Welcome to the Range Resources Fourth Quarter 2011 Earnings Conference Call. This call is being recorded. [Operator Instructions] Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risk 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. Today we have a lot of great material to cover so we're going to move directly to our speakers. Hopefully, this will allow for as many questions on the call as possible. Our speakers on the call today in order are: Jeff Ventura, President and our new Chief Executive Officer; Ray Walker, Senior Vice President and our new Chief Operating Officer; Roger Manny, Executive Vice President and Chief Financial Officer; and John Pinkerton, our new Executive Chairman. Now let me turn the call over to Jeff for his opening remarks.

Thank you, Rodney. I'll begin with an overview of the company. Ray will follow with an operations update. Roger will be next with a discussion of our financial position and John will follow with his perspective. Then we'll open it up for Q&A. Let me begin with a review of where we've been as a company, where we are today and where the company can go in the future. Despite the current low gas price environment, Range is well positioned for 2012 and beyond. This is a result of our multiyear strategy of growth in reserves and production on a per share basis, debt adjusted, with one of the lowest cost structures in our peer group, coupled with building and high grading our inventory. It's also the result of long range planning, both operationally and financially. Our organic growth rate from 2003 to 2011 ranged from less than 5% to 2011's top rate of 12%. During this timeframe, Range went from being one of the higher cost companies in our peer group to one of the lowest cost companies. This was the result of getting into plays that if successful, offered very repeatable high rate of return growth opportunities such as the Marcellus Shale and horizontal Mississippian plays. It's also the result of exiting relatively high cost low-growth plays with little repeatability, like the Gulf of Mexico and Deepwood Viner Chalk [ph]. As a result of our strategy, we sold about $1.8 billion of properties during this timeframe. This focused our technical resources on higher quality opportunities and lowered our cost structure. It also provided significant funding for better return projects. Looking back, we were fortunate to have sold these properties in a higher commodity price environment. Carrying over a portion of the 2011 sale proceeds into 2012, coupled with…

Thanks, Jeff. Let me start out by saying that 2011 was a great year, full of great accomplishments. And I'd really want to give a strong shout out to all the members of our operations and technical teams across the company. In all the divisions we have great news, great metrics and great upside, and it's truly a testament to their dedication and efforts. Our people make this company great. And it's the people that create the value that they as well as we all appreciate as shareholders. What I really want to do with my remarks this afternoon is focus on going forward and give you some additional color and details that maybe you hadn't thought about just yet. On our website, in our investor presentation, you will now find maps of our acreage position across the state of Pennsylvania. This is the first time we have disclosed this level of detail. Let me focus on Southwestern Pennsylvania for just a few minutes. There's about 210,000 net acres in the wet area, which is that acreage we have been drilling in for several years now, in and around the MarkWest Houston plant. The wet area is defined as that acreage which is between 1,050 Btus and 1,350 Btus. In the dry area, we have about 235,000 net acres, and of course, this area is that acreage where the gas is not processed and is less than 1,050. We have 125,000 net acres with greater than 1,350 Btu like Jeff referred to, which we now define as the super-rich Marcellus. We are introducing 5 new enhancements to our portfolio. These are not new projects thrown together in response to current market conditions. In fact, several of them have been in the works for more than a few years. We have…

Thank you, Ray. Before I take you through the quarterly expense items and first quarter expense guidance figures, let me follow up on some of the balance sheet issues Jeff mentioned earlier. Our leverage, prior to the Barnett sale, stood at a debt-to-EBITDAX ratio of 3x. Following the Barnett sale, this ratio declined to 2.2x. Range has the financial flexibility to fund our 2012 and 2013 capital spend through cash flow and our remaining proceeds from asset sales, combined with our existing credit capacity and without taking our leverage to uncomfortable levels. By uncomfortable levels, I mean that even though our debt-to-EBITDAX ratio covenant limit is 4.25x, if our debt-to-EBITDAX ratio gets much over 3x, we become uncomfortable. And it will not stay there for an extended period. One of the reasons we're so confident with our 2012 and 2013 funding plan is because Range has always had such solid underpinnings to its credit quality. Our low operating cost structure, our disciplined hedge program, our operating control over our major growth areas, our long reserve life, our simple balance sheet, our orderly staggered debt maturity ladder, our sizeable liquidity cushion from our well diversified $2 billion borrowing base credit facility, and perhaps most important, a long track record of low reserve replacement cost and consistent reserve and production growth. These strengths are not going to change. We've never compromised our balance sheet to achieve growth for growth's sake. And we're not about to start now. Moving to the income statement. There's a new line item this quarter that I need to bring to your attention. E&P companies generally report their transportation, compression and firm capacity expense 1 of 2 ways. These expenses are either netted against revenue or these costs are itemized and included as an operating expense. Because our…

Thanks, Roger. Terrific update. As everybody has mentioned today, obviously, our 2011 results, I'm very pleased with. I want to congratulate the entire Range team for their extraordinary performance in 2011. Over the past 8 years, we've repositioned Range driven by our strategy of consistently growing production reserves at low cost. The 4 key takeaways are: One, Range has achieved 6 consecutive years of double digit per share production in reserve growth. Only a handful of companies have ever achieved this high level of consistent growth. Importantly, we have the ability to extend this streak for many years. Second, we have one of the lowest cost structures now in the industry. We have seen unit operating cost decline from a high of $1.05 in 2008 to $0.49 in the fourth quarter of 2011. We've also seen our D&A expense drop from a high of $2.48 in 2009 to $1.69 in the fourth quarter of 2011. We expect to generate further enhancements to our cost structure in the years ahead. Three, we have painstakingly pieced together very high return low-cost inventory of drilling projects that now totals over 8,600 locations. These projects generate attractive returns even in the current low natural gas price environment. Fourth, we have assembled a very talented group of people who work together extremely well and are extraordinarily focused on delivering our strategy of low cost -- I mean, of consistent growth at low cost. Inflection point has been mentioned several times on the call. I think inflection point very clearly defines where Range is positioned today. We have worked tirelessly over the past years to sell $1.8 billion of mature higher cost properties, lower our cost structure and strengthen our balance sheet. In particular, the bold move last year of selling our Barnett Shale properties, which…

[Operator Instructions] Our first question comes from Neal Dingmann with SunTrust.

Just a question on the liquids play. Could you tell us, I know it's very early, but could you talk about potential spacing here, as well as kind of drilling plans, how active you intend to become on that play.

Yes, Neal, that's a good question. We currently today are drilling our wells generally on 1,000-foot between laterals, which would translate into longer -- moderately longer lateral cases to something around 80 acres. Do we expect, I mean the question is, do we expect it to get denser? I think in most plays today, we are seeing denser development as time goes on, but it's just too early to give you a number at this point because we just simply got to do more wells. We got to get reserves, do some modeling, measure the hydrocarbons in place and so forth. So today, we're generally looking at 1,000 acres and also trying to HBP all the acreage through there as we drill.

And I would just add on to what Ray said. Particularly if you look at the oil plays, specifically like the Mississippian, we put out recovery factors of 4% to 9% of the oil in place. Do I expect ultimately it'll be that? No, I would say it probably will be higher. Most likely will come from down spacing. Same with the Cline Shale, whenever you get oil plays with more viscous fluid, to go to tighter spacing I think is clearly reasonable.

Okay, then just one follow-up. Just on the horizontal Miss. We've heard some chatter about just, over at [indiscernible] County and I guess state results showing a bit more volatility, some not as good. But if you can maybe just a comment on just overall results and shale expectations for the play.

I think in any of these places it's really important on where you are. There's always a core area and non-core areas. There's better areas and poor areas. I would say looking at the results of our Mississippian wells even though it's early, there's only 8 wells, but the average results of 485,000 barrels per well is really great. It's outstanding. So I feel comfortable that we're in a good position. And we think really what drives that is the fact that where our acreage is located. Really that's an oil play with a lot of water. We think being high structurally is good. A lot of our acreage is up on the Nemaha Ridge, so we're higher uplift, so we're higher structurally. The other advantage of being up on the ridge is that you have a chat component to your production. And with chat comes higher porosity. The chat -- when you get off structure, you tend to lose chat or you don't have nearly as much. The porosity in the chat is 30% to 40%. The porosity in the carbonate is 3% to 5%. So you have significantly higher porosity and a better structural position is what we think leads to those results.

Our next question comes from Dave Kistler of Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: Real quickly on your CapEx for '13 and growth for '13. You talked about those numbers with respect to living within cash flow. What are you actually targeting? I mean, that seems more like a kind of a test case or an illustrative example, but should we be thinking about more like 30%-type production growth numbers? And living outside of cash flow kind of tying up our models to maybe 3x that debt to EBITDAX figure.

Let me take a crack at answering that. It's a great question. Really what we want to give total granularity on what we're doing in 2012, what we're seeing for 2013, it shows you the flexibility of the company and the optionality of what we can do. If we choose to live within cash flow, we can still grow at 15% to 20% per year, if we choose to do that. And importantly, I think when you look at a company our size and given our portfolio, I'm not saying we are going to do this, but if you could grow consistently at 15% to 20% for years for a company that has a market cap for more than $10 billion with the cost structure and return we have, it's pretty impressive. That being said, we really want, what we're saying is, we want to maintain the flexibility that based on where gas and oil prices are, based on the results of our wells, even if we choose to cut back for a year to live within cash flow, if we do that, we have the ability to significantly ramp up the following year, say, and really capture a lot of the NPV. So we got the ability to ramp up or down depending on what we think is the most prudent to do. I know you guys probably want the answer to that today, but what we're going probably to do is what we've done in past years. Where we'll continue to look throughout the year and we'll continue to look at where gas and oil prices are, where our portfolio is, what the results of the wells are, present it to our board in the fall, come out with our plan, most likely early next year like we do every year. But we'll give you -- we'll continue to give you guidance or a little bit of color as we go throughout the year. Most importantly, we're telling you what we can do. We can, if we want to, choose to cut back and live within cash flow even if it's for a year, still retain all the resource potential, still retain our acreage and then ramp up when we want to. So we're not saying we're doing that for 2012. But we're saying we have the ability to do that if we choose to do so. David W. Kistler - Simmons & Company International, Research Division: Okay, I appreciate that. And then just a clarification on your liquids production growth number for '12. If I heard it correctly, you said 40% liquids production growth. Can you split that up for us between oil and gas?

Well, the percent growth, we've given guidance on the overall production 30% to 35%. And I guess the way to answer that is say, the liquids year-over-year 2012 compared to 2011 will be growth of 40%. So we're disproportionally growing more in liquids than we are in gas. It's definitely back-end loaded towards the end of this year. There's no question about that because we have been trying to consciously make this shift from dry gas over to the liquids-type plays for several months now. And we're still evolving that. We're still waiting on the infrastructure in certain cases and things like that. So the best clarity I can give you today is to tell you that year-over-year, it's going to be about 40% liquids. I think in the coming calls, into the next quarter or so we'll have a lot more granularity that we'll know by that point. Right now, we're just trying to maintain flexibility to be able to get to that point. David W. Kistler - Simmons & Company International, Research Division: I guess the clarification I was looking for was really with that 40% liquids growth, the split between oil and NGLs, I apologize.

Yes, what we've tried to do over the next few weeks is continue -- we're in the process of fine-tuning our models and everything else. Hopefully within the next few weeks, we can come out with something in guidance that we can put out for everyone in terms of what that will be. David W. Kistler - Simmons & Company International, Research Division: Okay, I appreciate that. One last one, if I might. Just looking at the Cline Shale, obviously returns there are little lower than what you're seen in the super-rich and what you're seeing in the Miss Lime. At anytime point would you think about liquidating that asset and redirecting capital in these high-return areas?

Yes, I think the key thing. Your comments are true, except what to me is so exciting is that's our very first well. If you go back and look at our very first Marcellus wells, they really weren't that good. And typically in all of these shale plays, you tend to see significant improvement with time in terms of what you can do in terms of driving down costs or driving up initial rates and reserves. The fact that our very first well IP-ed at 600 boes per day and has a rate of return off of today's costs, and assuming no improvement in reserves and just what we can drill it for today, still generates an attractive rate of return is really exciting. So I have great faith in the technical teams that are working that, led by Ray and Mark and the rest of the guys that at the end of the year, that's going to look a lot different and hopefully, I think a lot better. And then we always assess with where it looks a specific point in time. But to me, to come out of the box on the first well, usually it's a strike or foul tip or you're beaten out of bunk to first base, that's a solid single for a first well.

Our next question comes from Ron Mills of Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: On the Mississippi Lime, can you talk about -- maybe some of it has to do with where you are in the Nemaha Ridge and the structural component. But the variance between your well design and some other people in the play, you have a much shorter lateral with fewer frac stages. Is that something geologic in your area? Or is that something that you will begin to test longer laterals and increase frac stages like you have started to do up in the Marcellus?

Yes, Ron. And that's a great question and Jeff sort of alluded or hinted at an answer a little bit in that there are geologic reasons that we think it's better. We are primarily up on the uplift. We've done a real good job of concentrating our efforts in putting our operations and acreage together there in a consolidated manner because a lot of it is focused on operational efficiencies. We're a little bit shallower up on the ridge. We got a little bit less gas or pumps downhill can work a little bit more efficiently. We can drill shorter laterals because we think the rock is probably or potentially a little more fractured. We've got the chat, which has higher porosity. And so what we've seen with the first 8 wells and granted it's the first 8 wells, so it's very early in the play is that with 2,200 feet in 12 stages, which is approximately 1/2 of what people are doing out to the far edges of the basins, we're seeing the top end of the reserves. And I think all of those things kind of accumulate to get the results that we're getting. Of course, what we're doing this year, we're going to be -- we got 2 rigs running currently. We're going to drill, put online about 23 wells in that area this year. We'll drill about 3 saltwater disposal wells. And I fully expect that the team's going to do a great job in getting those costs down and learning things about where to target the laterals and become more efficiently -- more efficient in the way that they complete them. And then of course, we are going to look at some longer laterals and that sort of thing, just like we would in any play. So hopefully, without rambling on too much that answers your question. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And do you have, was this a seismic-driven portion of the play where you were looking for structure? And if you look at your total 125,000-acre position, do you start to get a little bit more into a strat portion of the play versus structure? Or have you been able to confine your acreage more along this uplift?

Yes. Let me try to answer your question. And I think it's important to get into the history of the play for us. We really started in that play back in 2004 as a reactivation of Tonkawa field, which was the world's or the U.S.'s largest light oilfield back in the early '20s, late 19-teens. And we started reacting within a shallow formation there was the Tonkawa at a depth of about 2,700 feet. So we did that, which is reactivating that old field. Once we did that after the first couple of years, plus or minus, the team recommended shooting a 3D over that old field which was to me was pretty creative at the time because there's such well density, you think, how can anybody missed anything. And what it led to, was it led us to drilling deeper targets like the Mississippian and even things below, in the Wilcox and Redfork and some of the other targets. As we did that, drilling them vertically we found that, "Hey, the Mississippian was even better than the Tonkawa." And then what it led us to do based on our interpretation was to move off that structure. Remembering, the whole structure really is up on the Nemaha Ridge and the ridge is 10 to 20 miles wide and several miles long, runs up into Kansas. So it's got us to drill off structures. So we found out, not only were the Mississippian wells good on structure in this localized area, they were good off structure. So then we started to drill horizontal wells 1.5 years, 2 years ago and really started ramping up our acreage position. So when you look at it from a broad sense, our acreage is all along, and it's up on for the most part to…

Well, let me lead off with the answer and then I'll turn it over to Ray for a little more color. To me, what's exciting is, in a broad sense, you have the equivalent amount of hydrocarbon in place in that Upper Devonian section that you do in the Marcellus. That's pretty exciting. And then when you look at it from a thermal maturity again, it's roughly equal. So you have just -- and we put the maps out on the website again so you can see dry, wet and super-rich in the Upper Devonian. And we've only really tried drilling and completed 2 wells so far. Again, what's exciting to me about those 2 wells and they both were in the wetter, on the dry side of the wet line or in the wet area, is you have a thick interval just like you described. And off of our first 2 tries again, we actually made pretty reasonable wells. And again, when you look at any of these shale plays, usually the first 2 tries are your strike outs or other science experiments, we actually made pretty decent wells the first 2 tries. To put it in context, just like you said on that slide and Rodney, are these the right numbers?

Yes.

So it's on Slide 27, you can see that the Marcellus is much thinner than that total Upper Devonian section. So in the Marcellus, plus or minus, what we're drilling is 80 to 120 feet. So we've found that if you still early on, where you land the well in the Marcellus, just moving it up or down within that 100 or 120 feet, you can double or quadruple the rate. So where you land it and how you complete it is extremely important. So now we have a broader interval in the Upper Devonian. So if you ask me, I'm going to turn it over to Ray in a minute. Did we optimally land those first 2 wells. I sincerely doubt we did because it's just so early on. But even not optimally landing them, we made reasonable wells. And now we're going to go into the super-rich area, and we'll see what the hydrocarbon content is. And again, I think we're really going to go up the learning curve in terms of how do we optimally land them and complete them and what they'll cost. So Ray, do you want to try to put a little more color on there or...

I don't know what else I could say.

By the way, Ray, you put in -- most, some of you know this, probably not all of you, when Ray started with this, he actually was out on the wells completing them and frac-ing them. Then he also was the first guy to open our office and built the office. And now, he's our Chief Operating Officer. So when he speaks, he's speaking with great authority because he's been there and done that.

The first 2 wells, we did primarily because we knew there was a lot of hydrocarbon in place. And in fact, like I finally used the term, it's almost like a lay down, double right on top of the Marcellus. And we knew it was there. The question is, can you complete it, can we make it economical, commercial, all those things? And so the first question was, was everything connected? Or when we completed the Marcellus well, were we in fact connecting to the Upper Devonian since it was so close. With those first 2 wells, we designed them in such a manner to try to answer that question. We did isentropic analysis, which is simply fingerprinting the gas, to determine if it's 2 separate reservoirs. We did some downhole pressure work and different things. And so, we have proven that it's 2 separate reservoirs. And even where you're on the same pad completing in the Marcellus, you still have a unique isolated reservoir above it in the Upper Devonian. Now we've only done 2 wells. The industry has only done a handful of wells. And so I think we're far from knowing where the optimal place to land the lateral is. But I feel like, with the test that we have and with the information that other industry folks have shared with us, that there is a lot of potential there. And we'll probably be experimenting with 2 or 3 different places over the next year to try and to figure out what that optimum answer is. So that's about all I could add to it at this point. I think Jeff did a great job of describing where it started from. So... Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: But do you think you'll end up with potentially 4 different development zones? Or so in other words, is there an effective frac barrier between some of those Upper Devonians? Or you may end up getting contribution from multiple Upper Devonian zones in one frac?

I think today, we'll get it all from one lateral. I mean, potentially down the road, might there be 2 laterals pretty close together. Like for instance, there is in the thicker parts of the Barnett. I mean you could see that way out in the future. But I think at this point, we believe it will all frac together. And we'd be able to complete it that way.

You're saying -- and to clarify that, we're saying we think the Marcellus is one completion and then the double is the Upper Devonian. So one well can frac all those intervals, the Upper Devonian intervals together as a separate second unit.

Our next question comes from Leo Mariani with RBC.

A couple of quick questions here for you. Looking at your acreage in Pennsylvania, it looks like some numbers have kind of moved around a little bit this quarter. I'm seeing your acreage in Northeast Pennsylvania go from 240,000 net to 180,000 net. And your acreage in Southwest PA went from 550,000 to 570,000 net. Just curious is there kind of -- what's going on there maybe there is some acreage swaps? Or maybe you guys have let some acreage in Northeast expire? Any color you have around that would be helpful.

Yes. We can all chime in a little bit. I think what you're saying is exactly true. Our focus really is right now is the wet and super-rich of the Southwest. It's our big core position and given where oil prices are and gas prices are, clearly, our best economics. So the land dollars that we're spending are down in that area. So 100% of it is down in that area. Also when we're trading, we're trading to block up in that area. So we're trading stuff that's outside of the area to get stuff inside. And not all those trades, they aren't proportional because we really like the area and we think it has stacked pay and superior economics, we may trade 1.3, 1.4 acres for 1 acre to get it in the wet because we think the value is so much greater. So it's a variety of things like that.

Okay. And I guess looking at your super liquids rich area of 125,000 acres, how much of that do you think is de-risked at this point, if you guys could talk a little bit about infrastructure in terms of gathering and processing on that acreage.

Well, we feel like it's all de-risked. There's enough well data, penetrations all around it that we feel pretty confident it's there. Now there's different levels of de-risking. We still got to get in there and drill and determine what the exact composition of the liquids will be and all that sort of thing. We have contracted additional process capacity with MarkWest. There were some announcements that went out on that. Here a while back, a month or so ago. And we've got plans with MarkWest to lay infrastructure, put compressor stations in that area. So that was part of what I said in my notes that we've really been working on this for a couple of years, both doing acreage trades, consolidating, filling in the holes and putting plans together for infrastructure. These big pipelines and the transportation on some of the lines that go through there and the rail facilities and the de-ethanizers and all of the things that are coming together didn't happen overnight. So we've actually been working on that for quite a while. So...

And including the ethane agreements, the 2 got signed and the others that we're working on. It's all part of the master plan to optimize that because it obviously has the highest returns and the highest net present value.

Right, and so to coin the phrase we've been using a lot, it's really an inflection point for that area because we've now got 8 wells that are online. We've got all these infrastructure plans in place and it's now time to start drilling. So like I said, we'll put approximately 55 wells online this year in that area. So I think you'll see us talk about that area a lot this year because that's really going to be a big focus for teams in Pennsylvania.

Okay. And in terms of your program for this year, you guys talked about outstanding cash flow. Any other plans for any other non-core asset sales this year that might prevent the debt from ramping up as much?

We've got several small properties, cats and dogs and a couple of positions in some non-operated cases that we'd like to divest of at some point. But at this point, we're not going to give them away in this kind of environment. So I think that's going to always be part of our plans going forward is to continue to take the high cost, low return type properties off the bottom of the pile and monetize it and take that money and then reinvest in the higher return projects. We're just down to the smaller properties at this point.

I would just add. Like I mentioned, I think the bulk of the heavy lifting's done, and we sold $1.8 billion worth of those properties. There's small things here and there, if we can sell them, great. And if we can't, we're still in good shape.

Yes, and this is John, even taking it a step further, I think, we've now got the balance sheet that we could -- we've got several levers we can pull and we can pick and choose. Obviously, like we've always said, if somebody comes in and wants to make us an offer for something, and we think it's attractive, we'll take advantage of that and then recycle that money. But the good news is, given all the great work the team's done and under Roger's leadership, now we have the balance sheet and liquidity and availability to really pull either one of those levers and do the one that's most attractive for the shareholders. So I think that's, again that's an inflection point, too, that I think is really driven again by what I said was the bold move of the big Barnett last year. It really puts us in a position to be on the offensive versus being on the defense in the low gas price environment.

Yes, and I would just add. Last year was critical but more like I'll go back, it's really the last 8 or 9 years of just having a consistent strategy of growth at low cost on a per share basis, building high-grade inventory. Because we've consistently done and executed on that for years, it's put us in a great position for 2012 and beyond.

Okay and I guess a question on your production guidance. You talked about 638 million a day in the first quarter. Because if I look at that number compared to the fourth quarter of '11, it's up about 13 million a day. In 4Q '11, you guys added about 90 million a day sequentially. Obviously, that's kind of lumpy growth. Could you guys maybe just talk a little bit more about how you expect it may play out into the next quarter, are there any significant sort of milestones in terms of infrastructure components that are looking to come on, where you might see production jump dramatically in the second quarter or maybe the third quarter? Any color you guys have around that will be helpful.

I'd give you a little color, but before you downgrade our growth a little bit. Let me say, it's still 17% production increase over the first quarter of last year. And then if you account for the Barnett sale, it's 40% -- 47% year-over-year, quarter-over-quarter growth, which to me is pretty impressive. Granted, when you look at the 30% to 35% for this year, it'll be back-end loaded sort of like what it was for 2011. I couldn't be more excited and not only are we getting the growth, but we're growing our liquids disproportionately relative to the gas like Ray pointed out earlier. But we're going to stick with quarter-by-quarter guidance like we have every other year.

And I can add just a little color in that. It's pretty traditional especially in the Northeast for the first quarter of every year to not grow a whole lot over the fourth quarter. I mean, you've got wintertime, you got everybody's in a real crunch at year end and there's a lot of maintenance and things that happen in January, February, March timeframe. So that's pretty traditional and so that kind of helps explain it.

Our next question comes from Mike Scialla of Stifel, Nicolaus. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: You've given a lot of guidance on your plans for infrastructure and agreements that you've entered into for ethane. I'm just wondering given some recent weakness in propane prices, what are your thoughts on the other NGLs and maybe condensate as well in terms of where you see price going and would you be willing to hedge more here?

Well, I would and several of us will probably chime in on this one. I would say we have continued to hedge the condensate price that we received now is basically close to oil price for that area. So that's encouraging. We are hedging. We'll continue to look out to hedge to lock in the strong returns that we have. So again, you got to look at the whole program of, we have a very rich gas. And in order to build and grow volumes, you got to handle the ethane. But that's a good thing because the ethane is an enhancement to the economics and will add value over time, creates more space in the pipelines to move more gas and more liquids. So I think we're in a great position.

And just add on what Jeff said. I think the key here is you want to grow volumes and reserves, but you also really want to focus on growing your cash flow. And where going to get the biggest bang for your buck given where oil and gas prices are is obviously the condensate and NGLs. So we're aggressively hedging those out because there's such high prices. And we got great markets in the Northeast for those. And MarkWest is doing a good job in terms of storage and selling and all the contacts that they've got. So we are aggressively hedging our condensate and our NGLs up in the Northeast. And you'll see that on the hedging program slide and you'll also see it in the quarters -- the months and quarters to come. You'll see us continue to hedge that. And we talked about it a lot at the board, so we're going to take that price risk off the table. We like those prices a lot and we'll accept those because we make such great rates of return.

On your condensate up in the Marcellus, it's about 84% of WTI posted prices. So that's selling at $84 to $85 a barrel up there, which typically has -- it's probably $5 or $10 more a barrel than what it traditionally has been. So you're C5s and your C4s and your C3s, which are your heaviers really have had a very stable and increasing price over the last 6 months. Where you've had a little weakness is propane. Propane is primarily a heating fuel. We didn't have much of winter. So therefore, you've got a weakness there. You've had a weakness in the ethanes, which basically is because you got 2 crackers down off the Gulf of Mexico. So it's going to have some seasonality and they always do a lot of maintenance at the first part of the year. But with our C5 proxy hedges that we're working off of, we're actually locking in on the heavy side of the barrel, the liquids and we think that will give us some uplift to the weaker side of the barrel until we know exactly what our ethane productions are, et cetera. And then in 2013 and '14, be able to move and be able to bifurcate that barrel to hedge both the heavies and the lights appropriately. So we're just working there, but that's something we look at every day. And we hedged some C5s yesterday, probably at $6 above our average of what we have got built into the system. So it's a thin market. You just do it when you can. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: I appreciate that. Looking at your presentation, you show well cost in Southwest Pennsylvania for your wet area of $4 million for your 5.9 Bcf type well. Is that a projected development mode kind of cost or representative of what you're seeing recently?

Well, when you look at those -- it's interesting when you look at the cost we have in the development mode and by area particularly, I'm glad you asked. When you look at the wet area, when you look at existing pad drilling down there, they're straight away wells or right at about $4.4 million, some of them as low as $3.8 million. The wider swing outs maybe $4.3 million, $4.4 million. So that number, we basically achieved the development mode cost for that particular area. I would also say for the horizontal Mississippian play, when we're seeing in a development mode, we're basically at those costs. And theoretically, in a development mode, if we've got 1,000 or 2,000 wells to drill which could be if it all drills out, I expect that team will do 1 of 2 things like they have in the Marcellus, either significantly drive down costs or we'll have longer laterals with higher rates of return or longer laterals with more stages and higher rates of return. Also when we say development mode cost, on the Cline Shale same thing, it's what we're drilling them for today. So hopefully that answers that question.

Yes and I'll just add a little more color in that. We are really excited about this reduced cluster spacing in the longer laterals. So we will be drilling longer laterals. And we'll be putting more fracs per foot of lateral. And that's all going to increase cost. And so you may see cost on a well-by-well basis that are higher than some of the numbers in here, but that's because there's a lot more money spent on completion. And consequently, we'll get a better return with more reserves that, that well produces. So it's a little bit of apples and oranges, but that -- what we try to do is take the average of the last 188 wells that have been drilled in that area and that's the kind of numbers that we come up with.

Yes, let me just pile on to Ray a little bit. What we've talked about is the wet area having very strong economics. But the super-rich area, because of the higher liquids component coupled with the longer laterals or more stages, are moderately longer laterals with more stages, it's even an enhancement of that.

Right.

Ray also mentioned a couple of the wells in the wet area where we've tried longer laterals and more frac stages and reduced cluster spacing and those wells look really attractive. We didn't tell you the rates of return, but if we drill more of those types of wells in there, we believe we can really even potentially enhance the rates of return in the wet area beyond where we are now with that new technology. And throughout the year, towards the end of the year, that should be another significant improvement to what we're doing. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: That's helpful. And this is probably a dumb question. But I'm just wondering, with gas prices as low as they are and really almost all the value in the wet gas, part of the Marcellus being driven by the liquids and you mentioned earlier that the very low recovery factor, have you looked at all at the feasibility of reinjecting the methane, could that help maintain reservoir pressure and maybe improve the liquids recovery?

Let me come back and clarify what you're saying. When I was talking about lower recovery factors of 4% to 9% of the hydrocarbon in place, I was referring to the horizontal Mississippian oil play. So one, I want to clarify that. The second one is when you look at a shale and reinvesting gas in, it's just too low permeability. Again, gas prices are where they are today, our economics are strong. Personally, I believe at some point in time, and I can't tell you whether it's -- or even if you look at the strip, when you go out a few years, I don't think gas is going to be $2.50. Gas maybe $4 to $6, or $4 to $5, or $4.50 to $5.50 but I expect that gas at some point in time will move up a little bit. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Okay. I thought that was a dumb question. I'm glad you clarified that. Let me end with one last one. Looking up at Venango County in the Northwest part of the state, you mentioned you have drilled some wells up there. Any color around what you're seeing up there?

We -- I want to clarify that. We're saying we will drill in the Utica up there in the summer and spud a well there. But given the well control that we have from looking at old wells and even current wells around us, we feel that our acreage is very prospective for wet Utica and for having the Point Pleasant.

Our next question comes from Dan McSpirit of BMO Capital Markets.

You illustrate what percentage of your Marcellus shale acreage is held by production today. What are the same ratios look like say, over the next 1 to 2 years from the Southwest to the Northwest and I guess to the Northeast of Pennsylvania?

Well, let me see if I can handle it, to start with the easy one. Northwest is 100% HBP today.

Well the -- we have the -- let me clarify that.

Almost. Yes.

If you look at the traditional Cooper's timeframe of an area, which is where the bulk of our acreage is, it's all HBP. We've added a little acreage in and around the fringe so that number is 83% HBP today.

Oh, okay, okay.

So but I think right now it's showing 47% to 51% in the Southwest and Northeast. You're probably going to add roughly 10% per year to that. But let me talk about a really important point there, so if we look at the 3 areas, the Northwest is pretty easy. I mean, you can drill a hole that, we'll see what the Utica looks like. That isn't an issue. In the Northeast, this is really an important point. We talked about we have the ability, if we choose to do so, to take the roughly 4 rigs we're running in Alabama to -- a rig or 2 at the end of the year and a minimal program next year. The way we can do that is those leases up there tend to be bigger leases and there's continuous drilling clauses with them. And I always use the example of the best one. So I'm telling you, it's the best one. But we have one lease up there that's 25,000 acres. And literally, it just requires one well per year to hold the lease in perpetuity. And as long as you drill one well per year. So to HBP it would take a lot of drilling and take a long time. But we can hold the acreage for the next 50 years by just drilling one well per year. And a lot of those leases are 1,000, 2,000, 5000-acre blocks. That's what gives us the ability to cut back to 1 to 2 rigs next year in the dry area. If you look at where we really need to drill to HBP, it's primarily in the wet and super-rich area in the Southwest, which fortunately is where our highest rates of return are. That's where we have a lot smaller leases, and we really need to drill to hold more. So that's -- and then the other part of that is if you look at the Southwest and on the map, it shows super-rich dry or super-rich wet and dry, most of that dry acreage in the Southwest is HBP by old -- by shallow legacy production, just like most of the stuff in the Northwest is. So really, it's a little better than it sounds. That's why we have a lot of flexibility to ramp up or down in certain areas or direct our dollars to where we think we're going to get the highest rates of return.

And just to pile on to that, if you look at our capital budget this year, the great preponderance of our leasehold dollars will go towards the Southwest Pennsylvania and locking up and continue to...

In Southwest PA, wet and super-rich.

Yes, and to build that position and continue to fill in and whatnot. The good news is we own, we're the 800-pound gorilla in that area. So we're in great shape there. But the bulk of those dollars just to give complete transparency is going to go there. And there'll be a little bit of money out on the Cline Shale and the horizontal Mississippian, but the bulk of the dollars are going to go into Southwest PA as Jeff mentioned.

Okay, got it. And second question here. You continue to demonstrate higher yields on lower cost in the Marcellus. Can you speak to at least in general terms your -- where you go from here? That is, what could drive the next step change in targeted economics? Is it including the ethane stream?

Let me start and I mean, Ray and other people, we're going to give you joint team answers today to show the integration of our team or the excitement I have that I had to jump in, in front of Ray. I think that it's really interesting when you look at the rates of return in the wet area and the upgrade by going to the super-rich. We're taking a well that's rate of return at strip pricing in the 70s up to the mid to high 90s by moving into the wetter areas and into the super-rich, just the quality of the type of reservoir fluid coupled with moderate length laterals with more stages. I think the next big jump will be taking that same technology and just doing it in the wet area. And the evidence of that is we've tried it on 2 wells. What we didn't show you but we have are the rates of return of the wet area. So we want to get a bigger sample set and we want to make more history. But it could be we can then significantly improve what's in the wet by drilling and completing them differently than we have. I think that's the next big change and it may not be that far out there. And Ray, you can -- and the other thing with Ray, other than being a great guy and a good -- a great manager, he's really strong technically. I think one of the best completions guys out there. So now with that big build up, what's next?

Wow, I'm excited to hear what I'm going to say. Well, I think what I envision as the next big steps is, one is this reduced cluster spacing. Because coupled with everything that Jeff was talking about in the liquids rich play and our better understanding of all of that. This reduced cluster spacing, which is not really that new. It's kind of a term that we use, but it's essentially putting more fractures along the wellbore in a better optimized position, let's call it, that's reflective of that particular situation. We're seeing some real step changes in performance. And that's pretty exciting. I've often been asked what's the most exciting thing or most surprising thing about the Marcellus today and it's been just simply the rock. It's mother nature who was really good and she put some really good rock. And for lots of different reasons that I won't go into, Range finds itself with I think some of the best rock that there is anywhere. And so past that, it's really going to be our technical team becoming better and better, able to understand what the rock's telling us. We're continually improving our reservoir description capabilities. In other words, to try to describe exactly what the porosity and the permeability means, exactly what the thermal maturity means, exactly what the Btus, exactly what kind of conductivity we need in the wellbore. And then past that, I think we're seeing a real step change in the quality of the service industry in Pennsylvania. I mean, we went from -- when I first went up there in 2006, being so bad that I'd really won't talk about it here, to a point today that all of the latest, greatest technologies and things that are happening are happening in Pennsylvania around the Marcellus. And so we are very much a company that likes to apply technology off the shelf. And it's really the, finding the people that understand the right way to apply that technology. And then trying to optimize performance not only on a well-by-well basis but on a project basis over several years. In other words, we could drill really long laterals and make great big reserves and IPs, but our project for the year might get less return than it would drilling moderately long laterals and getting wells online faster. So it's going to be a real evolution and I kind of handicap us as being in inning 3 or 4 of a 9-inning baseball game. We've made great deals. We're way out in front, but we got a long ways to go. So...

And let me add a little bit. I talked about something that we literally could experience this year not that far out and that's just taking that technology and applying it in the wet area. Ray talked about some things that can go on beyond that. And then I'm going to paint the picture for 5 to 10 years down the road. I mean, they can even get more exotic, assuming the Upper Devonian really drills out, can you have stacked laterals off the same pads or all kinds of things like that. Beneath there, we don't talk about, but you actually have dry Utica. We're excited about the wet Utica in Northwest PA, but there's a bunch of dry Utica right underneath that same acreage. You'd literally have 3 stacked pays there. Might you have triple stacked laterals in year 10? Who knows. But I think -- but what I can say is historically for the whole history of the industry, technology has improved consistently with time. And I don't expect that it will stop.

We will go to Jon Wolff of ISI Group for the last question.

I'm just thinking about the commercial acreage. I think you said 315,000 in the wet gas area. There's a significant amount of acreage to the east of that, which you -- a couple in your southwest acreage out of Westmoreland and Fayette. I was curious if there are wells there and what your feeling was. And then when we think about the commercial acreage that's outside of the sort of 700,000 that you talked about, when we look at like Venango and some of the northern areas, wouldn't they pose perhaps lesser economic risk than some of the dry gas in the Southwest?

Well, let me say, and if you look at the dry gas in the Southwest, again, a lot of that acreage is HBP by legacy shallow wells that we control and operate. So I think that the potential of that acreage given drilling in and around there, there's no doubt it's prospective for the Marcellus and there's some good wells in Fayette County, in Westmoreland, Armstrong County, I think EQT has a 16 million a day well. And we've got wells on the edge of it that are that good or better. So I think that acreage in time will be very attractive. When you go up to Northwest PA, I think it's very prospective for Utica. We've got some control on the edge of our acreage on either side of it that shows -- we know where the oil, wet gas contact is. And I think we believe we have a pretty good feel for the wet gas dry contact. Our acreage is sort of right in the fairway. We believe we got Point Pleasant on it. So I think that acreage position is very prospective. It's at a reasonable depth, not unlike what we're drilling in the Marcellus. Long term, a lot of it, well, almost all that acreage is HBP, 83%. So it's a big chunk of it. It is held by old historic Medina wells at about 5,500 feet. Up-hole there, you have Marcellus potential and we actually tried one well in the Marcellus. We haven't reported it. But it was an interesting and I'd say somewhat encouraging first try. It will be something down the road or something we can look at how we take value out of it. But there is, I think there's no question there's value on that acreage. It's wet gas, so that's very interesting. And then I think when you go up to, our acreage position in the Northeast, again, it's new technology. We announced really we've got 4 wells. We talked about 2 of them in the release. But if you look on the website, it shows there's a couple of other wells on the big blocks we have up there that are encouraging. There's other horizons behind pipe. It's really lightly explored. So I think there's a lot of upside on all that acreage. But because a lot of it's either HBP or we have these really good favorable drilling clauses, we can direct and focus most of our near-term capital in the areas that have really high rates of return and we're retaining that upside for another point in time.

Okay. And on the Utica plan, you'll drill a well soon, spud a well soon.

That's probably around the middle of summer of this year.

Okay. So do we have any feeling of what point you'd say some of it's de-risked or not de-risked on the 330,000 acres up north?

Well, I mean the first well is good. I'll be very encouraged because we got pretty good control. So if the first well is good, I'd expect that future wells probably would be. But again to be conservative, we'll do what we've done in some of the other plays, we'll probably just scatter a handful of wells probably over the next 12-month period past that, across that acreage position to show what our acreage is. But we're also looking at, there's a lot of industry activity that either has or will be occurring in and around our acreage. So I think that's a very exciting upside.

I've never been a big fan of selling acreage in your core areas, but given the capital need as potential for super wet, a lot of super wet gas, is any of the dry gas acreage potentially JV-able or saleable perhaps in the Southwest dry?

I think we'll always look at optimum ways to run our company, optimum levels of growth and optimum ways. We look at NAV. Really, what we're looking about is how do we maximize the value our company. And a lot of that depends on the quality of the acreage. It depends on what you think future of oil and gas prices are going to be and what the market is for those pieces. So we'll continue to stay focused on maximizing the value our company. And we'll be open-minded about that. That being said, everybody around the table here, people on the call, it's a huge part of their net worth. So we're aligned with the shareholders and each -- every individual in our company is a shareholder. It's an important part of our culture. So we're aligned with you.

And I might have missed it, but was there any talk about a potential third NGL or ethane solution such as at Mariner East and how likely do you think that is?

We're continuing to look, yes, we really think we have an opportunity to really drive up volumes in the wet and super-rich areas. So these first 2 ethane solutions are just that. The first 2, we're looking at other solutions. Mariner East is one of them. There's some real advantages to that in terms of where you can potentially bring the product. And we'll be looking at growth and expansion. And I think you'll hear more and more about that with time.

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

I'd like to close with what I believe are the 4 main takeaways for Range. First, we have a very large acreage positions and some of the best plays in the country, led by the Marcellus. Given the acreage we have, we should be able to achieve double-digit growth in production and reserves on a per share basis for many years. Second, given the high quality of our acreage and the plays that we're in, we should continue to be one of the lowest cost producers in our peer group. Third, given the good financial position that we have, which Roger just described, we can clearly fund our 2012 program with cash flow and existing liquidity without levering up the company and keeping our debt-to-EBITDAX ratio at or below 2.7x. For 2013, we believe we can grow 15% to 20% within cash flow, if we choose to do so. Finally, the 5 enhancements to our portfolio, the super-rich Marcellus, the super-rich Upper Devonian, the wet Utica, the horizontal Mississippian oil play and the Cline Shale oil play, all offer significant upside to the Range story. These 4 keys will drive shareholder value for years to come. Thank you for participating on the call.

Thank you for participation in today's conference. You may disconnect at this time.