Welcome to Range Resources Second Quarter 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. Good morning, and welcome. Range reported results for the second quarter of 2010 with record production and reduction in our unit cost in most of the major cost categories. Second quarter marks our 30th consecutive quarter of sequential record production growth. As our operations continue to become more efficient, we're able to spend capital more efficiently and realize greater returns. Range is committed to maximizing per share growth values as we grow the company. I think you'll hear the 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 with the SEC this morning. It is 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 non-GAAP measures of cash flow, EBITDAX, cash margins and the reconciliation of our adjusted non-GAAP earnings to reported earnings that are discussed on the call today. We've also added tables, which will guide you in forecasting our future realized prices for natural gas, crude oil and natural gas liquids. Detailed information of our current hedge position by quarter is also available on the website. Second, we'll be participating in several conferences this August. Check out our website for a complete listing for the next several months. We'll be at Tudor, Pickering Energy Conference on August 12 in Houston, energy conference in New York on August 18 and the EnerCom 15th Annual Oil and Gas Annual Conference in Denver on August 23. Now let me turn the call over to John

Thanks, Rodney. Before Roger reviews the second quarter financial results, I'll take a little time to review the key second quarter accomplishments. On a year-over-year basis, second quarter production rose 9%, materially beating the high end of our guidance. If we adjusted the asset sales, first quarter production growth would have been about 13%, 14%. This marks the 30th consecutive quarter of sequential production growth as Rodney mentioned, and obviously a great milestone for our company. After closing the Ohio sale, right up into March and losing roughly 25 million a day of production, our analysis indicates we would not overcome the entire Ohio loss in the second quarter. Therefore, this would stamp our record consecutive record of production growth. However, our operating teams proved the analysis wrong, and made it happen, our growth record continues, which I'm ecstatic about. It's truly a team effort with all of our divisions that are contributing. The Marcellus division was the largest contributor as they continue to drive up production by drilling outstanding wells. The 9% increase in production was more than offset by an 18% decrease in realized prices. As a result, second quarter natural gas, NGL and oil revenues were 11% lower than the prior period. We are most pleased on the cost side. On a per-unit of production basis, three out of the four of our major cost categories were lower than the prior period. Direct operating cost came in at $0.68 per Mcfe, that's 21% lower than the prior year period. DD&A expense per Mcfe came in 6% lower than last year, while interest expense per unit saw a 4% decrease. G&A saw a $0.07 increase over the last year. As you all know, we're still building out our Marcellus team and we'll continue to see the impact for…

Thanks, John. The second quarter of 2010 is setup to be a bit of a sequel to the first quarter this year. Production against all odds and asset, hit a new record high and we completed the sale of our Ohio tight sand gas properties. Also like last quarter, direct operating costs were again reduced on both in absolute and unit cost basis. Natural gas, NGL and oil sales for the second quarter, including cash settled derivatives totaled $217 million, down 11% from last year, a 9% increase from falling production over last year could not overcome the 18% decline in realized prices. Now year-to-date, natural gas, NGL and oil revenue including cash settled derivatives totaled $450 million. Cash flow for the second quarter was $129 million, 17% below last year. Cash flow per share for the quarter is $0.82, $0.01 below the analyst consensus estimate of $0.83. Lower realized prices caused that $0.01 variance. Year-to-date cash flow totaled $277 million. EBITDAX for the second quarter is $156 million, 15% lower than the second quarter of last year. EBITDAX for the year-to-date period was $332 million. Even though cash expenses were 6% less than the second quarter of last year, an 18% lower realized Mcfe price reduced our cash margins to $2.92 per Mcfe in the second quarter. In order to better equip analysts and our investors to make estimates of our natural gas, NGL and oil price realizations as Rodney mentioned, his team has done a great job and they put three new financial guidance tables, those appears as tabs numbers six, seven and eight up there on the website under the Quarterly Supplemental Financial Tables section of our Financial Information portion of the website. So please feel free to contact Rodney or me with any questions you have…

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

Thanks, John. I'll start the operations update with the Marcellus Shale. As we get more production data from our horizontal wells, the high-quality nature of the wells is being confirmed. Our midyear estimate for all of our horizontal wells that are online averages 5 Bcfe per well. Updates of our zero time slots have been posted on our website in the current company presentation. The five Bcfe average is based on 95 horizontal wells that all have greater than 30 days of production and they're all in the southwest part of the play. Our estimate of reserves per well per acreage has been 4 to 5 Bcfe. To date, we are clearly at the high end of that range. In the southwest part of the play, given our current average lateral length of 3,050 feet with 10 frac stages, our completed well cost is about $4 million. The rate of return for our wells in Southwest Pennsylvania, which is in the wet gas area, assuming that we spent $4 million to get 5 Bcfe and that the gas price is $4 dollars per Mcf flat forever is 60%, and $5 flat forever, the rate of return at 79% and that's $6 flat and increases to 100%. I believe that this is one of the highest, if not the highest rate of return gas play in the United States. Again, the qualifiers that we are drilling in the core portion of the wet gas area of the play in the Southwest Pennsylvania. By far, Range has the dominant position in this area. The buildout of the infrastructure continues on plan. We currently expect crowd capacity will be increased by MarkWest from $155 million per day today to $350 million per day by the second quarter of 2011, and then up to…

Thanks, Jeff. Terrific update. Before we look to the remainder of 2010, I'll spend a few minutes in summarizing of what we we've accomplished so far in the first half of the year. As we discussed production in the first half exceeded expectations, due to better-than-expected drilling results, and due to these results and the small Virginia acquisition, we're increasing our production guidance for the year from 12% to 14% and this does include the impact of the asset sales. On the cost side, we continue to drive down our unit cost, in particular the reduction in direct operating cost and DD&A are particularly encouraging. The good news is that these are not onetime events. We expect the unit cost to continue and decline in the quarters ahead. Another significant accomplishment was completing the Ohio sale earlier in the year, when gas prices were higher and by completing the initial closing in the first quarter, where we're able to lock down our drilling plans for the year. Next, the Virginia acquisition we completed in June couldn't have come along at a better time, and we're excited about the potential of the properties as Jeff has mentioned. Acquiring the properties at good prices and using the 1031 account proceeds were the home run. As I've said many times, I love the Nora area. It is our Energizer bunny and that it keeps on going and going and gets better and better. The most significant achievement in the first half of 2010 is clearly the progress we continue to make in the Marcellus Shale play. As Jeff mentioned, our well performance continues to improve, our returns continue to improve. The infrastructure buildout was right on track, the quality and depth of the field service partners continues to improve, and the regulatory environment…

[Operator Instructions] Gentlemen, our first question is from Dave Kistler with Simmons & Company. David Kistler - Simmons & Company: Real quickly, just following up on your last statements there, John, with the increase in CapEx for 2010 and a lot of that tail end with the year CapEx flowing through the production in 2011, can you talk a little bit about maybe what we should be thinking about for CapEx in 2011, flat versus up substantially from 2010? And then as you mentioned, kind of a pass to free cash flow neutral, had that pushed this out in any way, shape or form at this point?

We're just in the throws of putting together our 2011 analysis, and we're going to share that to the board in September, and then what we normally do is, based on our comments, finalize that in December. So that's what we'll do again this year. I think it's too early to tell in terms of where we're going to be. Obviously, we'll be sensitive to where natural gas prices are. Historically, it's been a pretty easy playbook and that we've taken cash flow and asset sales to fund the bulk of our capital. And then we try to use debt and equity securities at the high end, at the end of it, and then obviously, the equity side is the very end of it. And we'll continue to do that. So it's just a little bit too early to look at 2011 in my mind. But again, the good news is that we're really driving down the cost per unit, so we'd be able to do more with less. The other thing, I think, is really, really important is if you kind of step back and look at this from a kind of NAV per share perspective, and we're running models all the time to try to figure out what's the best way to drive up our NAV per share. And that's really what we're all focused about. And we've run a ton of models on the $210 million that we're going to spend this year, and we're actually convinced it's the right thing to do, and we'll do the same thing for next year's capital budget. That being said, we're going to tee up some more asset sales for this year. John and his team are already worked at that, so we'll try to look at that. And obviously, asset sales for 2011 will be a big part of the plan as well. So that's kind of where we stand. David Kistler - Simmons & Company: John, following up on that, you mentioned as part of the sales in your prepared speech the possibility of selling production. Did you mean that outright in terms of doing maybe a volumetric production payment to be able to accelerate cash from that to then reinvest in accelerating the NAV out of the Marcellus, or am I reading too much into that comment?

Well, I think the asset sales are being more along the lines of what we've historically done. One of the rules at Range is because they try to keep it simple, and production payments, at least in our view, are highly complicated. They really trash up your balance sheet, and it creates a lot of legal documents that you have, like the lawyers running around and review all the time, so that those aren't things we think are productive in the long-term trying to run a business. So we're going to stay away from production payments for the most part. We've got, I don't know what the total number is, but roughly 130 million, 150 million a day of production that's not from our big three. And we'll continue to take a look at that and high-grade that and look at the more marginal higher costs up. Just like what we have in the past, we'll continue to sell that stuff off and help generate proceeds. So I don't think there's going to be anything fancy that we're going to come out with. Like I said, we're not going to try to douse you with some kind of new, financial trick of the trade here. We're going to stick to our knitting, we're going to stick to what we've historically done. And again, I think there's a lot of different ways to spending the cash. If you look how Southwestern did what they did, have done, we obviously studied that quite hard and some other things. So we'll continue to look at things, and at the end of the day, again, the one thing that you can, I'll put the stake in the ground, so to speak, is whatever we do, we'll look at all the alternatives, and we'll pick the one that generates the highest NAV per share. So whatever it comes down to, that'll be the stake in the ground. David Kistler - Simmons & Company: Looking at the uptick in 2011 Marcellus gas production, can you guys give us a little bit more of a breakdown in terms of southwestern production, northeastern production, is that larger number just being driven purely by the efficiencies or should we expect maybe the Northeastern gas to be coming on sooner? And then as a follow-up to that, just I know you guys are in the process of putting a propane line in place, so obviously, NGLs across that whole area would increase production like yours is going higher, where are we on that propane line and is it on schedule, et cetera, et cetera?

So let me talk about the production a little bit. We're not going to -- the bulk of that is going to be coming from the Southwest. That's the de-risk area. We're really building out a lot of infrastructure. What we got, the liquid ridge part of it, so all of that is going to be where the bulk of our drilling and bulk of production is. However, by the end of this year, we expect we will get production on from the Northeast, so that will start to contribute. But if you look at our acreage, 900,000 acres that allows us to grow significantly from where we are on the order of 8x over just from the Marcellus, the bulk of that acre, 600,000 of that is in the Southwest, and there's been a lot of industry drilling, a lot of our drilling, I'd say 90-plus percent of that acreage has been de-risked. So that's where you're going to see the bulk of our activity. In terms of the propane line, I mean, it's moving along as we thought, and we're pleased with -- there's some regulatory stuff they got to get through, but it's making great progress. And so we're right on scale in that, right on schedule. David Kistler - Simmons & Company: Just a clarification, like, most of the production coming from the Southwest liquids ridge propane line, feels like it'll be done in time to ensure that there aren't any liquid-related issues there. Just trying to kind of check that box, more than anything else.

Yes, I mean, let me back up a little bit. The propane line, we're already doing propane down the pipeline even though the big line we're talking about is a longer-term issue that really deals with the ethane. And as we ramp up in the Southwest, we'll ramp up the ethanes. Currently, we're just selling the ethane in the back stream. We put just a little [ph] amount that selling of ethane because we get paid more. So that's what we're trying to do. We're trying to capture the whole gas stream there. The good news is that we dominate the liquid-richer, so a lot of this progress is going through us, and we're seeing a lot of different things. And the good news is that there's a lot of neat, creative things going out there, and so we're encouraged by that, and if you think over time, it'll continue to help the margins and whatnot.

And Marshall Carver with Capital One Southcoast.

The new bolt-on acreage at Nora/Haysi, I know you helped the mineral interest on the old acreage. What's the royalty on that new acreage?

1/8.

And on the production mix for next quarter, could you give us a feel for what, either in absolute numbers or percentages, what the split would be between oil, NGLs and gas?

What I'd suggest there is after the call, I mean, Rodney is trying to put out a lot more information on that split in mix, and so people can get pricing right. It's probably better, I would say, to just call Rodney. He can give you some of that detail.

And then finally, a question on the Huron and Devonian wells. It looks like you're encouraged with the initial results. Trying to think long term, it seems like it would have trouble competing with the Marcellus in terms of economics unless it's really good because the Marcellus is so good. So how would it be able to get capital or would you potentially sell that or JV it? What would your plan be on success here on Devonian Shales?

Let me clarify that, and so that it's really clear. The Huron potential is down in Virginia. That's on our existing Nora acreage, Haysi acreage and the new acquisition acreage. The Huron is a Devonian age shale. When we go up to Southwest Pennsylvania, and we're saying Upper Devonian, it's not Huron. It's Genesee briquette lines, Great Middlesex, it's an aggregate of those shales. And it's literally in Southwest Pennsylvania right on top of the Marcellus. And I wish I could actually, with a lobbing heart, to be able to talk about it in more detail because we have a lot of data and a lot of exciting data, but I can tell you, I'll say this, after drilling our first well, we're clearly ahead of where we were in the Marcellus at the same point in time. As we drill every Marcellus well, you're drilling right through that Upper Devonian package. We've now drilled and completed our first well. We have long-term testing on it. It'll be online later this year. We've actually drilled our second well and we will be completing probably by the end of September, and we'll have a third well. It's right on top of the Marcellus, so it's really going to help us with efficiencies. All those its lines and compression and gathering and everything, so literally like the same area. The acreage is -- there's no acreage cost; it's right on top of where we are. That has a huge potential, I mean the potential, when you look at Bcf per mile off of Bcf logs, what's in the Upper Devonian aggregate is on par with what we have in the Marcellus. So it's extremely high upside. So it's not -- it has fantastic potential. That was a very general answer, and hopefully, whether it's the next quarter or the following quarter, we can get more specific. But so far, I just say we're encouraged. And well, for total clarification, we have Huron down in Virginia, and the whole of that acreage is perspective for the Huron. You have Upper Devonian basically in Southwest Pennsylvania, and then there's a third upside in the Utica Shale, which is below the Marcellus. And again, we've drilled and completed our first unit of well, have long-term testing. We will be spreading another well probably early in the first quarter of next year. And there's tremendous upside in the Utica as well, so you have three horizons.

Our next question is from Ron Mills with Johnson Rice. Ronald Mills - Johnson Rice & Company, L.L.C.: Jeff, on the 2 to 3 Bcf per day that you think you can now get to, at what point down the road do you think you can achieve that level? Is that five years from now or three years or even longer?

Well, let me start with where we've been historically, and then I'll, in big ways, talk about going forward, and hopefully, give you some guidance. If you go to the end of 2008, I believe we were about 26 million per day, net, onto the Marcellus. At the end of 2009, we tripled it or we actually quadrupled it to 100 million per day, net. The end of this year, basically, we'll double it, 200 million to 210 million. And we're giving guidance for end of 2011 to double that again till we get to 400 to 420 million per day, net. That's the kind of trajectory that you'll see. If you look in our current book or current presentation out on our website, on Slide 13, I believe -- it's Rodney giving me the right information, you can see the Range hockey stick. You can take that, and you can get a French curve, which is what you'll need because it is exponential up. And you can project forward with where you think we'll be at the end of 2011. Once we go through that budgeting process that John talked and present to the board and walk down on where we'll be, I would imagine, sometime around the end of this year, we'll probably come out and ping out that euphoria. And I believe it's pretty exciting. I mean, again, you can look at the hockey stick, see where it has been, where it was going, and as we ping out that extra year, then I think you get a pretty clear feeling. And you can probably do it yourself with the data that's out there on when you think we'll break that. So that's exciting. I mean, a lot of people, I think, just to a little more color, and I tried to do it in my notes, and I know you guys go through a lot of presentations and a lot of conferences and everybody's talking about Bcf, but how many of those really materialize? How many companies have done organically and have been able to literally grow from 2 Bcf per day or two or beyond, and that's I can think of two, and since I've been in the business for 31 years. Range clearly is on that trajectory, and we have the potential to get into that slot and do it organically and to do it with an extremely low-cost structure, really strong economics. And that's really what's going to drive NAV, and like John said, that's what we're focused on. Ronald Mills - Johnson Rice & Company, L.L.C.: On the ethane production, it sounds like you're still keeping that in the gas stream for now. What will be the trigger point that gets you to start to strip that out, begin to sell it, especially given the current price situation for ethane?

Well, I think you got to remember, we always have a couple of options. I mean, one option is to continue to do what we're doing and to blend. And right now, we're getting paid for the Btus, and even after we strip out the liquids, which are really nice positive boost to our rate of return, we still get paid for the Btus. So after processing, we still have 1,140 Btu gas roughly. So we have the ability to keep blending, but like John said, since we have a dominant position there, a lot of those projects were critical piece, turning those projects going forward. And we look at them all to see what's optimum. Is it better to continue to blend long term, or is it better to break it out? And again, like John said, all this is going to be based on what maximizes NAV per range. Ronald Mills - Johnson Rice & Company, L.L.C.: And Roger, just a couple questions. On the G&A, you talked about you expect it to be flat with the second quarter. Is that flat after backing out the $2.5 million legal fee, or is it going to continue to grow at kind of that level just because the increased staffing year you're undergoing up in Pennsylvania?

I think it'll be in that $0.57 ,$0.58 slot for the remainder of the year on. We're continuing to add staff and gear up the capital increase. You need more people, but again, like Jeff said, a lot of these expenditures are really -- their project expenditures were just moving from '11 to '10, so got to get extra people to handle that. So it's a little bit of a fast-forward and broad, too. So it's the eight-ish. Ronald Mills - Johnson Rice & Company, L.L.C.: And then finally on liquidity, can you walk through which is current liquidity is in terms of cash and under your revolver?

Yes, sure. Our borrowing base is currently $1.5 billion on our bank credit facility. That was just reaffirmed in March of this year, and our next bank meeting is in September. All indications are what kind of reserve performance we're seeing there is that our maximum conforming capacity will be above that $1.5 billion number by a considerable margin, but we don't have a need to access that. Our legal and binding commitment, Ron, is $1,250,000,000. And the way our facility works is we can send a notice with the agent and then we can increase from that $1,250,000,000 to $1,500,000,000 with 20 days notice among existing groups. So just see enough the $1,250,000,000, we've got $475 million outstanding, but that's a little misleading because we've got $160 million parked in that escrow. So you're looking at a net bank debt in the low $300 million against $1,250,000,000 in committed availability. So we're just under $1 billion in liquidity on a legally binding basis, and about $1,250,000,000 on a maximum volume base.

Our next question is from Gil Yang with Bank of America.

Granted you accelerate your activity, as you increase more NAV per share, I just want to get inside your head a little bit and think about what limits the ability to accelerate even more if you think that you can create NAV through this acceleration?

Well, I think when you look at it, a big driver was when we entered the year or at the end of last year when we set our budget, we went through the same process last September, October, November, December. We commenced with the number of wells we think, the rigs we have under contract of drill, and the reality is our technical organization with those same number of rigs can now drill more wells. That was a key part. So as we've gone up the learning curves, we really had two choices there. One is we could format a rig. But given the strong economics and strong rates of return, and again, look at where we were last year, rate of return under a fixed price than where we are this year, significantly better. It was great last year; it's even better this year. So our decision was rather than to format a rig, that's what prompts those points to the extent our team gets faster and faster with the same number of rigs. That's been accelerate production. And again, that acceleration, some people are looking at what did it do to this year, what does it do to next year, and we raised guidance both years. But I think actually, the question, and I think Ron asked it, where does it take you, where are you going to be out there in terms of breaking the Bcf per day. That acceleration helps you in 2012 and beyond because as you build those into an area, when you build a pan off of it, well, then you can combine and can build additional pans off the same road. You can drill additional wells off the same acreage. There is additional wells off the same path. So those efficiencies are what is going to drive of this. We're not about running the most number of rigs or like John said, many times being the biggest and baddest and running the most number of rigs in the play, we're about rate of return and NAV, and we let our technical team sort of dictate that. And we learn as we go. The good news is as the more we drill, the more the acreage gets de-risked. The more the industry drills, the more the acreage gets de-risked. So that 20-plus Bcf that we see at there right now is looking extremely strong. The production growth is looking great. The rates of return are better, and you're seeing it quarter-to-quarter, and our unit cost, they are coming down, as Roger's mentioned. So that's what drives our decisions.

So the increase in spending for the roads and the pads, et cetera for next that you're accelerating into 2010, again, a result of the more efficient drilling rigs that you've seen?

Yes, well, it's a combination of that, but also, as we're starting to develop in the Northeast, we're getting more efficient organization. In the Southwest, you're out in front of the mountains. When you go into the Northeast, you're up in the mountain, so you have winter in Pennsylvania. It's important in both areas, but pre-building some of that stuff in the fall and before wintertime, again, makes this more efficient. It's more cost-effective, it's a better thing to do. And as we ramp up in that area, we're pulling some of that fast forward because I talked about those two rates for our first two horizontals in Lycoming County being 13.5 million per day roughly each. Those are seven-day averages. So those are pretty impressive rates, and those are pretty strong wells when we finish. That's a heck of a shale well, so we're excited about that. We're up there drilling right now, and we want to bring that stuff online. So it's all part of how do we maximize the value of our share price, how do we maximize NAV. And those are the things that drive us.

When you already have had capital in your budget for the Northeast expansion in terms of the accelerating, in getting out in front of a wintertime?

Well, we had capital. We have some capital in there, but it comes back to -- you remember, a lot of that capital, most of the capital predominantly is for the Southwest. That's for most of our infrastructure and most of our drilling is. But as you have the capital in there, we did our deal with PVR. PVR looks like they're on track. It looks it won't be delayed. It looks like it'll be, if anything, maybe a little earlier, so we want to pull some of that a little bit forward to make sure -- if we can get it on this year, we think that just continue with the great story that we have.

For the Talisman joint venture, of the $25 million, just like you said, how much is the total commitment to hold that acreage for that joint venture?

Well, it's really about developing acreage that we think is prospective. In that plan to develop the acreage or to maximize value of the acreage will not only drive our production but will hold the acreage. That capital does, in essence, both. It's not one or the other, it's both.

There's no quote. We haven't committed $100 million or $200 million or $300 million. It's just the normal operating agreement and when Talisman or Nashville [ph] sit down and decide how to drill wells and then either party can either commit or not commit to those wells, and you could -- see you have a little lever there where you want to commit capital or not. So it's not like -- it's much different in the JV, these financial JVs. This is a regular industry joint venture where you've got two industry partners, just developing an acreage position. And again, I think one of the things that's encouraging to me is that, that acreage up 14,000, 15,000 acres would not have been developed in the short term for us. So what we're doing is we're pulling that forward, that acreage forward in our NAV curve, and we're using the benefit, our Talisman technical team in their rigs and people to help us develop that. And I think it's pretty smart on our part to do that. What we have to give up is the day-to-day operations, which a lot of companies don't like to do, but obviously, Talisman's a first-class organization. As Jeff said, they drill from terrific wells up there. So we feel really comfortable with them. Not they will do a lot of these, but we're talking to different people about some of the stuff and other prices where we have bits and pieces of acreage that we're not going to get to in the short-term. It's a great solution to deal with that NAV issue in terms of pulling that forward into the NAV curve. So again, it's part of it. As Jeff mentioned, now when we have Talisman's team now working on that is that we brought Mark Whitley and his team from the Barnett Shale, and they're going to be working a lot on this Northeast acreage. So this time last year, we had one team working on it, now we'll have three teams working on it. We just think that makes sense in terms of bringing -- you're getting of them with three teams, and you only have one team. So again, it's pretty -- it's just the maturation of the process. You kind of learn as you go.

We will go to David Heikkinen of Tudor, Pickering, Holt for our final question. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: As I think about the acceleration of CapEx from 2010 into 2011, I'm thinking about that as a recurring talk that all these years, you pre-invest in roads and pads and the like. Is that a reasonable expectation or would CapEx actually drop in 2011 versus 2010?

So I think a better way to think about it is the total project CapEx is the same. We're just pulling it forward. It's as simple as that. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: And you'll pull forward 2012 into 2011. I mean, it's kind of acceleration. That train target keeps going for roads and pads and the like.

Right, but you're pulling forward and increasing the rate of production, and the NPV of the project is greater. But the capital, the overall capital is the same. You're just moving it all forward, but you're moving the production and the reserves and everything else forward as well. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: And then just specifically on split of rigs running on the liquid ridge versus dry gas in the Southwest, do you have that?

Yes, right now, we just have one rig in the Northeast. All the other rigs are in the Southwest, and they're all in the wet gas. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: And then speaking about the Nora transaction, I know it's relatively small dollars and kind of a core area for range, but trying to think about how investing capital and blocking that up adds more NAV than investing more and just developing your huge Marcellus solution?

Well, I think it's -- again, I think we believe what our mission is to build NAV per share. And we've got some core areas in the Barnett and then Nora and the Marcellus, and we're going to continue to build on those. We think it makes sense when you look at the overall risk of the industry, and we've done a lot of studying. At the end of the day, do we want to be a one-basin company? And I think the answer to that is no, we don't. And so when we see opportunities in these other areas, we think it's prudent from a risk prospective to go ahead and seize that opportunity. Like I said before, we haven't done an acquisition for, I think, way back into 2007, and then that was we had a little piece of Nora. I think going back to that, I think it was back in 2006, 2005. So we've been really disciplined on the acquisition side and not do anything because we've had this Marcellus opportunity. But we've had these opportunities in Nora, and we think they're exceptional. So we're going to go ahead and do it. And again, I think you got to look at the risk, the overall risk in the industry, in our company and just think through it. Do you want to put all your eggs in one basket? And we're obviously putting all our eggs in the Marcellus basket, but we think it's prudent to -- in an area like Nora, what we know so much about, we got a great team. I think Jeff mentioned we think the upside on those reserves is the 100-plus Bcf approved. We think that total reserve that size is close to 800 Bcf. So great, great long NAV-accretive acquisition.…

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