Welcome to the Range Resources Third Quarter 2013 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 risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. [Operator Instructions] 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 outstanding results for the third quarter of 2013 with record production and a continuing decrease in unit costs. Both earnings and cash flow per share results were greater than First Call consensus. The order of our speakers on the call today are Jeff Ventura, President and Chief Executive Officer; Ray Walker, Senior Vice President and Chief Operating Officer; and Roger Manny, Executive Vice President, Chief Financial Officer. In addition, Chad Stevens, our Senior Vice President in charge of marketing, will be available to answer questions after our prepared remarks, and Mr. Pinkerton, our Executive Chairman is also available. Range did file our 10-Q with the SEC yesterday. It should be available on the home page of our website, or you can access it using the SEC's EDGAR system. In addition, we have posted on our website supplemental tables, which will guide you in the calculation of the non-GAAP measures of cash flow, EBITDAX, cash margins and the reconciliations of our adjusted non-GAAP earnings to reported earnings that are discussed on the call. Now let me turn the call over to Jeff.

Thank you, Rodney. Before we get into the details of the third quarter and into Q&A, I would like to say that Range has a really simple story. At Range, we believe we have the opportunity to grow production 20% to 25% per year for many years. This is led by our Marcellus Shale position in Pennsylvania. Growing on a compounded basis of 20% of 25% per year means that we can double our net production every 3 to 4 years. Not only is that great growth, it comes with some of the best returns in the industry. As shown on Slide 28 in the investor presentation on our website, our pretax rate of return for our super-rich wet and dry areas in the Marcellus in southwest Pennsylvania is currently projected to be about 100% for all 3 areas. What differentiates Range from its peers is the size and quality of our position. We have approximately 1 million net acres in the state of Pennsylvania. When the stacked pay potential of the acreage is considered, we believe it's like approximately 2 million net acres. This is shown on Slides 9 and 10 in the investor presentation. We're also advantaged in that a lot of the acreage in Pennsylvania is in the southwest part of the state. When mapping hydrocarbon in plays for the Marcellus, the overlying Upper Devonian shales and the Utica/Point Pleasant play, the southwest portion of Pennsylvania, and notably, Washington County is the only place where you can stack all 3 horizons. Stated another way, if you consider all 3 horizons, the maximum hydrocarbon in place is in southwest Pennsylvania, with Washington County being an optimum place to be. This is shown on Slides 11 to 14 in our investor presentation. The southwest Marcellus offers other advantages. This…

Thanks, Jeff. Over the last few calls, I've discussed many of the technologies that we've introduced down hole, things like RCS completions, enhanced frac designs, better targeting and increasingly longer laterals. Not only do our teams do a great job down hole, they are also making impressive strides on the surface. One of the best measures of that performance is direct operating expense, and compared to the prior-year quarter, our direct operating expenses on a per unit basis are down 15%. In the southern Marcellus, we averaged 166 frac stages per month in 2012. And this year with the same amount of frac crews and equipment, we're averaging 196 stages per month, which is a staggering 18% improvement at this stage of the development. Last year, our facilities team, who developed the first 0-vapor protocol designs in the basin, was building facilities that already exceeded the new EPA standards, which in and of itself is a great accomplishment. Recently, they fine-tuned that design, resulting in a 20% upgrade in condensate pricing at some of our sites. And they're working on expanding that application, which we expect to add real value going forward. They were also able to realize a 15% reduction in facility costs this year at the same time. On the land side, we're developing 75% more acreage per pad year-over-year. So when considering operating expenses, facility designs, logistics, marketing and even the efficiency of which we're developing our acreage, I believe our teams are among the best out there, and I want to congratulate all our teams across the company. We are exceeding our operating targets across-the-board. Third quarter production for the company came in at 960 million cubic feet equivalent per day with 23% liquids, which was above the high end of our guidance, which was 940…

Thank you, Ray. Over on the financial side, the third quarter was positive and predictable with another quarter of substantial cash flow growth, approved cash margins and continued unit cost expense reductions. Revenue from oil, gas and NGL sales, including cash settled derivatives, was $424 million, 20% higher than last year. Cash margins for the quarter of $2.74 per mcfe were up 7% from the third quarter last year and slightly higher than the second quarter of this year. Cash flow for the third quarter was $244 million, a 29% increase over last year's third quarter, while cash flow per fully diluted share came in at $1.51, 28% higher than the third quarter of 2012. Third quarter EBITDAX was $286 million, 24% higher than last year. GAAP net income was $19 million for the third quarter, while earnings calculated using analyst methodology, which excludes asset sales, derivative mark-to-market entries, various nonrecurring items, was $57 million or $0.35 per fully diluted share. As Rodney mentioned earlier, the non-GAAP measures I just mentioned are fully reconciled to GAAP on the various supplemental tables posted to the Range website under the Investor Relations tab. Looking briefly at our cost performance compared to guidance for the third quarter, all of the cost items came in at or below guidance. A few of the cost categories warranting special mention. Our third quarter direct operating expense at $0.34 in mcfe, which continues to fall as we build volumes in our low-cost, high-return Pennsylvania shale plays. Third-party transportation, gathering and compression unit cost was $0.69 for the third quarter. Approximately half the favorable variance to guidance, was due to higher volume utilization of existing facilities and the other half was due to a prior adjustment taken during the quarter. Fourth quarter should see this expense go back…

Operator, let's open it up for Q&A.

[Operator Instructions] And our first question comes from the line of Dave Kistler with Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: Real quickly, looking at the firm transport you added in Marcellus, it's now about 1.5 Bcf a day in 15, would certainly imply a growth trajectory north of 25% if we're just looking at filling those volumes versus FY '13 volumes. If I think about what you've outlined in the Miss and the Permian, it would seem that, that would certainly be putting you on a corporate production growth basis that would be towards the high end of that 20% to 25% for the future years. Can you help me understand why it wouldn't be traversing more towards the high end? Or why you're putting that kind of a range around it at this juncture?

Yes. I mean, one, we're looking at long term. We really believe it will be 20% to 25% per year for many years. And by many years, we've said it in the past, we think we can double in 3 to 4 years, double again and beyond that. So I'm talking about for 5 to 10 years. For a long, long time, we think we have that kind of growth. And I think importantly, when you look at the gas in place maps in there that I think are significant, it's a new disclosure, it helps to really justify why we believe that. And there's a lot of data and a lot of control for that. So I'd spend some time looking at those, and we'll be glad to work with you on them. And then, what we look at are a variety of things. We look at oil and gas prices. We look at infrastructure buildout. We look at timing. Ray has talked a lot about the pace we've drilled at. And with the pace we've drilled at, how just consistently, year after year, the wells get better and better and better. And I think that will continue, so we really try to roll all those things together. And then the practicality of it is, we work on it. We present it to our board in December and come out with -- to the market sometime usually in late January, early February. But I do believe, we can grow for a long, long time at those rates. Some years, it will be at the high end. Other years, it may be in the middle or low end, and that's a function of product prices and timing and all kinds of other things. David W. Kistler - Simmons & Company International, Research Division: I appreciate that clarification. And then just thinking about the multi-stacked pays, sort of the gas in place that you talked about. You've outlined how capital efficiency benefits will come from that. When would we really start to see those capital efficiency benefits rule through? And what I mean by that is when do you think you'll be truly developing Upper Devonian or Utica, given that you're only scratching the surface in the Marcellus interval with about 7% of your identified locations drilled at this juncture? So I completely understand that, that drives capital efficiency growth in the long term. But in the short term, can we expect being able to leverage that stacked pay? Or is that something just to highlight longer-term inventory?

This is Jeff. Let me start and I'm sure Ray or Roger or others will chime in. But one, I think it's really important to look back since we started. Again, I think you've seen capital efficiencies every year, you're right, though, driven by the Marcellus. So we've seen everything, not just production, climbing, but we've seen unit cost in really every single category start to come down. And that will continue on. But you're correct, when you start to add the other horizons, like Ray said, I think that will continue. In the short term, you'll see us -- by short-term, I'm talking about like 2014, a lot of the focus will continue to be on the Marcellus. But like Ray mentioned, and he can talk a little bit more in a minute, you'll see us come out and try a horizontal Utica well in Washington County next year. We're really excited by the prospect. And when you look at the gas in place maps for the Utica and zooming in on page -- if I can get there quickly on Page 13. When you look at the highest amount of gas in place, and we feel good about that, there's a number of control points from old existing wells or even coupled with the modern data and the well just offsetting us about a mile off of our -- the edge of our acreage that has a relatively high rate from a short lateral with not a lot of stages. We feel confident with those maps. So you'll see us try that next year and confirm that, that high rate production that we believe is there. And then you're probably start seeing in '15 and '16 a bigger mix of those types of wells.

Dave, I agree totally with everything that Jeff said, but I want to go back and emphasize what he said earlier. I think we're already seeing a lot of that stuff hit the bottom line. Our unit costs, quarter-to-quarter, we're down, I think, 9%. Our operating expenses are down 15%. We've seen the cost of our facilities on our well sites decrease 15% just from the beginning of this year to today, we've seen our well costs come down and our well performance go up. We are -- at all times, in the Marcellus, we're beginning to go back in to some of these locations that already had the location built. The water impoundment's there. The facilities are already there. We're already doing that in a small way, as we go back in to drill additional 80-acre wells or maybe even to do additional infill well. So I think it's just going to be a gradual process, but we're still very much -- we've only drilled about 7% of the acreage, we've still got a long ways to go. But like Jeff said, we're going to be testing the Utica. We're really confident of what we're going to find there. We've already cracked the code on the Upper Devonian. So we just see a really -- a lot of durability and versatility in our story going forward. And I think that's the real story. David W. Kistler - Simmons & Company International, Research Division: Appreciate that. And maybe just switching real quick to Miss, and I'll let somebody else hop on. When you look at doing these larger fracs there and -- obviously, early days, but increasing the uplift, relative to your previous wells, obviously, that drives the rate of return higher, which would probably put it above, certainly, what you're showing in the Marcellus since they're competitive right now. Does that mean that as we look towards '14, a larger percentage of your CapEx budget could be allocated to the Miss versus the kind of the 17% you're allocating currently?

Well, we're still -- I mean, it's a great question. And we are really, really encouraged by what we see so far. But again, this is only 4 wells. It's only 65 days online. We'll bring 4 more wells on with the same sort of designs in the fourth quarter. We simply need to see more production history on these wells to really understand it. And it's hard to say how long that's going to be, but until we get more data to really support our ability to allocate capital in the Mississippian, we're going to kind of stay at the mode we're at right now and doing some more -- we'll do some more delineation wells. Stepping out, we'll prove up some more areas, and we'll continue to evaluate the larger frac designs. But again, we are highly encouraged. I mean, everything we're seeing right now from the step-out well, from the larger fracs, everything looks really good. But this is still emerging and we'll consider all that when it comes time to recommend a budget to the board in December, and we'll go from there. And I'm sure, we'll announce it like we typically do in February of what our plans are.

And our next question comes from the line of David Tameron with Wells Fargo.

Just going back to the gas in place maps, can -- I mean, you obviously gave us a lot of color during the prepared remarks. But can you talk about how should we think about recovery factors within those? And I guess, we could go back and do a gas in place number for Range, specifically, but how should we think about just recovery factors in those 3 areas?

Well, that's a great question and it's something we talk about a lot at Range. First of all, I think the industry's ability to estimate the hydrocarbon in place is getting better and better as time goes on. I mean, typically in the past, we underestimated that. I think most of us in the industry, we believe, today, we're still underestimating it some. But we've also seen with the horizontal development, the RCS completions, the better frac designs, the better targeting, there's no doubt that we're pushing our recoveries up into the 30% range, maybe 35% range. But ultimately, there are -- probably, the shale with the most history is the Barnett, which is not really applicable or that analogous anymore to the Marcellus because it's so much better than the Marcellus. But you can see things, hear people talk about recoveries up in the 50% to 60% range. Certainly, we've seen that in unconventional reservoirs like the Cotton Valley and the Wilcox and the Almas [ph] and Jonah Field and places like that. So there's no question it's going to go up into those ranges. But how we get there, how long the laterals are, how close we space them together, do we put them in multiple intervals, all of those questions are yet to be determined. It will be years before we get to that point. But I think if you estimate something in the 25% to 35% range, you're going to cover most of what everybody believes today.

This is Jeff. Let me throw a little more color on. These -- my gas in place maps -- and remember they're really hydrocarbon in place because liquids are gaseous in the reservoir. But when you look at the maps, you see clearly core spots, like on Slide 11 in the Marcellus, there's one in the northeast and one in the southwest. And the gas in place or hydrocarbon in place is really critical. The other key part of that would be in addition to the map is permeability, which this doesn't encompass. But it's interesting, that at least from my observations, the higher flow rates and the better permeability tend to be in areas where you have the maximum hydrocarbon in place. So I think the recovery factors, when you are in the core of the play -- and then back to that comment, it's really important where your acreage is or you're core or non-core. And that's true of the Barnett or Fayetteville or Haynesville or any play. So in the core, typically the recoveries are higher. And I think in the core parts of the plays, maybe they'll be pushed ultimately, like Ray said, to 40% of 50%. In the non-core areas, they may be very low. When you're out in the no-man's land somewhere, it may be 5% or 0% or -- so where you are in the plays is really critical. And again, I think that's why these maps are so important. If you think about hydrocarbon in place and then rock quality and where they are, were in the Marcellus, Upper Devonian and Utica, and then sum all 3 together on Slide 14, that's a bull's-eye right on top of our acreage. Going the other way, that's why we leased a lot of the acreage and why acquired and put our roots there.

Okay. And are you at -- I don't know, Ray or Jeff, whoever, are you at 30% today?

Well, the other part of that is -- and I'll turn it over to Alan in a minute, Alan Farquharson, who's our Senior Reservoir Engineer. We've drilled historically because we have such a big position. A lot of our wells are 1,000 feet apart. We announced last time that drilling the wells 500 feet apart that we think that's very successful as well and the recoveries may be on the order very high. They're in the book and you can look at them. We've had up to 3 years worth of history on our infills, so I think the 500-foot spacing will work. As well as -- or some of the other partners or not partners -- competitors, actually, in the area have drilled on 500-foot successfully as well. Peers is probably a better word. So it's not just Range that has said that. EQT has successfully drilled on tighter spacing and others. So I think it's a combination of drilling the wells on tighter spacing, 500-foot, say, or whatever it ends up being; better targeting; longer laterals; more RCS; those are the things that will tend to drive it higher. But let me turn it over to Alan.

Dave, just to add on to Jeff's comments, it really comes down to, as he said, what your spacing is and how you're completing your wells, et cetera. When you get into these plays early on, I think everyone looks at a relatively low end, in terms of gas in place numbers or at least in terms of recovery factors. And then from there, as you continue to learn from it, you expand your recovery faster based upon well performance. What's great about these wells in the Marcellus is you can see that the ones that Ray alluded to on the call that we've updated performance on, these things are really, really flat in terms of well performance. So you're getting a significant contribution from a near wellbore. With that, we think where we currently are is probably, if you look at about 1,000-foot space in between wells in some of those estimates, the range of what you're given is probably reasonable for where we are in the Southwest. We think that with some of the recent productivity we've seen on our wells up in, like Lycoming County, we think that you're going to possibly see us a significantly higher recovery there, in terms of 1,000-foot spacing. So it's a range of outcomes more than anything else.

Alan, let me ask you a question. For the resource potential numbers that we have in our book for the Marcellus, what do you think the average recovery factor that we're currently using would be?

For the resource potential that we're out, excluding the tighter spacing, we are probably in the 25% to 35% range, probably in the low-30s to the 35%. Then, as we added in the infill potential, we think that gets us up into the low- to mid-40s.

And my point being was leading question. The resource numbers that you'll see from us because we're in the areas of the high hydrocarbon in place and with the good permeability, the bias is those numbers will go up with time.

Okay. That's all great color. Let me just ask a second question and I'll let somebody else jump in. In your guidance section of the press release, the total wells planned to sell went up to 196 from, I think, it was 173 before. Is that -- and I talked with David about this a little bit last time, but is that just acceleration into '13? And if so, what's kind of going on there with the thought process there?

Yes. Most of that, David, is in the southern Marcellus. And it's the result of -- it is accelerating some wells, but it's because the guys are just getting way more efficient. They're drilling faster and completing faster. At more efficient use of their capital, they're able to put more wells online than we originally planned. So that's why I made real clear that statement that I said in my prepared remarks that more than or a lot of those wells were coming online in the month of December. They're not really going to impact our volumes at all this year. But the well count officially does go up because that's the way we track it, so it's just timing, more than anything.

And our question comes from the line of Leo Mariani with RBC Capital Markets.

You talked about a Utica well, it sounded like in and around Washington County and it sounded like an industry well that de-risked the formation, at least in you all's mind. Can give a little bit more color here? And then obviously, you talked a lot about southwest PA, getting 540,000 acres. I mean, what percentage -- do you guys have any estimates on what percentage of that may ultimately be developed for the Upper Devonian and Utica?

Yes, that's a great question, Leo. If you flip to Slide 31, you can see it sort of zooms in on our acreage position in and around Washington County. And when we map -- and the key well we're talking about there is that Chesapeake covered well, the 3H. So if you flip to Slide 31 for those of you that can do it real quick on your computers there, the Hubbard well is 1 mile west of our acreage. It's right on the western edge. It tested 11.1 million per day, with a lateral length of 2,900 feet and 8 frac stages, so that was a key test nearby. So you can envision that if you drilled, say, a 7,500-foot lateral or 7,000, 8,000-foot lateral, and you tripled the frac stages from 8 to 24, if it was proportional, that well would be over 30 million per day. Even if you pull it down a bit, you got 25 million to 30 million of per day type potential. A really important point, though, is that's a test nearby. There's other wells that were drilled historically in and around Washington County or, say, in Washington County, that we have control on that were drilled for -- they're old Trenton-Black River tests or deeper tests to give us control points and relatively modern logs to know what the Utica/Point Pleasant thickness is, what the porosity is, what the water saturation is, what the reservoir pressure is. All those types of things that you use for math to get gas in place. So when you take all that data -- plus we have a 3D seismic over basically a lot of that acreage. So when you take all that and you integrate that in -- back on Slide 13, you can see…

Great. Really helpful color here. I guess, is there, based on your mapping and the logs you've seen -- people have drilled through the Utica. I mean, is there kind of a ballpark kind of amount of target acreage? Is it safe to say something like more than half of your acres [indiscernible] perspective, can you throw out any color [ph] about stuff like that?

Sure, go back to Slide 10 and we tried to do that there. When you look at that dry acreage, we think 400,000 acres of that is perspective. So the orange and red blobs, ultimately, will correspond to about 400,000 acres. 400,000 acres with all that gas in place and you multiply it out and then put a recovery factor on it. If you've noticed, we do not have any Utica resource potential. I think you'll see that come in, in a big way and verified by the well that we'll drill next year.

Okay. That's helpful. And I guess, just jumping over to transportation. Obviously, guys, you focused a lot of that in your press release and your prepared comments. Can you just maybe just talk about sort of your longer-term transportation goals? I mean, do you guys intend to get a lot of the gas kind of out of the basin, potentially go into the Midwest, Midcon or Southeast? And can you maybe talk about how you see that trending over time in terms of you all's goals?

Leo, this is Chad. Thanks for the question. As we've seen the play grow and the volume of gas grow, we've focused on diversity, diversity pipelines and transportation, markets and buyers, and how we sell our gas, what industries we sell our gas into that spreads our risk and spreads our opportunity. So yes, we're now looking outside the basin, have been for quite a while, looking to the Midwest and the Southeast. And as we do so and layer in firm transportation, you'll see more of our gas sold at indices outside of the Appalachian basin.

And our next question comes from the line of Matt Portillo from Tudor, Pickering, Holt & Co. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Two quick questions for me. Just back to the Marcellus for a second. With the multiple stacks potential, I was wondering if you could talk a little bit about kind of planned pad development. And ultimately, as you guys look at the multitude of horizons here, how you may adjust the number of wells per pad or how that may improve some of the drilling efficiencies you guys are seeing? And then I have a second follow-up question just in regards to your Permian acreage and some of the drilling you're doing there.

Sure, Matt. It's a good question. We typically design these pads for more wells than we actually drill, the first pass-through. We will typically drill anywhere from 2 up to 6 wells per pad in today's world. That's trying to optimize our capital efficiency and that we get economies of scales, the more wells we put on a pad. But yet we're still trying to build infrastructure and delineate all of those different issues by stepping out as much as we can and doing that. As we go back, we have the ability to put a whole lot of wells on there. And I don't know if we could quote a number today because we've had various evolutions of designs as we go forward. But I think there will be a point in time where you could have 20, 30, 40 wells on a pad. There's no question about that. The real technology breakthrough that we need going forward is the ability to do multiple laterals out of a single wellbore. That technology does exist today, but it's extremely expensive. It's just simply cheaper to start over and drill a new grassroots vertical for each well today. But I think there's no doubt that, that's coming down the road. And what the good news is, in our overall long-term design -- and again, I can't stress this enough. We look at this project, really, for a long, long term going forward, 10, 15, 20 years out, because we think we have the resource potential as we've continued to demonstrate with gas in place maps. We keep rolling out more information as we gain confidence in history and have become very confident of what we're putting out there, that we can actually grow this for many years. So that's in all of our plans for midstream infrastructure, whether it's compressors, whether it's processing plants, how we power those compressor stations and processing plants. We're looking at how we would stack wells together, how we would handle condensate on these well site facilities. All of that's going into that plan. So to answer your question, although I can't give you a black-and-white answer, is it's a lot of wells. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And a second follow-up question, just in regards to your Permian drilling program, could you give us a little bit of color on, I guess, just around the acreage that you have in kind of the southern Glasscock area. And then as you guys mentioned, kind of the step-out Wolfberry test, I wanted to know kind of the implication on the number of locations. I think you guys mentioned up to 1,000 locations on 20-acre spacing, and how you may be able to accelerate development if that's kind of successful with incremental delineation here?

Well, let me -- on Page 67 in our presentation, for those of you that can, is a good map showing that. But we have about 100,000 acres -- 90,000 to 100,000 acres, that's all HBP. It's the legacy position. We've got hundreds of wells across it. We've tested virtually all the intervals, pretty much all across the field now at one time or another. Our Wolfberry program this year, we allocated it some additional capital out there. They were making really good progress. I think the wells were -- we were projecting the EURs over 200 Mboe for about $2.3 million. In 14 wells this year, they drove the cost down to less than $2 million down to $1.9 million range and the EURs look like they're going to be at expectations, if not better. So that was a really successful program. One of those wells -- typically, we've shown the Wolfberry potential, on Page 68, as the west edge of that field. One of those wells that we drilled this year was over in the east side. And it's turned out to be a really decent well. We've still got some things to figure out. There's no doubt about. It's one well. It's early, but we think it now potentially opens up 800 more locations. There were 200 20-acre wells on the west side, so this could open up the rest of the field. We say that because we've got so much log data and historical information as we've drilled through it in the years past. As far as the Cline and the Wolfcamp, we potentially have Wolfcamp horizontal potential in multiple Wolfcamp intervals. We're watching that actively closely to the west of us there. And some to the south, there's been some impressive completions. It's very early…

Yes. That's fair. Yes.

And your next question comes from Bob Brackett with Bernstein. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Had a couple quick ones. One was going back to those beautiful gas in place maps. You're drawing that 1,050-BTU contour. If I look at the Upper Devonian, I would've thought that would be further to the east since it's stratigraphically higher? Are you being conservative? Is there potential for more wet gas in that Upper Devonian?

Well, the Upper Devonian's only somewhere between 300- and 500-foot shallower than the Marcellus, so from an age standpoint, it's not that much different. So it may be a shift to the -- very slightly, but it's very slightly if at all. Also remember, we've got almost as much information on the Upper Devonian as we do the Marcellus because every time we drill a Marcellus well, we drill through the Upper Devonian. We get a really good indication how thick it is, what's there, every time we go through it. And we've done enough testing now, and us and our peers across the basin, I think, we've got a real good confirmation of those analyses that we've performed to date. So we feel pretty confident in that Upper Devonian map. I mean, there's a lot of data behind that and it should hold up really well. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: The follow-up is kind of further down the road. Have you guys given any thought to how you might develop some of the more Pittsburgh metropolitan area? I mean, clearly, you've had experience in the Barnett in a pretty densely populated area?

The short answer is no. We're not going there. We don't really have experience in the Barnett. I mean, Range never did that in the urban areas, per se. And I don't know -- I mean, there's still a moratorium on drilling inside the Pittsburgh City limits. So I can't imagine anybody wanting to tackle that. The urban development, coupled with the surface topography and all that, it's just going to be a nightmare. So trust me, I used to live there.

I grew up there. Pittsburgh's a lot older city. It's a lot more urbanized. And we have such a great position in areas where we can operate. So we're going to stay focused where we are.

We are nearing the ends of today's conference. We will go to Doug Leggate with Bank of America for our final question.

I want to go back to the 500-foot spacing question, if I may. I wanted to try and understand what this means in terms of your development plan. I know that you're HBP acreage is essentially done. The 80% interference number, I guess, an 80% EUR number, I guess, it was mentioned in the prior presentations. How should we think about the primary development pattern? Are you going after the 1,000-foot first and then do the infills? Or what's the implication if you do the 500-foot from the get-go? And I've got a quick follow-up please.

Well, that's a really interesting question. And to answer your question, we're probably going to do both over the next couple of years. We're actually going back into -- next year into couple of locations to drill some 500-foot infills. So I think several months after we bring those wells online, we'll have data to talk about. We're also going to be looking at some 500-foot grassroots developments. There's a lot of advantages, potentially, to that in that you get a better, more complex fracturing network when you frac the wells closer together, stress shadowing and some of those impacts can be a real positive influence on your results. So we're really interested in all that, and we're starting to develop those things. We took a lot of time to look at our 500-foot spaced wells versus the 1,000-foot spaced wells before we came out with that data earlier this year because we wanted to have a high degree of confidence in what we were putting out. So we feel really confident in those numbers, but again, there could be a lot more potential upside. And again, we only put out data for the wet and super-rich. We will be working on the dry area, too, just to see if -- what the numbers look like there.

My follow-up, I guess, my last question. No one has really talked about the Mississippian too much today. I'm just wondering if you could -- I know you've gone back to the more aggressive fracs. How are you feeling about how that asset has now been de-risked relative to your expectations? And I leave it there.

Well, earlier this year, as all our teams are focused very much on lowering costs and becoming more capital efficient. Earlier this year, we tried some smaller frac jobs and, of course, we talked about on the last call how the results didn't look that good. We've now gone back to pumping a much larger fracs and those wells look really, really encouraging. We're pretty excited about it. And -- but again, it's only 4 wells. It's only 65 days. But they're substantially above the 600 Mboe curve. We did a step-out well that's got really, really good oil production. It's about 85% oil, which is way higher than anything else we've seen. Even with these larger fracs, we're keeping our well costs flat at $3.2 million, and I expect the team will be real successful even driving that down. So we think the play has got a lot of potential. It could be a really nice oil play at 4,500-foot or less. In Oklahoma, I mean, it just doesn't get a lot better than that. So we're pretty excited about it. The team up there is pretty excited. They're doing a great job. But again, we just need more time. We need to make sure that, like we do in all our plays, like we've done in the Marcellus and everywhere we've worked, we try to make really data-based decisions, performance-based and it's all about performance and reserve growth per share and keeping our cost structure low. And all of those things are really important to us, and so were going to take our time and make sure that play is emerging for us. But all indications at this point are really good.

Jeff, is the Woodford perspective on your acreage?

I'm sorry, you broke up on the first part of that?

I'm sorry. Is the Woodford perspective in your Mississippian acreage?

Yes, there is a some perspective Woodford, especially on the southern end of our acreage. We haven't tested that yet but we're monitoring some offset activity. I think Devon has drilled some wells and there may be a few others now that I hadn't kept up with. But our team up there is watching that really closely, and we may test that at some point.

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

As I stated at the beginning of the call, Range has a very simple story. Given Range's large, high-quality, low-risk acreage position and drilling inventory, we continue to believe that we have 20% to 25% line-of-sight growth for many years. Led by our approximately 1 million net acre position in Pennsylvania, we project that we'll consistently drive up both production and reserves on a per-share basis, net adjusted for years to come. We believe that this plan will translate into substantial shareholder value in the months and years ahead. Rodney just let me know that there's still at least 15 more people on there that have questions, so I'd encourage you to follow up with our IR team, and we want to get all those questions answered. Really appreciate everybody being on the call. Thank you very much.

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