Greetings and welcome to the Range Resources 2009 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. Thank you. Mr. Waller, you may now begin.

Thank you, operator. Good afternoon and welcome. Range reported results for the calendar year 2009 with record production, leading the consensus number and setting a firm platform of continuing growth at low cost with high rates of return for 2010. The fourth quarter marked our 28th consecutive quarter of sequential production growth. Range has now completed its seven years of quarterly sequential production growth, with 2009 finding and development costs at the lowest in the company’s history. Although we are encouraged with our resource base to continue to grow production and reserves, we are more focused on achieving those targets at an optimum cost structure on a per share basis to maximize shareholder value. I think you will hear those 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, 10-K 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 margin, and the reconciliation of our adjusted non-GAAP earnings to reported earnings that are discussed on the call today. Tables are also posted on the website that will give you the detailed information of our current hedge position by quarter. Secondly, we will be participating in several conferences in the coming weeks. Check our website for a complete listing for the next several months. Jeff Ventura just spoke at Enercom’s Conference in San Francisco last week, and his remarks are still on the website. Next week we will be attending the Simmons Energy Conference in Las Vegas, the JPMorgan High Yield Conference in Miami, Thomas Weisel Partners Energy Conference is Denver, and we will finish up March with the Raymond James Conference in Orlando, the Wells Fargo Energy Forum in Boston, and finally see everyone in New Orleans at the Howard Weil Energy Conference at the end of the month. Now let me turn the call over to John.

Thanks, Rodney. Before Roger reviews the financial results, I will review some of the key accomplishments for 2009. Overall, we are very pleased with 2009 results. On a year-over-year basis, production rose 13%, beating the high end of our guidance. Fourth quarter production averaged $457 million a day, a record high for Range. It also represented the 28th consecutive quarter of sequential production growth. I should note that no other company in our peer group, to our knowledge, has achieved 28 consecutive quarters of sequential production growth. I believe this is a vivid testimony to the quality of our operating teams we have in each of our divisions. At year-end, proved reserves totaled 3.1 Tcfe, an 18% increase over 2008. Reserve replacement was 486% from all sources, including price revisions. Our FD&A costs averaged $1 an Mcf, the lowest in our history. Our drilling program alone delivered 540% reserve replacement at a cost of $0.69 per Mcfe, again the lowest in our history. Based on what we’ve seen today, these look to be some of the results of our peer group. We combine excellent growth in production reserves with low finding and development costs. That’s the hard part of our business that combined high growth with low cost. Again, this performance is attributable directly to our very talented technical teams in our divisions. Most importantly, production and reserves per share on a debt adjusted basis again increased over 10%. This marks the fifth consecutive year that we have achieved double-digit production and reserve growth per share. In 2009, we completed $219 million of asset sales. Over the last three years, we sold over $0.5 billion of properties. We would believe periodically selling our more mature properties have several benefits. First, it helps focus us on our higher growth opportunities; second,…

Thank you, John. Range ended 2009 on a high note with a very solid fourth quarter operating and financial performance. Cash flow for the fourth quarter exceeded last year’s even though oil and gas prices were lower. We lost significant production to asset sales during the year, but oil and gas production still set a new record high for the fourth quarter and year. Direct operating cost remains well below last year, and our record drill bit growth did not come with the expense of the balance sheet or the shareholders, as we ended the quarter and the year with less debt, more liquidity, and a share count very close to where we started. Oil and gas sales for the fourth quarter, including all settled derivatives, came to $277 million, a 9% increase from last year, as our increase in production won out over the 4% decline in realized price. Cash flow for the fourth quarter of 2009 was $188 million, up 14% from last year and up 10% from last quarter. Cash flow per share for the quarter was $1.18, $0.02 per share higher than the analyst consensus estimate of $1.16. Quarterly EBITDAX was $215 million, 12% higher than last year. Cash margins for the fourth quarter were $4.34 per Mcfe, and that’s the third consecutive quarter of improved margins. Year-over-year, while prices declined by $0.27 per Mcfe, cash margins only declined by $0.07, thanks to reductions in operating costs. Fourth quarter cash direct operating expense was $0.75 per Mcfe, 20% below the fourth quarter of last year. And to further illustrate our lower operating cost on an absolute dollar basis, direct operating cost was almost $3 million less in the fourth quarter of this year than last year even though production was 13% higher. Expect directing operating cost…

Thanks, Roger. Good report. I’ll now turn the call over to Jeff Venture to review our operations. Jeff?

Thanks, John. I’ll start the operations update with the Marcellus Shale. This time last year, our plan was to exit 2009 with net production from the Marcellus Shale from 80 million to 100 million cubic feet equivalent per day. We hit the high end of our guidance and we exited just over 100 million per day net. Today we are producing about 115 million per day net. We currently have 31 horizontal wells that have been drilled and are not yet online. Six of these wells have been completed and are waiting on hook-up and the remainder are waiting on completion. All of the wells will be completed within the next 90 days. Our plan is to exit 2010 at a net rate of 182 million per day from the Marcellus Shale and to exit 2011 at a net rate of 360 million to 400 million per day. Give n our large acreage position and our net resource potential of 18 to 25 Bcfe, I believe that we can surpass 1 Bcf per day net production from the Marcellus Shale to grow towards 2 Bcf per day in the future. In the Southwest part of the play, Range now has 40 horizontal wells with at least 120 days of production, with the oldest horizontal well having approximately 2.5 years of production history. We expect the average recovery of these wells to be 4.4 Bcfe gross. Zero time plot for these wells is on our website. We’ve also shown zero time plots for all of our horizontal wells by program year. It’s interesting to note that from 2007 to 2009, our effective horizontal lateral length has ranged from approximately 2,200 feet to 2,800 feet. And for the last two years, we’ve been averaging eight frac stages per well. Beginning in August…

Thanks, Jeff. Terrific report. Now let’s turn to 2010. Looking to 2010, it’s going to continue to be a challenging but also an exciting year for Range. Obviously the macroeconomic climate and the low commodity prices will be challenging, but we are extremely excited about the opportunities before us. Now, regarding Marcellus Shale, our goal in 2010 is continue to ramp up our drilling and double our production. In 2010, we are planning to drill 150 horizontal wells and anticipating exiting the year at 180 [ph] to 200 million per day net. In addition, we focus on continuing to maximize our drilling returns, as Jeff mentioned, experimenting with our lateral lengths and the number of frac stages. The good news is that we are off to a great start. Again, as Jeff mentioned, the drilling results continue to exceed our expectations. Our first two horizontal wells in Northeast PA tested for over 13 million a day on a seven-day test. These are clearly outstanding results. And we are very excited about it. In addition, while early, we are encouraged by the first Upper Devonian test and our first initial Utica test. In addition, the Marcellus infrastructure is proceeding as planned, as the cryogenic gas processing capacity is now at 155 million a day, heading into 335 million a day by early 2011. As Jeff again mentioned, on the dry gas side, we are making considerable progress on the infrastructure as well in terms of the dry gas side. Regarding the Marcellus Shale play, we discovered what many believe is a giant natural gas field. When you look back in history, there are only a handful of companies of Range’s size that have discovered and developed fields at this potential magnitude. We’ve not only moved from the R&D side to the…

Thank you, Mr. Pinkerton. (Operator instructions) Our first question comes from the line of David Kistler with Simmons & Company. Please proceed with your question. Your mike is now live. David Kistler – Simmons & Company: Hi, guys. Diving into the northeastern portion for a bit, I want to talk through development plans with the two recent horizontal well results. Little curious about how far apart those two wells were. And then you mentioned in your release pipelines tying in I think at the tail end of 2010 and also in 2011. And so I wanted to think about how rig count was directed there and the number of wells you might be tying in as the pipeline meets the project deadlines.

Okay. This is Jeff Ventura. To answer your first question, the wells are approximately 9 miles apart. So they are good ways apart. And again, we’ve drilled other vertical wells in there. So I feel confident about the acreage and that we have really high quality acreage. Let me put a little color on it too. To keep the variables at a minimum back to the – we drilled a 2,500-foot lateral with eight stages. So it was more standard design. So I think you have the upside there with volume, with longer laterals and more stages and show improvement there. But I couldn’t be happier about our initial results. The pipeline will be there at the end of this year. So what you will see us do this year, of the roughly 150 wells that we will be drilling, 15 to 20 of those are going to be up in the Northeast. And what we will do is both delineate additional acreage, de-risk additional acreage, and have wells ready to tie in when the pipelines get there. You will see production really start right at the tail end of this year, and then you will see a significant ramp-up in drilling curve in 2011. David Kistler – Simmons & Company: Okay. That’s helpful. Jumping over to Nora just for a second, you guys probably had a little less commentary on that, but I imagine experiencing the same sort of efficiency gains that you are seeing in days to drill and recoveries per well as you work through the typical learning curve. Can you give us an additional color around the economics of that play right now and potentially thoughts about increasing acreage position there?

Yes. We talked a little bit about Nora itself. The results in Nora have been great. When we embarked on our strategy in the Huron Shale a year and a half ago, we just wanted to equally space wells across our roughly 300,000 acre position to understand the shale and its potential. And the good news, it looks like there is great potential really across the entire acreage position. The wells tend to – costs were coming down today. You are probably at $1.2 million per horizontal well, and I think that number will continue to come down. And reserves are roughly a Bcf for Huron Shale well. So that’s going great. And then the other interesting thing, when you look at the other horizons, we’ve started to apply horizontal technology to the Big Lime and to the Berea and other horizons, and the economics look there is strong. We have a great acreage position. We are less than what we own the minerals there. So there is absolutely no pressure to drill. We will do it as it makes sense. And also there is really no need to expand. We think we’ve got tons of upside where we aren’t, but as usual, we will continue to look around and be opportunistic, but we will be very disciplined as well in terms of what we will do. David Kistler – Simmons & Company: Great. Thank you guys very much.

Thank you. Our next question comes from the line of Ron Mills with Johnson Rice. Please proceed with your question. Your mike is now live. Ron Mills – Johnson Rice: Hey, guys. Jeff, you just mentioned a couple – answered a couple questions on the Lycoming wells in terms of lateral length and stages. Can you comment a little bit on the cost of those wells relative to Southwest PA and how that relates to guys like Cabot and Chesapeake have talked about as they move more to Susquehanna County, but talking more about 5-plus Bcf type wells?

Yes. When you look at Lycoming County well we are drilling, and you’ve got to be careful when you are in the Northeast because you can find the Marcellus at a variety of depths, and if you go far enough east, it actually outcrops and is at the surface. Where we are in Lycoming County, it’s at about 8,500 feet deep. So the wells are going to cost a little more, roughly about $1 million more than our wells in the Southwest. In the development mode today, when we had drilling, our wells in the Southwest to drill and complete are about $3.5 million. In a development mode in the Northeast, in Lycoming County where the wells are about 8,500 feet deep, I think you’re looking at $4.5 million. But couldn’t be happier, our first two tries out of the box, 13.5 million per day, and those are seven-day averages. And we’ll continue to test wells, and they look – they are going to be great wells. I can tell you that. So I think the reserves are going to be very strong. It’s a little early to pin down a number, but they are strong and they are going to be great. Ron Mills – Johnson Rice: Okay. And then from – you obviously didn’t want to put out the 24-hour rates, but obviously much higher than that. Is there something going on in that – this is also one of those wells, I think located adjacent to where you drilled the vertical well, tested at 6.5 million a day. I’m trying to get a sense, as you move across your acreage position there, some of the attributes of the rocks that may cause those production rigs to differ, if any.

Yes. One advantage that you have there, you’re deeper, you’re 8,500 feet and you have high pressure gradient. So you’ve got a lot of reservoir pressure, which is positive. You’ve got a lot of gas in place, and obviously you have some quality rock with this if you’re getting rates like that. The 24-hour rates were fantastic. We’re just putting out, we think, longer-term rates are still fantastic and they are probably more indicative of longer-term performance. But they are super wells. So I’m really excited about our position there.

Yes. And this is John. It’s important to note that the vertical well rate is plus 6 million a day. That was a 24-hour IP versus these are seven-day rates. And obviously our view is 24-hour rates (inaudible). That’s why hopefully as we go along here, we will give you more of these, like, seven-day rates and even longer rates, because I think those are much more indicative in terms of the quality of the wells versus given 24-hour IP. In some cases, that’s all you have. But in this case, we’ve tested these wells now and we had the seven-day number. So we decided those were more appropriate, more indicative of what we thought the well quality was versus giving you a 24-hour rate, which as you mentioned as probably a bit higher.

And the other thing I’ll say is, like I said, we’ve actually given you guys the rates for all of our horizontal wells in the form of zero time plots, which I think are much better than type curve. That’s the actual real data by program year just put back the time zero. And the curve that we’ve put out is – and you can see the curves going up and down when you look at it by year. That’s just the actual real data. And then the sum of that data, we did smooth it, but it’s still a zero time plot, which I think is higher quality than a type curve. Ron Mills – Johnson Rice: Okay. And then lastly, maybe this is for Rodney or Roger. With the sale of Ohio properties at the end of March, John, I guess you provided the first quarter production guidance, but with the impact of that sales, something where the second quarter will tend on an absolute basis to look more flat with the first quarter because of the timing of that sale and then their allocation or re-allocation of those sales proceeds would then drive more second half growth. Is that the right way to look at that 12% target?

Yes, that’s exactly the way to – and most likely, we will break our 29 consecutive quarter sequential production growth because we’re probably going to sell – close on the Ohio, say, right at the end of the first quarter. So we’ll have 25 million a day or so. It’s going to go flying off the production books. The good news is, as Jeff mentioned, we do have a number of plays that are in the process of being completed. And then we hook up whether we can overcome all 25 million of that in day one of the first quarter, first part of the second quarter. It’s going to be a real, real challenge for our operating team. I wouldn’t bet against on it, but my gut feel is that we will see production either be flat or down a little bit in the second quarter, and then as we get the wells hooked and as these pipelines and whatnot, then you will see production really ramp up in the second half of the year on a relative basis for the first half. So again that’s – I think that makes absolute sense, and again it was part of the whole process we went through this year in terms of – if you think about what we’ve done last year, we sold Fuhrman right at about the middle of the year. This year we felt it is really important to really tee up the Ohio. Really we teed it up at the end of – in the fourth quarter of 2009, really opened it up to data rooms in December. Chad and his team did a terrific job of getting all that organized and getting the data room open. And we had a lot of interest in those properties and we were able to come what we believe is a very good agreement with our friends at EnerVest in terms of VAT. And I think it’s a good deal for both sides. I think again it’s a really high quality property that had some upsides from some formations that they are focused on. Obviously we’re much more focused on the Marcellus over in PA. So it’s – I think it’s a win-win deal for each side. I think getting it done soon early in the year and getting it done in the first quarter is really important I think for us to be able to kind of charge-off on our capital program. Ron Mills – Johnson Rice: And then the $950 million capital program, given your hedge position and the sales proceeds, is that based on a particular NYMEX price, somewhere in the low-to-mid sized, who were you continue to fund yourselves out of cash flow in the sales proceeds or how was that –?

Ron, given that we’ve got 75% of our gas production hedged at 5.50 floor, I mean, gas price could go to $4 and we’re still in good shape. Ron Mills – Johnson Rice: Okay, great. Thank you.

Thank you. Our next question comes from the line of Marshall Carver with Capital One Southcoast. Please proceed with your question. Your mike is now live. Marshall Carver – Capital One Southcoast: Yes. Of the 150 wells that you’re drilling and casing this year, how many do you plan on putting on line?

About 90 of them. Marshall Carver – Capital One Southcoast: Okay. And based on your commentary, I assume that’s more way towards the back half of the year.

Yes, we’ll put them on as soon as we can, but the growth will be just like John described. Marshall Carver – Capital One Southcoast: Okay, great. Cabot announced an impressive well in the Purcell Limestone earlier this week. Do you have a feel for how much of that could be on your acreage and do you plan on doing any test there?

We have a lot of upside that’s very similar to that, but it isn’t the Purcell. It’s very analogous to the Purcell, and that the Purcell is a limy interval in the middle of the Marcellus. What we have in the Southwest, in particular, is we have the Tully, which is in between our Marcellus and the Upper Devonian shales that we have there. So we have a lot of gas in place to find because we’ve drilled through continually. We’re now just starting to test it. So we have a huge upside in terms of the Upper Devonian, and of course we are testing the Utica of the lowest. I think more importantly, when you stand back and look at all that, what you’re really getting at is, I should say in my opinion, which is really important is, looking at gas in place throughout the trend and throughout the plays in the various horizons. You have to quantify where is that gas and plays located and looking what can the recovery be. We’ve told you that and particularly in the Marcellus acreage, we’ve got 18 to 25 Tcf of upside just from the Marcellus. I can tell you the upside from this Upper Devonian Shale and from the Utica is tremendous. And it’s literally on par with that. We haven’t put a number out yet. We’ve quantified it, we’ve been studying it for a long time, and we’re now testing it. But we’ve got tremendous upside in other horizons, and some of it is very analogous to what they have. Marshall Carver – Capital One Southcoast: Okay, that’s helpful. And one last question, on the longer laterals, what’s the additional cost on those compared to the laterals – the average laterals that you’ve been drilling?

The cost to drill the lateral is really inexpensive because the shale drill is really flat. It really comes down to how many additional pages are you pumping. So if you’re going to from eight stages to 16 stages or from eight to 12 or whatever that optimum ends up being. Marshall Carver – Capital One Southcoast: But what was the total –?

Just to put color on it, it may take a while that the development well in the Southwest from 3.5 million maybe to 4.0 million or 4.1 million. But again I think that if it’s worse, you’re going to be looking at better rates of return and actually lower finding cost. Marshall Carver – Capital One Southcoast: Great. Okay, thank you very much.

Thank you. Our next question comes from the line of David Heikkinen with Tudor Pickering Holt. Please proceed with your question. Your mike is now live. David Heikkinen – Tudor Pickering Holt: As you think about services cost and one of the things that we’ve heard on the live calls is increasing pressure pumping costs and kind of adding seven stages will affect your estimate kind of $85,000 a stage. Is it reasonable to think that those could escalate to 15% or 20% this year on a per-stage basis?

That to me, it sounds a little high. I think you will see upward pressure. To me, it sounds a little high though based on what you’re saying. David Heikkinen – Tudor Pickering Holt: Where would you expect the average stage cost to go?

Maybe goes up 10% to 15% rather than 15% to 20%. And then now I think you’re going to have other things or it will be – a lot of our rigs are locked in and obviously those costs are flat fuel cost relative to last year, at least for the first half of the year probably will be relatively flat. So there is a variety of pieces in that total cost. David Heikkinen – Tudor Pickering Holt: I’ll get right into the next question. As you think about rig contracts that you contracted as you’re growing into an increasing schedule, your ability to contract now is yet to be potentially at a little lower day rate. Is that sort of you see an offset to any increasing pressure pumping cost and a lower drilling cost?

Yes. David Heikkinen – Tudor Pickering Holt: Okay. That was – you walked right into that.

That’s (inaudible). Even with the rigs we have, the costs are – I'm thrilled that we are at $3.5 million. Those new rigs, the efficiencies are so much greater that it’s a slight thing to do for us, and it will average out with time, it will help offset some of the costs like you’re saying.

Yes. David, as you know, I think one of the important things about the Marcellus, at least in the Southwest, is that when the rig rate (inaudible) in the Barnett, a lot of that equipment end up going to the Marcellus because it fit the Marcellus in terms of pressure pumping ability and size of rigs and whatnot. It wasn’t really able to migrate to the Haynesville because the Haynesville is obviously much deeper, a lot more pressure in terms of pressure pumping. So the good news is, in terms of I think in the piece of Barnett, there were 215 well rigs being in operation. Today it’s probably way less than half of that. So there is still a lot of equipment, and I just think that the pressure in terms of that is going to be less than, let’s say, some of the other shale plays. That being said, at least in our view, there is probably a pretty good chance that the Marcellus by the end of this year will be the most active gas play in the world. So there is going to be pressure. The good news is, we’ve got great relationships with the vendors. We’ve been up there for a long time. We’ve got a lot of long-term contracts and relationships. And I think it would be crazy for most vendors know that we own 900,000 net acres in the fairway. We own another several hundred thousand outside of the fairway that has the chance of being good. So I think our ability to attract high quality services – and it’s not just the equipment, the quality of people that work on that equipment as well. And the good news is that’s changing because a lot of people have moved up to Appalachia and…

I use the strip, the gas strip on February – I think February 20th or something is what we used. I don’t have it right in front of me, but – David Heikkinen – Tudor Pickering Holt: That’s fine, thanks. And then thinking about segregating activity levels as you ramped from 40 to 150 to 250 to 300 wells in 2011, how much will you do in the Southwest dry gas and then the wet gas, and then how much will you do in the Northeast region as you balance your program across the state?

We really haven’t – I mean, we have some ideas on that. I think Jeff gave you some pretty good numbers for 2010. I think it’s a little early to figure all that out obviously. David Heikkinen – Tudor Pickering Holt: You’re obviously planning it just –

Yes, we are planning it. I think – I think at this point in time, we’re just not – we haven’t – we really haven’t got enough numbers on the paper. I feel comfortable to give those out in the public. David Heikkinen – Tudor Pickering Holt: And then as you look at 900,000 acres and over 1 million acres, how does getting acreage or additional property acquisitions into that big inventory work? I mean, how do you think about that kind of big picture-wise as opportunities come up?

It’s obviously interesting, and it’s something that we spend a lot of time on. And let me just give you – it's really – David, that’s really a great, great question. Let me take just a little bit of time because I think it’s really important. If you think about it, we spent, I don’t know, $100 million this year on acreage. But our net acreage count in the fairway actually stayed even at about 900,000 acres. So yes, the question is, what did you do with that money? And what we did with that money is really block up our existing key areas. We really think blocking up the acreage is the key to success in terms of being able to ramp up production at low cost, because if you think about it, if you block up your acreage and you can drill multiple wells from a well site. You’ve got one location, you’ve got one road, you’ve got one pipeline. You don’t have to – you don’t have pipelines all over the place and roads all over the place. It’s just much more efficient. It’s also much more environmentally friendly, and we’re being very sensitive to the citizens and the commonwealth in terms of doing that because we don’t want to tear up the surface. So it’s a challenge. I think the good news is, is that we’ve been blocking up literally for about 2.5 years now. We haven’t bought any, what I’d call, trend acreage for over two, 2.5 years. In fact, we sold off what we considered to be some C-quality acreage in 2009. And we’re going to continue to do that, as time goes on. But I think you will see us do a number of things this year. We will continue to block up…

Thank you. Our next question comes from the line of Mike Scialla with Thomas Weisel Partners. Please proceed with your question. Your mike is now live. Mike Scialla – Thomas Weisel Partners: Hi, guys. I guess, John, if somebody offers you $14,000 an acre tomorrow, you’re not a seller?

No. Mike Scialla – Thomas Weisel Partners: Okay. In terms of some of the older wells in the Marcellus, do you see any changes in the liquid yields there? There has been some talk here recently about some of these (inaudible) areas, potentially rich for condensate type reservoirs. Have you seen any evidence of that with your area in the Marcellus?

No. Mike Scialla – Thomas Weisel Partners: Good quick answers.

We are not seeing any changes – Mike Scialla – Thomas Weisel Partners: In terms of the long-term plans for produced water, can you talk about those at all?

Yes. I’ve been really proud of our team up there. Not only we discovered the play in five years, in terms of the drilling and completion, but in terms of what to do with the water, really starting in about spring of last year, we started recycling water, and by August/September in the Southwest, where we’ve had drilling, we’re recycling 100% of our water. And that’s going really well. I told you the number other day. We’ve recycled over 70 million gallons of water, and the team has done a great job there. And so far, that looks great. And the other thing we are doing is we are working with the authorities in terms of testing some disposals on and then setting up some water disposal wells. And the state liked – the DEP liked that solution, the EPA liked that solution, and we will be doing that this year as well. I think by the end of the year, and so far they are encouraging as well. By the end of the year, I’m hoping to couple recycling with the social wells, and if that works, those two things in common, I think that basically will take care of the water disposal problem. So basically in the pad [ph] drilling right now with recycling, we’re at zero discharge. It also reduces the need on the front end because you’re recycling on the water. And then to the extent you have step-out wells or extraneous wells, hopefully we will just go to our own disposal wells. Mike Scialla – Thomas Weisel Partners: Okay. And Jeff, you said you are encouraged by the year-to-go. What you have seen there? Did you take course with schedule approach?

What’s encouraging, I think, is a combination of two things. The answer is, no, we did not core. But clearly we ran extensive logs across including the (inaudible) logs where you’re coming with an estimate of how many Bcf per mount [ph] you have in place, and those numbers look very strong. Obviously you need to test to confirm it. As you’re drilling through it, you get gas shelves [ph]. There is different data that you gather. And so far, all of that looks encouraging. Obviously until you tested that the proof in the pudding. But so far it looks great, and we’re excited for the past. Mike Scialla – Thomas Weisel Partners: Okay. And just one last one from me. John talked about blocking up your acreage, where does the state stand in terms of getting unit position or sometimes (inaudible)?

Yes, great question. We are – one of the real positives I think in the Marcellus is that there is a group of the industry, the E&P industry has formed a group called the Marcellus Shale coalition. And we hired a president of that, and this is real live organism that’s really doing good work, not only in terms of best practices across the play, which are in most cases much better and much higher stringent in terms of what the DEP is requesting, which I think I see that as a real positive. But some of the other things we’re doing is, as coalition come together to try to look at the current regulatory environment in some of the rules and regulations. We’ve worked by to come up with proposals to the stake in terms of modernizing some of the rule sin there. And we’ve had very good dial log [ph], not only among the companies, but also among the regulators and the legislator that obviously to some degree ha a hand in that. So I see that all progressed very, very well, and I think you will see the fruits of all that hard work over the last year or so – we are at two years, come out later this year, with some hopefully some modernization signs that aren’t critical but that is important as the play ramps up in terms of just making everybody’s life easy, we’re also making it easier for the state, for the royalty owner, and for the companies that we maximize the place for all the different constituencies, which is really, really important. I think as we look out over the next five to 10 years in this play. Mike Scialla – Thomas Weisel Partners: Great, thank you.

Thank you. Our next question comes from the line of Dan McSpirit with BMO Capital Markets. Please proceed with your question. Your mike is now live. Dan McSpirit – BMO Capital Markets: Gentlemen, good afternoon and thank you for taking my questions. Turning to the Northeast part of the Marcellus, 15 to 20 wells that you will drill there this year, what are the distances between wells and how much acreage do you think you will de-risk by drilling these wells?

The distances between the wells will vary. Some of them are stepping out quite away, probably on the order of – when I said the 9 miles between the two wells, it’s actually 8.9 miles. To answer your question, I haven’t physically majored the ones that you’re probably looking at wells that are as far part as 20 or 30 miles. So they are pretty good plays. Other wells would be close and drilled to where the pipeline connections are. So the combination of wells and rates are stepping out. I think by the end of this year, through our drilling and through the industry drilling that a very significant portion of that acreage is going to be de-risk.

Let me just – this is John. Let me just take on what just Jeff said. One of the things, they give a little bit of what our plan was. Obviously we’re not a giant company with a giant budget. So we had to be very frugal in terms of how we ramped up and how we did that. That’s one of the reasons we picked this up. We’ll have to start. There is a whole bunch of technical reasons, but one of the business reasons was, we had pipelines in place. We already had field operations in Marcellus drilling. So there were a lot of reasons to start that. And now that’s up and gone, and we feel like we de-risk a whole boat load of acreage and we’re really excited about, and that’s what’s going to drive our production this year and have a big impact on the next several years. The second stage of the next leg of stool is the Northeast. And one of the things that we’re really hoping that would happen that’s happened is that other companies would help de-risk our acreage. And that’s happening in a huge way. And we get calls all the time from companies and we share data and we share logs and test data and whatnot, and big companies, small companies, private companies, public companies. So the good news is a lot of wells have been drilled in the Northeast that’s really de-risking our acreage, without our capital dollars. And that was something that we hoped to happen and now it’s really happened, because the Northeast is really, really competitive. It’s really ramping up in terms of the number of rigs up there. And that really helps us. We’re all in favor of that. We’re a cheerleader on that side as we do that. And then again, we will have a better idea how to develop our acreage from that. And then also the infrastructure will be easy. Now, the Southwest, we’re basically towing the road to us with our joint venture with MarkWest. Up in the Northeast, I think we will be more infrastructure joint ventures and thing with the other independents, so we’ll be able to share the cost and that freight going forward just because the acreage is – that’s the way the acreage is done. So again, both of time – so I think – stepping back, our grand vision is actually bearing the fruit pretty much like we thought and hoped it would. So all in all, we’ll – again, we’re pretty hectic. Dan McSpirit – BMO Capital Markets: Okay, okay. And then turning to Texas Panhandle, the wells that you plan for 2010, can you talk about the objective there that you are drilling and the target of the economics?

Yes. In the Texas Panhandle, specifically, we are targeting primarily the St. Louis formation. Our guys up there – we've got a pretty good acreage position already built, but we’re still leasing. So I don’t give a lot of details. But I will tell you the economics on it look really strong. You’re looking at cost to find and develop well below $1 and rates of return that are competitive with the Marcellus. So it’s – they have got a great play. Again, it’s something our team discovered and is leading the industry. And so that’s what we’re doing in the Panhandle. Dan McSpirit – BMO Capital Markets: Okay. And then one more if I can. On both the Upper Devonian and the Utica tests, can you share any thoughts on maybe timing of results, expectations on economics and including costs?

It’s probably for us going to be similar to what the Marcellus was a couple of years ago. Hopefully, and you’ve been looking and following us for a long time, and we continue to peel back the layers of the onion in the Marcellus and give more and more information. And in time we’ll be totally transparent with all of it. They are really spotting up our acreage and showing you the wells and help de-risking the whole thing. However, with the Upper Devonian and the Utica, sort of back where we were a few years back with the Marcellus. We think there is big upside and we want to make sure we capture that value for our shareholders. There is tremendous amounts of gas in place, and potentially large amounts in recoverable gas there. So we’ll be coy there, but in time again we will be putting up results. Dan McSpirit – BMO Capital Markets: Very good. That’s all I have. Thank you again.

Thanks, Dan.

Thank you. We are nearing the end of today’s conference. We will go to Leo Mariani of RBC Capital Markets for our final question. Leo Mariani – RBC Capital Markets: Hi, good afternoon here, guys.

Hi, Leo. Leo Mariani – RBC Capital Markets: You guys talked about your retail being about 13 rigs right now in the Marcellus, going to 24 in 2011. Want to get a breakdown of how many of those are going to be spudded rigs versus horizontal rigs.

Currently it’s about 50/50. I think that mix with time will just vary depending on how efficient the various rigs become. But right now, it’s about 50/50. Leo Mariani – RBC Capital Markets: Hi. You guys plan on continuing to employ spudded rigs going forward, it sounds like.

Yes. Where we are today, it looks like they drilled the vertical part in a more cost effective way and then we move off the air rig and come back, mud up, and bring in the bigger rigs. Today that gives us the best economic. And again, we can always try to improve with time, and we’ll see where that leads us. Leo Mariani – RBC Capital Markets: Okay. I think you guys have made a comment on the call that a portion of your acreage a decent chunk in the Marcellus (inaudible) 900,000 is APP. Just curious if you guys could quantify a little.

It’s less than half, but it’s a big chunk

Leo Mariani – RBC Capital Markets: Okay. And your position in Northeast Pennsylvania, I think about 350,000 acres, you drilled your first couple in Lycoming. What other counties in Northeast PA do you guys have significant acreages?

We haven’t put out the specific counties, and again that’s jut for competitive reasons. We’re becoming more transparent. We told you where those really good vertical wells are and that’s where we drill our horizontals. But I’ll just say it’s a slot from Bradford, from Lycoming and a little bit through there. It’s right in the guts of where Mitsui just paid Anadarko $14,000 an acre for. Leo Mariani – RBC Capital Markets: Okay. You talked about 4.4 Bs in Southwest PA I guess on the wells you drilled to date at this point in time being for your actual EUR. What’s your average lateral length over those particular wells?

It’s probably going to be about 2,400, 2,500 feet. The low end is 2,200 feet. The high end is 2,800 feet. The low frac stages are three, although it was really in the first year. And there is – actually it’s on our website for the other years at seven or eight stages. And again, I think that’s fantastic results when you look at the economic that that generates, but I’m really excited about the experiment that we have in place. And that we will talk about over time. We just want to gather more production history, and what you will see us do is continue to update those plots and curves. And again, we’ve given you every single horizontal well we drilled in the form of a zero time plot, which is the just the actual data by program year. And we will continue to update that. Probably what we will do is break apart the shorter laterals that we drilled through August of last year and then this whole series of longer laterals and more stages. So we can quantify the difference. Leo Mariani – RBC Capital Markets: All right. And I guess in your 2010 drilling program, is it going to be a majority of the wells that are going to have longer laterals at this point in time or is it more of a small fraction?

Where we are today, the wells will be typically longer laterals than that and with more stages. What we don’t know at this point in time is where that optimum is, but we’ve got a lot of things in place and we will be defining that as we go forward. And of course, we will continually look and see we can improve there as we gather data. But we are setting them up for typically more than eight stages and more than 2,800-foot laterals. Leo Mariani – RBC Capital Markets: All right. Thanks a lot, guys.

Thanks, Leo.

Thanks, Leo.

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

Well, we’ve run quite a bit over. We really appreciate all of you who joined us today. Obviously we’re really excited about what we’ve got in the potential at Range. And we will continue to work hard and hopefully perform. And why don’t we just terminate the call? Thanks a lot.

Thank you for participating in today’s conference. You may disconnect your lines at this time, and we appreciate your participation.