Greetings and welcome to the Range Resources Third Quarter 2010 Earnings Conference Call. [Operator Instructions] It is now my pleasure to introduce your host, Mr. Rodney Waller, Senior Vice President for Range Resources. Thank you, Mr. Waller, you may begin.

Thank you, operator. Good afternoon, and welcome. Range Resources reported its results for the third quarter 2010 with record production breaking the 500 million a day mark for the first time. Range reported increase production in our liquid-rich areas of the Marcellus, Midcontinent and the Permian Basin and announced the decision to market our Barnett Shale properties. I know that these items, along with our operations update last week, will generate a number of questions 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 would like to cover a few administrative items. First, we did file our 10-Q with the SEC this morning. It's available now 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 non-GAAP measures of cash flow, EBITDAX, cash margins and the reconciliation of our non-GAAP earnings or 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. Second, we'll be participating in several conferences and road shows in the coming weeks. Please check our website for a complete listing for the next several months. John will be speaking at the DUG East conference in Pittsburgh on November 4. Range will be attending the Morningstar Stock Forum in Chicago next week, the Boenning & Scattergood Energy Conference in New York on November 9, the Pritchard Capital Conference in Boston on November 10; the Bank of America Energy Conference in Miami on November 12; the UBS Energy Conference in New York on November 17; the Bank of America Credit Conference in New York on November 17; and the JP Morgan Conference in Boston on November 30. We hope we can see you at one of these conferences. Now let me turn it over to John.

Thanks, Rodney. Before Roger reviews the third quarter financial results, I'd like to take just a few minutes to review the key accomplishments in the third quarter. On a year-over-year basis, third quarter production rose 15% beating the high end of our guidance. This marks the 31st consecutive quarter of sequential production growth. In addition we reached, as Rodney mentioned, the 500 million per day production milestone for the first time in our company's history. Kudos goes out to our operating teams on that. Our financial results reflect the fact that the 15% increase in production was more than offset by a 22% decrease in realized prices. We are pleased on the cost side. As on a per unit production basis, three out of the four major cost categories were lower than the prior year period. D&A expense per mcfe came in at 18% lower than last year, which is really significant. Interest expense per unit saw a 4% decrease, direct operating costs per mcfe were 3% lower than the prior period. On the higher side of the G&A costs, we saw an 8% increase over last year. We're still building out our Marcellus team. And we'll see the impact of that for a couple more quarters or so in G&A, before we begin to see a decline or in unit production basis like the other metrics. For the first nine months of the year, we have spent $780 million or 65% of our capital budget. For the year, we certainly don't want to spend more than our budget. And if anything, we may end up spending a few dollars less than budgeted. With regard to our Marcellus Shale play, we continue to make significant headway in the quarter as we continue to drill fantastic wells, filling our acreage position, test the other shale formations and continue to build out the infrastructure. I'm particularly pleased with the Marcellus acreage trade we've accomplished so far this year. In the third quarter, we did our largest trade to date. The acreage trades are difficult and very time-consuming to complete but are extremely beneficial to help to block out our acreage positions, which in turn significantly increase our capital efficiency. The most encouraging aspect of the quarter is the 136% increase in our NGL volumes and the drilling results in our oil and liquid-rich plays in the Midcontinent and Permian areas. Our operating teams did an excellent job quickly shifting capital and getting these projects online. All in all, third quarter was a very solid one. We executed on the production side, continued to reduce cost, successfully shifted capital to higher-margin liquid-rich plays and maintained a strong balance sheet. With that, I'll turn the call over to Roger to review the financial results.

Thank you, John. Financially, third quarter 2010 saw significant progress in capital efficiency, balance sheet strength and incremental cash flow growth versus the second quarter of 2010. Third quarter natural gas, NGL and oil sales, including all cash-settled derivatives totaled $245 million, down 4% from last year due to lower prices, but up from last quarter on higher production. This figure also includes $15.7 million from the early settlement of hedged 2011 oil production that was subsequently re-hedged. Year-to-date natural gas, NGL and oil revenue, including all cash-settled derivatives, totaled $696 million. Cash flow for the third quarter was $141 million, 18% below last year and 9% higher than the second quarter this year. Cash flow per share for the quarter was $0.88, matching the analysts' consensus estimate, year-to-date cash flow over $418 million. EBITDAX for the third quarter was $173 million, 13% lower than the third quarter of '09 but 11% higher than last quarter. EBITDAX for the year-to-date period was $505 million. Cash margins for the quarter was $3 per mcfe. That's 28% lower than last year solely due to lower gas prices. With the Ohio asset sale behind us, there are only a few unusual revenue and expense items to highlight in the third quarter results. Our non-cash derivative mark-to-market losses totaled $15.9 million. And our deferred compensation plan actually had a $5.3 million non-cash income posting due to declining market values of assets held in the plan. An income statement category appearing for the first time was a $5.4 million loss on early extinguishment of debt. This amount represents financing costs from redeeming our old 7 3/8% notes slated to mature in 2013 and replacing them with new 6 3/4% notes maturing in 2020. Our nearest long-term bond maturity is now not until 2015. The $5.4…

Thanks, Roger. I'll now turn the call over to Jeff to review our operations.

Thanks, John. I'll begin with the Marcellus update. Our exit rate for the third quarter of 2010 in the Marcellus was 191 million cubic feet equivalent per day net, with approximately 71% of the production being natural gas and 29% NGLs and condensate. At the end of the third quarter, approximately 34 million cubic feet equivalent per day of net production was shut in and waiting on gathering and compression facilities currently under construction. By year end, we expect all of these production will be online. We announced a series of great wells in the liquid-rich portion of the Marcellus play last week in our operations release. These 18 new wells look like they will exceed our five Bcfe average reserve estimate for the Southwest part of the play. The five Bcfe reserve estimate is comprised of 3.6 Bcf of gas and 239,000 barrels of liquids. At a $4 flat gas price for ever a $60 per oil price flat for ever, the rate of return from Marcellus well and the wet gas area is 60%. Fully loading this case with 100% of our current corporate G&A rate and with all land costs, the rate of return is still 47%. Running the base case with current script pricing versus the $4 flat gas and $60 flat oil, the rate of return goes from 60% up to 75% and looking at the fully loaded case and assuming script pricing, the rate of return goes from 70% up to 60%. Given a low gas price in our development plan to hold acreage, our plan is to drill fewer wells per pad with moderate lateral lengths and frac stages. Doing this will keep our cost to drilling complete at approximately 4 million in the Southwest, given the economics I just stated, and will…

Thanks, Jeff. Good update. Looking to the remainder of 2010, we see continued strong operating results. For the fourth quarter, we're looking for production average roughly 535 million equivalents per day, representing a 17% increase year-over-year. Fourth quarter production will reflect the sale of the Ohio properties in March of this year. So the 17% fourth quarter production growth estimate equates to 23% after adjusting for property sales. As Roger mentioned, we expect fourth quarter unit cost to continue to decline. Importantly, we have 76% of our fourth quarter natural gas production hedged at an average floor of $5.56 and a cap of $7.20. Also we're confident that our all-in 2010 finding and development costs will come in at or below $1 per mcfe. This will help us to continue to drive down our DD&A rate in the fourth quarter and into 2011 as well. Let's now shift gears a bit and discuss our announcement that we have decided to market our Barnett Shale properties. Over the last three months, we've conducted a full review of all of our properties, including both producing and nonproducing properties. After considering all the alternatives, we concluded that selling the Barnett Shale properties best fits our strategy of growing production reserves on a per share basis at low cost. While we like our Barnett Shale properties, and our team has done a great job at developing them, we are in an enviable position of having a very deep inventory of high-quality projects. As a result, we believe taking the proceeds from the sale of the Barnett and redeploying that sales proceeds into our other projects over the next several years will accelerate the value generation process. Because of our $322 million of NOLs and capitalized IDCs, we don't expect any cash taxes on the…

[Operator Instructions] Our first question is from the line of Rehan Rashid with FBR Capital Markets. Rehan Rashid - FBR Capital Markets & Co.: Could you walk us through the direction of operating costs or unit operating cost as you've kind of rolled out the next four, six quarters' worth of production growth from the Marcellus?

Let me start at kind of high level, and I'll move down a bit. And Jeff and Roger, please chime in. There's really two reasons why you've seen a material drop in our operating costs over the last year or so. First the production we're adding, in particular the Marcellus, is a lot lower than the average production rate of our current properties. Currently in the Marcellus, LOE rate's somewhere in the $0.30 to $0.35 range. The other thing is the sale of our higher cost properties. So again as you take that money and recycle it out of the higher cost properties and move it into the lower cost properties, you get kind of a double whammy approach of LOE decrease. And as Roger mentioned, we had third quarter is $0.73, which is $0.05 higher than we had hoped for some reasons that Roger mentioned. But we should be back under $0.70 and the upper $0.60 range in the fourth quarter, which, especially in Appalachia, tends to be a little higher quarter because of all the road maintenance and all the weather issues you get in the winter time up there. But when you look at our 2011, we're going to be continuing to decrease it. Our goal is to be in the low $0.60 range hopefully for 2011, trending hopefully below that towards the end of the year. And then again as we move into 2012, we ought to see continued decrease of that as well. And as I mentioned, the Marcellus is in the $0.30 to $0.35 range. So as more and more of our production becomes Marcellus, you'll see that trend down. And again the key here is when you connect all the dots at the end of 2011 or end of this year, we'll be…

The bulk of our drilling is still in the liquids-rich wet area. But I think we'll be adding -- now at Northeast will be coming online. It would be interesting to watch the performance of the wells and to change that from acreage value into PDP value. But we'll still directing the bulk of our activity found in the Woodford. Rehan Rashid - FBR Capital Markets & Co.: So 70% to 80% would be a good ballpark number?

Well, we'll come out with numbers later on in the year like we typically do when we released our budget, we'll have all that detail in there or early next year when we release that. But yes, it will be a significant portion.

Your next question comes from the line of Dave Kistler from Simmons & Company. David Kistler - Simmons & Company International: The choice of the Barnett assets versus maybe Permian assets or Cana Woodford assets, given the kind of relationship between gas and oil, the kind of 20:1, can you walk us through that? And should we be reading anything into your view on dry gas versus liquids-rich versus liquids in general?

Really, what we do, we did a really thorough analysis, looking into all of our assets, literally put everything on the table. And we went through that analysis, there's a lot of consideration. So one consideration is what assets are currently selling for, where you can market things, where we think we can get fair value relative to how we view them. We also looked at what we view or are the upside of the various properties that we have. And one of the things about the Fort Worth basin and the Barnett Shale is it's really a single-pay horizon. We have great properties, a lot of gas in play. But one of the advantages of things like really the Appalachian Basin and the Permian or Midcontinent is you have stacked pays and lot of water hydrocarbon in plays, new technology, horizontal drilling that's really unlocking, it allow us to recover a lot more horizon. So we felt with the valuations and particularly with the recent transaction that John said, we could raise a lot of money at we think a fair price. And it would really do a lot of us, and John talked about all those of different things. While at the same time from our perspective, retain a lot of the upside that we really like. So those are some of the considerations that were in there. David Kistler - Simmons & Company International: And then with respect to having additional capital come into the company and be redeployed towards the Marcellus, I believe on the last conference call, you talked about kind of peak Marcellus rates about 2 to 3 Bcf a day of production and kind of I think were targeting about a 2013 time frame for that. Does that potentially get accelerated? And how should we think about the growth? Obviously you've indicated, you'll backfill what you'll lose in the Barnett, but really thinking about trying to triangulate the capital spending going forward

Well, let's work at different pieces of that. Like we said, when you look at the Barnett at sale time, it will be 120 million to 130 million per day net. In the Marcellus next year, we're going to go from 200 million to 400 million net. So we'll more than make up the Barnett within 12 months. Going forward and on the last call, I did talk about, I believe, the most exciting part about the Marcellus, as we drill and other people drill, the quality of play keeps expanding. It gets better, it gets broader. So the acreage we have primarily, a lot of it looks really good. So we have the opportunity with the position we have to drive rates up to, I believe, two to three Bcf per day net. We have that kind of potential. We did not put a time frame on it, as far as I'm aware. But we'll come out, when we come out with our capital budget early next year like we do, we'll continue to paint out the picture and connect the dots so you can see what that is. We'll be very mindful of where we're drilling, and, the rates of return that we're getting will be very capital-disciplined. But we think we got a great opportunity to capture. And really, this sale will allow us to do that and do it in -- like John said, our focus is about growth per share at low cost; growth per share, both reserves and production that adjusted at low cost. And we think you'll see it continue to funnel a lot of money into the Marcellus. Eventually the Marcellus will go cash flow positive, and we'll continue to paint that up with time when we've captured than we have in a lot of the areas, a lot of great opportunities to continue to grow. When you look at the rates of some of the Woodford wells, those are impressive, 1,000 to 1,500 barrels of oil equivalent per day. And in Galum, [ph] Mississippi, 400 to 500 barrels per day. We think that our properties in the Permian have a lot of that Bone Spring, Avalon, Wolfcamp potential that others are doing. So we think we're in a great, great position. David Kistler - Simmons & Company International: Just in terms of trying to increase the predictability of the returns coming out of the Marcellus, as you talked about hedging et cetera, do you look at potentially vertically integrating there in terms of any services, businesses you'd want to get more deeply involved with, especially as we're looking at kind of a backlog of drilled uncompleted wells up there.

Our team's done a really good job of well one, planning ahead, not just one-year and two-year, but five-year and 10-year and looking the whole way through depletion. So we know the rigs we need and the fractures we need and the takeaway capacity and staff size and office space. And they've done a really good job of planning. And we think our strengths and what we're really good at is exactly what we're doing, building reserves and production per share at low cost. We're not drillers, we're not frac guys. But we've wind up and locked in the services we need in order to accomplish the task that we want to accomplish, and we've already done that. So I don't anticipate that we're going to end those businesses.

And plus, just add on to Jeff's comment there, it's just like the pipeline of processing business. We don't believe that's our strength. Other thing is, I think, obviously we're very mindful of the amount of capital it takes to do those things too. They're not free. It takes a lot of upfront capital to fund those and whatnot. So again, it's just trying to allocate your capital. But you're also trying to focus your expertise in areas where you think you can have the biggest impact. So I think it's a combination of both those things.

Your next question is from the line of Gil Yang with Bank of America.

Can you comment on after the sales of Barnett whether or not your bank line and credit would need to be reduced, by how much?

Gil, this is Roger. We don't anticipate any reductions there. That's best we can tell, we don't have the new $4 and slide escalation case the banks are using in this modern day season. We've got ample borrowing base capacity that we haven't elected to use over and above that $1.5 billion number. So I think we're going to in good shape there.

What is it exactly?

We're currently at $1.5 billion borrowing base. But we've probably got easily another $500 million to $700 million over that if we needed it. So I think we've got a big enough cushion in there over and above our existing commitment to accommodate the sale.

And you said something about earlier that the $34 million that they shut in would go away at some point. When would that go away?

By year end.

And is it usual that you won't have any shut-ins, so there's no sort of shut-in inventory, so to speak?

Whether any company, on any play, on any area, anywhere in the world at any point in time, would be actively drilling is going to have wells in various stages of completion and shut-in. There were some confusion in our operations released last week, hopefully not by too many people but least by one individual who said there's infrastructure problems. There's no infrastructure problem. That's just part of the normal build-out and flow that you see the team again is doing a good job of staying ahead of the drilling machine. So that will go away, but there'll be some other wells. And that's just part of a normal business and our normal business and everyone else's taboo.

Can you quantify what normally would be there? I know it will go off announced but it's a bit more like five Bs day shut-in or....

Well, you said Bs per day, let me clarify that. It's roughly $30 million. So when you bring a pad on, you have four wells on a pad, maybe 25 million or 30 million you have wells more, if you have one or two wells, it will be less so it will be in those ranges.

Can you sort of just say anything in terms of the 44 I guess wells waiting in completion? What would be sort of normal number, and when you get to expect to get the normal number?

That's probably going to slow up and down, maybe it will be somewhere in the range of 25 to 50 or something like that at any point in time. This isn't like the Bakken. We're not waiting or parts of the Permian, we're not waiting on frac crews or things like that, if that's what you're getting at.

And then, do you plan to update what your expected or what views are when you report reserves? When do you think...

Well we do year end reserves, and we typically I think put that on in February. We'll probably continue to update it. I think we've been very transparent showing you our team's progression and how we've driven out production for time and recovers per well with time, so we'll continue to try to do that.

And then in the quarter you said I think $60 or so on land and acreage, could you comment on where that is? Is that for the bonus extension that you've talked about for the labor and rental payment you talked about, or there's something else going on?

About $50 million of that is in the Marcellus. And of that, 2/3 of it or 65% are new leases. So the rest of it is extensions and renewals. And the other $15 million is scattered amongst the three divisions.

And the new leases, just to put some color on that, is picking the little bits and pieces in and around our big blocks where we're just filling in.

Those are all right. What we're saying the wells are 5 billions and fully loaded at strip pricing of 60% rate of return, it's all right there, three acres here, five acres there.

When you swap acreage or comment that you swap acres, there's no cash involved with that, right?

Sometimes we've actually, and we've done five trades. And so far all of them have been, no cash has been involved. I can assure you, there are no discussions. Oftentimes there were, a time or two in terms of there was some discussion of selling some cash into making the number of acres worked out and everything else. It's just at the end of the day, it's just been net acres for net acres. And try to put them together. And that's one good thing I think now that the play is getting more mature. All the operators are coming to the same conclusion I think that we have several years ago is blocking of their acreage it's really, really important. And the capital and the low price environment is really important. So that has facilitated a lot of the acreage trace. And quite frankly we've got four or five others that we're working on. And again, they take a really long time because everybody do their acreage slightly better than yours and negotiations and whatnot. So they just take a long, long time to work out. But the good news is the fact that we've done a five, and we got a number more that we're looking at. I think it tells you that the play's getting more mature, people are getting more comfortable with our technical views of different acreage. And it's allowing these trades to get done. And I just said, it's a win-win deal. One good thing about a trade is you're not selling out for cash, you're actually, in most cases, it's one plus one equals three because both sides getting something as benefit. And so that's why they work. Again they just take a long time to work out in most cases.

I want to finish this up, along those line with the roughly 40 million or 35 million that you're spending to buy new acreage to fill in those gaps, are you also selling something that are sort of out there, that you can't trade it but you just sort of don't really need it?

We did one very small deal like that a couple of years ago. And going forward, we'll look at optimizing our position as best we can. And that will be drilling the hole, renewing some stuff, filling in holes by buying, trading, it may be letting some stuff expire and maybe selling little bits here and there. It will be all of the above. uppertor: Our next question is from line of Leo Mariani from RBC.

In the Marcellus, just curious as to how the rig ramp is progressing, how menu horizontal rigs do you guys have today, and kind of where you expect to be in a year or two?

We have six big rigs today. And we'll probably pick up on another three by the end of first quarter next year and stay there for that of your. So we're still putting those plans together, and of course there's some small rigs in front of them. We're going to be very capital disciplined.

And obviously, you guys are slightly tweaking the way you approach it there in terms of fewer wells per pad and shorter laterals. How much does it take to take the return?

I think the jury is still out. Like I said with the laterals we're drilling, the economics are pretty spectacular and part of that is we're in the wet gas area and the quality of the wells and everything else. And we're looking at great rates of return, doing. We have drilled a number of wells and will watch the long-term production with time plus watch each others people's long-term production through time. And really at the end of the day, it's very how you economic loss and that's answered this in certainty of that answer, we'll know a lot more next year than we'll know now. For sure, you know that a longer lateral, if you put 30 stages in a well versus eight, you're going to get a higher IP. The question is if you get a better rate of return. We're still looking at laterals and that, they'll be in that 2,500 a little bit more that 3,000 eight stage, maybe 10 stage jobs and those are fantastic rates for return. We've got some of those experiments in there, We'll just watch wash them and look.

In terms of the Permian, how much total acreage do you guys have out there, and it seems like pretty early days in your investigation of a lot of these for the new horizons even though it's in the Marcellus quite a bit for the last couple of years. Is that a fair realization in terms of the Permian?

Well, no. We have different that were different things. We have quite a bit acreage, what I try to do is rather than just talk about acreage, talk about geology and deal focus. So those number that I just gave in terms of the Permian, were based on all of that work, and it's a 155 gross and hundred 18 that maybe we do have a lot of acreage out there and we're in a good hydrocarbon rich area. Like I said, we'll start our first wells there first quarter next year.

Your next question is from line of Ron Mills with Johnson Rice. Ronald Mills - Johnson Rice & Company, L.L.C.: Question on just the Barnett properties. If you compare those to the talent properties in terms of production mix, I know that they had plus almost 30% if you associate with their production, a lot of different properties I think with overlapped in some of your 120 million to 130 million a day of production, what's the production profile of that gas versus the deal.

If you have that talent properties, they're roughly, they're 29% liquid, 71% gas. If you look at ours, well, they're 71% gas, we're 81%, and the difference is liquid. So they have a little bit more liquid bur it's not tremendously higher. When you look at the overlap of property, they really don't overlap very well. Calen [ph] is predominantly west of us. Almost all of their acreage is in Parker County. And when you look at a lot of our acreage, it's more on the quarter to play to proven core and a lot of it is in Johnson counties. So when you look at the quality of the wells in those areas, and it's public wells, the quality of the well is clearly higher there. So that's important. When you look at they're 71% gas, we're 81%, they're a little more liquids. But when you look at acreage, our acreage is clearly more in the core. The other thing is when you look at, I'll just do gross to gross on acreage, they announced 20,000 gross acreage is what they had in the package. We have 64,000 gross acres and out to be net to net. But we have basically more than 3x the acreage in a higher quality area. So I think that's how it compares.

And Ron, the other thing I think is important is the production profile is slightly different either. As you know, we've only had one or two rigs Barnett for a good long time here. And so, our production kind of comes by the decline curve. They got those properties some other guys and put a bunch of money and ramp the production up, which is what I do in almost all properties too. But their production rate is at the higher end of that curve deeper into the current than ours. And you know, I think that has an impact in terms of relative value to somebody. So there's a lot that goes into it. We always been known to those properties pretty well. We actually look at that onetime. And our team obviously because we've spent him fair amount of time. So we're not saying that the properties aren't in good properties for most of the say what the financial terms as we can in terms of the relative quality of these assets. Still good quality assets and we've got some a lot of people talent call us announcing that want to know our thoughts on it and would it be to adjusted so we have a pretty good insight in terms of that as well as some it all comes that the decision that they made but at the end of the they come it all comes down in a "no" quickly a couple of months three months. So that's kind of where we stand. Ronald Mills - Johnson Rice & Company, L.L.C.: And I'm looking back to older presentations and press releases, both of your three plus Bcfe of crude reserves and the production percent plus or minus a quarter of the production is the reserve split pretty similar or is there a significant difference of Barnett deserves versus the production?

For obvious reasons, we're not going to get direct. One is a don't disclose reserves on a segment basis because it's not a segment business. Anything is not our best interest to do that in terms of the process. So we were looking that confidential for the time being. Ronald Mills - Johnson Rice & Company, L.L.C.: Just trying to back into on a relative margin of Barnett versus your Southwestern division versus Marcellus division, trying to back into what the EBITDAX margin is on the Barnett.

This is what we're going to do in the sales process and I don't want to go into detail, but I'll say on that sale, when we look at our lower cost, it will help lower our DD&A and it will help our elderly. It's positive for us in terms of getting to know. We're adding in getting to dollars for the Marcellus are just getting better plus an average and higher than the those areas. So have continued to drive down those costs. Ronald Mills - Johnson Rice & Company, L.L.C.: You talked about the redeployment of capital. One thing with the discussion of a number of liquids plays that you discussed in the past when you look at the redeployment of capital, we should an expectation be to redeployment of that in the liquid or some of the newer liquid phase you identified versus all of that being redeployed on the Marcellus.

We're going through a rigorous analysis of our budget and no look at where we will discussions like to turn trying new concepts holding acreage and all of those types of things. You see the bulk of the cap that goes even more works as John said in the past, will have one or two drilled in the Barnett obviously and we'll be looking at and not mindful of a aspects of our business. Ronald Mills - Johnson Rice & Company, L.L.C.: Jeff, but the CapEx budget that you've all talked about for this year, But the total CapEx this year, you've spent on development plus or minus $600 million so far. I think you had talked about $850 million and $900 million budget. I think John said you might spend a little less than that. Is that accurate?

The numbers are on our website and that's roughly $1.2 million budget. And we spent about $700 million, $765 million. But if you look on our website, the exact budget is that an if match at what's in there and you see where the exact numbers on that.

And our final question comes from the line of Dan McSpirit with BMO Capital Markets.

On the Marcellus, on the press release, can you talk about the conditions that was used to describe the IP-based of the 18 Marcellus well stood in the quarter? I think you're talking about six side but what chokes I'd vote for load and maybe just a deliberate move to maintain that pressure are really just to make it at the position you to restrict the volumes?

If you look at our wells, we had our best wells so far down there when you look at unconstrained. At the end of 2008, we knew we have $20 million a day and you decide to see what we can do. It came in at $26 million per day. And that's million is about a Bcfe well. So we've had other mouth as she that are really strong like that and the multiple wells could be over $50 million per day. so we decided to do after that first well is rather than design really everything is the highest rates and from the economic point of view, we believe it's better to design for what more of an average rate is versus what our wells make on peak. So it's about optimizing about maximizing rates and issues. So you can make it been like that Haynesville where you guys have pressure and really high pusher pressures so you have soft rock for crushing and all kinds of things in order to minimize that early on that district the rates. And it's a much different situation. We don't need high-strength profits were frac-ing bitterly with 100 other things like that and to standard that are inexpensive. So yes, all those have the capacity. We were just designing for ICs and the urge building and just producing a lot of fuss over 20 million per day and we started putting 20 stage fracs or 20 stage facts. We would get some fantastic growth and we're really looking at rates of returns and we have maximizing the project getting capital discipline and watching that over time.

Mindful of the sensitivity of that sale process on the Barnett Shale assets but just for the basis of comparison and get a better handle on what you're selling, is from a field level economics point of view, if you run the fully loaded economics of the Barnett Shale assets, like you run on the Marcellus, what the IRR at $4 or $5 gas and I assume that would exclude cash interest cost and cash taxes?

The easiest thing to do is just look at our website and report our economics out of the same gas prices whether the average who will be on the Barnett versus the Marcellus versus. So just open the book. So that $4, that 60% rate of return in the Marcellus at $4 on the Barnett is 23. So that's right off on our website.

What makes the trend $2.5 million in non-cash improve property in payments that was recorded in the quarter?

This is Roger. Our amortization for lack of a better word of our acreage is going to be expired over time or that is impaired by new developments maybe to drive a whole and impaired acreage. On a successful methods of counting comment on accounted for separately to improve properties. So you don't have that you can develop this in and then periodically pushed a big savings identity care of all your a push for successful in business under and you have for us otherness the past, we have to account for separately so you a list looking at your improved and assessing the value of your improve and adjusting your provision expense, which is a quarterly expense to basically forecast what your future impairment and exploration schedules going to be like. So that's where the $20 million comes from and that's really a realtime process that we undertake.

Are there specific properties that you can identify behind the $20.5 million? Is that the same set of properties each quarter that we're looking at here?

At this point, there's only one or two specific categories and improve groupings. Really it's all done by a division on a division basis ongoing basis and so it's a more up amortization approach for the puppets that you see there now are still going to be there.

I think the simpler way to say is this division have the number of visas that are going to expire over the next five years and we take that and divide that monthly and that's what the monthly or quarterly amortization is. It's a very simplistic approach to that end in the race that's what we're doing. To some specific identification as Roger mentioned some of the fastest time to take kind of a long-term approach and pay me now, pay me later and amortize it over time. Well with that, I guess that concludes our call. We really appreciate everybody taking the time to join us today. It's really a very exciting time at Range. Think of Range and even going back two or three years, is the idea that we would sell our Barnett properties is pretty amazing. And I think it really tells you how far the company has come over the last two or three years for the management team and as Jeff and I think it would also extend to we've taken a lot of time to think through this discussion or decision. We spent a lot of time with the Board in terms of making this decision. But I think it's really exciting. I think what that tells you it's the confidence level for us to think that we 120 to 130 million of production for 12 months or less, we couldn't get any closer to that two or three years ago. So I think it's a complete sea change in terms of the capability of the company and the capital efficiency. Also I think it really beckons the fact that management really is very confident in not only Marcellus but these other projects that we've got and our ability to execute. And I…