Greetings and welcome to the Range Resources first quarter 2010 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 speaker's 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 Resources reported results for the first quarter 2010 with record production, leading the consensus numbers and continued to execute our business plan with improvement in unit cost while navigation this period of challenging commodity prices. The first quarter marked our 29th consecutive quarter of sequential production growth. Although we are encouraged with our resource base to continue to grow production and reserves in the future, 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 the speakers today. On the call with me today are John Pinkerton, our Chairman and Chief Executive Officer; Jeff Ventura, our President and Chief Operating Officer; 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 and cash margins, 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 May. Check our website for a complete listing for the next several months. Moving at (inaudible) it's going be held at May 13 to 14, on last 13 (inaudible) conference in Houston on May 21st, and the UBS Oil & Gas Conference on May 27 stockholders meeting will be held on May the 19th, with the help of each of the stockholder as received their proxy material and we urge each stockholder for the proposal being submitted in the proxy. Now let me turn it over the call to John.

Thanks, Rodney. Before Roger reviews the first quarter financial results, I will review some of the key accomplishments so far in 2010. First, on a year-over-year basis, first quarter production rose 12%, reaching the high end of guidance. This also marks the 29th consecutive quarter of sequential production growth. If you adjust for asset sales first quarter 2010 production would have been 18%. Second, our joint program is on schedule throughout the quarter as we drilled 72 wells. We continue to be very pleased with our drilling results and despite the lower prices. We are generating attractive returns on the capital. Currently, we have 22 rigs in operation. A 12% increase in production was more than offset by 16% decrease in realized prices. As a result, first quarter oil and gas revenues were down 6%, compared to the prior year. We are most pleased on the cost side as on our per unit production basis nearly all cost categories were lower than the prior period. In particular, direct operating cost came in $0.73 per Mcfe. This is 22% lower than the prior year period, quite an achievement. With regards to our Marcellus Shale play, significant headwind was made in the quarter as we continue to drill some fantastic wells filling our acreage position to test the other Shale formations and continue to build out infrastructure. In addition, we continue to add high quality technical personnel to our Marcellus team in Pittsburgh, which now includes over 200 people. Right at the end of the quarter, we completed the initial phase of our Ohio asset sale which generated roughly $300 million of proceeds. This sale included 3300 wells in over 13,000 leases. I'm really pleased that we were able to get it close so early in the year. All now I couldn't be more pleased on how much we accomplished in the first quarter. I think it's a real testimony to all of us here at Range especially the technical folks. With that I will turn the call over to Roger to view financial results.

Thank you, John. The first quarter of 2010 in some way was a lot like the first quarter of 2009. Production reached to record quarterly high 12% higher than the prior year and Range posted another solidly profitable first quarter despite oil and gas prices in the first quarter like last year been sharply low. Turning to a bit deeper into the numbers however, revealed a stronger operating performance in the last year, to significantly lower unit operating cost plus the balance sheet benefits having sold most of our Ohio tight gas sand properties at the end of March. Quarterly oil and gas sales including past settled derivatives totaled $233 million down 6% from the last year's revenue figure of 248. Once again unfortunately, the decline in prices just offset the benefit of higher production volumes. Cash flow for the first quarter of 2010 was $147 million, 7% below the first quarter of '09 with cash flow per share $0.92, $0.02 above the analyst consensus estimate of $0.90. EBITDAX for the quarter was $176 million, 5% lower than the first quarter of '09. First quarter of 2010 cash margins were down 18% from last year at $3.49 per Mcfe compared to $4.25 per Mcfe in 2009. There were a few extraordinary revenue and expense items going through the financial statements this quarter starting with the pretax unrealized marketing and market gain on our hedges of $46 million, and a $69 million pretax book gain primarily from the sale of our Ohio properties. On the expense side, we have $7.9 million in severance cost from Ohio sale along with the $6.5 million low gas price in dues impairment of the Gulf Coast property. Lastly, as our stock price declined slightly during the quarter, we reported non-cash income of $5.7 million related…

Thanks, Roger. Terrific update; I'll now turn the call over to Jeff Ventura who will review our operating activity. Jeff?

Thanks, John. I will start the operations update with the Marcellus Shale. Our strategy at Range is and has been growth of low cost. Range's Marcellus production has the best economics of any large scale, repeatable gas play in the U.S. There are basically four reasons for these. The first is this discovery in the Appalachian Basin, which is in close proximity to the best gas markets in the U.S. Therefore, the gas produced here is advantaged versus other gas in the U.S. It doesn't have to be transported forward to get to the end users. Second, not all layers in the Marcellus or any other gas play for that matter are equal. To have the best economics, you will have to be in the core part of the play where the rock quality is the best. Range clearly has a great position in the core as evidenced by the high quality wells that we have drilled in combined with the way which we've been able to grow our net production with relatively few rigs. The third reason is that Range discovered the modern Marcellus Shale play and has a strategic first mover advantage. Since we were the first to pursue the play, our acreage acquisition cost is very low, which significantly impacts our economics in a positive way. The fourth reason, our economics is so good perhaps the best in the Marcellus play so that we are in the wet gas portion of the play, which relatively speaking is a small part of the total Marcellus acreage. It exists in the Western half of the Southwest portion of the play, primarily in Southwest Pennsylvania and into the West Virginia Panhandle. Given our gas prices and oil prices are if you are processing which Range does through our contract with…

Thanks, Jeff. That was a terrific update. Looking to the remainder of 2009, we see continued strong operating results here at Range. For the second quarter, we are looking for production to average, second quarter production for 2010 to average 450 to 455 million a day representing a 10% increase year-over-year. The second quarter production reflected sales, the Fuhrman Mascho properties last June, the New York properties last December and the Ohio properties in March of this year. So, the 10% second quarter growth target equates to 18% after adjusting for the property sales. However, given that we sold the Ohio properties right at the end of the March it is unlikely we will be able to make up the full amount of the Ohio production loss of 25 million a day in the second quarter. As a result it is likely our straight 29 consecutive quarters of sequential production growth will come to a halt. As I've said in the past, I would not be disappointed to see this to retain if that was in our best interest. Clearly the Ohio property sale wasn't our best interest given the terrific price we received. For the year, we still anticipate with our production growth target of 13% even after accounting for the property sale. Now that we close the Ohio property sale, I will take a moment to look at the impact of our divestiture program. Over the past three years, we have reduced our well count by roughly 6000 wells. This represents 57% of our well count, but only approximately 9% of our production reserves. The properties we sold were more mature higher cost properties. The good news is that while we were selling our mature higher cost properties, we were focusing on our capital into higher return projects…

Thank you, Mr. Pinkerton. The question-and-answer session will be conducted electronically. (Operator Instructions) Our first question is coming from the line of Mr. Marshall Carver with Capital One Southcoast. Your line is now open. You may proceed with your question. Marshall Carver – Capital One Southcoast: All right, just a couple of questions. The St. Louis and Stron [ph] areas where you drilled some successful wells, how many locations or net locations do you have in each of those areas?

Well, St. Louis is very early for us, but we've got a good acreage position that we are building. We got close to 40,000 growth acres and we think approaching 250 potential growth locations, so it can be very impactful. We are going slow. It's early on, but so far we are encouraged by what we see and it's particularly it's just great economics, $1.3 million for a little over 2 Bcfe coupled with the fact that you got an oil component, wells have come online and 2 billion with 50 barrels to 100 barrels of oil per day. The gas is relatively rich even after that 1080 BCU. So, we are excited by the play before our guidance generated up there. It's early on and then in the strong not as much potential so that when you look at the acreage you're having and things we could acquire and again it's early on in the play that we drilled several great wells. IP is of 300 barrels to 700 barrels per day rift out with in aggregate. It could approach 100 wells overtime if we continue to successfully grow and acquire a few things that we see. So, the guys are doing a good job not only in driving up production in the Marcellus and in making better and better wells, better economics, keeping all eyes on the ball there, but the guys in the other division are extracting a lot of value out of our old properties in old areas. Marshall Carver – Capital One Southcoast: Okay. That's very helpful. Thank you.

Sure.

Thank you. Our next question is coming from the line of Mr. Leo Mariani with RBC Capital Markets. Your line is now open. You may proceed with your question. Leo Mariani – RBC Capital Markets: John, I guess you just mentioned you potentially would consider a JV in the Marcellus or some acreage sales for the right price. Seems like a bit of a shift from what you have been saying in the past. Can you talk a little about strategy behind this? Is this more of a value unlocker for Range because it appears as though you have plenty of capital to execute your near terms plans here?

Yes Leo, it's a great question. And I appreciate you asking it. Maybe I wasn't – as I should have been, but historically our strategy is always been at Range. We are going to do what's in the shareholders best interest, and therefore, I didn't think, our team didn't think doing JV is a relatively low prices make any sense because like as you said, we really didn't need the capital to exploit it. As things move along in the play and clearly Chesap did their deal at 5800, Atlas and Anadarko did their deals at 14,000 or better. We think those prices are going to continue to move up. So, over some period of time we think that the price that repay will come closer to what we think fair value is and so we will continue to monitor that and if we think we are getting something that we believe is in fair value and its NAV accretive when you take the time value into account. We think that is in our shareholders best interest and we will – we've look at it very closely. We consider that and take it to the Board to get their input. So, again it all comes back to driving up on NAV per share. So, if we can do that don't screw up the balance sheet, will screw up the simplicity of the company materially will look at those for the best interest for the shareholders and we will move forward with that and as you can imagine with all the different things that add there, we had lots of discussions with lots of people. We will continue to have lots of discussions with lots of people and we will do the right thing. Leo Mariani – RBC Capital Markets: Okay. Just switching gears here, in your press release you talked about seeing some encouraging things in your initial horizontal well in the Utica and the Upper Devonian. Have you production tested these wells or flow tested them at this time here?

Yes, we have. When we talked about on the last quarter because we have drilled them and logged them and we are encouraged by what we saw based on ETS launch and such, and shows we have now drilled in case tested on, and in the press release, we mentioned that we are going to be looking a lot. So, clearly refine gas, but in general with any specifics we are going to hold that pipe very early on in the play. Importantly, I think I just want to reemphasize that we think the most perspective part for Upper Devonian Shale is primarily in the Southwestern portion of the State. Actually, they have the right thickness in large properties of making perspective and we are looking at all the various things that make Shale plays work. And in the Utica Shale, we think it's primarily perspective on the Western half of the State. The good news is we've got 1.3 million acres in the State from primarily all in Pennsylvania of which 600,000 acres are in the Southwest portion of the play. So, a lot of our acreages perspective for that is the big upside. We are encouraged by what we see early on, but it's early. We've drilled a couple of more wells probably by the end of the year and like we were with the Marcellus a few years back. We will keep it relatively applied and make sure we capture that. Therefore, our shareholders, it's good news as a lot of it is stacked on our existing acreage. So, we've captured a lot already, but Rodney said there would be things would want to fill in. Leo Mariani – RBC Capital Markets: Okay. One other thing; you guys mentioned in your press release as you're taking your EURs up on your Marcellus from 3 Bcf to 4 Bcf to 4 Bcf to 5 Bcf for your "high" graded acreage, is your high graded acreage – is that just the same thing as core 900,000 acres?

Yes and our acreage, gas is again 1.3 million acres basically within the fairway 900,000 that is high graded in it. It's really well positioned I've mentioned before there's been over 600 wells in the Southwest , Range wells and others both vertical and one horizontal, a huge portion of the acreage in the Southwest . The other 300,000 acres in the Northeast is predominantly a lay down where Anadarko and Mitsui did their deal. They haven't put it up specifically but a lot of its like homing, plus or minus accounting on either side like Bradford, Lycoming in there. So we feel, given the industries result to date that the very high quality acreage as evidenced by the quality of wells and evidenced by the deals that John mentioned. Leo Mariani – RBC Capital Markets: Okay. I guess the last question for you guys. Obviously your direct operating costs LOE looked great this quarter. It sounds like that's going to drop again next quarter. Can you give us any kind of ballpark as to where that can go this year?

Yes, I think Roger mentioned that it's going to drop another nickel or so. So it will be in the mid-to upper $0.60 next quarter. Leo Mariani – RBC Capital Markets: Okay. Thanks a lot guys.

Thank you.

Thank you. Our next question is coming from the line of Dave Kistler with Simmons & Company. Your line is now open. You may proceed with your question. Dave Kistler – Simmons & Company: Good morning Dave.

Good morning Dave. Dave Kistler – Simmons & Company: Or I guess afternoon. I apologize. Let's see. Just thinking about your drilling activity over the next few years and more specifically as you reiterated the $360 million to $400 million of production by year end 2011 out of the Marcellus. Can you delineate what portion of that is going to be coming out of the Northwest PA portion and what portion would be coming, obviously the balance of the Southwestern portion?

We can guide you somewhat. Through the end of this, we're not going to have the Lycoming County from Northeast until the end of this year. So basically and that's in almost all of the $180 million to $200 million per day net – and again, I want to emphasize the word net – will be coming from the Southeast and predominantly from the wet gas portion, almost all of that. When you project going into next year, a lot of our drilling is going to be in the Southwest although we'll start to ramp up the Northeast. So the vast majority of it in those early years is going to be coming from the Southwest and from the wet gas part of it. Beyond that we'll start to see a good contribution from the other areas. Dave Kistler – Simmons & Company: Okay. And diving into your hedges a little bit, when I looked at the 2011 hedges, if we just run oil production relatively flattish for you guys or liquids portions, whatnot, it ends up being over 90% hedged. So I'm gathering that there is – relative to any announcements you made about Stron [ph] and other areas, that we should be anticipating an uptick in the liquids production as well. Can you just give us some additional color there?

Yes, that's intuitive. If you just look at the delta change in the liquids, our liquids production is going to go streaming up this year and next year and next year for example we think the liquids production will be more than twice of what the oil production is and be heading north from there. So pretty intuitive question and again we really kind of circled back around with what Jeff was talking about in terms of the wet gas area of the Marcellus and in particular, when you're in a low price gas environment, a high price oil environment, the benefit of being in wet-gas is dramatic and so I mean, again as part of the message or the madness in terms of how we developed our acreage position and what we're doing and why we're doing what we're doing is well encompassing all that. Dave Kistler – Simmons & Company: Okay. So if I look at percentage hedges right now and I just try to project growth, I think the same quarter percentages are what you're going to be targeting for 2011 if I want to project the oil and liquids growth that I should be thinking about?

I'm not following you completely. I just – it's really hard to hedge liquids and most people who hedge liquids, they simply hedge oil. So we look at it as a basket. Clearly our biggest percentage of our production is going to be natural gas. So we're kind of focused on that, especially given where it is today. If you want to get into the details of the oil versus the NGL I suggest you call Rodney Waller and he can run you through all those detailed numbers after the call. Dave Kistler – Simmons & Company: That's great. That's actually very helpful, and primarily I was focusing more on the oil component piece just as you have shown those hedges for 2011. But one last thing on liquids if I can sneak it in. Everybody is obviously trying to take up their liquids components in this current environment. You guys have great position there. How are you thinking about that? Do we worry that liquids over time become pressured from pricing standpoint as everybody is seeing that same sort deviation in value and obviously wants to capitalize on it?

Again, that's a very intuitive question. It's something that our marketing team has really looked at very carefully. When you look at the Marcellus, the wet-gas area is a relatively small percentage of the total acreage in the Marcellus. So therefore the liquids component and the liquids that's going to be generated from the Marcellus, when you look at the entire play, it's not as big as I think some people have anticipated. That being said, one of the reasons why we chose to do our venture with Mark West is their expertise, when it comes to liquids and how you distribute the liquids up in the Northeast and we'll give you an example. Within 12 months we'll have a propane line in and we'll be selling our propane 12 to 24 through a pipeline. We're putting a rail for it and so instead of trucking the liquids we'll be rail-carrying the liquids out and the good news is, almost all of that will be used in the Northeast. There is some very good markets in the Northeast for all that stuff. So we analyzed that and don't see that there is any issue. In fact one of the good things that's happening is on a relative basis on liquids everything, we're seeing a higher price for liquids as they come out of Marcellus and we are in other places because the market is so robust in the Northeast versus the other parts there is more competition and more liquids coming onto the market. So that's kind of how we look at it on a 50,000 level.

And just to be crystal clear adding onto what John is saying, the wet-gas part of the Marcellus of the total play is small but Range sort of dominates that wet-gas part which is an advantage we have. A big part of what we have is a small part of the total play for the industry.

And one thing I can do is direct you to probably Mark West's website. Randy Nickerson made a presentation last week at Doug East Marcellus Midstream conference in Pittsburg showing what the total demand of Appalachian products were or each of the components built in the winter and the summer markets and showed what our production would be that is going to be largely, maybe a third of capacity is it possibly weak during the three to four years. So therefore I think the mid information about the market being overrun, to reiterate what John said is because the markets we are selling to in Appalachia have to get all the labels out of the Gulf Coast and pay a transportation charge for it, we can compete very competitively with those. We can avoid the large transportation charges coming out of the Gulf. So it kind of ensures a ready market for us and people, they really are able to take that as long as we can give them consistent quality and consistent quantities. Dave Kistler – Simmons & Company: That's very helpful, guys. I appreciate the additional color there.

Thank you. Our next question is coming from the line of Mr. Ron Mills with Johnson Rice. Your line is now open. You may proceed with your question. Ron Mills – Johnson Rice: Hi guys. Just a question on leasing and lease expirations. I know you have plus or minus 15% of your budgets going towards leasing. Can you add a little direction in terms of how much of that is new leasing and is most of that directed in continuing to fill out your Marcellus area and how much is dedicated to re-upping leases with current lessees?

Hi Ron. This is John. Pretty good game last night, huh? Ron Mills – Johnson Rice: Yes. I think the fix was in.

Great question, Ron. We, and let me just start at a high level. Then I'll work down. We haven't been by any what I'd call trend acreage in the play for two years. What we've really been doing, and the reason is because we grow a bunch of wells and we drill our first – completed our first well in '04 and we drilled a bunch of wells in '05 and '06 in areas that we thought were really, really, really perspective. So we immediately started buying acreage in there for a $50 to $100 an acre and it moves up to $500 an acres. So in most of acreage we've got relatively cheaply and most of them have very low royalty burden. So we're in terrific shape. What we're doing now, what we've done the last couple of years is we're simply filling in the holes in those big blocks of acreage we've got to try to continue to block our acreage position. We believe strongly and the Barnett is a perfect example, the Fayetteville is a good example and the Woodford is a very good example, if you can block up your acreage it really helps dramatically in rolling your costs as you go forward and it's everything from pipeline costs to road costs to infrastructure costs. All those costs go down and the economics of the play go up. So our budget this year is to do a number of things, one filling the hole. The only thing is we've got a huge average position, 1.3 million acres. We are not going to hold all that acreage from drilling. So we have to decide each year, what do we want to hold, what do we want to let go. The good news is everything that we've wanted…

If you look at the major plays, we're looking at; we're on track to hit our $180 million to $200 million in the Marcellus. Today we're approximately $130 million per day net, something like that. The Barnett is working at $120 million to $125 million, Nora, about $65 million per day. Those will be top three and the rest of it is a lot of legacy price-gas standard of oil production. Ron Mills – Johnson Rice: And then in terms of the timing of production ramp, particularly in the Marcellus, obviously you'll have some come on at the end of the year in Northeast Pennsylvania. But in terms of March from $130 million a day to the $180 million to $200 million a day, how consistent is that over the remaining three quarters or are there major infrastructure bottlenecks being relieved at a particular date?

No, I mean infrastructure in the Southwest predominantly will be there. Because of the fact, some of that – we're doing a combination of pad drilling to drive up rates and to be efficient, coupled with step out wells and things to delineate. So when you pad drill, what we do is we'll drill the wells and then we complete them all at the same time. So it's a little bit lumpy that way, which is typical of all the shale plays out there. But with the guys that are focused, they know where we are and there will be, March would be a straight line but I feel comfortable and confident we'll hit our $180 million to $200 million in the Marcellus net and we'll get our 12% growth for the year corporately and do it with a great cost structure. Ron Mills – Johnson Rice: And then lastly, the Granite Wash play, you outlined in your operational portion of your release, that's obviously a different play than what a lot of other operators are talking about in that area. What kind of running room do you have I guess along Leo's lines in that Granite Wash vertical play?

Yes, our play is different. It's a good point. That's why we put a little color on it in the release. The wells are on the order of $1.2 million on the order of 1 Bcf to 2 Bcf. And importantly there is an oil component. IP is again about $2 million per day, 50 to 100 barrels of oil per day with that and very importantly per day the gas of 1,240 Btu. So you get the oil up and you get the oil revenue, also your gas price of 1.24. So that's the huge plus. And very low risk. The other part about a lot of our areas, particularly the Panhandle but as well as our Stron [ph] areas as well, they're in fact pay areas and I'm just talking about and I think every one of those St. Louis wells we've drilled so far, they are up full pays, and with our Granite Wash wells, a lot of time to catch other plays as well. Stron [ph] well is the same. They're up all full pays with those. I'm just talking about the reserves in the main horizon. So it's good to be in areas that have stacked pays, a lot of hydrocarbon in place with a high quality team that just does a great job of continuing to get more and more out of those order properties. Ron Mills – Johnson Rice: Thank you very much.

Thank you. Our next question is coming from the line of Mr. David Heikkinen with Tudor, Pickering & Holt. Your line is now open. You may proceed with your question. David Heikkinen – Tudor, Pickering & Holt: Thanks guys. Just wanted to get into firm transportation and just the thought of taking gas into Canada as we have seen some proposals in that direction and your willingness to try to think about opening up new markets for both gas and then ethane as well as the propane side.

Well this is John. Let me – I'll talk a little bit. Then I'll let Jeff and Rodney chime in a little bit. Again, back to the Marcellus, we've been thinking about kind of markets and where we want to be for a number of years now and we've got a great team in Pittsburg, very high quality team that's been in the basin for many, many years. That is directing us on the ground for us and a couple of things. One, just picking the right partners to do the midstream on and I think we've done that feel very good about it. We're not burdening our capital or our balance sheet with those – they're paying for and ultimately we'll a fee, transportation and compression fee to get those volumes to the biggest pieces of the pipe. Once you get to the get to the bigger pieces of pipe and the good news with that is there is a lot of big pieces of pipe running around in Appalachia. I think five of those seven largest gas pipelines in United States went right through the Marcellus shale play. So you've got the big tow roads. So it's really a question of just building the feeder roads onto the tow roads. That's much different in the Barnett where we had to build several big tow roads to get it out of the Fort Worth basin. So that's a plus. As you think through that, we have taken some firm transportation of several pieces of pipe. Our strategy again is simple, is that we want to be able to have flexibility and move our gas to different areas in Appalachia. We don't know like a lot of people where all the gas bottlenecks are going to be over time. So…

Well I think we would want I mean again that's a rough question, but we would want at least half of your gas to be on firm and what we also want to do is develop relationships with these other big users of gas out there. What's happened in the basin and I am getting into the weeds a little bit but I think it's important and then historically the basin never, another producers in the basin ever produce large quantities of gas that some of these big end users could use. So, they want to these marketing companies are aggregate and the gas to them. That's all changing now and now they are coming to our range and some of the other big players in the Marcellus again be able to deliver large quantities of gas. So, and still are going through some of the aggregate is not even go directly to the end users and I actually like it because they get a much more of a connection and where the gas is coming from and they can quite frankly, because to some degree you are cutting out the middle-man, you can get better deal off of your gas on both sides of equation. So, I think it's a combination of having your own firm transportation but also having the relationships in the contract for some of the big users. Again it's a portfolio effect and then we will have some of our gas uninterruptible because again you don't want to have too much firm transportation. So, I think it's a portfolio, understanding where the end users are and the other thing is that marketing gas in the Southwest is much different than in the North East. The Southwest has a lot more pipeline infrastructure than the North East, especially the gathering side and that's where Rodney and the team up in Pittsburg have done a terrific job of really taking through that and putting us where I think is in a superior position.

From a simple point of view it just has a big advantage still versus gas and the Rockies or gas in the Gulf Coast or in South Texas or wherever it may come from and you don't have to pay the transport, it's the biggest markets in the U.S.

, : : David Heikkinen – Tudor, Pickering & Holt: And then can you talk some about the JV side and to make an accretive deal one of the best ways to do that is to figure out acceleration and does that lean you towards an operator that actually would be picking up – you won't to want give up operator ship so – or do you or where you could actually – they could bring rigs to part of the play or something that's not going to be as important to Range or is it just purely the financial that comes in and gives you the capital to allow you to double the rig count or really do an acceleration of well count?

I think every deal is different and I think, we have talked both sides of that equation. People who just at least an argue and their main asset is money and then we talked to others that are dying to get into play there are very technical competent or quite frankly we're already in the play just want a bigger position and so we talk to both sides and continue to think through those and I think both of those are interesting in that regard I think you have hit the nail in the hammer. Obviously to the extent that we are looking forward to just money that's a different JV partner to the extent outside of the some of our core areas let's say we have got what I would call some fringe acreage that we could pull together with an operator that we have a lot of confidence then yeah it would make sense and argue to go ahead and take that acreage pool it with them and then must let 13 developer. As soon as – as long as our team had some kind of input into how you drill the wells and how design them, Whose drilling rig it is and that kind of stuff I could care less who is land team is putting together the units is really not all that important. It's really is how you drill the wells and design it and what not, so again I think both of those are different and its and our team we sit around for hours and hours and hours discussing those exact points. But why not let Jeff kind of bury in on that as well.

Exactly let me bury in a little bit, if you look at it we have run a number of cases looking at our developing our acreage position from now really through depletion. We run a number of scenarios of faster flow in between joint venture all kinds of different options and what we think maximizes our share price because that's what it is all about is doing good job be a good storage for the shareholders of which we are totally aligned with is because that's where the bulk of our network is. But to be specific the path we're on now we look at that constantly and periodically to optimize this. We are currently at 13 rigs by the end of this year we will be at 16, by the end of next year 2011, 24 and in our IR material we say the full development will be 50 plus rig but I mean if you look at the trajectory of 13 now going 24 to be simplistic about it cost 48 or doubling it again but potentially its early and we haven't said that yet and there will be a function of lot of things. We are along a path that we think generally it's a tremendous NAV on par or better than the thing that you see with some of the recent market like John said if you use the market transaction of a $1 striker you can pack to it like share prices more than double where we are today. You can calculate any devalues that are significantly high with that trajectory, so we are on high point on that thing, we are not on a full page but however we will look at any point in time are we going to be better by JV, we are doing with Southwestern did a few years back selling a piece off or partnering on some of our current acreages, where that might be fringed us, it might be core for somebody else. We will look at all those opportunities because clearly we want to pack them on values of our company. David Heikkinen – Tudor, Pickering & Holt: As we look at acreage values versus the joint ventures, for your assets you can get values that are 2X pretty easily what the joint ventures have been done on a value per acre and that acceleration case is probably the most compelling thing that we see in the Marcellus particularly given the size and scope of plays, why it is so important. Thanks, guys.

David I think just to reiterate, the one thing I would like to just put out there for everybody is there has not been any material acreage JVs done in the wet gas area and if you just think through the economics in the wet gas area and in today's economics even using the NYMEX curve for ten year for both oil and gas. Your acreage values in the wet gas area when you run the numbers and thus coming back and view all the stuff and all the hocks pocks and divide and whatever you want to call it. It's substantially hard, so you really need to careful when you are looking acreage values in the JV deals to think through kind of what makes sense in valuations when it comes to the wet gas areas versus the dry gas. So, that's my, I will get off the soap box and will get to another question.

: Dan McSpirit – BMO Capital Markets: Gentlemen, good afternoon, and thank you for taking my question. We have observed off late here gas companies chasing the oil story by buying properties in places like South Texas. Can you share your thoughts on this trend whether or not you think it is too late for some of these companies to change their stripes and if it is not too late, do we see range do the same to diversify its asset base at least in terms of the hydrocarbons produced or is that just a ridiculous thought?

Jeff let me start with some technical thoughts on that and then I will turn it over to John for more global thoughts. One when you look at range, one of the advantages we have is – we have discovered what maybe the largest gas field in the U.S. and now we have the dominant part of it plus we have maybe the best economies because of the wet gas part. Now, when you look at the growth opportunities we have and with that in passing 600 wells from the Southwest is de-risk over 12 or 13 piece to it already, with that kind of inventory in hand de-risk over 600 wells and like John said our first well was back in 2004. We are saying that we are going to be at 180 to 20 this year, 360 to 400 end of next year and with that kind of volume of 12 pieces with the opportunity that could be easily doubled at. I believe that in time we will break the Bcf to 2 Bcf per day. What I believe we have the best economics of almost any play out there particularly any gas play and again we had in liquid. So, we are in a great position, we don't have to chase things I think get our growth and get it at low cost. So, I think we have got a lot of multi-year baked in low cost growth of which we are ramping up rapidly approaching 50 rigs in order to capture NPV. So, that's a comment one, comment two would be, a lot of people are and we have been talking about this and we have a South team, that's out there looking at different plays. A lot of people we are talking about getting into…

: If you think about it kind of simplistically, if I were out in the acquisition market today and going to buy reserves what would I buy. I got to tell you I would then buy gas, not oil because I think oil is trading at the high end and gas you are getting at trading at the low end. Again I think some why Exxon bought XTO. They thought they were buying a resource base that was at the lower end its long-term of view of gas I mean prices and the NYMEX curve, I am not talking about this year but if you look at NYMEX curve for 10 or 20 years it would suggest that. So, if I am buying reserve today I am buying natural gas versus oil. On the other side if I had a big oil field and if I had two places to spend money and one was oil and one was gas I would simply run the economies, figure out which one is going to generate the highest return over the period of time and do that and I have the same company and our friends in Newfield shifted some of their capital dollars over to existing oil fields they own and are seeing up that development. I think that is very prudent and I think Newfield is a great company and I think it makes absolute sense, where I think what Jeff said is absolutely right though to jump out of lower risk projects and to jump, push your money in through dramatically higher risk projects chasing oil can be a two edge story. So, if you are good at that and it works you are going to over perform. But if you don't then you are going weigh you're underperformed…

Let me add one another technical comment, long answer to your question but it's an important question is and I just want to caution people on IP's, a lot of people talk about IP's are jumping to oil shale, I will use Eagle Ford for an example, and if you look at the oil part of the Eagle Ford very few wells in there and there are couple of high rate wells and as you come up in Eagle Ford from the dry gas window to the wet gas for the oil you go basically from a true shale to basically a carbonate and it's a black looking rock but when you look at the mineralogy's it's really a carbonate. And when you come up into the shallow part in fact there you have the Eagle Ford, (inaudible), and then Austin Chalk right and a fairly narrow package. When you look at those early wells and time will tell clearly you can get some high rates if you get into fracs there and now against the Chalk in fact some – like I said when you move the Eagle Ford out in some of the shallow areas basically it's a carbonate which is like things what a Chalk is and same family. So, there is no question if you get into the good fractured area you can get good and as it relates the question is long-term. Once you drain the fracture system what's the matrix going to feed into the fractures there and that's really going to tell the tale on what's the rate of return and the economies to your well. So, again those things may work, they may not work but I am just saying it's a different risk profile and the good news is given the inventory we have in the economies of our project even down to extremely low gas prices we can just stay focused on driving Marcellus up and keeping our cost down and improving our wells. Even as 250 gas and $60 oil, our Marcellus oil and wet gas areas in Southwest still generate a rate of return of about 35%. So, that we will stay focused on. Dan McSpirit – BMO Capital Markets: Got it. John and Jeff, I appreciate your thoughts. Gentlemen, that's all I have.

Thank you, Ladies and gentlemen this concludes today's question and session. I would like to turn the call back over to Mr. Pinkerton for his concluding remarks.

: :