Rodney L. Waller - Senior Vice President and Assistant Secretary Jeffrey L. Ventura - Chief Executive Officer, President and Director Ray N. Walker - Chief Operating Officer and Senior Vice President Roger S. Manny - Chief Financial Officer and Executive Vice President

David W. Kistler - Simmons & Company International, Research Division Marshall H. Carver - Capital One Southcoast, Inc., Research Division Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division David R. Tameron - Wells Fargo Securities, LLC, Research Division Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division Leo P. Mariani - RBC Capital Markets, LLC, Research Division Joseph Patrick Magner - Macquarie Research

Welcome to the Range Resources Third Quarter 2012 Earnings Conference Call. This call is being recorded. [Operator Instructions] Statements contained in this conference call that a 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. Rodney L. Waller: Thank you, operator. Good morning, and welcome. Range reported outstanding results for the third quarter with record production and a continuing decrease in unit costs. Both earnings and cash flow per share results were greater than first call consensus. But first, 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 and Chief Financial Officer. After the speakers, we will conduct a question-and-answer period. Also Mr. Pinkerton, our Executive Chairman, is on the call today. Range did file our 10-Q with the SEC this morning that's now available on the homepage of our website or you can access it using SEC's EDGAR system. In addition, we've 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 reconciliation of our adjusted non-GAAP earnings to reported earnings that are discussed on the call today. We've also added tables, which will guide you in the modeling of our future realized prices for natural gas, crude oil and natural gas liquids. Detailed information of our current hedge position by quarter is also included on the website. Now, let me turn the call over to Jeff. Jeffrey L. Ventura: Thank you, Rodney. The third quarter was another great quarter for Range. Production for the third quarter of 2012 was 790 million cubic feet equivalent per day, which was 47% higher than the third quarter of 2011 and 10% higher than the second quarter of 2012. We're on track to achieve 35% year-over-year growth for 2012 versus 2011 within our capital budget of $1.6 billion. On the cost side, absolute LOE dollars for the third quarter were below the prior year quarter, resulting in LOE per mcfe dropping from $0.58 per mcfe to $0.40 per mcfe. This is directly related to the quality of the wells that we're drilling and the quality of the teams operating the properties. All line unit costs continue to drop and are continuing the trend that we have in the first 2 quarters for 2012. Roger will discuss the cost management and results in more detail in a few minutes. We also achieved an important marketing milestone in the third quarter. Rain announced that we have become the anchor ship around the Mariner East NGL pipelines project. As the anchor shipper, we have firm transportation to ship 40,000 barrels per day of processed liquids from MarkWest Houston Pennsylvania plant to Sunoco's Markus Hook terminal facility near Philadelphia. The 40,000 barrels per day will consist of 20,000 barrels of ethane per day and 20,000 barrels of propane per day. Under the agreements, we also have access to a very significant portion of the 1 million barrels of propane storage at the facility. The propane can be delivered into the East Coast and Northeast U.S. markets and/or exported internationally, which opens up significant new markets for us. In addition to this agreement, we also announced the 15-year ethane sales agreement with Eneos. Eneos is a global manufacturer of specialty chemical and oil products and currently plans to utilize its own ship fleet to take delivery of our ethane at the Sunoco's Marcus Hook dock facilities. Contracted volumes are planned to start in the first half of 2015 and increase over time to 20,000 barrels per day. The Mariner East project is the third ethane project in which we have announced our participation. The first ethane project was Mariner West. Mariner West is expected to start in midyear 2013 and ramp up to 15,000 barrels of ethane per day. The ethane will be purchased by Novo Chemical and transported to Sarnia, Canada. The second project that we announced was our participation in the ATEX project, which will move ethane to the Gulf Coast Petrochemical Complex. This project is planned to start in 2014 and ramp-up to 20,000 barrels per day. All 3 ethane projects originate at the MarkWest Houston plant in Washington County, Pennsylvania. In essence, these 3 projects ensure that will be able to meet gas pipeline specifications in a timely manner, they give us operational flexibility and they enable us to build and grow our wet Marcellus production volumes. These 3 projects, assuming minimum ethane extraction, allow us to potentially grow Marcellus volumes in the wet portion of the play up to 1.8 Bcf per day. In addition these 3 projects will add about $0.40 per mcf to our effective gas price. On Slide 10 of our current IR presentation on our website, it shows that we have about 335,000 net acres in the wet portion of the Marcellus, which is in the Southwest portion of the play. In addition, we have about 235,000 net acres of dry gas in the same area. Summing both areas, we have 570,000 net acres here. Since we discovered the play in October of 2004, approximately 1,500 wells have been drilled in this area. Based on those roughly 1,500 wells or so, our many long-distance step out and delineation wells, and considering that our discovery well came online in 2005 and that we now have up to 7 years our production history, we believe that all of this acreage is highly perspective for Marcellus Shale. Combined, between the wet and dry portions of the play, we believe that we can possibly grow the Marcellus production alone to 2 to 3 Bcfe per day. In addition, we believe a lot of this acreage has perspective for both the Upper Devonian and Utica Shales and would allow us to leverage existing Marcellus infrastructure. With success in these other horizons, we have the possibility of growing beyond 3 Bcfe per day. It's important to note that it's not just growth. The growth in gas filled with the best large scale repeatable economics in the U.S., particularly given Range's dominant position in the wet portion of the play. The economics are very good given the capital required to drill and complete the wells versus the projected recoveries per well. The other key is the effective uplift in price due to the liquids production. If natural gas is priced at roughly $3, given all the uplifts from a natural gas liquids and condensates, the effective price we receive on the wet gas portion of the Marcellus is about $6 or about double gas price alone. That assumes the ethane stays in the gas. Once we begin to recover ethane, and once all 3 ethane and propane agreements are in effect based on current strip prices, it adds about $0.40 per mcf to the $6 price, which further enhances our economics. For 2012, we entered the year with a goal of growing between 30% to 35% with a $1.6 billion capital budget. I stated on a couple of previous calls this year that if we choose to live within projected cash flow for 2013, we could grow at 15% to 20%. This year, we drilled in the dry gas portions of the Marcellus Shale in the Northeast, which, for us, centers in and around Lycoming County, Pennsylvania. We did this in order to drill the hole that we believe are some of the most perspective acreage in this region. We ran 4 and, at times, up to 5 rigs in this area. By January 2013, we plan to be down to one drilling rig here. The reason is, at this point, we can run one rig and still hold the key acreage we want to keep in that area given the continuous drilling plazas that we have, coupled with larger tracks in general than in the Southwest part of the play. Therefore, given the relatively low price of dry gas as compared to wet gas and oil, for 2013, we're planning to focus on the wet and oil areas of our portfolio. Also, come January 2013, the 2 areas that we plan to focus on drilling to convert acreage that held by production are the wet portion of the Marcellus in the horizontal Mississippian oil play in Northern Oklahoma and Southern Kansas, which has a large liquid and oil component. The good news is that our 2 most economic plays happened to be where we need and want to drill to hold acreage. Given that we can reduce drilling in the northeast portion of the Marcellus from 4 to 5 rigs to 1 in 2013, we will most likely be reducing capital spending in 2013. I want to stress that we don't set our budget into our December board meeting, our budget is subject to board approval. In past years, after board approval, we typically announce our 2013 capital program at the end of January or early February. Given those caveats and realizing that it's still early, looking at strip pricing today, preliminarily, it looks like even with the reduction to a single rig in the Northeast dry Marcellus, we can still grow volumes for 2013 at a rate of 20% to 25% over 2012 focusing on the liquids-rich and oil areas. To do so, we currently estimate that we would overspend cash flow by approximately $250 million, plus or minus, assuming current strip pricing. Over the next month and a half, we'll prepare a recommended 2013 budget for our board and present it in our December board meeting. Looking at 2014 and beyond, we control and operate almost all of our assets, except for Nora field in Virginia. If strip prices hold for 2014 and beyond, we will look at ramping up our growth -- in ramping our growth back up. In essence, we'll move the growth lever up with higher prices, while being mindful of holding key Marcellus in Mississippian acreage and fulfilling our longer-term ethane and propane commitments. In the Mississippian play, given continued drilling success in our 150,000 net acre position we're planning on ramping up drilling. If we begin 2013 with 5 drilling rigs and move to 10 rigs in 2014 and 15 rigs in 2015, we believe we can hold all of our acreage within the primary term and significantly grow our oil, NGL and gas volumes in the play. As most of you probably recall, in the timeframe from 2004 to 2011, we sold about $1.8 billion of properties. These asset sales did several important things for us. They allowed us to keep focusing on growing our most economic projects, which had the highest growth rates with the lowest cost, while divesting of our low-growth high-cost projects. This focus not only our capital on our best projects, but it also enabled us to focus our technical talent on our best projects. In our release this week, we announced another $170 million of sales, most of which consist of our Ardmore Basin assets and some scattered Marcellus acreage. Completing this transaction, as we expect, will bring us a total of about $190 million in sales this year. We'll continue to identify assets that we think make sense to divest. In summary, we believe that we have the ability to create substantial shareholder value in the current commodity price environment and have the quality of assets and flexibility to do so for many years to come. I'll now turn the call over to Ray to discuss operations. Ray N. Walker: Thanks, Jeff. We exceeded our production guidance coming in higher on gas and NGLs and right in the strike zone on oil. In fact, 47% organic production growth, when comparing to the prior year quarter, is the highest production growth in the company's history. Again, this is a great testament to our operating and technical teams. They've reached record production levels while, at the same time, substantially reducing expenses and improving efficiencies. To illustrate that point, let's talk about operating cost. In addition to our record production, we continue to see an impressive decrease in field level expenses. As I've pointed out in the past, we've seen really great improvements and efficiencies all across the board. And we still see those happening, and we believe that they will continue to happen as we're going forward. But when you combine the increased efficiencies with what our operating teams have achieved in lowering the finding and operating cost, it's truly impressive. For example, when comparing the third quarter of this year with the same quarter last year, we've seen a 47% increase in production, with a 31% decrease in LOE per mcfes. In fact, our absolute field level expenses have decreased, year-to-date, this year as compared to the same timeframe last year by 12%. Accomplishments like this really help us to achieve great economics, long-term, in what we believe to be some of the best and largest repeatable plays out there. Not only are we seeing great growth at low cost, we are also seeing improving well results. Now, let me highlight some of those results that we're seeing across the company. Please refer to our press release for specific well results. I'm not going to repeat all of those results in my remarks here, but they are certainly noteworthy, and we can discuss them during the Q&A. However, I do want to call your attention to the table in the Southern Marcellus section of the press release. It shows 64 wells coming online during the third quarter in the super-rich and wet Marcellus areas. If you compare those rates to the type curves in our current IR presentation, you'll notice that the average RPs of those 64 wells is above the type curves and, in particular, the liquids rates are well above the type curves. In the super-rich area, we had a significant step-out well that tested at 1,044 barrels of liquids per day and 10.3 million gas, excluding ethane. If you figure in ethane, the well was 2,053 barrels of liquids per day with 8.7 million gas. The lateral length is approximately 3,800 feet, and it was completed using a 20-stage RCS completion. As you can imagine, the economics on a well like this would be phenomenal. What I want to stress here is that this well is one more example of how our wet and super-rich acreage is not only being derisked as we step out across the acreage, but it also illustrates the exceptional resource base that we put together over the last several years. As we're working on designs and stepping out across this position, we're continuing to see improving results as this position is derisked. We expect that our 335,000 net acres in the wet and super-rich Marcellus will provide for a highly profitable drilling program for many years to come. In addition, in our Northern Marcellus division, we continue to see outstanding results with good economics. But as Jeff said, we'll be ramping down our activity to enter 2013 with one rig as we continue to focus the majority of our capital towards liquids-rich and oil projects. Next year, we expect of able to meet our lease commitments on our key acreage in Northeast PA with generally one rig as now most of that acreage is HPP'd or in a continuous drilling mode. Also of importance, I want to give a quick update on the Upper Devonian shale. Our second super-rich Upper Devonian well continued to clean up following our early August announcement. It ultimately had a peak 24-hour rate of 552 barrels of liquids per day, of which 31% was condensate and 4.7 million a day of gas. With ethane extraction the well would be 998 barrels of liquids per day and 4 million gas. We don't plan any further Upper Devonian tests this year, and we're currently developing our plans for 2013. Shifting to the Utica, our first wet Utica well in Northwest PA was drilled and completed successfully. The log data and core data that we collected, along with the pressure testing we performed, show us to be right in the strike zone for liquids-rich production. The well is currently set in for a 60- to 90-day period post frac and we'll be keeping any results proprietary for a while longer. With the data we've gathered, we now believe the Utica, in this area, could potentially benefit from the so-called aging or seasoning process that you may have heard others talk about. And that's why we have the wells set in. Of course, we'll have our own conclusions as to the technical and economic viability of this technique after we finish some of this testing. We are encouraged by what we see, and we still plan to spud the second wet Utica horizontal well late in the quarter. As it's still real early in this play, we expect to know a lot more about the potential of the wet Utica on our 190,000 net acres in Northwest PA by our next conference call. Now, let me shift to Oklahoma. The horizontal Mississippian oil play is progressing well. We're up to 156,000 net acres and now have our second well that exceeded 1,000 boe per day. We had a peak 24-hour rate of 1,227 boe per day. The lateral link that's approximately 4,000 feet, and it was completed with a 20-stage frac. We own a 74.9% working interest in that well. I think it's also important to point out that our first 1,000-plus boe per day well that we previously announced was turned to sales in the second quarter and has held up very well. The well has now achieved a 90-day average of 1,049 boe per day. Let me also point out that when we look at the IPs of the wells turned on in the last 2 quarters, the average IP is 552 boe per day, which is well above our 600 Mboe type curve. The team is continuing to optimize midstream and power infrastructure and is steadily improving our completion designs. While it's early in the play, we believe our team can continue to produce these wells at very attractive operating costs that will continue to enhance our economics. In West Texas, at our Conger field properties, we've drilled our third Wolfberry vertical well. That well had an initial 24-hour production rate of 505 boe per day. This is substantially better than our first 2 Wolfberry wells. Those first 2 wells were projected to recover 216 Mboe each, and we expect this well will do better. It's also significant to point out that it was completed at 11% lower cost than the first 2 wells, and when you combine that with the better expected recovery, the economics will improve substantially. Plans are to drill and complete 3 additional vertical Wolfberry wells at Conger in the fourth quarter. Shifting to the horizontal Cline oil play, there's still a lot of offset activity in the area, and we are monitoring that closely. We successfully drilled and completed our third horizontal Cline oil well and is currently being tested. It's still early in the cleanup process, and we expect to have test results to discuss at our next conference call. I also want to give a big attaboy to our marketing department. As the Marcellus and the Utica have grown, our team has taken many important and strategic steps in the Northeast markets. These steps ensure that our production flows steadily on a year-round basis for many years to come. Certainly, the ethane and propane deals are great examples of just a few of those strategic moves. Our team is always evaluating future opportunities and is consistently adjusting our portfolio, working with both pipelines and customers. Again, our marketing folks have done a great job staying right out in front in of the ever evolving Northeast markets. Our already strong safety record continues to improve as we remain well below our peer group averages. Our incident rate is 53% below our peer group's rate and 39% below our own incident rate in 2011. And our lost time rate is 54% below our peer group's rate and 64% below our 2011 rate. Safety and environmental protections remain a core value at Range. And from the bottom up, our operating teams believe it, live it and own it. As for guidance, like Jeff said, while our drilling and completion activity level will slow down a bit during the fourth quarter, which is primarily in Northeast PA and in spite of the Ardmore Woodford Shale, we still expect to come in right at a 35% year-over-year production growth target, with our fourth quarter liquids growth in the range of 33% to 36% as compared to the fourth quarter of 2011. As you can tell, we are really proud of our operating and technical teams. They make it really easy to talk about our results each quarter. In summary, cost and well performance are steadily improving, while working safely and protecting the environment. And we have some great way to return projects that are continuing to get better and better. Now, over to Roger. Roger S. Manny: Thanks, Ray. The third quarter extended our favorable growth and cost trends evidenced in the first 2 quarters of 2012. Fueled by strong production growth at low-cost, cash flow and EBITDAX both registered quarter-to-quarter increases. Turning first to the income statement, third quarter cash direct operating cost, including workovers, was $0.40 per mcfe, $0.18 below last year and equal to the second quarter. Year-to-date cash direct operating expense on an absolute dollar basis was $11.4 million lower than last year on 36% higher production volume. It would be impossible for every increase in production, while at the same time reducing cost, so we expect cash direct operating unit costs to be in the $0.43 to $0.45 range in the fourth quarter as we further increase our oil and liquids-rich production, which carry higher margins but also higher unit operating cost. Cash G&A expense for the third quarter was $0.46 per Mcfe, $0.07 below the third quarter of last year and $0.01 lower than the second quarter of this year. Salaries and benefits make up the largest component of our G&A expense, and we've seen these costs decline on a unit cost basis for the past 6 consecutive quarters. This is a key indicator of the quality and maturation of our play expansions as we are now increasing production consistently faster than our overhead. Fourth quarter G&A unit cost is expected to be $0.44 to $0.46 per Mcfe. Third-party transportation, gathering and compression expense in the third quarter came in at $0.71 per Mcfe, $0.03 higher than last year. The timing of additional firm transportation capacity and the capital spent to hook up incremental production, do not always coincide with the timing of production commencement, which makes this expense somewhat variable. We anticipate this expense to be $0.75 to $0.79 per Mcfe in the fourth quarter. The third quarter DD&A rate was $1.69 per Mcfe, $0.20 per Mcfe lower than last year. Fourth quarter DD&A rate should be in the $1.65 to $1.68 per Mcfe range. And we believe that the DD&A rate will continue to decline as our capital efficiency further improves. The fourth quarter DD&A rate should reflect this as it will incorporate our year-end reserve report results. Recalling that most state production taxes are assessed on wellhead prices rather than effective prices after hedging, third quarter production taxes were $0.05 per Mcfe plus the Pennsylvania impact fee of $5.4 million. That brings the total production tax burden for the quarter to $0.12 per Mcfe. Prices have improved a bit recently, making our best estimate for fourth quarter production taxes $0.08 per Mcfe on total company production, plus $5 million for the Pennsylvania impact fee, making the total $0.15 per Mcfe. Interest expense for the third quarter were $0.61 per Mcfe, $0.08 below last year's figure. Higher production volume and incremental debt funded under the lower floating-rate bank revolver is what helped bring the unit interest cost down. The fourth quarter should see this trend continue, with interest expense of $0.59 to $0.60 per Mcfe. Exploration expense in the third quarter, excluding noncash compensation was $14 million, that's $3 million below last year due to lower dry hole and lower seismic expenditures. Seismic expenditures in the third quarter were only 1/3 of the budgeted amount due to project timing. So we expect to catch up in the fourth quarter, with total exploration expense of approximately $19 million. Our ordinary unproved property impairment for the third quarter was $20 million, and we also recognized an unusual impairment on an unproved property of $20 million, bringing the total unproved property impairment for the quarter to $40 million. The unusual item consisted of our last undeveloped Barnett Shale lease, which was held out on the 2011 sale. The fourth quarter estimate for unproved impairment is $19 million to $21 million. Third quarter cash flow was $189 million, essentially the same as the third quarter of last year, while EBITDAX for the quarter was $230 million, 4% higher than the third quarter of last year. On a per fully diluted share basis, cash flow was $1.18 per share, $0.03 above analyst consensus estimates. Cash margin for the third quarter was $2.56 per Mcfe and earnings calculated using analyst methodology were $32 million or $0.20 per share, also $0.03 above analyst consensus estimate. As Rodney mentioned, please see our website for detailed reconciliations of these non-GAAP figures to GAAP, along with hedging schedules and other helpful information for investors. Over on the balance sheet, things are pretty much business as usual in the third quarter. We funded our capital program with cash flow and draws under our $1.75 billion bank credit facility. The bank credit facility has a $2 billion borrowing base, which was unanimously reaffirmed by the 28-member Range bank group earlier this month and it's currently approximately 25% drawn. Though our rate of spending slowed considerably in the third quarter this year compared to the second quarter, our leverage, as measured by current total debt to trailing 4 quarter EBITDAX, increased slightly to 3.3x. We remain comfortable with our leverage around the 3x EBITDAX level, thanks to our high rate of return plays, low cost structure, long reserve life, operating control of our growth assets, substantial liquidity and our hedge position. EBITDAX is beginning to grow again, thanks to higher production and slightly higher prices, which should give us a bit of a tailwind on the leverage ratio going forward into 2013. Our increase in EBITDAX in 2013 will enable us to outspend cash flow by approximately $250 million, while also reducing the leverage ratio to below 3x. As has been our practice, as Jeff mentioned, we continually evaluate our assets for potential sale and will likely entertain additional sales periodically to sharpen our operating focus, which will also help keep leverage in check. As Jeff also mentioned, we have signed a purchase and sale agreement to sell our Ardmore Basin Woodford shale properties at a gain, which when closed, along with several small miscellaneous assets, will garner approximately $170 million in proceeds to shave the peak off of our leverage and help keep leverage from going any higher in the fourth quarter. We're pleased to have increased our hedge position during the third quarter. We added new hedges in 2012, 2013 and 2014. For the fourth quarter this year, we've got approximately 85% of our projected gas production hedged at a floor price of $4.17 MMBtu. We've got approximately 60% of our NGLs hedged at above market prices and approximately 80% of our projected oil production hedged at $90.82 a barrel. Our 2013 and 2014 natural gas and liquids hedge positions were increased during the third quarter such that we will again be entering the new year with approximately 3/4 of our 2013 production hedged and over half of our 2014 production hedged. Please reference the updated hedging schedules on the Range website for these new and existing hedge volumes and prices. To summarize, the third quarter showed continued cost reductions, which, when combined with record increases in production volume, increased our quarterly earnings and cash flow, positioning us very well for the fourth quarter. Jeff, back to you. Jeffrey L. Ventura: Operator, let's open it up for Q&A.

[Operator Instructions] Our first question comes from the line of Dave Kistler with Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: Real quickly with your comments about outspending for next year and tying that to discretionary cash flow, obviously, that discretionary cash flow is going to move with commodity prices, but you must have some sort of range in mind currently. Any chance you can share that with us? Jeffrey L. Ventura: Yes. Well, let me start and then I'm sure Roger can pile on. But what we're talking about for next year and it's preliminary and subject to board approval, but what it looks like right now is we would get year-over-year growth of 20% to 25% outspending cash flow, looking at current strip prices by approximately $250 million, plus or minus. And then the other important part is looking at the strip in 2014 and beyond. In essence, we would look at ramping growth back up. And let me talk about it philosophically before I turn it over to Roger. Our strategy, and we've talked about it before, is on the low end. Within cash flow, we can grow at 15% to 20%. Of course, on the high end, it depends where you focus, whether you're focusing oil, liquids-rich or gas. But this year, obviously, we're growing at 35%. And now we have a huge inventory and a lot of flexibility, both in oil, wet and dry. And then we operate and control almost all of it. So as prices move up or as the strip looks better, we'll look at ramping up and as prices are worked, then growth rate will be a little lower. Then there's several key things in there. When we look at growth, for instance, for 2013 we're not focused on absolute growth. We're focused on best economics and best returns. So our drilling, therefore, next year, like I said, is we're going to cut down in the dry gas areas in Northeast Pennsylvania and focus our drilling on the liquids-rich and oil areas. Liquids-rich down in the Southwest part of the Marcellus and oil in the horizontal Mississippian. And so we're looking at cash flow per share rate of return, that type of stuff. If we are looking at just best absolute growth, obviously, what we'll do is drill 100% dry gas and for $250 million of our cash flow, we'll probably drill it at 35% to 40% or more. So and the other thing I think is important, we think in a dry gas area, it's just looking out. We ran some economics earlier this summer. If we delay drilling in, say, Lycoming County for a year or 2, in essence it doubles the rates of return if you move on a per well basis, if you move the capital out to the point in time when the strip's better. For 2014 and beyond, again, I just wanted to give you a little context before Roger comments more on the financial part. But in the Mississippian, we talked about ramping beginning of this year, 5 rigs, and then we'll success to 10 and 15. So, it sort of gives you a feel for the shape of the curve there and the growth in the Mississippian. In the wet Marcellus, you can look at those ethane agreements as a proxy for what our gas rate's going to be in the wet areas. When you add the 3 together, we have committed a 55,000 barrels of ethane per day. So currently we're 0 selling ethane. So by mid-to-late 2016, we need to be at 55,000 barrels of ethane per day to fulfill those agreements. Under minimum extraction, that's 1.8 Bcf per day. Under most likely extraction that's 800 million. To put that in context, currently in the wet area, we're about 370 million per day. So on the minimum, on the low end, we're going to more than double production in the wet Marcellus to fill those agreements by mid-to-late 2016. So when I sort of put it all in context and I think probably the most important thing to do that is what our portfolio and we talk about 44 to 60 Tcf. But I want to stress a lot of that's in the Marcellus and down in the Southwest. Highly derisked because there's 1,500 wells and it's not just 1,500 wells, but when you go on our IR presentation, you can look at the quality of the wells in the wet, the super-rich and in the dry. There's a big data set with up to 7 years worth of history, and that's where our acreage is. So not only can we grow at 20% to 25% and then ramp up in subsequent years to potentially something higher, we can do that for many years to come, for probably a decade or more to come. So I think that -- I'm not saying we're unique, but because we discovered and have a big position and what we think it's one of the best, the largest gas field now in the U.S. and particularly in the wet area where the best economics are, we're very well-positioned to do that for a long time to come. So let me flip it back to Roger to talk more about the funding and leverage. Roger S. Manny: Yes, just commenting on the overspend, Dave, we're obviously in a capital-intensive, highly-cyclical business and we mind our balance sheet very closely and our balance sheet is in great shape and we want to keep it that way. We've got a lot of financial flexibility and liquidity built into the balance sheet. So the question is how comfortable are we leaning on the debt throttle in times like 2012 and in times like 2013. And the reason we're comfortable at this point talking about overspending cash flow, $250 million, plus or minus, as Jeff says, is that with the trailing -- current debt to trailing 4 quarter EBITDAX measure, which we feel is the best measure of leverage, given a tailwind from higher EBITDAX from higher prices and higher production, let's just go into 2013 to where you can overspend cash flow by about a quarter billion and still actually drive that leverage ratio down a few ticks. So that's really the plan behind that. We have, as I mentioned, plenty of liquidity. The question is how we use that liquidity and we intend to be prudent about how we go about doing that. David W. Kistler - Simmons & Company International, Research Division: Appreciate that, and maybe just to clarify a little bit, you must have kind of a range around that discretionary cash flow, and I'm imagining that, that organic discretionary cash flow, not necessarily cash inflows, i.e. asset sales, and just roughly looking at kind of our model that would put you in a range of maybe call it $850 million to $950 million for next year. Am I way off the mark, I'm just trying to triangulate to what that CapEx, aggregate CapEx number would be. Roger S. Manny: We've never given cash flow guidance. And I certainly don't want to start now. What I can comment -- and I'm also not going to second-guess the board on the CapEx budget for next year. So I really can't comment on your range. But I can assure you that we've run the numbers, and we feel confident in the 20%, 25% range and the 250 approximate overspend.

[Operator Instructions] Our next question comes from the line of Marshall Carver with Capital One Southcoast. Marshall H. Carver - Capital One Southcoast, Inc., Research Division: On the 2013 growth, thanks for the color there, with the emphasis on liquids in both the Mississippian and Southwest PA, is it safe to assume that the liquids growth would probably be a little bit higher than 20% to 25% and the gas growth would be lower? Jeffrey L. Ventura: We're not going to come out with the specifics again until we present to the board and get it approved. But in generally speaking, yes, the liquids grow disproportionately to the gas and to the overall. But we'll come out with all those specific numbers once we get formal approval from our board, December. Typically, we get approval and so roughly around the first week of December, and it's been like end of January and early February when we do it. Maybe we'll accelerate that, we can bat that around, maybe we'll do it in mid-December or something or January. But, yes, the overall answer to your question is, yes. They will grow disproportionately. Marshall H. Carver - Capital One Southcoast, Inc., Research Division: And just sort of follow-on to that, then I'll hop out of queue, are there any bottlenecks or the liquids end in next year? Or how should we think about that? Ray N. Walker: Well, I think what we're seeing in the fourth quarter is due to some of the timing issues that we talked about a couple of quarters back. A lot of these wells are getting compressed into the third and fourth quarter. So we're seeing a lot of wells come online, and that's just kind of exaggerating the bottlenecks that are there. And I think that we're seeing that unwind, and we really expect that to unwind even further into 2013. We turned on 84 wells in the third quarter, which is a bunch of wells. And as we see that backlog unwind, which we're beginning to see the effects of that, I really believe in 2013, most of that will have worked its way out as, especially as we get into the second quarter or so of next year.

Our next question comes from the line of Brian Lively with Tudor, Pickering, Holt. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just a follow-up on the 2013 preliminary numbers, specifically on the outspend, it sounds like you guys are comfortable with just using the leverage to grow. Or are you guys going to plan to plug that $250 million gap via additional asset sales? And if so, what's kind of next step on the list in terms of what you would consider selling? Jeffrey L. Ventura: Well, let me talk about it in general terms. If you look at the period from 2004 through 2011, we sold $1.8 billion worth of properties. And through that time, we significantly drove up production and drove up our share price. This year, so far, because we sold a little bit in the beginning of the year, to date, we've sold $190 million worth of properties. So Roger and his team and working together with the board will come up with a way we can optimally finance that as we look forward. Clearly, we have the ability, if we choose to do so, to carve off a little more assets like we have historically. But Roger will be making that recommendation as we go forward. Our strategy has been, we think periodically selling things makes a lot of sense for a number of reasons. One, it really keeps us focused operationally. It keeps us directing our capital into our highest return, best growth, large scale repeatable projects, and by the same time selling them, it prevents us from investing like when we had the offshore, I guarantee you, whenever you're in an area you get AFE'd by a partner, you have to react to something. The only way that you get out and spending money in areas that you prefer not to spend a lot of times, it is just to sell it. Plus, it enables you to redirect your people. So, I think we have a very focused company, and we've shown the ability this year, even with the sales that we have, we're still hitting our growth targets even when we sold the Barnett, literally, selling 120 million a day within 6 months we have such robust, large-scale projects now. We more than made it up within a short period of time, with much higher rates of return. So that's what we've done historically and as we finalize our budget and look into next year, we'll come out with what that plan is. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, and in that vein, for the Permian, how much more do you guys need to see from a delineation standpoint to sort of bucket that area in terms of being one of those core assets versus being something that you would consider monetizing? Jeffrey L. Ventura: I think the key part with the Permian, it's sort of like our Utica play as well. All of that Permian acreage is held by production, which really gives you great flexibility. It gives us time to watch our wells, to watch our competitors' wells. Same with Utica there, we have another 190,000 net acres that's all held by production. And again going back to a higher level theme of Range, we like to get into areas where there's high quality, large-scale repeatable stack pays, rich hydrocarbon charge and then put a really strong technical team on there and continuing to work and work and work and coming up with those new opportunities. And that's really paid a lot of dividends for the company. So we don't have a time frame per se, but we continually look at the results of our wells and others, and that will determine what's optimum for the company. Like I said, as evidenced, we're not -- we're all about -- we're aligning with the shareholders. It's all about share price performance, growing production per share, reserves per share, debt adjusted. So whatever makes the most sense to do, we'll do. We sold $1.8 billion worth of properties. So if that's the right thing to do, we'll do it. We're really focused on the best returns and the best opportunities as we go forward. And as we learn more about those areas, then they need to go higher into the list or lower, based on performance.

Our next question comes from the line of David Tameron with Wells Fargo. David R. Tameron - Wells Fargo Securities, LLC, Research Division: Did you guys -- I'm not sure who alluded this, but could you just talk about all the infrastructure coming online in the Marcellus and how much more capacity that frees up for you, when, and as you think about the timeframe over the next few quarters that, that comes on, when do you anticipate most of that additional infrastructure to be in place and what's the timeframe look like for the next couple of quarters? Ray N. Walker: Yes, David, this is Ray. The infrastructure bottlenecks, per se, that we experienced this year were really midstream, had to do with low-pressure gathering and compression and so forth. And like we've said earlier, MarkWest is kind of a [indiscernible] job by catching up and actually getting ahead of us now and now we're beginning to get those wells put online. And so we kind of -- as far as the infrastructure needs, going into 2013, the amount of pipe, for instance, that they have to put in place in 2013 is a whole lot less than it was this year. So we're kind of, for lack of being cheesy about it, we kind of have reached an inflection point in the infrastructure. And the fact that the biggest part of it's been built, and now we're going to go -- basically, now, we're just kind of tying in wells to already major infrastructure that's there. So in Southwest PA, we really don't see any big issues. Of course, we're still going to be ordering plants going into the future in different things like that. But that's all way out in front of where we're at, and we feel really, really good about that. Like Jeff talked about in his remarks, we've got a definite plan to be getting to the point where we can deliver on all these commitments that we've got and do it in an economic and reasonable manner to get there. So we feel pretty good about infrastructure going forward, and we don't foresee any huge bottlenecks, especially in Southwest PA or really in Northeast PA where PVRs just put phase 3 online up there. So we're really good shape for the next couple of years on infrastructure. Jeffrey L. Ventura: And I'd just add, back to the ethane agreements and as we continue to ramp up in ethane, in essence we're taking the ethane out of the gas and selling it as a liquid, which frees up about 100 million a day in the gas pipeline. So there's another benefit that comes out of those projects. David R. Tameron - Wells Fargo Securities, LLC, Research Division: Okay, let me ask an unrelated follow-up. Equitable's, if you're talking about selling assets and here on presumably on the potential board for being sold, would you guys sell that generally with Equitable? How would that process work? Jeffrey L. Ventura: Well, I'm not -- you have to ask Equitable what they’re doing, which I'm sure you've done. But EQT, to make it modern-day, yes, we are partners with them. They have the Huron in Kentucky; and then on the Virginia side, we're partners with them in Nora; and then separately, we have other assets, friends [ph] since we own Haysi 100% and Big Rock 100% and that type of thing, Widen 100%. But we like those assets in Virginia. We always want to be -- do whatever the right thing is for the shareholders, but we really like the assets we have in the Virginia. It has that same characteristic that we like to see at Range. Their stack pays. Everything from literally from a lot of thousand feet down, you have the CBM, you have the CBM, then you have the traditional zones in the Berea and Big Lime, then you have the Huron Shale. All of it is either held by production or we own the minerals. Actually, our economics are superior to what EQT has, because we own the royalty. We actually get paid the royalty on those pieces. Our team, even though we've cut the capital way back there, because we can, and we have that in idle, they're still growing production this year, even with a $13 million budget, which is just a minor fraction. So we have really high-quality asset with a high-quality team. But we do have other scattered assets throughout the company, if we want to sell things, that we control and we operate, and we -- like I said, as evidenced by the past 7, 8 years now, periodically, we're always looking at it, and we've ranked those assets out and there's things that fall to the bottom and we would consider selling those if it's the right time in the right place in the right area. Don't get lost a little bit in our flipbook and if you look at the IR presentation. We're focusing on the things we're spending money on, but we have a lot of production in other areas, we just don't list it all. And for those of you who have been with us for a while, we used to have the pyramid that Rodney loved. So, the pyramid and all those other things that would be possible considerations for asset sales.

Our next question comes from line of Neal Dingmann with SunTrust. Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division: Just 2 questions here. First on that great result you had on that step out on that super-rich area, I was wondering are you planning, I guess, to drill a number around that? Is that why kind of the delay to bring that online and by the result you're seeing there, have you already essentially delineated and sort of connected the dots in that area if you know where I'm going with that? Ray N. Walker: We are -- it was a significant step out. And by definition, we didn't have infrastructure out there where that well is. So it's going to be a while before it comes online. And to answer your question, yes, I mean now that we have derisked that step out area, we'll begin marching towards it with infrastructure and with wells as we go forward. That way, you kind of know there's a great target out there and, again, that's been real surprising to me, especially since I was there essentially from the beginning that as we stepped out and continue to step out, we're just seeing better and better and better results. So the size and scale of this play is really truly amazing. It just keeps getting better. Jeffrey L. Ventura: Yes, it's really exciting like what Ray said in that area as we stepped out in the super-rich, we have 125,000 acres out there, really big blocky position. So it's a great opportunity and even though we've been drilling out there for years now, I would argue -- and Bill Zagorski, our geologist, has said, we probably haven't drilled our best wells yet. So the future is really bright. Ray N. Walker: And there's significantly higher rate of returns. I mean if you look at our updated PowerPoint slides on the website, you can see that in that area, just because prices have come up a little lightly and we're making better wells too, but I mean those wells are over 90% rate of return now. Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division: Yes, that's very noticeable. Good -- great point, guys. And just a follow-up, on the Utica, I noticed you need to have in that first one, shut-in, and talking about drilling as second. Here in the fourth quarter, again, I know you haven't said too much yet on that, Jeff, either for you or for Ray. Just wondering the expectations on liquids expectations and then thoughts on once you'll see these 2, will this dictate, I know you've kind of talked about your budget next year with this depending how good or how liquid these wells are, would this could dictate some of your spending next year in that area? Ray N. Walker: Yes, I'll start. I'm sure Jeff will jump in afterwards. The Utica well, we've done -- being the first well for us, we did not have to bear a lot of the cost of the learning curve that we did in the Marcellus. So we kind of setback on purposes, an HBP position. It's been there for years. And so we've kind of tried to learn from everybody else. But we began gathering data and then on this well what we've done is the actual data from this well, and I mean logs, cores, pressure data, everything that we've done to date puts us right on strike with some of the good stuff that's happening down in Carolyn and Harrison County that we're reading about. And we've been working a lot with offset operators and talking about that and exchanging data. So we've learned a whole lot. Everything we've seen today, we were very encouraged with, and so currently we've got the wells shut-in, doing the aging or seasoning or shake and bake or whatever you want to call it. And we do believe that there's some technical reasons that, that could help the well and could work on it. So we're just trying to gather all this information, get our test results, everything we see tells us we still should go ahead and drill the second well. As far as next year, it's way too early to tell. I mean I'm going to make the case until we get the results from these first 2 wells in some of the offset activity, we probably won't plan anything. Again, it's an HBP position, so we don't have to do anything next year. And I'd rather put our money in some known projects down in the super-rich, for instance, and make 100% rate of return wells if I could do that. Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division: Ray, are you talking Utica or the Point Pleasant? Ray N. Walker: It's the point Pleasant. In most cases, it's the Point Pleasant that's what's producing this, not really the Utica. Although, we all call it that. Jeffrey L. Ventura: And I'd just add a little bit, like Ray said, we're confident that we're in the liquids part of it, got all the right ingredients, we'll see when we test it. And Ray's point is really a key one. It's all held by production, just like all that stuff out in the Permian, where we're testing different things too. In the Marcellus, when we started, since it was a Range idea, when we were the first company out there, we had to carry 100% of the cost of the R&D. We don't have to do that for the Utica or for the Cline some of these other plays because they're HBP positions. I've noticed recently Floyd Wilson's company, Halcón, spotted a lot of wells just in and around it. So up there, they have a big position. You have [indiscernible] company has that and others. And we're right on strike with the good stuff and a lot of other people are -- you are going to start to see a lot of wells popping up in and around it. So, we'll do -- we'll carry some of the R&D and let others carry some of that as well.

Our next question comes from the line of Leo Mariani with RBC Capital Markets. Leo P. Mariani - RBC Capital Markets, LLC, Research Division: Just kind of a follow-up on 2013. You talked about ramping down the pure gas activity in Northeast Pennsylvania Marcellus and ramping up Mississippian by a fair bit. You said you will start the year with 5 rigs, just -- and then go to 10 in '14. Would you expect to kind of ramp up the rig count in '13 in the Mississippian kind of literally over the next couple of years to get to 10 rigs in '14 and then to 15 rigs in 2015? And would also expect any potential reductions in the wet Marcellus in 2013 as part of your plan to lower CapEx? Jeffrey L. Ventura: We'll reverse it, I'll start this time and Ray can go add on. When you look at the Mississippian, what we're thinking about right now, it's a little more stair stepped. We'll probably have 5 rigs starting the year probably in January of '13 going to 10 rigs in January of '14 and 15 rigs in the following year. And then obviously, as we learn to become more efficient, we'll tweak in all that, but that's trajectory. We really significantly drive up oil volumes, liquids volumes and gas volumes up there by doing that and hold all the acreage within the primary terms. So we think that we've got a really strong team up there, really good plan. In the wet and super-rich part of the Marcellus, as I said, we're looking at -- an easy way to think about it, and we'll get more clarity with time, but if you just look at that 3 ethane deals we committed to, we have to be by 55,000 barrels per day by mid- to late 2016, which dictates, if you back calculate it the other way, under most likely ethane extraction, it's 800 million a day. Under a minimum, it's 1.8 Bcf per day. We're currently at 3.70 Bcf. So it sort of gives you a feel, high and low, what the trajectory is just in the wet and super-rich part. Obviously, Ray is working with the teams there and the guys that we have on the ground. They're going to do that as efficiently as they can with the fewest number of rigs and lease capital to get the highest returns. So there's my -- I'm tossing the baton back to Ray. Ray N. Walker: Thanks, Jeff. It's really -- there's no -- it's really hard to think about slowing down in the southern Marcellus because we're really not slowing down in 2013. We're really continuing to grow pretty substantially. Jeffrey L. Ventura: We're slowing down the dry part in the Northeast, and we're keeping the southern Appalachia down in Nora idled. But, I think, as the gas prices pick up, those areas will kick in and really supercharge the growth. And at that time, we'll have better returns. So, I've seen a rupture from that. [indiscernible] I've never done that before. Ray N. Walker: And the drilling rigs, again, this is sort of one of my pet peeves. It's hard to think about rig count anymore as describing activity because these rigs are getting so fast, and so efficient that, I mean, we're literally doing twice the work with the drilling rig today than we did a year ago. So it's really more about in these kind of plays is what all of the industry is learning. It's more about infrastructure and pads and timing and bringing those pads online and all that sort of things. So what we're seeing next year is longer laterals, more frac stages. We're getting better and more efficient designs. We're having to build less infrastructure. So, we really are, activity-level wise, probably still going. We may be growing slower than we were, but we are still growing next year. We're not slowing down by any means. Jeffrey L. Ventura: And growing at a significant level. Ray N. Walker: Yes, very significant. Leo P. Mariani - RBC Capital Markets, LLC, Research Division: Okay, that's helpful there on the clarity. Question on the cost side, I've just been noticing that your transport cost has kind of been going up on $1 per Mcfe basis, really, ever since you guys kind of established that metric, I think it was in the fourth quarter of '11. You guys are expected to go up again this quarter. Do you just have any kind of longer-term color on when that may start to flatten out? Should we see that flat in '13 at $0.75 to $0.79 per mcf? Is that going to keep climbing? Just any thoughts you have around that would be helpful. Roger S. Manny: This is Roger. As I mentioned on the note, it's truly a variable cost. There's a lot going on under the hood with that metric. You've got money being spent, you've got production volumes varying in different areas of the company. So you got a lot of moving parts that come up with that. The uptick in fourth quarter, we've got some capacity on the team project that's coming on the fourth quarter. So the bills are going to start coming in for that capacity. So creates a little lump there. And the production will start to catch up and maybe you're putting out a plant somewhere. So it's just kind of a constant tug of war between volume and capital spend. So we'll continue try to guide you guys as best we can, but as I mentioned in the notes, the timing doesn't always kind of work out the way your spreadsheet says it's going to. But you'll probably see that continue to trend upwards for a piece and then eventually the volume will build, and it'll trend back down. Ray N. Walker: Especially, on the gathering side, Leo, and then on your transportation side, as we can transport this gas to newer markets that have a higher positive basis in the market to sell the gas at, that sales price is going to go up in gas sales. It's not going to come reducing to your transportation cost. So you're going to have to be cognizant of the expansion of the market and our margin versus just the absolute cost. So there'll be different arrangements that come that direction, but Roger is exactly right, is the gathering charges, you got to build it before you put the gas in it. There is our charging for you as soon as that comes on, but then as the volumes come on, it's going to ramp that per Mcfe down on the gathering. And we've discussed, internally, as to whether or not we actually break that line out into 2 components when it gets to some significant size. So as you can see, the gathering, ebbing and flowing, as you turn on things and then your transportation charge basically will translate back to your commitments footnote as to what you've got for firm takeaway capacity to be able to always deliver your gas to the markets and keep the gas to flow.

We are nearing the end of today's conference. We will go to Joe Magner of the Macquarie group for our final question. Joseph Patrick Magner - Macquarie Research: Just curious where the Permian fits in your plans for 2013 looks like you having good success down there I know a lot of it is HBP, but just curious how you're thinking about that. Ray N. Walker: Yes. I mean, right now we're not what I would call super active out there. It's a big HBP position, and we're drilling a few Wolfberry vertical wells. Those are, as we talked about earlier, they're improving dramatically just in the first 3 wells, and so we've got to see more wells we will do this quarter. We're still putting plans together to see what we do next year. Again, the important thing about that position is it's HBP. We don't have to do anything next year. So I'm guessing, at this point that we will have some minimal amount of activity there next year to kind of help prove up some things or more or less confirm some things that we learn from activity in the area. But no real big plans at all at this point. Joseph Patrick Magner - Macquarie Research: Okay, and then touched on a little bit, here, a second ago, just on improving rig efficiencies. Is there a way to quantify or perhaps provide us with an update on how many wells you think you can drill per rig per year in both the Southwest Marcellus as well as the horizontal Miss? Ray N. Walker: Well that's a great question, Joe, and unfortunately, there's not a real good black and white answer to it, because we're still finalizing plans on lateral length and completion styles and number of wells per pad and all of those different things. We're also looking at some better designed rigs as we've gotten smarter and gotten more wells under our belt and different things that we're considering. So it's hard to give you an answer, but you can go back and look at the -- I think it was in the last quarter where I spent a lot of time talking about the efficiencies that we saw year-over-year and quarter-over-quarter. And we're still seeing those kind of results. I can't quote you numbers today, but I'm sure we could get the IR guys to follow up with you on some numbers. But it's too early to talk about 2014 just because it's -- I mean, 2013 or '14, because we're still putting those plans together and finalizing kind of tweaking what the actual numbers will be. Jeffrey L. Ventura: Still need to present it to the board, still need to get approval, all those kinds of things. Ray N. Walker: Right. Joseph Patrick Magner - Macquarie Research: And just one last one, Jeff, you touched on gas prices, as gas prices pick up, perhaps ramping up some activity. What price level would you need to see on a sustainable basis for you to start thinking about dry gas activity again? Jeffrey L. Ventura: Well I think what's really key is if you look on our website for the dry gas areas, we have economics out there, and you can see them for both Southwest PA and in the Northeast. And -- I'll see if I can flip through it. I'll make my point and make sure I get it off the right numbers. If you look at, for instance, if you look at Slide 18, at PA, and it's on Slide 18 and you look at pricing, at $3 flat gas, it's a 21% rate of return; at a $4 flat price, it's 56%; at $5, it's over 100%. So, it's really price sensitive and really steep and the same thing is true in the Northeast with that going through it. When you look at -- and if you look at the strip out in 2014 and beyond, you're starting to see prices where you start to generate some really attractive returns in the dry areas. And the good news is we've got a really, again, we've got a really big bucket of dry gas opportunities, wet and super-rich opportunities and oil opportunities, and we have the operational flexibility to sort of throttle back and forth between those various buckets. And we're looking at maximizing the returns for the dollars we spent, most efficiently drive enough cash flow per share, production per share, reserves per share.

Thank you. This concludes today's question-and-answer session. I'd like to turn the call back over to Mr. Ventura for closing remarks. Jeffrey L. Ventura: Thanks to our hard-working teams in each division Range is on target to meet our 2012 production goals within our capital budget. We're driving down our unit cost in the process. Because we have very large acreage positions in some of the best plays in the country, we should be able to achieve double-digit growth in production and reserves on a per-share basis, debt adjusted for many years. Plus we continue to be one of the lowest cost producers in our peer group and are still improving. Therefore, we believe that this will translate into significant shareholder value in months and years ahead. I want to say, before I thank everybody for participating on the call, let me just add to that. We're out of time and, in fact, we've over run time by 5 or 10 minutes and there's still some people queued up in Q&A. So please feel free, sorry, we didn't get to everybody, but follow-up with Rodney and the IR team and we'll make sure that we do our best to answer all your questions. Thanks for participating on the call.

Thank you for your participation in today's conference. You may now disconnect your lines.