Welcome to the Range Resources' Third Quarter 2014 Earnings Conference Call. This call is being recorded. [Operator Instructions] Statements contained in this conference call 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 turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, operator. Good morning, and welcome. Range reported results for the third quarter with record production and a continuing decrease in unit costs over the prior year. The order of our speakers on the call today are Jeff Ventura, President and Chief Executive Officer; Ray Walker, Executive Vice President and Chief Operating Officer; Roger Manny, Executive Vice President and Chief Financial Officer; and Chad Stephens, Senior Vice President, Corporate Development. Range did file our 10-Q with the SEC yesterday. It should be available on our website under the Investor tab, 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 reconciliation of reported earnings to our adjusted non-GAAP earnings that are discussed on the call today. Now let me turn it over to Jeff.

Thank you, Rodney. The past several months have been a very challenging time for E&P stocks as Appalachian natural gas prices and now oil prices have been under pressure. We appreciate our shareholders' continued support as the commodity market sort themselves out as they always do. At Range, we remain focused on the things that will make Range and its shareholders successful in the long run, which is executing our plan for low-cost growth day in and day out. As one of the lowest-cost producers with the largest position in the core of the Marcellus, we are excited about what we have in store. Hopefully, in the next hour, you'll have a renewed or newfound appreciation for all the things that are going right at Range and how we've differentiated ourselves. This is the 10th year anniversary of the discovery well for the Marcellus, which was Range's rents #1 in October of 2004. This was the first commercial well in the Marcellus and the one that kicked off the play. It was a vertical well. Range followed with the first commercial horizontal well in August of 2007 and announced multiple successful horizontal offsets in December of 2007. Today, anchored by this discovery, we believe that Range has a simple story. One, Range has the largest acreage position in the core of the Marcellus, and being in the core makes a big difference in shale plays. Two, most of that acreage is in Southwest Pennsylvania area, where the Upper Devonian, Marcellus and Utica/Point Pleasant are all stacked on top of each other, which gives us built-in future capital efficiencies. Three, Range has identified the wells to be drilled that will take us to 3 Bcfe per day and beyond. Four, Range has the gathering, compression and processing plants already planned and…

Thanks, Jeff. For the third quarter, we beat our production guidance and either beat or met all of our operating cost metrics. And we continue to see exceptional well results, lower costs and improving capital efficiencies across all our divisions. Production for the third quarter came in at 1.21 Bcf equivalent per day, and we're currently right on track for our fourth quarter guidance of 1.35 Bcf equivalent per day with 30% liquids. This, of course, will put us at the high end of our year-over-year production growth guidance of 20% to 25%. For the third quarter, as compared to the same time frame last year, the company achieved 26% production growth. And our unit cost and cash flow improved, as Roger will discuss in his remarks. In the Southern Marcellus Shale division, our well results remain the best in the southwest portion of the Marcellus, and our finding costs are amongst the lowest in the entire play. Let me give you just a couple of examples illustrating recent well performance. In our wet and super-rich area, during the third quarter, 4 of the pads, which total 18 wells that we've brought online, had an average 24-hour IP of 16.1 million per day per each well. Again, it's important that I point out that these are actual 24-hour production rates to sales under production facility limited conditions. These 18 wells averaged 4,400-foot laterals and were completed with 25 stages. As I point out, one of those pads was a 5-well super-rich pad where 2 of the wells averaged over 1,000 barrels of condensate per day each, and 2 of the other wells on the pad averaged over 900 barrels of condensate per day each, all for a full 24 hours. In our Southwest PA dry area, we brought online a…

Thanks, Ray. The third quarter brought steady improvement in our cost structure and balance sheet, with continued year-over-year growth and cash flow despite lower realized prices. Starting with the balance sheet this time. Since our last quarterly call, Range has received an upgrade from S&P to BB+ and Moody's with our Ba1 credit outlook from neutral to positive. These upward moves by both rating agencies ratify our continued progress, both operationally and financially. As natural gas and natural gas liquids continue to become true global commodities in the years ahead, our improved credit standing and favorable export contracts will help us continue to compete for long-term customers and new and better priced markets, not just in the U.S. but all over the world. Following the ratings upgrade. Even though Range has continued to add significant, long-term, firm transportation commitments and now has sufficient contracted capacity to see us through many years of double-digit production growth, the amount of standby letter of credit collateral posted behind these commitments has declined by 21% from its peak earlier this year. Posting collateral behind pipeline contracts or taking an equity interest in a pipeline to avoid posting collateral adds the hidden cost of transportation and reduces available liquidity. Credit quality matters now, and we believe it'll matter even more later. Complementing our new credit ratings, Range restructured and renewed for another 5 years our bank credit facility. The facility size was increased to $4 billion. The borrowing base was increased to $3 billion, and we chose an additional commitment of $2 billion. Importantly, borrowings under the new credit facility are priced 1.25% below the old facility, and the new credit contains a fallaway collateral feature that will enhance our future transition to investment grade. Like the old credit facility, the new facility is comprised…

Thanks, Roger. First, I'd like to provide a little macro perspective on Appalachian natural gas. Northeast natural gas supply has grown to a current rate of roughly 60.5 Bcf per day. Half of that coming from Southwest Pennsylvania, Ohio and West Virginia, and the other half from Northeast Pennsylvania. Most of the recent volume growth has come from the Southwest Pennsylvania region, with Northeast PA supply flattening due to pipeline constraints in that area. Base demand in the overall northeast is approximately 12 to 13 Bcf per day, including summer injection. This seasonal oversupply has had a negative impact on regional Appalachian index prices during the current shoulder period. Index prices in other parts of the country have remained relatively stable. As the current shoulder period ends and winter season demand picks up, northeast regional index prices are expected to improve. The good news is the Midstream industry is bringing relief to the oversupplied Appalachian region. Beginning in mid-2015 through 2018, new announced pipeline takeaway capacity from Appalachia totaling an estimated 31 -- excuse me, 34 Bcf per day and representing over $35 billion of capital investment will provide improved supply/demand equilibrium, strengthening Appalachian basis differentials and improving net realized prices. Also, beginning in 2015 and growing through 2020, increasing demand, totaling an estimated 15 to 20 Bcf per day, is expected to come from DOE FERC-approved LNG exports, the majority of which is on the Gulf Coast, increasing exports to Mexico, power generation, especially in the Southeast and pet chem industry growth. As we have emphasized in our third quarter earnings release and in our IR presentations, Range's early entry into the Marcellus has allowed us to secure relatively low-cost, firm transportation, the in-service date of which follow our projected annual production growth of 20% to 25%. We want…

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

[Operator Instructions] Our first question comes from Brian Singer with Goldman Sachs.

You've talked about the increase in your takeaway contracts in detail in your slides over the past couple of months in 2016 versus 2014, but can you talk a bit about 2015 and how those contracts look if we would take away the benefit of Mariner East out of the equation and assume no changes to recent pricing? What you see as the benefits to your margins from the contracts that would be coming on in the next year?

Yes, Brian, this is Chad. As we've alluded to in the notes, there are other areas of the country where the indexes have remained relatively stable. One of those is in the Midwest. We do have, in 2015, some significant volume coming on to take gas through the Chicago, Michcon area, which is -- that's really the main amount that's coming on in 2015. Again, 2016, we have quite a bit coming on that's going to the Gulf Coast. It's really competitive, and we do have some other deals we're working on with NiSource and TETCO that we really don't want to get into specifically. So I can just say that, that level [ph] in lateral Michcon, Chicago volume that's coming on in 2015 is what we want to talk about.

Yes, and I would just add to it. What Chad had mentioned earlier, we're going to get into winter pricing, assuming we have any kind of normal winter, which some of the weather forecasters are saying we will. So we'll get into winter pricing, which is good in Appalachia and with our contracts. And we get into Mariner East propane in the first quarter of next year of 2015. We get into Mariner East ethane at the middle of the year, and all these things are uplifts. And now we get into the better gas price contracts that Chad mentioned, coupled with just the increased demand with the LNG exports, Cheniere starting up, hopefully, and projected to be on time about this time next year. Plus some of the increased Mexican exports and also -- we think that Range is uniquely positioned with ethane contracts and propane contracts and some things that some of our competitors don't have that will give us an uplift in a stable price environment or steady price environment. But we have some incremental contracts and things coming on as well.

And as a follow-up, switching to the Utica. Your Utica heat map [ph] now focuses more heavily on Southwest PA. If your thesis is correct, how would that change how you think about your capital priorities between Utica -- between drilling the Utica versus the Marcellus within Southwest PA? And how strategic would that change, how strategic your Northeast PA position as to the company?

Yes, let me talk a little bit about -- one of the things we do that you just mentioned is our map before for gas in place or hydrocarbon in place was for Utica/Point Pleasant. So we stripped it out and showed just the Point Pleasant since that's the real reservoir target, and that's where the more prolific wells are. And we think it's not just about gas in place, but we think there's other things that factor into it. Another key factor other than gas in place is we think the areas of the highest pore pressure and highest geo pressure really relate to where the high-quality gas wells are. And we've outlined that in green on Slide 14. So when you look at where those 2 things coincide, we have a really dominant position in there, of course, where -- there's old Trenton-Black River wells that gives us the ability to map that, and then we've just drilled, and pet logged, and cased our first well, and we're in the process of completing it. Importantly, when you look at our hydrocarbon in place numbers, there's no potential in there right now for Utica/Point Pleasant. When you look at the acreage map back on Slide 11, in that Southwest -- we have south -- 537,000 acres in Southwest PA on Slide 11. 400,000 of those acres are prospective for Utica/Point Pleasant. So you can kind of do the math yourself, take the gas in place numbers, times that, and come up with what the resource potential could be. Specifically getting into your question, our strategy is to have that well completed, tested, and if all goes well, announced towards the end of December. We'll put that well online and test it, and we have the capacity and ability to…

Our next question comes from Doug Leggate with Bank of America.

Doug, are you on? You may be muted, we can't hear you. Operator, we're not hearing anything on our end from Doug.

Okay, I'll go on to the next -- next question comes from Neal Dingmann with SunTrust.

Say, Jeff, for you or Ray, the first question is, obviously, just -- I was looking at, I guess, the expected wells that come online in the fourth quarter. Certainly, a large number of the wet area in the Marcellus and then, obviously, in the Nora. So I guess, as you look out into 2015, is this an indication of getting kind of the -- indication of, I guess, the direction you're going to go there? Or how do we think about 2015 CapEx directionally?

Let me talk at a high level, and then, Ray, you may want to add to it. What we typically do every year is we -- of course, we have a long-range plan. We've revised that periodically. We present it to our board in December. Upon board approval -- and typically, what we've done is announce it towards the end of January. So our capital budget is not set yet. That being said, I think what you'll see -- and we've talked about it a lot through a number of things like longer laterals and more stages and better targeting and LOE coming down and unit costs coming down, ultimately, land costs coming down, you're going to see the capital efficiency roll through. Roger mentioned, we're already seeing it in the DD&A coming down strongly over time. So we haven't set that yet. Clearly, our budget next year will continue. The value driver will be the Marcellus. And -- but you may see a little bit of incremental capital go towards Nora and/or a little bit in the Midcontinent. But you're still going to see 90-plus strong percentage of our capital being directed towards the Marcellus with the longer lateral wells. Ray, do you want to comment about some of the wells lateral lines in the fourth quarter and a little bit maybe what you're thinking about for the '15?

Yes, sure. Neal, what -- I think we're -- there is no question, we're striving to drill longer and longer laterals. We see that as really improving our capital efficiency. Our team is learning a lot of technical things about targeting and RCF completions and frac designs. We're making a lot of really great progress from what we think is already a leading position as far as well performance because we do have that core area. I think another thing to point out is the mix of wells, I think, will change from time to time just simply because we have -- remember, we have 1 million net acres. We're developing over 500,000 of that in Southwest PA. We have dry, we have wet, and we have super-rich. When you look at our presentation that the economics of those 3 different areas, you'll see they're all relatively close, something over 100% even at today's -- all of today's prices, today's EBITDAX, transportation costs, everything rolled in as it is. They're all very competitive. So HBP is not really an issue anymore. We've got that taken care of. And what we see going forward is just really a focus on driving up our capital efficiency even to higher levels than we are today. And I think you'll just see that kind of ebb and flow between super-rich, wet and dry as we go and as we build out infrastructure and make all that happen.

Ray, just a follow-up to that. How do the -- sort of the near term differentials play into your thoughts about what to drill? I mean, I was just looking, obviously, where your guidance -- we certainly know that just in the near term, the Northeast PA has a little bit wider differentials until some of your FT and other things come online. How do the differentials sort of play into this in the near term until some of the FT and other arrangements come online?

Well, we look at everything on a real-time basis. So we make real-time capital allocations throughout the year. And when you look at the economics in Northeast PA today, again, with all the basis differentials, with all -- everything that the Northeast PA market is challenged with right now, because our team is doing so well with those wells, our well costs are down below $5 million, and we're making wells that are -- have 90-day production of over 20 million a day. Well, some of the top 10 wells in the Northeast PA, those wells still, on a rate of return basis, compete very favorably, even with the wells in Southwest PA. And of course, in Northeast PA, we have -- everything is HBP-ed up there. We can maintain that area with the 1- to 2-rig program, but that's, again, like Jeff was talking about earlier, as we move into the out years, past 2016, when we go cash flow neutral or slightly positive, we're going to start throwing off lots of cash in the outer years. We see Northeast PA as another area that we can ramp up because we do believe, as Chad was speaking about earlier, the increased takeaway projects, the increased demand, that's -- there's billions of dollars being spent on, we believe all of this is going to allow us a great option to able to accelerate areas going forward. And one of those areas could potentially be Northeast PA.

Got it. And Jeff, one last one, if I could. You all mentioned just a large amount of mineral ownership that you all have. Would you think down the line, either '15 or '16, of some sort of monetization around this like one of your peers has done at Perm or? Have you all got any thought to that?

Yes. Neal, this is Roger. I'll take a swing at that one. When you look back 8 years, Range has sold or exchanged over $3 billion worth of assets. So I think we've got a pretty clear history of when we have an asset that we feel is worth more to a different set of shareholders than ours, than we will part with that asset. And I don't -- we don't view this any different view. I think, though, in the case of the Nora royalty, when you look at the low decline underlying that field, I mean, this is an enormously high-quality royalty interest. And I think even as faulty is the valuation might look out there today, I think it's better than most of what's out there. So -- but looking back at our history, we're very reluctant to part with an asset until we know with a high degree of certainty what it's really worth. So for us, the issue isn't so much the front [ph] evaluations that might be out there today. But as Ray was mentioning, the extraordinary improvements that we're seeing in recovery, in production out there, what does that asset going to be worth a year or 2 out. We want to get our arms around that before we make those kind of decisions. I think that's very characteristic of how we've done things in the past and what you'll see us do going forward.

Our next question comes from Doug Leggate with Bank of America.

Two quick questions, if I may. First of all, on the Nora. I don't know if you touched on -- or at least not to the extent that we wanted to on the deeper opportunity in the Nora. Is this a dry gas play in the deeper -- down the basement that you talked about? Or is there a liquids opportunity? I'm just -- and I'm thinking really more about the premium gas market. How does this impact your capital allocation decisions, particularly as it relates to Northern Marcellus? And I've got a follow-up, please.

Yes, let me take that one. Yes, Nora is really interesting, and Ray mentioned we're doing some fairly low-tech things that are really inexpensive to enhance value of the tight gas sands in CBMs and having great success right out of the box. I think we're 10 for 10 or 12 for 12. But it's interesting, there's potential, deeper potential. Some of that deeper potential is in the Devonian section, literally. I mean, by deep, I mean, we're talking 5,500 feet. But there are other horizons as you go below that. According to our exploration, and we'll see over time, some of the upside or optionality is, even though the southern part of the Appalachian basin is subnormally pressured, our explorationists think as you drill deeper, and remember, deeper may be, ultimately, basement. We're not sure where basement is, which is really exciting. It may be 11,000 12,000, 13,000 feet because nobody's ever drilled that deep. There's only -- the deepest -- most of the well stop at 4,000. Some at the 5,500. There's a couple of wells, one goes to 7,000 and one goes to 7,500. But they're old wells, old technology. No 3D seismic and just a couple of old 2D [ph] lines. Our explorationists feel as you go deeper, you actually break back in to normal pressure, and then potentially, geopressure, which is exciting. And they also think some of those horizons, as you go deeper, may contain liquids or wet gas. Well, we'll see with time. The nice part about it is we have 475,000 acres that are basically unexplored deep. Again, deep, being below 5,500 feet, which isn't really that deep in most parts of the U.S. So we have that potential. We own 475,000 acres, 100% working interest and most of 100% net revenue interest. And we totally control the timing. So what you'll see us do in the short run is experiment with some of these completion techniques, which really is just running a higher strength pipe so we can pump at a higher pressure, pump at higher rates, pump bigger fracs and better stimulate the wells. And there, it's fairly inexpensive, and we're seeing, on average, almost double the rates for an incremental cost of, call it, $15,000. So long-winded answer again, but I think there is the potential for higher pressure as we go deeper and there is the potential for liquids.

So Jeff, just -- again, this is obviously arguably a better gas market than your Northern Marcellus. So I guess you're just running minimum activity there any way to hold acreage. But how does it stack up in terms of the overall portfolio, as almost like a diversification play if you like, now that you own the whole thing?

Yes, and we have in the book and there's some slides in there, and Ray talked about it last time. We're just flipping through the slides. On Slide 19, you can see the returns in the -- under various gas prices in the southwest part of the Marcellus, depending on price you use and where you are. Anywhere between about 90% to 120% rate of return. You've got strong returns in the Northern Marcellus there in that -- really in that same range. And then when you flip to the Appalachian slides that we have in there, on Slides, really, 31 -- Slides 30 and 31, we're saying the returns of some of those projects are also up to 100%. So they're all strong returns. The one area that you'll see us focus on drilling again in the short run is the Southwest Marcellus in that that's the only area where, ultimately, we need to drill to hold all the production. To make it really clear, with the leases we have and the drilling plans we have, we'll hold all that acreage within the existing lease terms that we have. So there's no concern over losing it. But we need to drill it to hold it. So you'll see us focus our activity down there. It also happens to be where we have some of the highest returns, and it also happens to be where we have the flexibility of wet, dry and super-rich, plus we have all the stacked pay potential and information that we gather as we drill those wells. But in time, I think there's a great upside in the Nora. When you look at that area, we're making roughly 100 million per day. I think with what we've identified, I think we have the potential to drive it to greater than 500 million per day, with stuff that's already on the books, 500 million could become 700 million. You throw a little bit upside in, and I think there's great potential if we have some exploration success and stuff down in that part of the basin. And it's near good gas markets.

I don't want to labor the point, but can you put a time line on that? Because, actually, what I'm trying to get at is how quickly do you think you...

Yes. I think, what I mean, -- we have it again. We'll present our budget to the board in December because of the fact that we didn't have a JOA with EQT down under. And most areas, you do have a JOA. We couldn't spend capital. So really, capital allocation in Nora has been close to 0. And with last year, I think we had allocated -- or this year $20 million roughly. So we haven't set our budget yet. I think for next year, $20 million may become $50 million, something like that, $40 million, $50 million, $60 million. We haven't set it yet. The year after that, it may become something like $100 million, again, all subject to board approval. And then $100 million may become $200 million. And you'll see that ramp kind of in that time frame. And as we do that, we'll unlock what we believe is great value or out-of-the-box, I think, we're off to a strong start in enhancing the value. And then we can decide that ultimate ramp and how to ultimately maximize the value even from a financial perspective.

Okay. Jeff, I don't want to take out too much time here, but I've got a very quick follow-up, if I may. Just real quick. You've been very good about optimizing capital. When I look at the stock that you mentioned there, I just kind of wonder, when you start talking about Utica, Devonian and Marcellus, all in the same kind of area, what can you do to reduce your surface footprint? I'm thinking about is there a multi-stock gradual opportunity somewhere down the line? Or is it still too early to think about that?

Well, I think one advantage, as Ray pointed out, is we can put a lot of wells on those pads in excess of 20 wells on the pad and to whatever horizon we want. So then you get the ability utilizing the same pads and roads and a lot of the other infrastructure. So there -- but I think you're right with time, having stacked pay like that, there's kind of a free auction of technology in the future of stacked laterals. And clearly, you can drill stacked laterals right now. And then, I'm sure, with time, ultimately, we may be able to drill stacked laterals and effectively stimulate them. So there's a nice upside to what technology can bring. And there's a big advantage to having all those horizons on top of one another, let alone scattered out across different parts of the country.

Our next question comes from Joe Allman with JPMorgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Regarding the new completion techniques and the completion designs, I heard what you said on Nora. I also heard what you said on longer laterals and better targeting. But what design changes do you think are having the most impact? And what are some of the new techniques that you're trying? And can you talk about the differentiation by area?

Ray, do you want to take that one?

Sure. I'll start with Nora. And like Jeff alluded to, really, what it amounted to there is, in the past, a lot of those wells were -- completed limited entry where you put a limited amount of perforations in a lot of different layers and try to accomplish the stimulation with one frac job. Essentially, what we're doing today, by running, investing a little more money in constructing the well with higher strength casing, we can pump at higher rates and higher pressures and allow us to pump more fluid at higher fracture pressures down hole, so to speak. You create more near wellbore complexity and fractures, which, therefore, yields more production. And that's been highly successful at this point. Again, we're early, but like Jeff said, I think we're 10 for 10 or 12 for 12. And some of the best results we've seen in 10 or 15 years, both in the tight gas vertical and the CBM. I think there's a huge potential for us to study and model that further and look at different types of frac designs, different volumes and a lot of things there. Like Jeff said for a number of years, we've not really spent much money there, and we just have really done a lot other than just maintenance type work. So we're pretty excited about that. Shifting to the Marcellus, we're doing a lot of the things. We're just continuing to refine and do a lot of the things that we've been doing all along. And you've seen us, year after year, continue to update our EURs. Our type curves continue to look better. Our results on a normalized per foot of lateral basis have been very consistent. And we think there's still a lot of work to do as we continue…

The only thing I'd add to what Ray said is we're in that maybe third inning of the Marcellus or so. And the Point Pleasant in Washington County, we have first batter up. So we're excited about the first batter. Joseph D. Allman - JP Morgan Chase & Co, Research Division: And Ray, do you think we're in the third or fourth inning in terms of the technological leaps? Or do you think we're in the third or fourth inning in terms of the application across your acreage?

I think it's -- mostly both is the way I would characterize it. I think there's some technological breakthroughs that are being looked at in a lot of different areas, whether it's modeling, whether it's frac design or just pure operations. Even in the well construction side of things, like Jeff referred to, being able to drill stacked laterals or even opposing laterals out of a single vertical wellbore, I think there's some major technological breakthroughs that will happen in the next, I think 3 years or 7 years out, but some of it exists and some of it is just not commercially applicable in our situation yet. But I think those things will happen. And when they do, it'll be a major step change. And none of that is built into our long-range plan, and I think that those kind of things are just going to be more upside for us going forward.

But I would -- I agree with Ray, but what I would add, though is, again, what's really important is to be in the core part of the play, whether it's in Marcellus or any play. So you want to be in the core and about -- on average, about 10% of the acreage is core. And then it's important when you compare cores of the various plays. And the advantage that the Marcellus had is its higher-quality rock versus some of the other plays in other parts of the country. The big technology increases will really impact people in those areas. What you want to have is acreage in the core with high-quality rock, a lot of hydrocarbon in place. And then using high-quality teams, tighter spacing, new technology and better completion and drilling techniques to just keep driving up recovery factors. And I think we're in that position. Joseph D. Allman - JP Morgan Chase & Co, Research Division: That's very helpful. And then are you convinced that you're getting increased EURs versus just bringing production forward?

Yes.

Yes.

Yes.

And the third yes was Alan Farquharson, our Senior Reservoir Engineer. If you heard 3 yeses on the call, so... Joseph D. Allman - JP Morgan Chase & Co, Research Division: I did. And I could say I got that confirmation. And then just quickly, in your Northeast PA, could you just remind us of your takeaway situation there? And is that also -- are you in good shape there, keeping up with production growth? And also talk about any asset, the after-sale right now or in the near future.

Yes, let me just say it at a high level, and then I think we'll probably take one more question. And then we're already running over a little bit. I don't want to run over it too long. The marketing team's done a really good job. We have a long-range plan, which is important part. We have really well-integrated team, everybody from all the engineering, geology, marketing, finance, midstream, all the different pieces. So the plans that we have, long range for that acreage, the marketing team's done a good job of varying the takeaway to good markets for that team as well. So I think in terms of takeaway out of there, I think we're in pretty good shape.

Nearing the end of today's conference, we will go to Dan McSpirit of BMO Capital Markets.

I have several questions, but will limit it to one and one that's maybe more philosophic. If you speak to an improving supply/demand balance in today's press release or yesterday's press release, what are the chief risks to that outlook, whether on the supply or demand side of the equation? I asked to not only get your view of the world but determine whether producers in the basin that are less well positioned have really felt maximum pain?

Well, let me start at the high level and then turn it over to Chad, and then there may be others on our team that want to talk about it. But I think the good news when you look on the demand side is -- there's a number of analysts out there, and I won't quote them, but there's a lot of people that show incremental gas demand, plus or minus 20 Bcf per day. Some people are saying 2018, 2019, 2020. I think on the high side, the University of Texas had 25 Bcf of incremental demand. And it comes from a number of things. So I think on the LNG side, again, Cheniere, the first project, everything that I hear is on time. And the second and third trains, they'll start in '16. All of that is on time, and it should happen. So I think the LNG stuff in the U.S. is important. I think gas is a superior fuel to coal. So in terms of -- gas has been displacing coal from power generation with time. I think that'll continue as well. Billions are being spent on the petrochemical side to convert the feedstock from an oil-based feedstock to a gas-based feedstock. So I think that'll happen. And slowly but surely, you're seeing transportation occur. So I think the demand is coming, the demand is coming timely, plus there's exports to Mexico. So I think those things will happen. On the supply side, again, I think most of the plays -- the core parts of the plays are about 10%. Our teams have looked at all the plays around the country. They range from a low of 6% being core to a high of 17%, according to our team, with an average of 10%, which means…

It's Chad. I couldn't have answered any better, but I will say that where commodity prices are right now, we know the demand is coming. It's just a matter of when will it come and at what levels. So with that being said, you got to look at the curve and see at what price are you able to drill and deliver the supply to meet that demand. So you'll see the curve play out as that demand -- as the market starts seeing that demand take traction between the LNG exports, power gen in the Southeast, Mexican exports, we're displacing gas from Canada. It's happening. It's just a matter of exactly when the markets will see it coming, at what price to be able to supply that demand.

Yes. And again, I think it's not that far out there, weather clearly plays an issue. I read something from AccuWeather that, hopefully, it's snowing in parts of the country on Halloween or at least raining and cold. So that's -- from our perspective, it's a good thing. I feel bad for some of the kids trick-or-treating, but that's helpful in the short run. And then it's back to differentiation for Range. We have that firm transportation and supply to bridge us through those harder periods, Dan, that you mentioned. And then in addition, we have contracts that none of our competitors have in terms of some of the liquids, which give us an uplift starting in the first quarter of '15, not that far out. Plus the weather, if we get any normal winter, though. It's not that far out. And then, again, it's an advantage for us so...

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.

Okay. I'll conclude on the same themes I discussed in my opening comments. Fundamentally, we believe that Range is a simple story. Range has the largest acreage position in the core to play, largely in the stacked pay area in Southwest Pennsylvania. We have the wells identified, the field infrastructure being built and the necessary takeaway capacity contracted to grow 20% to 25% each year to triple our current production to 3 Bcfe per day and beyond. The acreage position largely covers the most perspective liquids resources in the basin, with necessary transport and export facilities being built to handle our multiyear growth. We want to thank our shareholders for their support. We believe that Range will be a leader in building shareholder value. Thanks for participating on the call. If you have additional questions, please follow up with our IR team.

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