Welcome to the Range Resources Fourth Quarter and Full Year 2010 Earnings Conference Call. [Operator Instructions] Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements. After the speakers remarks, there will be a question-and-answer period. At this time, I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, Operator, and good afternoon, and welcome. Yesterday, Range reported results for 2010, announced the sale of our Barnett Shale properties and announced our capital spending for 2011. We want to leave as much time as possible to answer questions today, so we're going to move directly into our speakers. On the call with me today 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. Let me turn it over to John. John?

Thanks, Rodney. Overall, we're very pleased with fourth quarter and full year 2010 results. On a year-over-year basis, fourth quarter production rose 18%, beating the high end of our guidance. Fourth quarter production averaged $541 million a day, a record high for Range. This also represented our 32nd consecutive quarter of sequential production growth. For the year, production rose 14%. Adjusting for the property sales, production would have risen by 19%. At year end, crude reserves totaled 4.4 Tcf, a 42% increase over 2009. This represented a reserve replacement of 931% from all sources. Our SG&A cost averaged $0.71 per mcfe, the lowest in our history. Our drilling program delivered 840% reserve replacement at a cost of $0.59 per mcfe. These results reflect selling properties which contained 189 Bcfe and removing 230 Bcfe due to the five-year development rule. Based on what we see to date, these look like some of the best if not the best results in the industry. We combined exceptional growth in production reserves with low find and development cost. That is the hard part of our business, combining high growth with low costs. Again, this performance is attributable to our high-return, low-cost drilling inventory coupled with a very talented and dedicated technical team. Importantly, once again, both production and reserves per share on a debt-adjusted basis increased by over 10%. At Range, it's all about per-share results, as we believe that is what drives valuation. From a financial perspective, we continued our disciplined and simple approach. Bank debt declined, while total debt rose modestly. Debt per mcfe of reserves declined both on total proved and on a proved developed basis. We ended the year with almost $1 billion of liquidity under our bank credit facility, and, importantly, as the largest individual shareholder of Range, I…

Thank you, John. Normally, I lead with the income and expense items and close with the balance sheet liquidity update. However, since we only renew our bank credit facility every four years and there's so much more to the new credit facility than just the 2016 maturity date, I'll follow up John's comments with some additional color. Also to allow more time for questions, I'll be very brief in my income and expense commentary, focusing primarily upon trends and first quarter 2011 expense guidance. The new Range bank group consists of 27 experienced oil and gas lending institutions, each of which employs one or more petroleum engineers to evaluate the borrowing base lending capacity of each company's proved reserves, and they do this twice a year. The bank engineers are deemed insiders, so they have complete access to all requested internal data as well as public data reported to the various regulatory agencies. The bank evaluate our cost figures, reserve replacement performance, the quality of our reserves field by field and, in many cases, well by well. Changes in the E&P company's bank borrowing facility can be an excellent barometer that signals changes in proved reserve quality, cost structure, capital productivity and overall business outlook. Accordingly, we were keenly interested in the bank's determination of our pre- and post-Barnett sale borrowing base. See, we view the Barnett as one of our core properties, but the banks view it as some of their core collateral. So selling an asset this significant can be problematic for both lender and borrower as these opposing views must be reconciled. The fact that 100% of our existing banks plus one new bank committed to a 33% increase in our borrowing base, from $1.5 billion to $2 billion, without the Barnett asset is a significant ratification…

Thanks, Roger. Now I'll turn the call over to Jeff Ventura, our Chief Operating Officer, to give you his thoughts.

Thanks, John. I'll begin by discussing our year-end reserves. Range's 2010 reserve growth was the best in our history and, I believe, the best in our peer group. We grew reserves 42% to 4.4 Tcfe with all-in finding and development cost of $0.71 per mcfe. Our drill bit reserve replacement was 840% at a cost of $0.59 per mcfe. Reserves per share, debt-adjusted, grew 32%. Proved developed producing reserves grew 25%. Importantly, this was accomplished despite removing 230 Bcfe of proved undeveloped reserves in our historical Pennsylvania tight gas sands in lower CBM locations. Although these reserves are still economic, given the great success we're having in the Marcellus and elsewhere, we do not plan to develop them within the next five years. It's important to note that not only did our 42% growth overcome removing 230 Bcfe of historic tight gas sand in CBM locations, it also overcame selling 189 Bcfe of reserves. Thus removing a total of 419 Bcfe and producing 181 Bcfe, we still grew 42%, and did so with peer-leading F&D. During 2010, we focused 81% of our capital on the Marcellus, and the results were excellent. Utilizing performance history from 139 Range horizontal wells, our average well was 5 Bcfe. At year end, our Marcellus PUD location to proved developed ratio was 1.9. This year, we will focus about 86% of our capital into Marcellus. Given the large derisk acreage position we have in the play, 2011 should be an exceptional year. Despite our plans to sell the Barnett properties, we expect that we will achieve double-digit reserve growth in 2011, even without the Barnett properties. We should also achieve approximately 10% production growth. We believe we will overcome the lost production that is expected to go with the Barnett sale. Current Barnett production is…

Thanks, Jeff. I'll now provide some more details for 2011. For the first quarter of 2011, looking for production to come in at 540 million to 550 million a day. The midpoint represents a 19% production growth versus the prior quarter, and, if successful, it will represent our 33rd consecutive quarter of sequential production growth. Range, like many other companies, experienced material freeze-offs and shut-ins production in January and February. The weather impact as we currently know it has been reflected in this production guidance. Assuming the Barnett sale closes at the end of April, our second quarter production will be lower than first quarter. Third quarter production should be back up close to the first quarter, and we anticipate fourth quarter production to be well-above 600 million a day. We anticipate unit cost to continue to decline in 2011 and refer you to the guidance that both Roger and I gave you previously. Getting back to the capital budget, given the high degree of operational control, we can and will remain flexible as to the capital spending. As you recall, we underspent last year's budget by $100 million and still exceeded our production and reserve guidance. The good news is that at $4.50 flat NYMEX gas prices, our drilling projects in the Marcellus, where we are spending 86% of our capital budget, generate over a 50% rate of return. It's pretty amazing. In summary, while the Barnett sale is a couple of hundred million dollars less than we anticipate, it is a significant catalyst for Range ramping up the funding for our Marcellus play, which, as I mentioned, has really robust returns. And it's also a catalyst for reaching a cash-flow-positive position in 2013. As outlined in our operations release that we released a week or so ago, our drilling program is off to a tremendous start, having recently drilled our best wells in the Marcellus and Nora/Huron, Mississippian Lime and the St. Louis plays. We are confident that we can once again deliver double-digit production growth in 2011 and are also confident that we can achieve this growth at a find and development cost of $1 or less. If we achieve our plan, it will be another value-creating year in 2011. That concludes our prepared remarks. Operator, why don't we open up the call for questions?

[Operator Instructions] Our first question comes from the line of Ron Mills with Johnson Rice. Ronald Mills - Johnson Rice & Company, L.L.C.: A couple of questions for you. You described the Barnett sale as almost one of your like-kind exchanges and able to really focus your activities on the Marcellus. Of the 86% that's being spent on the Marcellus, can you give a breakdown of what you expect to spend in the Marcellus versus the Upper Devonian versus the Utica?

Yes, let me take that question. Our focus is going to be almost all on the Marcellus. We're really encouraged by what we see in the Upper Devonian. We've drilled and completed a couple of wells. We're in the process of testing the second well. And the same with our first Utica well, which we disclosed this month also. So the first Upper Devonian with over 500 million per day and the first Utica 4 4 for a seven-day average. But this year, we're looking at, we'll probably drill on the order of, literally, just a couple wells in each this year to continue to look at the potential and derisk parts of our acreage. Our focus is going to be on driving up value in the Marcellus. That being said, I think you're going to see a lot more of our -- the other E&P companies in the area drilling wells through the Utica and through the Upper Devonian. So just like originally, it was Range alone leading the charge in the Marcellus and then several other companies coming in and help to de-risk our acreage. You're going to see the same thing I think happen with the Utica and Upper Devonian. And in the meantime, we're going to stay focused on driving up rates in the Marcellus. Like John said, we entered this year at 200, and we're looking at exiting the year at about 400. Ronald Mills - Johnson Rice & Company, L.L.C.: And from the Southwest to Northeast with the gathering system in line, is the Northeast going to have a bit more capital allocated to it this year?

Yes, it will be a bit more, but the bulk of our drilling is still going to be, by far and away, down in the Southwest and in the wet area. Ronald Mills - Johnson Rice & Company, L.L.C.: And lastly, on the production, you talked about the production ramp, John, the quarterly ramp including the impact of the sales. What was the split of gas versus NGLs on the Barnett sale? And as we look forward to that ramp, particularly as you get to the fourth quarter and into 2012, what should we expect your gas-versus-NGL component to be?

Rodney, do you want to take that?

We're running right now about 79% gas, and the Barnett was about 20% liquid. So we expect same kind of composition of 79% gas. The NGLs will be twice what the crude oil is as you model it forward. And then we can kind of give you guidance as we drill in the Southwest and the Northeast.

Yes, I would just suggest any specific modeling questions that you have that you call Rodney and his team. Ronald Mills - Johnson Rice & Company, L.L.C.: Perfect. And then lastly on the Mississippian, that's obviously become a pretty hot topic. You have in your last presentation about 15,000 acres in that play. Can you provide any additional color in terms of what your activity levels are in that area and whether or not you're still ramping activity? Because the talk has been that you all have had some pretty strong results in your early activity there?

Yes, we've had good success. We announced a couple wells that tested, combined, 807 barrels of oil, 298 barrels NGLs, and 1.3 million per day. So we're 1,314 barrels per day combined, 657 barrels each. And when you look at the play, and we have it in the appendix that's out on our website, you're looking at really strong economics, cost of those is about $2.1 million to get about 300,000 barrels, 80-plus percent rate of return. So we have a good position. We've added to our acreage position, actually, we're a little over 20,000 acres now. So we have a good position. But like we said, for this year, 86% of our capital is going to be going into the Marcellus. And out on the website, I think, we have a book that breaks out the remainder of the capital in the other divisions. And you're looking at a relatively small allocation for the Midcontinent this year. It will be 6% of our total budget. And the reason is a lot of our acreage there and in other areas is held by production. So we got a great position, a great team, and really, if you look at the Range wells, I think, they're some of the best wells in the play so far, if you look at not only IPs, but 30-day averages.

Our next question comes from the line of Biju Perincheril from Jefferies. Biju Perincheril - Jefferies & Company, Inc.: Could you talk to me about the well that you mentioned, the Marcellus well that you mentioned in the release last week and the 18 million a day? Was that drilled with any -- was there any change in how you drilled and completed that well? Or was that result a function of location?

Yes, let me talk about that well. Rod mentioned the Mississippian. So let me just talk about some of our wells in general, maybe give you a little more color for the wells that were in the operations release a week ago. Let me start with that well. That well, that was a standard, basically 2,500-foot lateral, eight-stage frac, sort of a plain vanilla well. And really I think what speaks to it is the quality of acreage that we have there and also as we continue to go up the learning curve and how to drill and complete. When you look at that well, that was a really important well with a step-out well in a Southwest part of the play. It was 35 miles from our core area in Washington County. So that's a big distance away. The well tested 18.6 million per day on a five-day test. It may be our best well to date, or clearly it's one of our best wells to date, so we're really excited about that. When you look at that well, stepping out 35 miles plus some of our drillings plus the industry's drilling and you look at our position in the Southwest now, we estimate about 85% of our acreage in the Southwest has been derisked through our wells and others. So it's more than 800 wells that have derisked and defined that area. So we feel really good about that, and those are the economics that John mentioned. And again, look on our website and various analysts show that the rate of return when you're in the Southwest during the core part, like a lot of our acreages have, perhaps the best rate of return anywhere in any play in the U.S., or it's clearly in the very tippy…

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

I have a couple questions. One, on the St. Louis well, the horizontal well, how many locations do you think you have on your acreage? Do you have any sense of that yet?

Yes, when you look at -- it's on the website and in the appendix. We actually have the locations that we have out there. And we think right now we've identified an additional 71 horizontal locations and six vertical. Plus we've identified other areas where we think that's perspective that we'll attempt to lease and pick up.

And what would your working interest be there, or was that a net number?

No, that was 100%. On the first well, our working interest was about 50%.

So that was 71 gross or net locations on that?

Those are 71 gross locations. Our working interest on average, we'll probably have to get you, it's probably better than that on average, because a lot of it is 100% when we drilled the first well, it was -- we drilled the less risky well on in place where we had a partner carry or take part of the cost. So we have, on average, the working interest is higher. We can get you that number and we'll give it to Rodney.

A couple more questions. On the $200 million to $250 million in additional sales, how much production is associated with that? I know your production guidance is net of the sales number, but I wanted to get a feel for how much production you're planning on selling and whether that was oil or gas.

Yes, Marshall, this is John. It's a combination, quite frankly, of a lot of the little property, some in Texas, some in Mississippi, Louisiana and some kind of some scattered acreage that we own. So it's really not all that much production associated with that. Because honestly, I don't have that number in front of me, but it's relatively immaterial.

You gave your gas price forecast with your cash flow assumptions and balance sheet assumptions for the next couple of years. What were your NGL assumptions that you used in terms of NGL pricing for this year and next year?

Well, first of all, that wasn't really my, or Range's, or John Pinkerton's, or Jeff Ventura's, or anybody's. It was really just the future strip price that we could have locked it in on when we did the runs back in, I think it was mid-February, a week or two ago. So it's really that price. I'll let you all determine what you think gas price is going to be in the future, you probably have as good, if not better, idea than I do. In terms of the liquids and the oil, we base that off $80 oil and then we base the liquids off that as a percentage just using historical references. Fundamentally $80 oil.

Our next question comes from the line of David Heikkinen from Tudor, Pickering. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: John and Jeff, just given your successful testing of multiple new areas in Texas and Oklahoma this year and what you've had, what's your success case CapEx for those areas in 2012?

Well, for 2012, we are going to stay really disciplined. We're going to stay focused on the Marcellus. Really what we're doing is spending enough money to derisk and understand the play. So the plans John laid out, I mean, there's an allocation of capital for those areas. But the good news is the bulk of all those areas are held by production, so we can really control the timing and such.

We're spending $1 billion, $1.38 billion, we said the same, but I would round it to, let's say, $1.4 billion. And I think we'll spend probably again, we'll spend 80% to 85% of our dough in the Marcellus with the idea that, that is the one area where we don't have most of the acreage held by production. And so that's one of the primary reasons we want to sell the Barnett, is to term out all those leases. We're about 46% held by production in the Marcellus, and based on the plan that I gave you, we will hold 700,000 acres through the plan. And again, that's what the resource potential numbers are based on and everything else. So it all kind of ties together in terms of method to the madness. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: So then if you think about the focus on the Marcellus as you think about improving efficiency, improving plant capacity and as your cash flows grow and you have the debt capacity, I'm trying to understand why you wouldn't then accelerate into an improving efficiency in the Marcellus. Where are the governors there? As you get the cash flow growth, it seems like your CapEx could go up with it.

Well, hopefully, what we can do is spend more for less or keep it the same and get more out of it. And quite frankly, that's what happened this year and that's what happened last year, and that's what we're expecting for 2011 and a little bit of 2012 as we move forward. But again, I want to walk the walk before I talk the talk. So as we see those improving metrics, we'll deliver them to you. I mean I think in the overall sense, we've delivered pretty fantastic reserve growth at really low numbers. And I think if we can do $1 or less find and development costs for this year and next year, you're going to see our DD&A rate continue to go down. You're going to see our LOE rate continue to go down over time. And I think that's really the proof in the pudding, and it's interesting. I looked at what you all put out in terms of the four key criteria, which was make money in the current environment. And we really think that's important, too, is to be able to make money in a $4.50 or $5 environment. And that's where I get back to this whole thing where I think your DD&A rate and your LOE need to be about $2 to $2.25. So I think we're getting there. Your second point was focus on costs, we're really, I think more than anybody else, we're cost-focused. And then third, obviously, invest in the highest-return projects. I mean simply, and I've got a lot of questions today on the Barnett and have had over the last month, it's really simple to me, we've got drilling locations in the Marcellus that at $4.50 gas generate over a 50% return. Those same drilling locations…

Absolutely. That's a great way to characterize it. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And then, as I think about each of those other areas where you're just spending that 14% of your capital, how do those get sold? It seems like they're just naturally lined up for recapitalizing and selling small amounts of acreage production and the like. I mean, what's the time frame to appraise this?

Well, like what Jeff said, the good news is almost all of that is held by production. So there's really no -- we don't have a gun to our head in terms of having to develop it. I know it's hard for some of our listeners to really imagine, but in 2013, once we get to positive cash flow, when you look at '14 and '15, at least our numbers suggest we're going to be throwing off a whole lot of cash flow. So we're going to need projects like the Cana, projects like the St. Louis, projects like the Mississippi and Lime, some of the other projects we're doing out in the Permian. We're going to need those projects to continue to fuel our growth. That being said, I do think over time, just like anybody does, if somebody comes and makes us a great offer for one of these projects and we think it's NAV accretive, we'll take a hard look at it. So we try to be flexible, we do try to keep in terms of how we run our business -- fundamentally, it's really easy. Jeff and I and Roger really view our jobs as we allocate capital, and as we see it, we try to allocate capital to the highest-return projects each and every day. We still sign every AFE in this company over $200,000, all three of us still sign it. So we've got our hands firmly on the steering wheel. We think we've got a very good view on what drives value, and we got some really, really good people that are drilling some really, really good wells. And at the end of the day, we think that will all wash out, and we'll have top quartile performance. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Just one final question. As you think about management compensation, you've tied management compensation to debt-adjusted growth rates and efficiency. Do you adjust your debt-adjusted growth rates in the baseline whenever you sell assets? Or do they remain in that base and then is it off an annualized number?

What we do -- our compensation committee looks at our budget and our projection for the year, and that's the baseline. And to the extent that if we sell something after that baseline has been developed, then we have to live with that. But again, that's part of it, and we'll have to live with it. But as I tell all the management, that's life in the big city at Range.

Our next question comes from the line of Scott Lamont [ph] with Simmons and Company.

Just thinking a little more specifically about the Marcellus acceleration. What level of rig activity are you guys planning in 2012 to get to the 25% to 30% growth? And can you give me the split between Southwest and Northeast?

Yes, if you look at 2012, we're looking at a total of 17 rigs. And then you have to add the Talisman too, though. See, there's 17 Range-operated rigs. We will have 12 in the Southwest and five in the Northeast, and then two that get add the Talisman piece, the Bradford County stuff.

And your total in '11 is what?

Total in '11, we expect to end the year in '11 at 14 plus Talisman. So currently, we are at 13, we'll end this year at 14. We'll end '12 at 17. Talisman is currently at two. We expect them to end the year at four, and they should have four in 2012.

Can you give us an update on current well costs in the Marcellus, what your expectations are throughout the year and then kind of what's baked into your CapEx?

Yes, we can talk about that. When you look at, we really have three types of wells. And let me talk about them conceptually and I'll give some more specific numbers. You've got development wells in the Southwest part of the play. Then you've got step-out wells in the Southwest, and then you got wells in the Northeast. And then eventually, you'll role into that same category there. When you look at a development well, a pad well in the Southwest, we're approaching $4 million, like we said, in the development mode. Current AFEs are actually $4.2 million, so we're getting pretty close. And then when you step out, like I said I mentioned a well earlier that's made just over 18 million a day, 35-mile step-out. When you step out, those wells are going to be a lot more expensive. One, you've got -- instead of allocating the pad over multiple wells, it's on one well. When you drill step-out wells, you typically, you may cork part of the well, run a bunch of micro-seismic, run a bunch of experiments and all those kinds of things. Plus you aren't allocating the water impoundments [ph] and rows and stuff across multiple wells, either. So those are two kinds of wells. Then when you go to the Northeast in Lycoming County, the wells are roughly 2,000 feet deeper. So when you look at current drilling, we're looking at, for this year in the Marcellus, we're looking at 195 wells, roughly. That's our expectation of that. 172 would be in the Southwest, 23 in the Northeast. If you look at the average of the 4.2 plus the higher-cost step-out wells and delineation plus some science, those wells are going to average on the order of 4.4 million probably per well in the Southwest. And you could add roughly 1 million for the wells in the Northeast. And I expect with time, literally, again, if you go back and look at what we have, 85% of that acreage in the Southwest has been derisked, so when you look at our acreage position, you use 80-acre spacing there and you use -- and just assume 80% of the acreage is drilled, that's over 4,600 wells in the Southwest. I guarantee you, with the technical team we have, when you let them drill year in and year out over, literally, thousands of wells, I have high hopes that those guys are really going to drive those costs down dramatically from not only where we are today or our expectation, of course [ph] they'll break through that. Sort of what John was saying earlier, there will be a lot of capital efficiency gains that will come with time, and I believe the same thing will happen up in the Northeast also.

Great, I appreciate the color. And lastly, just can you give us an update on your acreage swaps, how much of those are ongoing? Do you continue to expect to do them in 2011?

What has gone on in the industry up there is that all, I think most of the companies that come to the conclusion that the key to life is blocking up your acreage, because you can gain -- that's where you gain these efficiencies. If you have to drag rigs all over creation up there and then your pipelines, and your gathering, your water, impoundments and your water gathering it really drives up your cost. So I think most people, like us, and you learn it just by doing it, you learn that if you can covey up part of your acreage together, you really drive down those costs. So I think that's -- the good news is we've had a number of discussions and continue with the industry participants up there. And we actually see the attitude for doing acreage swaps actually increasing dramatically. We've had a number of meetings with companies that heretofore weren't too keen on it, but I think has realized what the potential is, that it's really good for both sides. And the good news now is that some of these other companies, I think, quite frankly, the reason they didn't do it is because they probably, to some degree, viewed that we had a technical competitive advantage. So they were a little bit fearful. I think now, they drill the number of wells, their own technical teams have confidence in what they're doing. So it's really just trying to swap acreage, in most cases, like-kind for like-kind, but even when they're pretty far away I think there's a pretty good reasonable expectations in terms of quality of the acreage. So the ability to use that as currency, both from an add-to perspective and then have a technical understanding of it, I think has gone…

Our next question comes from the line of Mike Scialla with Stifel, Nicolaus. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Question on the southwest part of the Marcellus play. Jeff, those 11 wells you talked about that you think now are exceeding an EUR of 6.5 Bcf. I'm trying to get a sense for if you think that's a good average going forward. So can you talk about where those were drilled, were they in one concentrated area or were they scattered across your acreage? And then it looks to me like you booked about 4 Bcf a well in the southwest part of the play. I want to know if that's right. And then how do those numbers reconcile?

Those wells, some of them are off the same pad and some of them were scattered. And I think it's a reflection of the quality of the acreage. So those wells -- those 11 wells look like they're better than 6.5 Bcf. Our best well, just to remind people, is probably about 10 Bcf. So there's definitely high-quality Wells on our acreage and around our acreage. So I feel good about that. I think what we like to do, and Alan Farquharson that runs that effort for us, we book reserves, and then we like to just watch performance with time. And to the extent we see those wells year after year coming up, you'll see those increases in there. And that's the way we'll march forward. Actually, again, referring you to our most recent IR presentation, it's on the website. Rodney's looking for it. There's actually a graph that shows every single horizontal well we've drilled with time in the form of a zero-time plot. So you can see the performance coming up with time. And it's on Page 18 of the current IR presentation you can see on the website. Yes, you're right. I mean with booked, when we book some of those puds and stuff, they're booked at a lower number. I expect with time as we continue to drill them, and I'm hopeful, that we'll continue to see that positive increase that we are seeing. Michael Scialla - Stifel, Nicolaus & Co., Inc.: That's fair. Did you do anything differently? It sounds like you're leading us down the road that 5 Bcf is probably not going to be the last of those curves on that Page 18, that there's another step up to be anticipated down the road.

I think there's two things to look at. One, can the guys do things to improve performance to them. I'm really convinced in time, we'll do things to drive down cost. And at the end of the day, it's really about rate of return and repeatability. Again, we've got at 80-acre spacing, using 80% of the acreage, 4,600 wells to drill. And when you look on that same presentation on the website, you can see what our current rate of return is for those wells and we did it fully loaded as well, taking all the lands and the corporate G&A and putting it all on an individual well. That's on Page 15. So we've got strong rate of returns, even if we don't change what we currently have, at $4 gas, the 5-Bcfe well currently is 74%, fully loaded is 58%. I believe our team is going to do better than that with time, but those are pretty strong economics. Plus, medium to long term, personally, I think gas prices are going to be better than $4. You go to $5, you're approaching 100% rate of return.

This is John. I think just to be completely transparent, there are some people who view the Marcellus as a mature play. In some respects, it's still, compared to the other plays out there historically, it's still -- you'd have to put it in the relatively new category. There's really very few wells with over three years' worth of production. I think most of them, or nearly all of them, are our wells. So with all that being said, these 11 wells are pretty exciting. And I think we got a really good team that's executing, but 11 points is not what I'd call a huge statistical sample. So I think what we're telling you is that we're off to a great start for 2011. We drilled some really good wells. Stay tuned. We'll keep you up to date. We'll continue to post on that chart every single well we drill and do that zero-time plot. So we'll all get to see it realtime, and then we can, over time, we can look at it and see whether this ought to be 5 Bcf, 5.5 Bcf, 6 Bcf, 6.25 Bcf, 7 Bcf, I don't know where it's going to end. And the other thing about it is...

But again, I'd re-emphasize, if it ends where it is today, it's pretty darn good. And according to some people, right where it is today, it's the best play out there, including some of the oil plays.

I agree. So at the end of the day, we're in great shape. We'll be as transparent as we possibly can in terms of laying those things out for you and letting you all decide whether you think they're going to end up -- we got a view, but I think it's important, we're going to be -- we're going to keep it the Range way. We're going to start out, and like Jeff said, Alan Farquharson, who runs our reserves, is a very talented guy. And one of my views in life is, you want to have modest, upward performance revisions every year. I don't like it when we have negative performance revisions. Doesn't make me feel good. So we're going to take that position, and it's something that's just built into our culture and our DNA. Michael Scialla - Stifel, Nicolaus & Co., Inc.: I want to ask one quick one on the Upper Devonian. It seems like you may be a little bit more optimistic on that than Utica at this point. One, I wanted to see if that is a fair statement. Then secondly, I know the Upper Devonian is pretty widespread in Appalachia. That 10 Bcf to 14 Bcf of potential you talked about in that formation, do you think you've identified an area where the Upper Devonian is different geologically than most the rest of the basin? Or should we -- could you extrapolate those kind of numbers to a broader area?

On the Upper Devonian, I'd characterize it this way. The Upper Devonian -- the Marcellus is a Devonian-age shale, and it's at the base of the section. So when we drill to the Marcellus, you drill through the Upper Devonian. So we've got over 200, between the vertical Wells and horizontal Wells, over 200 of our own control points plus a lot of other control points in the basin. So we've got good data, pretty good data, in terms of well logs and gas shows and that type of information in the Upper Devonian. The neat part is our first well in the seven-day test made over 5 million per day. And now, we frac the second one and we're flowing it back. And then if you look at the Utica, the Utica's 2,000, 2,500 feet deeper than the Marcellus. And very few wells in the basin go to the Utica. So by definition, the Upper Devonian is lower-risk, there's a lot more control, a lot more data than in Utica. Plus, it's somewhat of an advantage in that it's shallower. So the wells are going to be less expensive. The other thing you mentioned -- so I feel -- so from that perspective, you have to feel better about, on a risk basis, at this point in time, the Upper Devonian. But it's early, and I'm sure there's going to be a number of Utica wells drilled this year by others plus the couple of wells we may drill. The other thing, we've mapped all these plays all over the entire basin. When you look at the Upper Devonian and the section we're talking about, it does not cover the entire basin. It's more specific, we feel, based on our mapping, sort of towards the southwest part of the play is primarily where it covers. So you don't have, when you look at all the things that you need for shale play, and you look at the gas shows and you look at the logs, primarily that's where we think it's perspective. We've mapped it. We've looked at -- we've mapped gas in place. We've applied reasonable recovery factors. Those are the reserve numbers that we came out with -- or our resource potential numbers that we came out with earlier this year. So that's what it’s based on, but it does not cover a widespread area. And relative to the basin it's unique more to the southwest part of Pennsylvania -- southwest, west part of Pennsylvania. Michael Scialla - Stifel, Nicolaus & Co., Inc.: I guess just one quick follow-up on that, too, is that well you said you had, it looked like it was overpressured. Do you expect that for most of your acreage in the Upper Devonian?

Yes, for the acreage and where we feel with perspective, the answer would be yes.

Our last question comes from the line of Dan McSpirit from BMO Capital Markets.

Recognizing it's not core to the Range story, but can you revisit the horizontal Huron shale well, specifically the depth and pressure as well as how the success rate of 2.6 million a day, I believe, compares to others, either horizontal or vertical wells and what this means for an EUR? And whether or not that rate is repeatable, or is it all about finding the virgin pressure?

Well, when you look at that, the Nora area is an important part of our company, it's a stacked-pay area, a lot of hydrocarbon in place specifically in terms of the Huron shale. There's been great success with EQT on the Kentucky side. And we, Range, led the way on the Virginia side, I believe, drilled the first horizontal Huron shale in Virginia. And all of our Wells have been in and around Nora. We picked up the acreage last year. North of there are extension properties that we acquired for $130 million. And we were pretty excited about it because, one, it's very sparsely drilled, but it's in the center of a giant gas field which ranges all the way from Virginia and Kentucky on up into West Virginia. But when you look at the acreage we picked up, it was very lightly drilled. But there were penetrations that went through the Huron Shales, we knew the Huron Shale had gas in it and had good thickness and all those characteristics. But what you never know until you drill it is sort of rock quality. So we drilled our first horizontal well in there, and the wells are roughly 5,000 feet deep, plus or minus. And we got a well at 2.6 million per day. That a typical Nora well probably on average is a little under $2 million per day, maybe around $1.8 million. Our better ones, take the high-end ones, they were up in that range. But most of them on average are probably 500,000 a day or 700,000 a day less than that. Those wells look like they'll make on the order of Bcf cost somewhere around 1.2 million to drill and complete. And so what's exciting is we have good control. We got good thickness. The rock quality up there looks a little better. It's more fractured, maybe more like Big Sandy is in Kentucky, the difference being that we're at virgin pressure because it's never been developed, where Big Sandy was developed back in 1920s, 30s, 40s and up until present day. So you have -- pressures there are a lot lower. So it's an important well and, like I said, it could add resource potential 400 to 500 Bcf net to us. Again, we're only a 4.4 Tcf company at year end. So that's a big number. And I think those numbers will grow with time.

And then turning to the Marcellus for two more questions here. If by the end of this year, 46% of your acreage will be held by production, what does that mean? What is that number at year end next year?

Well, currently we're at about 46%. I'd say, around the middle of next year, the number will, by the end of next year, will approach 60%. And literally, within a year or two after that, we'll be up into the 80% range. Remembering the number's probably never going to be at 100%, because it's a great play, and you're going to be picking up leases and renewing and trading. So we're well on our way to drilling and holding what we believe, like John said, will be 700,000 acres. And the important part again with the acres is what's perspective for us in the Marcellus also captures the upside and resource potential that we laid out for the Upper Devonian. We'll capture all of that and then whatever there is in the Utica blow. So far, we are encouraged there's gas down there for sure. And the other thing with the Upper Devonian, before I leave it -- I'm trying to give you a little color. The neat part about our position in the Marcellus -- not only do we have great acreage position, a large position with high quality, a big part of it is in the wet gas area, which clearly helps with today's economics. The Upper Devonian is going to be like the Marcellus, The wet dry line will be like the Marcellus. So where our acreage is wet in the Marcellus, most likely the Upper Devonian will be like that. So you get the liquids uplift as well. But let me put that in perspective, if you look at -- and this is out on Slide 19, you'll see it in the book, we're seeing the resource potential just in the Southwest and the Marcellus, 15 to 23 Tcfe. If you break that down, that's 13.5 to 20 Tcf of gas and 307 to 463 million barrels of liquids. So that's really like a giant oil field right there. And then you can add the Upper Devonian and liquids to that on top of it.

I understand, and one last one, if I could. Forgive me if this question has already been answered. Given the gross proceeds from the Barnett shale asset divestiture, where does this leave us with respect to a JV? How does that rank now? Or is that no longer relevant? That is, a JV on the Marcellus Shale acreage?

Well, I think the Barnett sale tells you a couple things. One, we felt like selling the Barnett was much more accretive than doing a JV in the Marcellus. And I think that's pretty easy math, and I think it's pretty easy to understand that. Now what we try to do is connect the dots and show you that at least we believe that we can be cash-flow positive by 2013. And I didn't mention the word JV in any of those discussions. So again, what the Barnett sale does, it gives us a rock-solid balance sheet, irrespective of where gas prices ago, whether they go to $0.50 or $10. And it allows us to really ramp forward the Marcellus at a much faster pace than we went last year. And we're going to go from $200 million a day to $400 million to $600 million, that's about as the fastest ramp-up as one could imagine in these plays on a relative basis. So it allows us to ramp up, but really what it does, what it also does, is allows us, at least we believe, if we stay disciplined, to be cash-flow positive by 2013 and retain 100% of the resource potential from the Marcellus, the Upper Devonian and the Utica for Range's existing shareholders. I'm in the business, I'm an existing shareholder. I still think I'm the largest individual shareholder. Where I'm really focused and anchored is I want my existing shareholders to get as much of the resource potential you possibly can out of this Marcellus. And I'm telling you, it's a world-class field. We've got the tiger by the tail. The good news is I think we've got a plan, and I think hopefully that we connected the dots. And therefore, you're going to see how…

Ladies and gentlemen, we have run out of time for questions. I'd like to hand the call back over to management for closing comments.

Well, on behalf of -- this is John Pinkerton. On behalf of the Range management team, Board of Directors and employees, we really appreciate you all being on the call today. We had, at least in our view, a very, very solid and value-creating 2010. We are pleased as punch to have the Barnett sale inked up where we could connect the dots for everybody, because I know I get that question -- that's the question I get from all the shareholders, and I really appreciate that. Hopefully, we've done a good job of connecting the dots. I know there were a number of callers that didn't get their questions answered, or if we need to connect a few more dots for you, feel free to call any of us, including Rodney and his top-notch IR team, and we'll try to do that. At the end of the day, regardless how you feel about the Barnett sale, we think it does two things. One, it allows us to ramp up development in the Marcellus in a big way. And two, it allows us to be cash-flow positive by 2013, which is just right down the road here. And we think those are two huge catalysts for our company, and really exciting catalysts. And then, obviously, to the extent that the other plays that Jeff talked about continue to fruition and some of the other things we're working on, I think the future for Range and shareholders is really bright, and we look forward to a terrific 2011. We are off to a terrific start, and we'll look forward to giving you another update in April when we have the first quarter results. So with that, we'll sign off. Thank you very much

Ladies and gentlemen, this does conclude today's teleconference. Thank you for your participation. You may disconnect your lines at this time, and have a wonderful day.