally in northeast and southwest PA, or could you give any color on that?

We’re adding some in the northeast, but primarily in the southwest. Marshall Carver – Capital One Southcoast: Okay, thank you.

And just to answer that, Marshall, the reason is that is obviously, we’ve drilled more wells there. And again, not the smartest bulb in the package here, but when you drill a good well, and if there’s some acreage that, we’ve got most of it tied up, but there may be some of it that needs prospective, so we’ll run out and probably pick that up. And again, trying to continue to block up the acreage, and key again, one of the keys is blocking up the acreage, because it allows you to do the recycling, like Jeff talked about. It’s cheaper in terms of roads and pipelines, and all the other stuff. And we’ve really encouraged all the operators in the basin to really block up, because we think that’s really environmentally, it’s the best way, and it’s going to drive up the production the quickest in the basin as well, in terms of pipeline and infrastructure. So it’s all part of the master plan.

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

Well, thank you all for being on the call. I think we ran over a bit, and I apologize for that. Just some great questions, and we try to be as transparent as we can at Range. If you didn’t get an answer to your question, or if you thought our answer wasn’t clear enough to you, feel free to call Rodney, and he’ll get you to the right person to get those questions answered for you. We really appreciate the time. I’ll just sign off, given that we’ve run over so much. Thank you very much.

And thanks for your participation today in this conference. You may disconnect your lines at this time.