Jeffrey L. Ventura - President, Chief Operating Officer and Director Rodney L. Waller - Senior Vice President and Assistant Secretary John H. Pinkerton - Chairman, Chief Executive Officer and Member of Dividend Committee Roger S. Manny - Chief Financial Officer and Executive Vice President

Brian Singer - Goldman Sachs Group Inc., Research Division Leo P. Mariani - RBC Capital Markets, LLC, Research Division Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division Rehan Rashid - FBR Capital Markets & Co., Research Division Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division David W. Kistler - Simmons & Company International, Research Division

Welcome to the Range Resources Third Quarter 2011 Earnings Conference Call. This call is being recorded. [Operator Instructions] Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. [Operator Instructions] At this time, I'd 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 an increase in production and realized prices and a decrease in unit costs. All the key success factors are all moving in the right direction. Both Earnings and cash flow per share results were also over First Call consensus. Production at the end of September showed that we had also met our goal of replacing the production sold in the Barnett sale by the end of the third quarter and that being within 5 months. Range ended the quarter with still $52 million in cash and no amounts drawn on the bank facility, demonstrating that cost and spending are right on track. Range is prepared to finish out 2011 with again record-setting production volumes and taking that momentum into 2012. I think you'll hear those same themes reiterated from each of our speakers today. On the call with me are John Pinkerton, our Chairman and Chief Executive Officer; Jeff Ventura, our President and Chief Operating Officer; and Roger Manny, our Executive Vice President and Chief Financial Officer. Before turning the call over to John, I would like to cover a few administrative items. First, we did file our 10-Q with the SEC this morning. It's available on the homepage of our website, or you can access it using the 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 forecasting 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 available on the website. Second, we will be participating in several conferences in November. Check our website for a complete listing for the next several months. We will be at the Morningstar Conference in Chicago on November 10; the Bank of America Energy Conference in Miami on November 15; and the UBS Access Conference in Boston on November 17. In addition, we'll have several teams on the road during November. We hope that we can meet with you personally in the very near future. Now let me give the call over to John. John? John H. Pinkerton: Thanks, Rodney. Before Roger reviews the third quarter financial results, I'll review the key accomplishments that we achieved in the third quarter. On a year-over-year basis, third quarter production rose 7%, materially exceeding the high end of our guidance due to better-than-expected timing as to infrastructure buildout. Adjusting for the Barnett sale, third quarter 2011 production growth would have been 27% year-over-year. Most importantly, by the end of September, we had fully replaced the production in sold in the Barnett sale. Because the Barnett production represented 20% of our total production at the time of the sale, this represents a tremendous achievement by our operating teams to have replaced the Barnett production in just 5 months as Rodney mentioned. They deserve a big round of applause. Our drilling program was on schedule throughout the quarter as we drilled 77 gross wells. We continue to be extremely excited with the drilling results. Despite the low natural gas prices, we continue to generate very attractive rates of return on our drilling. We currently have 21 rigs in operation. The 7% increase in production was complemented by a 15% increase in realized prices. As a result, third quarter oil and gas revenues were 15% higher than the prior year. Due to significantly lower unit costs, cash flow was a whopping 35% higher than last year. Speaking of costs, we are most pleased on the unit cost performance side. We saw a 9% decrease in our 5 largest cost categories combined. This was the first quarter where we saw a decrease in each of the 5 major cost categories. Most impressively, direct operating cost per Mcf was reduced by 20%, while G&A expense fell 12%. With regard to our Marcellus Shale play, significant headway was made in the quarter as we continue to drill fantastic wells, fill out our acreage position and continue to build out infrastructure. In particular, the progress made on the infrastructure and marketing fronts has been very impressive. My hat goes off to those teams as well. As a result, we were very well positioned to achieve our 400 million a day net production exit rate target for the Marcellus. Currently, we're approximately 350 million a day in the Marcellus net. While our focus for this year has clearly been on the Marcellus, we have quietly built a very high-quality acreage position in horizontal Mississippian play in Northern Oklahoma that now totals 105,000 net acres. We believe the horizontal Mississippian play will be an excellent complement for our Marcellus play. All in all, I'm very impressed and very pleased on how much we accomplished in the third quarter. I compliment the entire Range team for a job well done. With that, I'll turn the call over to Roger to review the financial results. Roger S. Manny: Thank you, John. From a financial perspective, the first half of 2011 was a transformative period, with the Barnett sale providing significant future funding and substantive improvements in our liquidity and balance sheet. The first half also brought about declining unit costs and increasing production revenue and cash flow. For the third quarter, we built upon the favorable trends of the first half with continued top line growth, lower costs and higher production. The primary Barnett sale closing occurred in April, so the third quarter is our first quarter which includes essentially no Barnett activity. And as I've mentioned on previous calls, with the Barnett sale, we're again required to report our financial statements using discontinued operations accounting. Our filed financial statements break out the historical results of our Barnett assets as discontinued operations. We've also posted supplemental tables on our website and in the press release that reconcile the discontinued operations results with our historical results that include the Barnett. This information's provided so that investors may more easily compare their prior period projections with our current period results. On this call, when referring to historical performance, I'll be referencing the non-GAAP results that include the Barnett matching those used in the press release and supplemental tables. Now starting with the income statement, oil and gas revenue, including cash-settled derivatives, totaled $283 million, 15% higher than the third quarter of last year and 6% higher than the second quarter of this year. Behind the revenue increase are higher production and higher prices. Cash flow logged a fifth consecutive quarterly increase, coming in at $190 million in the quarter. That's 35% higher than the third quarter of 2010. Cash flow per share for the third quarter of this year was $1.19, $0.12 above the analyst consensus estimate. EBITDAX for the third quarter was $221 million, 28% above last year's third quarter. Cash margin for the third quarter was $3.78 per mcfe, up 26% from last year's third quarter and up 6% from the second quarter of this year due to lower costs and higher prices. Third quarter earnings, calculated using analyst methodology, which excludes nonrecurring and noncash items, was $45 million or $0.28 per share, $0.05 above the analyst consensus estimates. Cash flow for the 9-month year-to-date period was $529 million, and EBITDAX year-to-date was $620 million, 25% and 23%, respectively, over last year's 9-month figures. These non-GAAP figures are fully reconciled to our GAAP numbers on the supplemental tables posted at the Range website. Before moving to the balance sheet, let's walk through the key cost items for the third quarter. Starting with the biggest number, our DD&A rate fell from $1.98 per mcfe last year to $1.89 in the third quarter of this year. Now this $1.89 figure includes several nonrecurring items: one, a $0.07 per mcfe entry to realign the valuations of several properties in the Midcontinent; and two, a $0.03 accelerated depreciation entry on some miscellaneous assets. Adjusting for these 2 items, our core third quarter DD&A rate from continuing operations is $1.79 per mcfe. The fourth quarter is when we roll our year-end reserve report results into the DD&A rate, which should result in a further decrease to our rate. Direct operating expense, including workovers and excluding noncash comp, was $0.58 per mcfe in the third quarter. Direct operating unit costs for the third quarter of last year was $0.73, marking a 20% year-over-year decline in this key metric. As John mentioned our operating teams continue to deliver terrific cost productions this year and with the fourth quarter operating expense anticipated to be in the $0.56 to $0.58 range. Production taxes, as predicted, fell $0.15 per mcfe in the third quarter. That's down from $0.19 in the third quarter of last year on lower wellhead gas prices and changes in our production mix. We expect production taxes to fall another $0.02 in the fourth quarter. G&A expense, adjusted for noncash stock comp and other nonrecurring items, was $0.53 per mcfe, $0.08 below last year's third quarter. While G&A expense was predicted to be a few cents below last quarter, the drop to $0.53 was somewhat unexpected. It was partially related to the timing of several large public relations expenditures. Normalized for expense timing, G&A expense is expected to be in the $0.57 to $0.59 per mcfe range in the fourth quarter. Interest expense for the third quarter was up over last year on an absolute basis due to the refinancing of our short-term bank debt with higher cost long-term fixed rate notes. But on a unit cost basis, third quarter interest expense declined from $0.73 per mcfe last year to $0.69 per mcfe this year, and we anticipate interest expense on a unit cost basis to decline another $0.04 during the fourth quarter as our production continues to build at a faster rate than our debt. Exploration expense, excluding noncash comp in the third quarter was $17 million, higher than the third quarter of last year due to increased seismic and dry hole expense. And we've got several new seismic projects that are commencing in the last quarter of this year and delay rentals always seem to spike in December. We anticipate exploration expense increase next quarter to between $20 million and $22 million. Unproved property abandonment and impairment for the third quarter totaled $17 million. That's down $4 million from the third quarter of last year due to the Barnett sale, and we expect unproved property impairment to run between $17 million and $19 million next quarter. Range incurred no current federal income taxes this quarter as our federal income tax obligation for the quarter was deferred. We currently have a $347 million federal tax NOL carryforward and continue to generate large intangible drilling cost deductions due to the ratio of our income to our capital spending. and we expect our federal income taxes to remain deferred, but we'll probably incur state-level income taxes averaging about $1 million a year starting next year. All the big balance sheet news was in the first half of 2011. That leaves the third quarter without any major changes. Now we ended the third quarter without any outstanding bank debt and $52 million in cash. However, we will begin to advance against our revolving bank credit facility in the fourth quarter, and as we start to draw down on our credit facility, please remember that we spent the first $538 million of the Barnett proceeds paying off the bank facility. But just because we'll be advancing on the bank facility in the fourth quarter, certainly doesn't mean that we spent all the Barnett proceeds. Now speaking of the bank facility, the 28-member Range bank group unanimously reaffirmed the existing $2 billion volume base last week and elected to retain the current $1.5 billion commitment under the facility. Our hedging position remains strong with approximately 74% of our remaining 2011 gas production hedged at a floor price of $4.96. And in 2012, we have approximately 260 million cubic feet per day hedged collars and swaps with an effective floor price of $5.01 per Mmbtu. In 2013, we have 160 million cubic feet per day hedged, using collars at a price of $5.09 by $5.65 per Mmbtu. We also have hedges on 7,000 barrels per day of our remaining 2011 liquids production at $104.17 per barrel and 5,000 barrels per day of 2012 liquids hedged at $102.59 per barrel. All the hedge prices I've just mentioned are net of any applicable premium paid when establishing the positions. Additional hedging information may be obtained from the tables attached to the press release and the more detailed hedging tables on the website. So with the first half of the Barnett sale and balance sheet improvements behind us, the third quarter built upon the revenue costs and productivity improvements of the second quarter, and we look forward to similar continued progress in the fourth quarter and into next year. John, back to you. John H. Pinkerton: Thanks, Roger. That's a terrific update. Now let's turn the call over to Jeff to review our operations. Jeff? Jeffrey L. Ventura: Thanks, John. Range's development of the Marcellus Shale play continues to successfully move forward on all fronts. During the third quarter, 28 wells were brought online in the Southwest part of the play. The peak 24-hour rate to sales for these wells averaged 7.1 million per day. That's comprised of approximately 4.6 million per day of gas and 420 barrels of liquids per day. In Lycoming County, 10 wells were brought online and their peak 24-hour rates to sales averaged 9 million per day. Importantly, the infrastructure buildout continues on plan as well. In the Southwest, we currently have 390 million per day of dedicated cryogenic gas processing capacity. We also currently have access to another 100 million per day of interruptible processing capacity. Gathering and compression for the processing capacity is planned to be built to stay ahead of our needs in this area. In the dry gas area of the Southwest, we currently have 40 million per day of gas gathering and compression capacity, which is on track to be expanded to 80 million per day by year end. In Lycoming County, we currently have 90 million per day of gathering capacity with plans to increase that capacity to 150 million per day by year end. Additional compression will be added as needed. For Southwest Pennsylvania, we currently have commitments for over 420 million per day to transport natural gas to market either with Range-owned firm transportation or firm sales arrangements with customers who hold firm transportation. Transportation commitments in the Southwest are planned increase to 550 million per day during 2012 to accommodate the expected increase in production from the region. In the Northeast, along the Transco-Leidy transmission line, we currently have commitments of 80 million per day, increasing to 100 million per day during 2012 in the form of firm sales arrangements with customers owning existing firm sales transportation on Transco and storage at Leidy. We believe that our existing firm sales arrangements both in the Southwest and Northeast can further be increased as we demonstrate that additional production volumes are available. For the third quarter, Range's bases in the Southwest area of the Marcellus continue to be flat to a positive $0.08 per Mcf range, above the NYMEX Henry Hub index price. In the Northeast, along the Transco-Leidy transmission system, our bases for the third quarter continue to be in the positive $0.10 to 15% range above the NYMEX Henry Hub index price. Range has ramped up volumes in the play from $100 million per day net exit rate in 2009 to 200 million per day net exit rate in 2010, and we're currently on plan to exit 2011 at 400 million per day net. We're currently growing volumes, and as Roger has just mentioned, we're driving down our unit costs. At the same time, our marketing team is doing an excellent job of not only selling our gas but doing so at good relative prices. The achievements above are the result of having a really talented technical team that works well together and being the first mover in the play combined with long-term vision and planning. Said another way, it's a culmination of analyzing data, acting quickly and handling ourselves and business in a way that would make our parents proud. Specifically, having our operations and marketing groups work well together early on in the play has resulted in Range being able to receive higher sales prices due to the following accomplishments. Early on, we worked with MarkWest, who is already the largest liquid company in the basin. This allowed us to fill existing capacity that they had at Salem, Kentucky and also to build new infrastructure and capacity. Early on, we obtained necessary gas quality waivers from pipelines to delay taking ethane out of the gas until market could be developed. The first ethane project is now moving forward and others will follow. We realized that the Marcellus was a different animal in size early on and contracted for key capacity on pipes at lower rates than was currently available. We were also able to negotiate long-term sales contracts with key capacity holders on the system at terms that were favorable to both parties. Importantly, we started in Southwest Pennsylvania because we knew there was a better market and more pipeline capacity, especially in the summertime, and we also realized that liquids were very valuable. Lastly, we had a philosophy of more than one sales meter into diversion interstate pipelines or local markets, which allows us to move gas around to maximize flow in price. Being first in the play and believing in it quickly allowed us to execute deals early on before others could get to their feet under them. Let me give a little more technical detail about the Marcellus before moving on to another division. In the Northeast portion of the play, we brought online our first 5 horizontal wells in the first quarter of this year. On the second quarter call, I said that our average estimated ultimate recovery for those 5 wells is 6 Bcf. The average lateral length of the wells is 2,573 feet with a 9 stage frac. Those wells are performing better than expected, and our currently estimate for those 5 wells has been revised upward to 6.5 Bcf per well. For the first 5 wells, that's very encouraging. Looking at the EURs on a per lateral length or per stage basis, these are outstanding wells. We're running our own analysis of various lateral lengths and frac stages, and we're also looking at the results of other operators. Currently, we're completing a 4,500 foot lateral with 15 stages in Lycoming County. By year end, we plan on drilling a 5,000 foot lateral there. In the Southwest wet area, we have frac-ed a 3,950 foot lateral with 20 stages and 2 wells that each had 22 frac stages and 3,350 foot laterals. Most likely, we'll discuss all 5 wells during the fourth quarter conference call, since by then, we should have longer-term production results for this group of wells. In the Upper Devonian, we'll be spudding our third well into this formation beginning early in the second quarter of 2012. This well will target the wet gas portion of the play and will be drilled into the area with what we expect to be the highest combined gas and liquids content in place. In terms of liquids content, we expect the Upper Devonian will be like the Marcellus Shale. Where the Marcellus is wet, the Upper Devonian should be wet. Where the Marcellus is dry, the Upper Devonian should be dry. I also want to point out that the first 2 wells continue to perform well. In the Utica Shale, we'll spud our next well in the second quarter of 2012. Industry has drilled and will be drilling several Utica wells. Results of some of these wells will help us to delineate Range's acreage. A lot of our acreage is perspective for both the Upper Devonian and Utica shale. We hold all depth rights on our fairway acreage, so as we focus on driving up reserves and production in the low-risk highly economic Marcellus play, we'll hold the Upper Devonian and Utica potential both above and below the Marcellus. As we better understand the other 2 horizons with time, we'll then determine the optimum plan for each horizon. Moving over to the Midcontinent Division, I'll start with the discussion of our horizontal Mississippian play. To date, excluding one very short lateral, we have drilled and completed 8 horizontal wells with an average lateral length of 2,197 feet with 12 frac stages. Our current average estimated ultimate recovery for these wells is 485,000 barrels of oil equivalent. We now have 105,000 net acres in the play, which equates to approximately 2,000 potential well locations. If we keep drilling with roughly 2,000 foot laterals, we believe it will take 12 wells per section to develop the reserves. That equates to a little over 50 acre spacing. Assuming that the average recovery of 485,000 barrel holds, that's a recovery factor of 4% to 9% of the oil in place. I believe that to compare the estimate of ultimate recovery per well between operators or between areas, you have to attempt to factor in the lateral length and frac stages to get somewhat of an apples-to-apples comparison. We will observe how longer laterals are doing in other areas and what the costs are to drill and complete those types of wells. We also tried different lateral lengths and different types of completion ourselves. We'll be seeking the solution that generates the best project economics, not the highest IP or best ultimate recovery. If the optimum lateral length is longer, say, 4,000 feet instead of 2,000 feet, then the number of wells per section would most likely decrease from 12 to 6, and the spacing per well would increase from over 50 acres to over 100 acres per well. Of course, the advantage of this play, like the Marcellus, is that there's a lot of hydrocarbon in place. Given the strong technical team that we have, coupled with industry's track record of driving up the recovery factor with time, I believe that's what we'll see happen here as well. Typically, the higher recovery factor comes from down spacing and better completions. Up in the Texas Panhandle, we had excellent success with our first horizontal St. Louis well. It came online at 13.8 million per day and 903 barrels of liquids or the equivalent of about 19.2 million cubic feet equivalent per day. After producing for about 9 months, it's still making about 11.2 million per day and 694 barrels of liquids or 15.4 million cubic feet equivalent per day or 4.7 million net. So far, this well has produced 3.3 Bcf of gas, 138,000 barrels of NGLs and 76,000 barrels of condensate. The payout was within weeks. Since then, we've completed 2 more wells for a combined rate of 24.4 million per day of gas and 1,394 barrels of liquids per day or 28.8 million per day gross or 13.1 million per day net. We'll be drilling 2 additional horizontal St. Louis wells this year and have identified other prospects, which we plan to drill in 2012. To summarize, operationally, I think the team is getting the right kind of results. They're driving up production and reserves while driving down costs. We're continuing to build new infrastructure, gathering and compression for each new pad, so there's still a lot of efforts to get every new 10 million per day on production. Therefore, timing and logistics are still critical factors in the growing production. However, we're learning how to resolve those issues and accelerate our development plans. We're continuing to work on our plans for 2012, which we'll submit to our Board of Directors in December. I believe our shareholders will like what we're planning for 2012. At this point, I'll turn the call back over to John. I'll be happy to answer your questions in the Q&A. John H. Pinkerton: Thanks, Jeff. Nice update. Looking to the fourth quarter of 2011, we see continued strong operating results. For the fourth quarter, we're looking for production to average 608 million a day on equivalent basis. Assuming we hit our guidance for the quarter, it will represent a 12% year-over-year increase. Adjusting for the Barnett sale, the year-over-year increase jumps up to 43%. For the entire year of 2011, we have increased our production guidance target from 10% to 11%. As I mentioned earlier, we expect to exit 2011 with the Marcellus Shale production at 400 million a day net and with total company exiting at roughly 650 million a day net. As noted in our release, we currently anticipate capital spending for 2012 to total $1.47 billion, which is $90 million or 6.5% higher than our beginning of the year budget. The budget increase was not related to service cost inflation. It is directly related to costs associated with nonoperative drilling operations in the Marcellus, Ardmore Woodford, Cana Woodford plays as well as additional leasehold acquisitions costs and the horizontal Mississippian play in Northern Oklahoma. So far this year, we have participated in 47 nonoperated wells. As Roger mentioned, the third quarter provides a very good picture of Range post the Barnett sale. In many respects, the third quarter was one of the best quarterly performances in the company's history. Production far exceeded guidance. Unit costs decreased significantly. Margins expanded. Cash flow increased 35%, and earnings more than doubled, and we ended the quarter with a very strong balance sheet, with $52 million of invested cash and no outstandings on our $2 billion bank credit facility. The good news is that the fourth quarter should be even better than the third quarter. Fourth quarter production is expected to jump roughly $70 million a day over the third quarter. As noted earlier on an apples-to-apples basis, adjusting for the Barnett sale, fourth quarter productions anticipate to be 43% higher than the prior period. That's a significant increase. At the same time that we're accelerating our production growth, we anticipate further reductions in our unit costs in the fourth quarter. All in all, the fourth quarter results should give our shareholders a good view of what 2012 should look like. Despite a lower commodity price outlook, we anticipate 2012 revenues, EBITDAX, cash flow and earnings to far exceed those of 2011. We see 2012 as a breakout year for Range. As just discussed, our operating teams are continuing to enhance and improve our well results while maintaining our solid safety record. In addition, Jeff discussed the tremendous progress our infrastructure and marketing teams have also achieved. The challenge is not only defined in the developed reserves at low cost but also to have low operating transportation costs and to market your production in an efficient and competitive way. Our third quarter results indicate that we're doing an excellent job in all these areas. While clearly biased, I'm convinced we have an exceptional asset base and drilling inventory as well as an exceptional team of people driving our performance from the drill bit to the burner tip. Our management team is keenly focused on enhancing our asset base and improving our team's performance. Selling our Barnett Shale properties was somewhat of a bold move, as the Barnett properties comprised 20% of our production at the time. However, we believe it best served Range's shareholders, as it provides a clear path for capital funding and allows our shareholders to retain 100% of our 40 to 56 Tcfe of current resource potential. From an investor's point of view, I believe Range is somewhat of a unique proposition. Because of our high-quality drilling inventory and low-cost structure, we can generate attractive returns even at today's low natural gas prices. This provides substantial downside protection. On the other hand, because of the extraordinary resource potential of the Marcellus Shale and our other projects, we have one of the largest per share upsides of any company in our peer group. With the Barnett production now fully replaced, our growth will accelerate sharply. Combining the fourth quarter growth rate with lower unit costs will have a big impact on our fourth quarter results, our 2012 results and our net asset value per share. We appreciate the support and guidance and confidence that our shareholders have shown us, and we look forward to the fourth quarter of 2011 with great anticipation. With that, operator, let's open up the call for questions.

[Operator Instructions] Our first question comes from the line of Dave Kistler from Simmons and Company. David W. Kistler - Simmons & Company International, Research Division: Real quickly. Just kind of a housekeeping item. Can you break out of the $100 million increase in CapEx, give or take, how that was broken up between higher nonoperating costs and leaseholds? Jeffrey L. Ventura: Yes, it was -- about $110 million of the increase was due to the -- excuse me, of the $90 million. It was -- if you're looking at probably about 25 leases and the rest was capital. David W. Kistler - Simmons & Company International, Research Division: Okay, great. And then based off commentary, obviously things are going very well in the Marcellus niche line, your St. Louis wells and then from your release, Nora wells as well. Can you talk a little bit about with strong activity in all those areas, how we should we think about capital being deployed next year? As John mentioned previously, he said the majority of capital was directed to the Marcellus. Will that break down differently next year? And while you can't give us the numbers specifically on that CapEx, directionally, I would imagine it's higher with that many attractive things in the portfolio. Jeffrey L. Ventura: Yes, I mean, we're still putting together our program for next year. We'll present it to the board in December. And with the new total of 1.47 billion, you're looking at -- the breakout by division would be 86% Marcellus, 6% Midcon, 4% Pine Mountain and 4% Southwest. Although it's early, directionally, it'll probably be very similar to that. Granted, it may go up or down a little bit between divisions. But you're still going to see big focus in the Marcellus, probably the biggest change next years. And when we put it in our release, you'll know ultimately we'll probably have a couple of rigs drilling horizontal, Mississippian wells in the Midcontinent and a program with both. David W. Kistler - Simmons & Company International, Research Division: Okay, great. And then one last one, obviously, you've had attractive production gains on a per well basis, but if I recall correctly, you've had pretty significant efficiency gains as well on the drilling and completion side. Can you guys just kind of give us an example from first of the year to where we are to date in terms of what kind of upticks you've had in drilling efficiency gains and completion efficiency gains in the Marcellus? Jeffrey L. Ventura: One thing I would say is we talked about all along, and I think about this on the last call, but in a development mode, ultimately, in the Southwest to get the 4 million per day. We just signed a pack of AFEs yesterday. The wells on those development wells in the Southwest that are 8 or 9 stages and that 2,500 to 3,000 foot, they're right at basically about 4 million. So we have achieved that number. Importantly in the Northeast, since we just started this year drilling, talked about in the development mode, we'd get the 5.2 million. The earlier wells this year were probably 6 million, plus or minus. Talking to Mike Middlebrook and Mark Whitley just this morning, but more recent AFEs, currently, up there 5.4 million for wells again that have about that same type of completion. So that's pretty great progress in a relatively short period of time to approach that development mode number. So what makes me excited is then looking forward -- again, and I've said this before, but I think 1 of 2 things will happen. We put out all of our horizontal wells that we've ever drilled by program here in the form of a 0 time plot, and what you've seen year after year after year is those numbers climb north. Hopefully, through continued optimization, you'll see improvement in terms of the reserve per well as we continue to update that. After year end, we'll do that again. As I just mentioned, in the Northeast, we've gone from 6 Bs per well to 6.5 Bs per well in a relatively short period of time just because the wells are declining less and producing better than that forecast. And then going the other way, once we lock down on an optimum design and we've got literally thousands of wells to drill, I think our team will really get better on the cost side as well with time. David W. Kistler - Simmons & Company International, Research Division: So just to kind of clarify a little bit, while you've hit that target cost in the Southwest and you're darn close in the Northeast, do you expect to actually come in below those now looking froward? Jeffrey L. Ventura: I think if we kept that same design year after year after year, then we would, clearly, I think break those numbers and come in lower, which is a huge upside. And if 2 or 3 years out, we kept that same design but we can knock $0.5 million off per well, which isn't unrealistic over that time frame, and you do that over 5,000 wells or 10,000 wells, you're talking $2.5 billion to $5 billion. But relatively on the front end of a projects, it fully would positively affect the economics. The other thing to remember though, I also said we have a lot of experiments, and I talked about the longer laterals or even moderate laterals but with a high number of stages, so you're breaking up more rock. To the extent we do that, those wells are more expensive, then the question is does the higher capital generate a higher rate of return, and do we ultimately shift some of our drilling in particular areas that way. The jury is still out, but the good news is whether you look at it as we keep the same design, we have really strong rates of return doing what we're doing today. If we keep the same design, there's upside that they can get better, or if we go to some of the higher density stage fracs or longer laterals with more stages, that also can improve rate of return. I think either way, we can do better than what we're doing today, and what we're doing today is great.

Our next question comes from the line of Brian Singer from Goldman Sachs. Brian Singer - Goldman Sachs Group Inc., Research Division: Looking at your exit rate guidance of 650 for the total company and 400 for the Marcellus, implies about 250 million a day coming outside the Marcellus, which is a decent step-up from what was just slightly north of 200 million for the third quarter. Does this represent an inflection point here in non-Marcellus production? Can you just add a little bit more color on whether that's backlog of wells, whether it's some of the strong St. louis wells that you just mentioned in your comments and a breakdown between the Mississippian and other plays? Jeffrey L. Ventura: Yes, I would say, when you look at the Midcontinent Division, those guys have done a great job. So even though they're allocated not a lot of capital this year, they're being very efficient with their capital. When you drill high-rate wells like that in the St. Louis, you're getting really good growth for not a lot of capital, coupled with what they've done in the horizontal Mississippian. So I think the guys up there are doing more with less, and they're showing the quality of some of those plays. Same with the team that we have in Virginia, in the Southern Appalachian basin. Even though they're not allocated a lot of capital, they're still getting growth with the dollars that they're spending. So I think the guys in the other divisions are doing a good job, and it shows the -- even though we're focused on the Marcellus, by clearing away, that's our -- John mentioned, we have 40 to 56 Tcf of upside. Just in the Marcellus, it's 22 to 32. But what that means, we have good growth in the other areas as well, so we've got high-quality portfolio. Brian Singer - Goldman Sachs Group Inc., Research Division: So I guess should we look at this as a run rate of incremental 40-plus million cubic feet a day? Or is there kind of some backlog of wells coming on? Or should we expect these increases, again, x Marcellus to be a bit more spotty? Jeffrey L. Ventura: Well, I think you're going to see -- we haven't set our budget for '12 yet. Part of that depends on how we allocate it. But to the extent we go to program drilling in the horizontal Mississippian and if we can continue that early success that we have, then those guys will be able to continue to drive up production. And again, I would think the spending level in Virginia is probably will be similar, although the board, we haven't presented and they haven't approved the budget yet. So you're looking at probably very modest growth there. Brian Singer - Goldman Sachs Group Inc., Research Division: And then as you look ahead into next year, how are you thinking about future asset sales? And is that something that's going to be a priority for 2012? John H. Pinkerton: Brian, John. I think we've done -- the Barnett really was, I think the inflection point and that it really, from our perspective, it kind of completely reloaded us in terms of, in our minds, having a clear path in terms of capital funding and in terms of self funding. So -- and we look at that as kind of the big guy. There's some other things that we will look at from time to time, and we sold some Mississippian asset this quarter. I think we sold some assets down in East Texas, and we sold a few other little assets, some CBM, some very shallow kind of marginal CBM assets in Pennsylvania, so we'll continue to look at some of that. And then we've got a few other little projects that we're looking at that either people come to us or we've gone out to people that we believe would have an interest in it, and Chad Stephens and our A&D team are doing a tremendous job of just looking at that and figuring out what we're going to do. My gut feel is over the next couple of -- or let's say between now and the end of next year, I would think that we'd be somewhere in the, if you want you to pin me down a number, probably somewhere in the $50 million to $100 million, maybe $150 million range of additional asset sales, of things that we're looking at. But again, I think the key is, is that one of the things we're really focused on at Range is really driving up NAV per share. And to the extent that if somebody were to come in and offer us a great price for a particular asset, we're going to take a hard look at it, and if we can then take those dollars and then reallocate it into other projects and accelerate that NAV, we're going to jump on those opportunities and try to do that. So we're in good shape. We don't have to do the asset sales, but to the extent that we do them, we've got place to put the capital and really ramp up our -- continue to ramp up our NAV.

Our next question comes from the line of Mike Scialla from Stifel, Nicholas. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: I wanted to ask on the Upper Devonian, I know you said your next test there you plan in the second quarter and it just seems to me that, that 10 to 14 Tcf is a big number obviously. Any -- do you feel any pressure there to go any faster to delineate that asset? I would think you'd need to kind of see how real that 10 to 14 number is in terms of how you want to lay out your infrastructure for the development of Southwest Pennsylvania. Jeffrey L. Ventura: I sort of view it as a 2-step process. I think if you go by the end of 2012, I think we'll have a lot more indications of what that is, and step one is just understanding it. We talked about just moving rigs into the center of the thick wet part and drilling them now. What we talked about operational is that there's sort of march in there a little bit, and that way, when -- other than drilling them and getting them a short-term test, we can actually drill them and put them online, which is much more meaningful data. To the extent we derisk, we can come back to the market and talk about the quality of the wells and the results, and particularly, if we can demonstrate a nice wet area like there is in the Marcellus, I think then, people will start giving us some value. The second stage is then how do you optimally develop that, and it depends on the quality of the wells and what we find. But -- so I think we're on track towards getting there. When we put our budget together, we'll have probably on the order of 5, 6, 7 wells in the Upper Devonian, and we'll test some of those better wells in 2012. So I think by the end of '12, we'll have that. And to the extent we can get in there a little quicker, we will. But we're trying to set it up, so when we drill them, we actually can bring them online. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: I guess along those same lines, it looks like the backlog of uncompleted wells or wells waiting on completion in the Marcellus continues to kind of go up. And just wondering how do you view that number over the next 12 months. And is the gating factor there really to access the completion crews? Or is it more on the gathering side? Jeffrey L. Ventura: It's probably more on the pipeline build-out and gathering. When we -- by the end of the year, we'll have the next phase of Lycoming County done, and that will bring a slug of the wells on. But remember, we've got such an attractive acreage position that really, across that whole fairway, looks like it's working. As we bring new areas on, you'll see the production come up, but as we step out and test and have success, you may see a little backlog again. So there'll probably be a little bit of a wave up and down. The good news is you go back to where we started, it's not only has it worked. It's worked across a broader area than I think most people expected, and the quality of the wells is much higher than what most people expected, to where now, I think, most people recognize the best gas play in the U.S. is that and particularly if you are in the wet area, which we are and we dominate, it stacks up well really versus any play out there in the U.S., including a lot of the oil plays, if not, all of them. John H. Pinkerton: Yes, I mean, Mike, just to kind of tie on to what Jeff said, I think you're right. I think it was not as good intuitive view of it. I think it has gone up a bit but I think we are going to put a big slug of wells on towards the end of the year in particularly in the Lycoming County. And then we have another pad in the Southwest PA that we're putting on, assuming we can get the Corp of Engineers out of our hair. That should come on later in the year as well. So that's going to bring it back down a bit, and I think, plus or minus, as Jeff said, I think it will stay pretty stable from there on out. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And, Jeff, you gave quite a bit of detail on your firm transportation agreements and your realized price. I guess one of your neighbors in particular, I guess maybe a couple to the north have talked about some basis widening to NYMEX, at least, for their realized price. It didn't sound like from your comments that you anticipate that. But can you talk in general about where you see that basis going and maybe the risk for the whole play given the growth potential for the Marcellus? Jeffrey L. Ventura: Well, let me start, and I'm sure some of my colleagues around the table will chime in. But I think the good news is we have a big position, 550,000 acres in the Southwest, another 240,000 in the Northeast for the numbers that have out, so we've got big positions across the play. And like I had mentioned, when you're in the Southwest part of the play, you just have better infrastructure in general and better ability to move the gas around, plus being the first mover and having a really good team, looking far ahead, we were able to capture a lot of things to where we can not only move our gas and sell our gas, but do so at a good price. And then out in Lycoming County, as you market, as you go as far as you can to the Northeast, throughout Bradford County and some of those areas, it's -- obviously, it's a lot more difficult to move gas, and that's where you've seen the people selling gas for less than $1. Range's focus is primarily in the Southwest, but a big position in Lycoming County and coming to the Southeast of there. So where our gas is located has an advantage, and like I said, being the first mover has an advantage. If you look farther out, we've talked about, currently we're at about 350 million per day net, with the ability given tremendous upside we have at 22 to 32 Ts of having the opportunity if that continues to drill out to maybe hit 1 Bcf per day, 1.5 Bcf, 2 Bs per day, potentially 3 Bs per day over time. And we just had a giant marketing meeting yesterday with the entire team and getting everybody together, and my biggest concern or our biggest concern is can we move Range's 3 Bs per day. If we can -- or 3 and that could be beyond that, we've got the opportunity to grow our rates in the Marcellus tenfold, let alone, reserves tenfold. That's really what concerns me. A lot of people talk about what can the play do we overall. I'm most concerned about can Range move our gas and do so for a good price. I feel bad for my brethren that give a lesser for their gas or they can't move theirs. But we can create a lot value for our shareholders if we can drive up our -- stay focused, stay disciplined, drive up our production per share and reserves per share like we have been doing. I think at the end of the day, the good news about the Marcellus is we're in the highest quality gas play with the lowest breakeven price located in the best area. We'll always have an advantage in terms of transportation, so those are some broader thoughts, but... John H. Pinkerton: Yes. Let me -- yes, this is John. A couple of things. I'll bring it back down a few thousand feet. What's interesting about the Marcellus more than a lot of the shale plays, in particular in the Barnett, which is we're headquartered in Fort Worth, so we saw it first hand is that there wasn't a lot of large pipeline systems in and around the Forth Worth basin when that play started. So all that had to be built out, including the big, big trunk lines that -- in particular, the big trunk line that [indiscernible] out of the Barnett. The Marcellus is different in that there is a number of very large transmission systems that run right through the middle of the play, so instead of having to build giant pipelines that go hundreds of miles, that cost billions and billions of dollars, what you're really having to build out are the toll roads -- or not so much the road, but the entry ramps on in and out of those big, big transmission systems. So that's really what's going on. That really gives the Marcellus a huge leg up compared to some of the other shale plays. Obviously, the other huge leg up is that the Marcellus is located in the best parts of the United States to sell gas, which is in the Northeast, so that's a huge upside as well. So again, I think -- and the other thing obviously, the whole industry we need to focus on, we found a heck of a lot of gas there. We need to work on the demand side and increase the demand side, and I think as an industry, we're starting to do that. And I'm seeing a lot of really good positive things both in terms of electric generation and also in transportation fuels. And yes, this is going to take a matter of time. The other thing I think, again, just going back down a little bit is that if you really think through some of the issues up in Appalachia in terms of some of the -- of our brethren that have gotten some pretty low prices, it all comes back to you've got to be able to built out your gathering and your compression. That's one thing. The second thing you've got to do in the Southwest, you've got to be able to process it. The other thing you need to do is be able to -- once you get on those big pipeline systems, there's a multitude of different ways of getting on those big transmission systems, and some people will take what they believe is the less expensive way out by not getting firm transportation, but in -- as we've seen, they paid a huge price for that. We've got really good marketing team, and we've got all the firm transportation, as Jeff mentioned, that we need to ramp our production way through 2012, '13 and '14, and they've done a really, really good job of getting all that firm transportation there at really reasonable cost, and they've done a really good job. These are -- our team has been up there for a long time, and they've been in Appalachia. They know what they're doing. They know the white hat from the black hat guys. These were not people to have to kind of get up to speed, and they've really done a tremendous job, and so that's why our basis is holding up. I think it will continue to hold up through the play because they've just done a really good job, and we've got those contracts in place to move it on those big transmission pipes. The other thing that's going to happen is you're going to see as the Marcellus -- continues, I think we're at -- they think we'll -- at least our analysis of it, the play will be over 4 Bs a day by year end, such huge ramp-up. We think you'll start seeing gas move out of the basin over time, over the next few years. You're going to see a lot of -- gas can go both ways, and you're going to see gas going out of the basin in a lot bigger volumes than you've ever seen, and again, the good new is, is all those transmission systems are in place to do that. We don't have to build a bunch of transmission systems. It's just really the access to get it on and off. On a relative basis, the Marcellus is well set up to be able to really get after that. Obviously, what we need is a better economy, better gas demand, in general, from industrial, and then we need an administration that actually embraces natural gas versus kicking us in the gutter, but we'll work on that as well.

Our next question comes from the line of Ron Mills from Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Jeff, question on the Mississippian Lime. You and John both talked about or at least, the press release, 2 rigs next year. What's the expectation in terms of timing of the startup? And can you just describe -- put a little bit more background on what you're doing now from an infrastructure standpoint to get prepared in terms of saltwater disposal wells and systems and how many Mississippian Limes you think -- well, lime wells you think can tie in to each saltwater disposal well just to get a sense of that development plan. Jeffrey L. Ventura: Yes, one thing you have to remember is how we got started in the play. We got started in the play roughly 5 years ago, plus or minus. We started up there and we started reactivating an old field called the Tonkawa field, and I'll recreate the history. It was the biggest light oilfield back in the 20s, pretty much depleted by the 30s. We went back in and started drilling Tonkawa wells, which were about 2,700 feet deep. That worked out real well. We ended shooting in 3D, and that's really what got us started in drilling the deeper horizons, deep being the Mississippian Lime and below. And we drilled some great verticals well, and then stepped out and -- so, we have a number of vertical wells and we have the 8 horizontal wells, and they're all producing. So we have our saltwater disposal wells in there, and we have capacity already. We're actually probably going to pick up one of those rigs maybe later this year. So we may spud a well sometime in late November. So a second rig, we're still working on. We'll probably have another saltwater disposal well to set up before we start drilling. So we're already selling gas. We're selling oil up there. We're disposing the water. The guys are preplanning for that 2-rig program now, so they're going to hit the ground running. The good news there is the horizontal Mississippian is somewhere on the order of 4,000, 4,500 feet true vertical depth. Below that, you have the Arbuckle. The Arbuckle wells are very prolific saltwater disposal wells, and those are 5,500 feet or so, plus or minus. And those wells can take 40,000, 50,000, 60,000 barrels of water per day barrels per well. So it depends on how prolific your horizontal well are and how hard you pull them, but you can put several producers into a single disposal. We've got a team that's worked that area for a long, long time. They have -- so we've been up there working it really since 2004 specifically. But I think we have guys there who have been working in the basin forever, so they know how to produce oil dispose of water and sell gas and process gas and they're working the well ahead. So I'm excited about what that is. They've done a great job of putting together a pretty blocky acreage position that we feel is one of the best areas out there. John H. Pinkerton: Ron, [indiscernible] this is John, is that just a week or so ago, we executed a midstream agreement with a private midstream company. Once you produce oil, you're going produce gas, high Btu gas and you produce water. On the high Btu gas side, we've just executed a midstream agreement with the company to help build out the -- with them, their balance sheet but build out the gathering system and also process the gas and extract the liquids, something that our marketing team has already done. That contract's in place. It's already been executed and they're already out there digging ditches and putting pipe in the ground and getting ready to build a cryogenic plant to help do that. So again, the team -- it all comes back, so you've got to have a team concept here. It takes, as I mentioned, you not only -- you got to find the reserves at low prices, but you got to produce and then you got to figure out how to market all the stuff. And the good news is that we kind of learned that in a big way in the Marcellus. We put a big team together on the marketing and infrastructure side, we've done the same thing in Oklahoma, and we've got a great team there, too. So that's really good. The One thing I also want to mention is that as -- when you're really sitting kind of where Jeff and I and Roger are is one of the things you're concerned of when you start off a new play like this and 100,000 acres is a lot of acreage, we can drill thousands of wells, is do we have the talent and the management and the technical team in place to be able both do the Marcellus and then start ramping up the Mississippian. And I think Jeff made a really good point is that we've up there. We got a team in Oklahoma City, and the good news is that team has done a good job, knowing the St. Louis with the Mississippian Lime. And so the team that's working on those projects in Oklahoma and Texas Panhandle is a completely separate team from the team that's working the Marcellus -- and so that's really good. I think -- I'm just looking at my headcount here. We've got about 102 people that work out of that Oklahoma City office. So you can see we've got -- and it's headed by Greg Kline [ph] and his whole team and Max [ph] and the others there, a really good type quality team. As Jeff mentioned, have been there years and years and years and been Range for years and years. So we're excited about it. I'm rooting for them because I think it's going to be a great play and it's really going to be a good complement because it's primarily oil. And so we've found enough gas for a while, so I think it's really going to complement us, and again, as you look forward, things through kind of Range and building out margins and all the things they're going to do in terms of NAV, it's really going to -- I think it's going to be fun to watch this project and see it tick off. I'm really rooting for them. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And one follow-up, just on the acreage. Obviously, your lease acquisition there has accelerated in the past 3 to 6 months and not as much activity/news flow kind of east of the Nemaha Ridge, although that sounds like that may be starting to change particularly next year. Can you just give a lay of the land of east of the ridge versus west of the ridge where other operators started developing the play earlier? Is east of the ridge more dominated by smaller mom and pops types privates, and so there's still ample acreage acquisition opportunities? Or is that also just starting to become more tightly held? Jeffrey L. Ventura: Well, I'd say one thing. We are on the ridge. So you have that whole area that's been defined and there's different mats out there. So there's -- you can go west of the ridge, on the ridge or east of the ridge. It's interesting -- and I saw somebody put a map out to just look at historical vertical wells out there. If you look at where the best historical, vertical oil wells are, that's where range's acreage is. Somebody asked me offline, why do your wells -- it's early on and granted, can we hold it up? And as we drill, we will continue to see those results, but why are your wells look so good for the -- why you're getting the 485,000 barrels for 2,000 foot lateral, while other people are drilling 4,000 foot laterals and their reserves are in the same range? And if you look at the historical vertical wells or where the best wells are, that's where are our acreage is in and around. So it's necessarily east of the ridge or west of the ridge. It can be on the ridge or there's -- just like in all of these plays, where your acreage is really matter. It's true in the Marcellus, and again, I got to say it because I'm excited about it because we've got a great position, but it's great having a dominant position in the southwest part of the play where the liquids are, where you get a lot of high-quality wells. It's great being in the Mississippian play that we have, obviously in the right area. The St. Louis play, those guys clearly have picked some really good perspective. St. Louis acreage given -- is evidenced by the quality of the well, so where you are in all these plays are what matters. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And then one on the Marcellus. I mean I think you had mentioned you have 21 rigs total right now. Can -- could you break down how many are in the Marcellus? And then of those, how many are busy performing pad development drilling versus moving around acreage from an maintenance program? Jeffrey L. Ventura: Okay. In the Midcontinent, we currently have one rig drilling. It's drilling the horizontal St. Louis. We have 3 rigs drilling at Pine Mountain, finishing out their program for the year, Pine Mountain being Virginia. We have at least 17 rigs in the Marcellus of which 3 are with Talisman. They're outside operated, so currently and we have -- so that leaves 14 rig that we operate, 9 in the Southwest, 5 in the Northeast. Actually, right now there's 4 in the Northeast. There's one air rig that was just popped in there temporarily. So when you look at that -- and this is the good position we're in. Again, going back to that 550,000 acres in the Southwest, currently, over 90% of that is derisked, and that's derisked of by over 1,000 wells by Range and industry with production dating back to 2005. So it's not like we're running around HBP-ing acreage, to HBP acreage. We're HBP-ing acreage as we're driving up production and reserves and driving down costs with rates of return at strip pricing and they're in out pitch book. You're looking to 80% to 100% type rates of return, depending on what price deck you pick. That being said, you are right and correct and that periodically, we'll jump into some of the new areas, which I mentioned earlier this year is 35 miles away. That acreage, people get lost. Just in Washington County, we have approximately 300,000 net acres. When you think of a county, that's a big area. So a lot of people get lost in the size and the scale of the project. So even though a lot the areas is derisked, our acreage is derisked, it's across a big area, so periodically, we're stepping out 20 miles, 30 miles, 40 miles and drill a well or 2 or 3, and what helps us do then is plan and bring in gathering at system and ultimately, compression so that we can produce it. It's sort of -- not that I'm evading what you're asking, but I mean, we're driving up production while we're with our rigs, at the same time stepping out and testing things. So it's sort of mixed in there, and while we're doing all that, we're holding acreage. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay, and then one, just I know you talked about this every once in a while, but you still have the legacy position in the Permian. Any plans to continue to test the horizontal Penn Shale or Wolfcamp Shale? Or is that really more back burner as you focus on Mississippian Lime and the Marcellus in the near term? Jeffrey L. Ventura: We have an interesting legacy position there, and in the Penn Shale, we talked about -- we have over 90,000 acres HBP in our Conger area. In fact, we've added to a little acreage around the fringe. we're probably over 100,000 net acres there today. So we've got a great position there. We drilled our Penn Shale well and on that first -- well, to back up, for those of you who haven't heard the story, we drilled a couple of vertical wells there a few years ago and we found oil in them. They were vertical wells, not very commercial, but it confirmed we had a nice, thick Penn Shale section saturated with oil. We came back and we drilled a horizontal well earlier this year, and I'm pretty excited about the well. It's early on, but for our first try out there, we got a pretty reasonable well. It wasn't a very long lateral. It was not a lot of stages. I'm sort of looking to John and Rodney here I have the rates in front of me. I'm debating whether I should just say what they are or if we should hold that back. It's pretty exciting from -- I mean, given the way we drilled and completed it, we made a pretty reasonable well. In fact, we're going to spud a second well here probably in November. We'll move about 10 miles way, drill a second well, delineate it, and we've got a good position. There's no question there's oil in it. It's interesting some of our brethren now are out there with buildings Penn Shale position and these are shale players in and around it. Again, it talks about the portfolio, and again, it's oil, so it's a balance against gas. It's HBP acreage. There's no pressure to drill it. It's at a reasonable depth, 8,500 feet, plus or minus, so it has a lot things going for us. The shale there ranges from 270 to 330 feet fixed, so it's nice fixed section. That was a little -- hopefully, that's a little more detailed than what I talked about before.

Our next question comes from the line of Rehan Rashid from FBR Capital Markets. Rehan Rashid - FBR Capital Markets & Co., Research Division: Real quick on the Marcellus again. Jeff, what recovery factors are being implied in the, call it, that 5.7 and 6.5 Bcf in the Southwest and Northeast? And kind of the latest wells are trending higher than that, I know you mentioned the beginning. But what will it take in terms of data to move the EURs possibly higher? Jeffrey L. Ventura: That's a great question. When we talk about those kinds of recoveries, you're really looking at a recovery factor that's about 30%, plus or minus. And when you look at plays -- other plays that have more history, like the Barnett and you look at the better parts and the higher quality parts of the Barnett, I think, people have reported recovery factors of up to 50% of the hydrocarbon in place. So given that I personally -- I believe what I think we could show people and most people would accept it, the quality of rock in the Marcellus is higher than the quality of the rock in the Barnett. That's why -- and you look at the best part of the Barnett, where you're looking at an entire county, you're looking at roughly 3 Bs per well on average. And now most people reporting in the Marcellus numbers that are a lot higher than that, so you're getting higher quality rocks or better performance. I think the recovery factors, in time, will come up. I don't think they're going to stay at 30%. It will come up either through performance, one, is what's driven it up. Better completions would be 2, and then tighter spacing ultimately would be 3. So I think in time you'll see that come up. That's the beauty of the position that we have when we say there's 22 to 32 Tcf of upside in the Marcellus, the bias is actually higher as the recovery factor comes up with that, and historically, that's what we've seen back when we started in 2004 to '05 to '06 to '07 till today. Year-after-year, we're seeing better performance, and that's exciting, and it doesn't happen in every play. And I won't go through the plays, but there are some plays that either didn't work or the performance actually has come down with time. So it's an extremely exciting play to in and I couldn't be more upbeat about our future. Rehan Rashid - FBR Capital Markets & Co., Research Division: And just a follow-up question to that was how much more data would you need to move to bar up a little bit? Jeffrey L. Ventura: Well, I think, it's a combination of what we have in place are a number of those different types of experiments, everything from longer laterals and with -- what a lot of people are going through, I think, more recently are moderate laterals with just a lot more stages in them. So it's a matter of looking how that performs, we think how you drill the land to well matters, so examples out there of tests we put in really over a year ago where we looked at tighter spacing, 500 feet versus 1,000 feet and on I think 3 different pads. So we have some of that information out there. What we'll do since we have so much acreage is continue to drill and probably hold on the spacing that we're on and then ultimately come back later and look at down spacing. If we can drive production up to 1 B per day, 2 Bs per day to 3 Bs per day, during that time -- we'll be driving up production per share, net adjusted reserves per share, net adjusted cash flow per share and at the same time, be able to demonstrate to the market of what the real upside of the properties are, I think we can really create a lot of value. Rehan Rashid - FBR Capital Markets & Co., Research Division: One last one. So industry colleagues have talked about a kind of new frac design going down 250 feet between stages rather than 300. Is there any experimentation kind of similar to this or something different that you feel excited about? I know you're calling different things, but... Jeffrey L. Ventura: Yes, that's one of the things we're looking that I think does have good promise. It's just more stages within the tighter spacing, additional stages, breaking up more rock with what you're doing. I think that's exciting. We've done some of that, and we'll watch those as well as our competitors.

We are nearing the end of today's conference. We will go to Leo Mariani of RBC Capital Markets for our final question. Leo P. Mariani - RBC Capital Markets, LLC, Research Division: Could you discuss kind of what your current well costs are in the Mississippian? And also, what's your acreage target as they're obviously adding pretty aggressively? Jeffrey L. Ventura: The current well costs are close to the 2.9 million drilling complete, and again, we've allocated saltwater disposal costs to that of a couple 100,000 allocating it back. We're close to that. Again, I think in a development mode, if we end up drilling 500 to 1,000, 1,500, 2,000 wells, I'm sure we'll do better than that with time. We haven't really built in and factored that in. As far as acreage, we've been fortunate. It's a big play and it's a big sandblock, so our average acreage cost is really pretty low. One, we've been out there for a long time, and again, we're a first mover, and we're continuing to lease for attractive prices. I don't want to get into the specifics. And when we stop, we'll stop filling our acreage in and one, we'll either build it out or two, when that goes away. And there are other -- a lot of other people getting into the play right now, both majors and large independents, so we'll continue to quietly built it out as long as we can so for very attractive costs and rates of return. Leo P. Mariani - RBC Capital Markets, LLC, Research Division: Okay. And I guess just in terms of need to hold the acreage, you guys talked obviously about 2 rigs next year. I mean, can you just talk about sort of longer term and what type of activity you may need to hold those leases and give us a little more detail on the terms of the leases? Jeffrey L. Ventura: Yes, we have really good term on our leases. A lot of the leases have tickers on them. We have everything, a variety of things. A lot of the leases are 5 years with 2-year extensions that are brand new and early on. So we got of plenty of time. we've run some quick scoping things. You can probably hold that with something on the order of 10 rigs with time. So you don't have to run a gazillion rigs to hold it. Remember, the fairly shallow wells to 4,500 foot TVD , and that will be a function. Right now, we've drilled 8 wells. Eight wells is exciting, but it's not 100 wells or 200 wells, so we need to see it rolls out and we continue see those kind of results. But if we do, I think we can really build a -- I don't want to get into the specifics, but I've looked at the amount of oil that you can generate in NGLs and liquids. You can generate impressive volumes that are really impactful to us in a relatively period of time without running a lot of rigs. Leo P. Mariani - RBC Capital Markets, LLC, Research Division: Okay. And I guess just looking at the St. Louis Lime, how many holes you guys think you have in inventory right now over there? Jeffrey L. Ventura: We have identified a number of other structures, and what we'll do next year is start to test some of those other structures. Again, that's a different play than the Marcellus Shale or the horizontal Mississippian play. You have to find a closed structure and -- but we've identified and leased a number of them. So I'm excited about what that can be, but I think that, again, can be a play that's very impactful to us. But we're probably -- this time next year, we'll be able to quantify that better, but it has nice upside and as you can see, with not a lot capital, running very few rigs. If that continues to drill out, you can really build a rate -- high rate of return project.

Thank you. This concludes today's question-and-answer session. I'd like to turn the call back over to Mr. Pinkerton for his closing remarks. John H. Pinkerton: Well, thank you, operator, and we want to really appreciate and thank everybody for joining us today. We -- obviously, from our perspective, we felt it was a terrific quarter, kind of hit it out of the park, so to speak, in terms of higher than guidance production, better pricing because of the job of our marketing teams but also because more and more of our production is coming out on the liquid side of the spicket, so to speak, and we're just driving it up. And then, I think, as you can tell from the Q&A, we're really focused on that, and we're making very solid gains, and that should really continue and really accelerate in 2012. The good news is that despite the deterioration of natural gas prices, I think, 2 things are really important: one is that all the gas wells we're drilling really make sense at very, very low prices. So we're absolutely convinced that we're generating attractive returns on the gas wells we're drilling. If we weren't, I would guarantee we would quit. Second thing is the progress we've made on the liquid side and the impact that, that's going to have as we move forward, and so because of that, our expectation, when we sold the Barnett and how we're going to fully fund all this stuff, the timing of that is still right where we thought it was to begin with. And so we feel very strongly that we can continue to fund these projects internally with the balance sheet and the cash flows and the projects we've got, and that we can do it and keep 100% of the upside for all the existing Range shareholders, which is what I really care about, and given the fact that I'm still a very large one, I care about it even more. So we're still right on track in terms of being able to fully fund everything internally, and we've got a number of different -- as Roger likes to say, we've got a number of different things, levers we can pull. We've got a great hedge position. We got a great balance sheet position. We've got a great low cost structure, and all that's really, really going to matter as we move into 2012 because I think it's going to be a very interesting time in our industry, and I think there's going to be a lot of stress in terms of the industry to be able to perform under those conditions that we're seeing. We obviously are very, very encouraged with what we're doing, and as Jeff said, we really just care about ourselves more than anything else. But really, we're very encouraged with what we're seeing and the results we've got, and it's really just a -- it's really testimony to the entire Range team and the quality of people we have and the quality of the assets. And really starting to see that, the onion peel back and starting to see the quality. And I think the fourth quarter, we'll see it even more. And then I think -- as Jeff said, I think we're going to be really excited when we display what we're going to do in 2012 and the capital and what's it's going to do in the accelerated production growth coupled with a decrease in costs. It really has a dramatic impact in terms of the company and NAV, and so I'm excited about getting the fourth quarter over so we can show you all that and get that coupled with the year-end reserves, because I think we're all going to be very, very pleased as shareholders, and it's going to set us up very well as we move into 2012. So with that, again, thank you, all, for being with us today. And to those who didn't get your questions answered, feel free to call Rodney and David and Laith and the others in our team or Jeff and I will be happy -- and Roger will be happy to answer those questions this afternoon. Thank you very much.

Ladies and gentlemen, this does conclude today's teleconference. Thank you for your participation. You may disconnect your lines at this time, and have a wonderful day.