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

Dan McSpirit - BMO Capital Markets U.S. Leo Mariani - RBC Capital Markets, LLC Ronald Mills - Johnson Rice & Company, L.L.C. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc. Gil Yang - BofA Merrill Lynch David Kistler - Simmons & Company Michael Scialla - Stifel, Nicolaus & Co., Inc.

Welcome to the Range Resources First 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. After the speakers' remarks, there will be a question-and-answer period. At this time, I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, operator, and good afternoon and welcome. Range reported results in the first quarter of 2011 with record production and improvement in unit cost. The first quarter marked our 33rd consecutive quarter of sequential production growth. Range has a very large inventory and base of reserves that will continue to drive our growth in production in reserves. At Range, we are focused on growth at low cost on a per share basis, to maximize shareholder value. I think you'll hear those same things 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'd like to cover a few administrative items. First, we did file our 10-Q with the SEC this morning. It is now available on the home page of our website, or you can access it using the SEC's EDGAR system. In addition, we 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. The tables are also posted in the website that will give you detailed information of our current hedge position by quarter, including our new NGL hedges. Second, we'll be participating in several conferences in May. Check our website for a complete listing in the next several months. Our Annual Stockholders Meeting is being held in Fort Worth on May 18. We hope that each stockholders received their proxy materials, and we urge each stockholder to vote for the proposals being submitted by the proxy. Now let me turn it over to John.

Thanks, Rodney. Before Roger reviews our first quarter financial results, I will do some of the key accomplishments we put together in the first quarter. On a year-over-year basis, first quarter production rose 17%, reaching the midpoint of our guidance. And also, production on a per share basis also rose 17%. As Rodney mentioned, this is the 33rd consecutive quarter of sequential production growth. If you adjust for the asset sales, first quarter 2011 production growth would have been over 20%. Our drilling program is on schedule throughout the quarter as we drilled 63 wells. We had 100% success rate. We continue to be extremely pleased with the drilling results, despite the low natural gas prices. We're generating some very attractive returns from the projects where we're spending our money. We currently have 20 rigs in operation. The 17% increase in production was partially offset by a 2% decrease in realized prices. As a result, first quarter oil and gas revenues were up 15% compared to the prior year period. Cash flow was also up 11% compared to last year. On the cost side, we're most -- we were pretty pleased. In particular, we saw a 10% decrease in our 5 largest cost categories combined. The only disappointment was that direct operating cost came in at $0.75 per Mcfe, $0.02 higher than last year. This was due to the extremely cold weather that we incurred throughout the first quarter and primarily February, and also due to some higher water handling cost in the Marcellus Shale. With regards to our Marcellus Shale play, we made a significant headway in the quarter as we continue to drill just some fantastic wells. We continue to fill in our acreage position and build out the -- our pipeline processing infrastructure. In addition, we continue to hire some really high quality people that work on our Marcellus team in Pittsburgh now or at Southpointe, we now have over 300 people working on the Marcellus. And we're very excited to see that team. Lastly, we've completed the due diligence phase of the Barnett sale, and we're just a few days away from closing the sale. All in all, I'm very pleased with how much we accomplished in the first quarter. I complement the entire Range team for a job well done. With that, I'll turn the call over to Roger Manny to review our financial results. Roger?

Thank you, John. The first quarter was a busy period for the accounting and finance team, as we closed the new bank credit facility, supported the Barnett sale process and reclassified our current and historical results for the Barnett sale assets as discontinued operations. We expect to soon file an 8-K that effectively amends our 2010 Form 10-K to reflect the Barnett assets as discontinued operations. But the last time we worked through discontinued operations accounting, was following the offshore Gulf of Mexico sale back in early 2007. I remember that reclassifying our historical financial statements, reflecting discontinued operations, was a source of confusion as investors attempted to reconcile year-over-year and quarter-to-quarter performance when our historical results have been changed due to the asset sale. For this reason, the financial results I'll be presenting on the call will include the historical results of the Barnett assets, including the first quarter of 2011. And these will match the supplemental non-GAAP figures in the press release. There are tables included in the press release and posted on our website that reconcile the discontinued operations results that appear in our 10-Q to the continuing operations results. Now starting with the income statement. Oil and gas revenue, including cash-settled derivatives, was $268 million for the first quarter, 15% higher than 2010. Cash flow for the first quarter was $163 million, 11% higher than last year and higher than the fourth quarter of last year. In fact, this was the third consecutive quarter of improving cash flow. Per share cash flow for the quarter was $1.02 even with the analyst consensus estimate. First quarter EBITDAX was $198 million, 12% higher than last year, and like cash flow, the third consecutive quarter of improvement. Cash margin for the first quarter was $3.29 in Mcfe, up $0.23 from the fourth quarter of last year, but down $0.20 from last year's first quarter due mostly to lower price realizations and to a lesser extent, higher operating costs. Quarterly earnings, calculated using analyst methodology for the first quarter, which excludes certain nonrecurring and noncash items, was $35.2 million or $0.22 per fully diluted share. That's $0.03 higher than the analyst consensus estimate of $0.19. As Rodney mentioned earlier, I'd like you to reference to Range Resources' website for any questions concerning the reconciliation of these non-GAAP figures, including cash flow, EBITDAX, cash margins and analysts earnings. Looking at the cost structure this quarter, we saw another significant drop in our DD&A rate from $2.12 per Mcfe the first quarter of last year to $1.65 per Mcfe in the first quarter of this year. We anticipate the DD&A rate for continuing operations in the second quarter will be approximately $1.84 per Mcfe. Now this projected $0.19 increase in the DD&A rate next quarter is not a step back in our drive for greater corporate -- capital productivity, but it's due to one of the peculiarities of asset sale accounting. Now when an asset is held for sale as a discontinued operation at fair value, that asset is no longer depreciated or depleted. And in the case of the Barnett, the assets were deemed held for sale at the end of February. So in accordance with accounting rules, there was no Barnett depletion book for the month of March, even though we recorded production from the assets. The mathematical result of this accounting treatment is a peculiar nonrecurring reduction in the DD&A rate. Now we look forward to continued progress driving down this noncash expense the rest of the year. And we predict that by year end, the DD&A rate really will be $1.65 per Mcfe, unaided by asset sale accounting treatment. As John mentioned, direct cash operating expense before noncash comp, but including workovers for the first quarter, was $0.75 per Mcfe. That's up $0.02 from last year and up $0.03 from last quarter. Part of the reason for exceeding the expense guidance on this item was reduced production from cold weather. For example, if you're running a compressor and that compressor is not running due to a frozen wellhead, unit cost will suffer. And we also saw increases in water handling expense up in the Marcellus and increased expense at various nonoperated well operations. Direct operating expense declined each month during the quarter. So while the total was higher than expected, we remain encouraged by the trend toward lower costs. Now listeners may anticipate cash direct operating expense in the second quarter to be approximately $0.71 to $0.73. We still believe we can push this cost down to below $0.60 range by the end of the fourth quarter. Production taxes for the first quarter were $0.16 in Mcfe. That's down $0.01 from last quarter and down $0.03 from the first quarter of 2010. Production taxes are expected to drop another $0.01 in the second quarter. G&A expense, adjusted for non-cash stock comp and other nonrecurring items, was $0.55, down $0.02 from last quarter, but up $0.06 from the first quarter of last year, due to higher legal fees and higher public relations expense. We performed favorable to guidance on this cost item during the first quarter, and that offset higher-than-anticipated direct operating cost. Now for the second quarter of 2011, our estimate is that G&A expense will be in the $0.56 to $0.59 range. First quarter interest expense was $0.73 in Mcfe. That's flat for the previous 2 quarters. Interest expense should decline slightly this year, once the Barnett sale proceeds are applied to pay off the outstanding bank debt. But once quarterly production volumes reflect the Barnett sale, interest unit costs are expected to be up $0.01 next quarter, but declining later by year end. Now exploration expense for the first quarter of 2011, excluding noncash stock comp was $26 million. That's up considerably from prior quarters, due to higher seismic expense, and to a lesser extent, higher delay rental expense. Seismic spending is always somewhat sporadic, but based on our budget for this year, we continue to estimate total exploration expense at approximately $25 million to $26 million per quarter in 2011. Abandonment and impairment of unproved properties for the first quarter was $16.5 million. That's down significantly from last quarter and spot on with last quarter's expense guidance. Acreage value estimates can change unpredictably, but the rest of 2011 should see improved impairment running $15 million to $18 million a quarter. As our capital spending currently exceeds cash flow, Range continues to generate excess intangible drilling cost productions for tax purposes. Now we expect to actually end the year with a larger NOL carryforward than we entered due to IDCs generated by our drilling program. So there'll be no tax leakage of the Barnett sale proceeds and no significant remuneration, if at all, of our NOL. Range has continued to add to its hedge position, with 80% of our total 2011 gas production hedged at a floor price of $5.40 MMBtu following the Barnett sale. For 2012, we have approximately 190 million cubic feet a day, hedged at a floor price of $5.32. And in 2013, we now have 100 million cubic feet per day hedged with collars at $5.00 by $5.73 per MMBtu. We've also hedged a portion of our 2011 and 2012 liquids production, with 7,000 barrels per day hedged in the third and fourth quarter of 2011 at $104.17 per barrel. And we have 5,000 barrels per day of 2012 liquids hedged and $102.59 per barrel. Now please see the hedging tables attached to the press release and a more detailed tables on the website, if you need some additional hedging information. In summary, the first quarter of 2011 brought continued increases in production and cash flow with reductions in our aggregate cost structure. And the path is cleared for the Barnett sale later this week, and we look forward to the balance sheet improvement and future funding certainly that, that sale will provide. John, back to you.

Thanks, Roger. Now let's turn the call over to Jeff Ventura to review our operations. Jeff?

Thanks, John. This year, we will focus about 86% of our capital in the Marcellus Shale. Given the large de-risked acreage position we have on the play, 2011 should be an exceptional year. Even with the Barnett sale, we still expect that we'll achieve double-digit reserves growth in 2011. We anticipate achieving 10% production growth. We believe we will overcome the production sold in the Barnett sale. Barnett production is approximately 110 million cubic feet equivalent per day. We exited the Marcellus at a net rate of approximately 200 million per day last year. And we are on target to exit the Marcellus at a net rate of 400 million equivalent per day this year. Currently, we have 9 drilling rigs in the southwest portion of the play and 4 in the northeast part of the play. I believe we'll have sufficient production capacity from the wells we have drilled and will drill this year to achieve our targeted goal of 400 million cubic feet per day net. I also believe we have adequate processing and gathering capacity. Let me take a few minutes to discuss processing and gathering capacity for 2011. In Southwest Pennsylvania, we currently have processing capacity of 170 million cubic feet per day at the Houston 1 and 2 plants. The Houston 3 plant is expected to come online tomorrow, and Range's capacity on that plant will be 165 million per day, which will increase our total processing capacity at that site to 335 million cubic feet per day. At the Majorsville 1 plant, Range's current processing capacity is 30 million per day. By mid-third quarter, the Majorsville 2 plant is planned to be in service. Once online, this will increase Range's processing capacity at that site to 70 million per day. Therefore, our total processing capacity under contract with MarkWest is growing to 390 million per day. In addition to our processing capacity in Southwest Pennsylvania, our gathering capacity is 375 million per day and is planned to be expanding well ahead of production volumes throughout the year. We are well positioned to be able to move the gas from the wellhead to the processing plant. In Lycoming County, our current gathering system capacity in Phase 1 is 50 million per day. The remainder of Phase 1 and Phase 2 gathering systems are planned to be completed in the third quarter. And at that point in time, our gathering capacity will be 200 million per day in Lycoming County. So in total, by year end 2011, between the northeast and southwest, our processing capacity for the wet gas is expected to be 390 million per day. And our gathering capacity, which is pipelines and compression, is expected to be more than 575 million per day. We have planned, and should have in place, processing and gathering in all areas to meet our needs this year, with plans to stay well ahead of our projected production ramp over the next few years. In Southwest Pennsylvania, Range's gas flow for 2011 is covered by firm pipeline capacity or long-term sales contracts with primary capacity holders. In Northeast Pennsylvania, Range's gas flow for 2011 is covered by long-term sales to customers who have firm capacity on the Transco Leidy line. Except for force majeure event or unexpected pipeline maintenance, we have the proper downstream capacity into our sales in place to move our production to market in 2011 and 2012. Range has also entered into 2 MOUs with ethane consumers, with the intent to negotiate long-term arrangements to sell ethane into the marketplace. We are staying focused on the Marcellus Shale, and are on target to meet our goal there of driving up production to 400 million per day with one of the best cost structures and one of the best rate of return plays. We continue to see great wellresults in the Marcellus. During the quarter, we brought online 15 new wells in the liquids-rich portion of the Marcellus, with an average initial production rate of 10.1 million cubic feet per day equivalent, which consists of 7.4 million per day of natural gas and 452 barrels of NGLs and condensate per day. Our plan for 2011 is to drill moderate lateral lengths, fewer wells per pad and retain our acreage in this prolific play, for not only the Marcellus potential, but also for the Upper Devonian and Utica Shale. However, we'll continue to undertake some interesting tests this year. The tests consist of different step-bound [ph] drilling, targeting and/or new completion approaches in multiple areas this year. The first is in the Upper Devonian shale. We brought online in the first quarter our first 2 Upper Devonian Shale wells. The first well, which was previously announced, had an IP of 5.1 million per day and was a dry gas well. The second well came online under constrained conditions at a rate of 2.5 million per day, which is comprised of 1.9 million cubic feet of gas and 91 barrels of liquids. The decline rate of the second well is significantly flatter than the first well, and the second well has a higher EUR than the first well. For our first 2 horizontal wells in the Upper Devonian Shale, we're encouraged about the results and the potential it has for unlocking the Upper Devonian Shale resource potential. The combined IPs of the first 2 Upper Devonian wells average 3.8 million cubic feet equivalent per day net. To provide perspective in the Marcellus Shale, we did not see an IP of 3.8 million per day until we completed our seventh horizontal well. Reserves for the first 2 Upper Devonian Shale wells look like they're in the range of 2.5 to 3.5 Bcfe per well. This is significantly ahead of where we were in the Marcellus at this point in time. Overall, the gas in place per section is similar to the Marcellus. Key future wells will focus on determining the optimum place to land the laterals within the section, optimum lateral length and number of stages. We plan 2 to 4 additional Upper Devonian tests this year. Importantly, like the Marcellus, a significant portion of the Upper Devonian Shale potential on our acreage should be wet gas. Of course, we have tremendous upside, not only in the Upper Devonian Shale, but also in the Utica Shale in Pennsylvania. Our next horizontal Utica well will be late this year, followed by a third well early next year. However, I expect multiple wells in both of these plays from others in the industry to continue prove up our acreage. Next is the liquids-rich portion of the Marcellus. Our average wells in the wet portion in the play make about 5 Bcfe, which is comprised of 3.6 Bcf of gas and 239,000 barrels of liquids, mostly with 8-stage fracs. We recently tested a 3,500-foot effective lateral, with a 12-stage frac in one of our wettest areas. And to date, it looks like the well will produce 6.7 Bcfe, which is split between 4.1 Bcf of gas and 425,000 barrels of liquids. We plan to go back into the liquids-rich area with new wells and test additional longer laterals, pump more stages per lateral and try to achieve higher conductivities in the fractures. Given the huge acreage position we have on the liquids-rich portion of the play, this could be very impactful. We'll also look at the effect of adding more stages and drilling longer laterals on a few of our wells in Lycoming County. In short, some part of the Marcellus play, that's wet -- some portions of the Marcellus play, that's wet versus dry, maybe more efficiently developed in slightly different ways. The tests we're doing for the purpose of finding the optimal rate of return for our entire Marcellus program and to improve Range's cash flow. In addition to the 790,000 net acres we had at the beginning of the year in the Marcellus Fairway, we have about 285,000 net held by production acres in Northwest Pennsylvania. The Marcellus in Northwest Pennsylvania is about 4,000 to 4,500 feet deep, more similar to the Fayetteville in terms of depth and pressure, however, within the wet portion of the Marcellus. Given the huge HBP position here and potentially significant impact, we'll drill the horizontal Marcellus well in that area this summer. Turning to the mid-continent. The horizontal Mississippi in play in Northern Oklahoma continues to show promise. Of our first 5 wells completed in the play, 30-day rates have averaged 340 barrels of oil equivalent per day with peak rates averaging 550 barrels of oil equivalent per day. This includes 1 short lateral drilled early in the program. The first well of a 4-well program in 2011 has been turned to sales at early rates of 380 barrels of oil equivalent per day, with the well restricted due to pipeline capacity issues. Plans are now underway to improve take-away capacity in the area. In addition, 2 wells are undergoing completion, while the fourth well has commenced drilling. Our play area continues to expand with over 28,400 net acres and potential for over 140 horizontal wells. We currently are estimating unrisked reserve potential of 300,000 to 500,000 barrels per well. Up in the Texas Panhandle, we had excellent success with our first horizontal St. Louis well. It came online at 13.8 million cubic feet of gas per day and 903 barrels of liquids or about 19.2 million cubic feet equivalent per day. After producing for about 3 months, it is still making 13 million cubic feet of gas per day and 900 barrels of liquids. Payout was within weeks. We'll be drilling 3 additional horizontal St. Louis wells this year. At this point, I'll turn the call back over to John. I will be happy to answer your questions in the Q&A.

Thanks, Jeff. Great update. Looking to the remainder of 2011, we see continued strong operating results. For the second quarter 2011, we're looking for production to average 500 million to 505 million per day. Factored into the second quarter production guidance is the Barnett sale, which we anticipate will close in a few days. So we'll have the Barnett production of approximately 1 month in the second quarter. The Barnett, as Jeff mentioned, is currently producing approximately 110 million a day. When you average the loss of 110 million a day for 2 months in the second quarter, it equates to losing 73 million a day over the entire quarter on average. Assuming we hit the mid-range of our guidance for the second quarter, it will represent a 7% year-over-year increase. The 7% increase does not adjust for the Barnett sale. If you adjust for the Barnett sale, the year-over-year growth would be 22%. We are looking to make up about 1/2 of the sold Barnett production by the end of the second quarter, and the other half by the end of the third quarter. For the entire year, we still expect to achieve 10% production growth despite the Barnett sale. We expect to exit 2011 with the Marcellus Shale at 400 million a day and with total company production exiting the year at over 600 million a day. Now that we're nearing the closing of the Barnett property sale, I'll take a moment to look at the impact of our divestiture program. Including the Barnett sale, our divestiture efforts have yielded nearly $2 billion in sales proceeds. It has also reduced our well count by over 6,000 wells. This represents roughly 60% of our original well count. The properties that were sold were our more mature higher cost properties. The good news is that we are selling our more mature properties -- that while we were selling our more mature properties, we were focusing our capital on higher return projects. Despite the asset sale, our production reserves have consistently increased during this period. As a result, Range is now a much more efficient company. We are doing more with less. By less, I mean less wells, lower find and development costs, lower operating cost, et cetera. The first quarter results reflect the lower cost. Over the medium to long term, this will have a significant impact on our per share value. This is critical to generating attractive returns in a low gas price environment as well. In addition, by having fewer wells and properties and a more compact asset base, we can better focus our technical team on higher return projects and making those projects even better. Lastly, one of Range's hallmarks is to keep things simple. By having fewer wells and properties, Range is a simpler company, allowing the Range team to focus more on efforts of driving up reserves and production on a per share basis. Turning to the Barnett sale, as mentioned previously, we anticipate closing the sale in a few days. This is a hugely important event for our company. First, the sales proceed will be more than sufficient to retire all of our outstanding bank debt, with excess proceeds available to help fund our 2011 capital program. As a result, Range will have, by far, the strongest balance sheet in its history. Second, the sales proceeds generated by the sale will be a catalyst for Range in becoming internally funded by 2013. Between now and then, we know exactly how we're going to fund our growth. Importantly, our shareholders, you now know specifically how we're going to fund our future growth. Having a strong balance sheet and knowing how we're going to fund our growth, puts us in a position of strength. We can now focus all of our energy on executing our business plan by driving up production reserves on a per share basis at a top quartile cost structure. The driver of this growth is our drilling inventory, which I believe is exceptional. We have the drilling projects in place that at low commodity prices, generate outstanding rates of return. As Jeff mentioned, our operating teams are continuing to enhance and improve our well results, while maintaining our stellar safety record. While I'm clearly biased, I am convinced we have an exceptional asset base and drilling inventory, as well as an exceptional team of people driving our performance. Our management team is keenly focused on enhancing our asset base and improving our team's performance. Selling our Barnett properties was somewhat of a bold move as the Barnett properties currently comprise about 20% of our production. After careful studying deliberation, we were convinced that it best served our strategy of growth at low cost. Most importantly, we believe it best served Range's shareholders, as it provides a clear path for capital funding and allows Range's existing shareholders to retain 100% of our 35 to 52 Tcf 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 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 upside of any company in our peer group. With the capital funding issue being clarified by the Barnett sale, we're extremely excited and motivated. We appreciate the support and confidence that our shareholders are showing us, and we look forward to the remainder of 2011. With that, operator, why don't we turn the call open to questions?

[Operator Instructions] Our first question is from David Heikkinen with Tudor, Pickering, Holt. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: John, given you expect to be free cash positive in 2013, can you walk us through 2 things? First, your capital budget, expectations for '12 and '13? And second, what your commodity price expectations are for that plan?

The price expectations, we were using roughly $4.50 NYMEX for 2011, $5 for -- I mean $4.50 for 2011, $5 for 2012 and $5.25 for 2013. In terms of capital budgets, the next year's budget will be similar to this year. And in 2013, we'll probably spend a couple of hundred million more than what we're spending for the next -- for '11 and '12. And there's some things baked into it, obviously, into those capital budgets. We expect to become more efficient in terms of some of our drilling. We'll be able to spend more on drilling as time goes by versus on things that are nondrilling expenditures. The other thing is as we build out the infrastructure and as you move through 2011, '12 and '13, a great -- a number of wells we're drilling this year won't get hooked up until next year. But as we get bigger and the pipelines get big -- become more -- we get more outreach of our pipeline system, we'll be able to connect more wells faster. So you'll see some production growth, more efficiency in terms of that than you're seeing, let's say, for the past 2 or 3 years. So all that's kind of baked in there. We've done a lot of work on it, and we're pretty confident that we can make all that work. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Just thinking about activity level. So you've got CapEx flat as rig count goes up by roughly 4 rigs. Is that all efficiency? Do you expect capital cost to come in as you go into development mode and get more concentrated? Can you, Jeff, maybe walk through some specifics around well cost or something along those lines?

We think well cost will come down with time. As we get -- we've got -- we're a little over a couple of hundred wells into the program of what could be, 5,000 to 10,000 wells. As we continue to drill wells, and it becomes more and more manufacturing, I think it's not unreasonable to think that within time, if we keep the same design, that we may be able to knock maybe $500,000 a well off. It may take us 2 or 3 years to get there, but we can move towards that as we get more into that mode. Of course, the other thing we'll do is continue to look at how to optimize completions and rate of return. And there's a variety of things. It may be that we tweak lateral length, stages, where we land them and all those things, it could lead to efficiencies. If we go -- it may be that if we stick with the same design, $500,000 per well comes off. Or it could mean with a more optimum design, it costs a little more, but the rate of return is higher, and we're more capital efficient. Either way, I think we'll get better with time. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And then just one specific question on your NGL hedges, you locked in C5+. Can you talk about realizations or expectations -- or realizations of production volumes for the C4- side that you haven't hedged?

Well we believe that the C5 is a good proxy for the C2s and lighters. So what we'll simply do is we're hedging that into a very liquid market, but we will modify the amount that we hedged to account for the difference and a dollar change in those commodity prices as we go forward. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: So out of your total NGL barrel, how much is C5+ and how isn't then? Just trying to get the split.

Well if you look at -- if you look at the slide in the flip book on 33 for the Marcellus, your C5s are going to run about 6% of that barrel. And it will be a little bit less than that in the midcontinent area. But if you look at the correlation, David, those C5s and C4s all correlate within $0.50 of each other. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: I'm still thinking that normal kind of 50-ish percent of total PI on everything else on the blend.

I'm sorry, I didn't hear the... David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Your Page 33 still is guiding to a 51% of WTI realization, you just locked in the C5+?

That's right.

The next question is from David Kistler with Simmons & Company. David Kistler - Simmons & Company: Real quickly following up on the CapEx before we get to '12 and '13. Looking at '11, Drillbit was $267 million this quarter with a target of about 1.38 for the year. Can you walk us through the ramp up? I think it's significantly heavier in 3Q and 4Q, but if you could just help us through that, that would be great.

I mean when you look at production, it's clearly going to follow that way in completions. But it's definitely going to be a little more weighted towards the third and fourth quarters. David Kistler - Simmons & Company: Can you give us a breakdown of how that -- in terms of percentage wise, we should be modeling that out?

We can -- maybe what we can do, the best thing is to talk to Rodney and Laith and David and they can just give you a little more granularity. We don't have that right in front of us, but they can give it to you after the call. David Kistler - Simmons & Company: No problem. And then speaking a little bit to the wells that were drilled and waiting on completion or tie in, there were about 51 this quarter on a gross basis. When we start thinking about that and comparing it to previous quarters or kind of what target rates are going forward, could you give some sort of sequential comparison so we know what you're going to be anticipating to flow through over time?

Part of the issue there is we're doing drilling now up in the northeast and in the southwest. To give you a little clarity there, once we get Phase -- the rest of Phase 1 on and Phase 2, we're looking at bringing 29 wells online towards the end of the third quarter in Lycoming County and additional 11 in the fourth quarter. So what is that -- 40 of those wells are going to be skewed towards the late third quarter and fourth quarter. So we feel comfortable. We entered the year at about 200 million per day net. We'll exit the year at about 400 million per day net. But it's going to be skewed towards the third and fourth quarters. David Kistler - Simmons & Company: And what should we anticipate is just sort of a typical backlog that you'd have of drilled uncompleted wells? Just so we get a sense of what's being held up by infrastructure or just service constraints at this point?

Well, in terms of service constraints, there isn't. Because what we tend to do is lock in. We have our rigs locked in, we have frac crews locked in. We're not waiting for a frac crew to pop open from another company in order to complete our wells. What you do have a little bit though, is like I said you have the -- we're waiting on phase -- the rest of Phase 1 and Phase 2 in Lycoming County and there's different events that I mentioned in terms of Majorsville and Houston 3 and all those different things coming on. We have a number of wells waiting on completion, and that should get better with time as we continue to build out infrastructure. Like John said, ultimately, once we plan, we delineate and have what we have. I have all that stuff in place. It'll come down. In terms of real specific guidance, I don't have that in front of me. That's another thing we can look at with time. But that's why we're trying -- rather than trying to give you rigs and when they come on, we're trying to give you the rigs that we currently have and what the rigs look like going forward in terms of the Marcellus. But we're also trying to give you the exact -- we're giving you production guidance for this year at 10%, next year at 25% to 30%. Exit this year or -- enter this year at 200 in the Marcellus, exit the year at 400, exit 2012 at 600. So we're giving you the production numbers that go with it. I think that's a lot simpler thing to do rather than you guys trying to time when the wells are going to come on. And I think if you follow the guidance, it's a better way to do it. David Kistler - Simmons & Company: I appreciate that clarification. And then as we just jump over to one last thing, the ethylene agreements that you or John mentioned on the call in the ops update, can you give us any kind of color on size of those, timing? Because obviously, those will kind of add a different hedge in place at some point.

We're under confidentially agreements. And I think Dow has given you more information than what we were allowed to give earlier until you get to these long-term agreements in place. We have 2 Memorandums of Understanding that will be going to 2 different directions, regionally. We have more proposals than we think that we could actually satisfy with us and the other producers there. But that will just simply come out over time. But once we have the fractionator in place in late 2011, then we'll be able to get our extractions as to where we want them. All the ethylene and the ethane production is going to be governed by, probably, a Sunoco line going to Sarnia. And the producer, the petrochemical companies in Ontario will have to retrofit. So that will probably be third or fourth quarter of 2012 at the earliest that we can actually start production. David Kistler - Simmons & Company: That clarification is very helpful, Rodney. I appreciate it.

And David, in terms of some of those detailed questions in terms of wells and things [ph], just holler at Rodney, and he'll be able to put some clarity around those for you.

The next question is from Gil Yang with Bank of America Merrill Lynch. Gil Yang - BofA Merrill Lynch: A couple of questions. Just to be clear, John, your comment that you'll be internally funded by 2013. So that sort of eliminates the need in your view with those assumptions for any equity going forward. Is that fair?

Gil, as you know, our view on equity has been and will continue to be for years and years and years is that we will issue equity if we have a clear use of proceeds. And that is still our view of equity. Right now, there is clearly not a clear use of proceeds. And we try to make that perfectly clear that with the Barnett, we don't have the need. But I'm not going to promise you that we'll never issue equity again. There's certainly opportunities out there that we look at from time to time. And to the extent that we choose to seize on one of those opportunities and believe it's clearly accretive on a per share value, then we'll try to seize that opportunity. And if that generates a clear use of proceeds, then we will issue equity. That being said, obviously, from our perspective, it's pretty clear to us what we need to be working on. We've got a huge opportunity in the Marcellus and in some of the other projects like Jeff talked about in terms of some of the things that we're doing up in the Texas Panhandle, in Mississippian Lime project, up in Northern Oklahoma and some of the projects we have in the Permian, we got a huge opportunity base. And so we'll continue to do that. We do also have a scout team that's out looking at other opportunities. And there's some exciting things that we're looking at. Nothing, I think, that's on the horizon that would qualify us to rush out and do anything. But again, I think the key, and I said and I'll say it again, is I think the Barnett sale does a number things. But it really puts us in the position of strength, and that we don't have to do anything in terms of that or equity in terms of the pace we're on. Again, that being said, if there's an opportunity presents itself that we think is in our shareholders' best interest, what you pay us to do is to seize that opportunity, and we'll be disciplined in terms of the balance sheet, how we raise to the extent that we issue equities. So still, same game plan, same theories, same strategy, nothing's changed in terms of that. Gil Yang - BofA Merrill Lynch: Okay, great. Thanks for that complete answer. In terms of the commodity price forecast for that, do you assume any ability for you to strategically lock in, let's say, $5.25 over the next -- going forward, beginning 2013, do you assume any ability to lock in hedges at a slight premium to that price?

Absolutely, absolutely. Gil Yang - BofA Merrill Lynch: So that's sort of built into your expectation of cash flow?

No. It's not built into our expectations, I sure as hell hope it happens though.

Just to be clear, and it's on our website, the numbers John gave you for gas price, I think it was the February 3 script, and that's what that's based on. That's the point in time that we put that slide out.

And let me tell you at least the way I look at it and I think we look at it, is that to the extent -- we got now, we'll have in a week or so, we'll have a balance sheet where we got a bunch of cash. And we have nothing outstanding on the $1.5 billion credit facility where we have the borrowing capacity to take that up to $2 billion if we choose to. And our friends at the banks, I think, are perfectly happy to do that assuming we pay them the appropriate fees. We've got enormous liquidity. So really, the lever here -- the leverage here is that to the extent the prices move up and we can lock them in, and we will do that. You've seen with the, quite frankly, with the little issue in Japan, we saw gas prices move up in '12 and '13. We took advantage of that and locked in some '13 gas, I think, at pretty good prices. So we'll be very opportunistic there. So to the extent that we can lock those in, that's great and everything else. But at the end of the day, if gas prices move down a little bit, we've got this balance sheet and this credit facility that we can draw down on to the extent that we need it. So again, I think, it puts us in a position of strength. We got a great balance sheet. Like Roger always says, we've worked really hard and he's done a fantastic job of being CFO of creating this really strong balance sheet. And to the extent that -- there's no use in creating it if you're never going to use it. So to the extent that we need to use it, if gas prices are a little lower than we need, then we'll take advantage of it. To the extent that it's not, then we'll be able to obviously increase our capital a little bit more or do some other things with it that we didn't anticipate either. So it gives us lots of leverage that we can pull. But I think, the thing that's important for the shareholders is that to the extent, and I obviously talk and Jeff and I and Roger, Rodney and the rest, we talked to a lot of shareholders and I think one of the things that's really important is it puts real clarity into between now and 2013. And it really focuses us, the management, to really just get after it, drill the wells, get them on, focus, focus, focus, be disciplined, disciplined and just continue to drive it up. As Jeff said, we're looking at 25% to 30% growth next year, given what we're doing. And our team is doing a great job. And so, I think they'll hit the ball out of the park and if they do, we'll hopefully exceed those numbers and proverbially kick some butt. So again, it just puts us in a position of strength. And I think it's really important, and it gives clarity to all the shareholders. I think that's other important thing.

The next question is from Mike Scialla with Stifel Nicholas. Michael Scialla - Stifel, Nicolaus & Co., Inc.: So you've talked in the past about drilling 2,500-foot, 3,000-foot laterals with 8-frac stages, which is not optimal but that's the recipe you're going to use to hold acreage. And, Jeff, you talked about the results you got from this 3,500-foot lateral with 12 fracs. I'm just wondering, is there any thoughts of doing a pilot where you try to get more aggressive and really optimize good development to just see what that might look like. Would that change your plans going forward or is that not a concern right now?

Well, let me take -- I'm going to take some time to answer that question. It's a good question. First of all, what we're doing this year, like I said is we're going to drill in that, call it, 2,500-foot, 2,700-foot usable lateral with roughly 8 stages for almost all of our wells. And what we know is, to date, the average of 139 wells primarily in all that are in production in the southwest part of the play, the average of all of them, the good, the bad and the ugly is 5 Bcfe. So in the development mode, that design well cost about $4 million. And today, we're not far from that. We're $4.1 million, $4.2 million, so we're very close to it. So spending, with that design, spending $4 million to get 5 Bcfe under -- and strip pricing right now, I think the 10-year strip is somewhere $5 to $5.50. But if you take a $5 flat gas price forever at 5 Bcfe, that's a 99% rate of return. So that may or may not be optimal, but it's pretty darn good. So we're happy with that, and we know if we stay today, keep that same design and go to fewer wells per pad. We can drill more wells, we can hold more acreage and still generate really strong rates of return. That being said, we've also done a number of experiments in the past, and we'll continue to do some going forward. And that's everything from longer laterals and more stages to where we land the well, we think is really important whether you're high, low or in the middle of the section. And that varies depending on where you are in the play, even where you are within a county, we believe. So there's a lot of different things that go into optimally developing it. And plus at this point in time in the play, early on when we started, back to Range pioneering the play and carrying 100% of the science, we're not doing that anymore. And early on, it was very competitive and for different reasons, companies didn't share a lot of information as everybody was building their acreage position. At this point in time, I think companies are more cooperative than they were competitive. So not only that Range doing experiments but we have other companies out there that are drilling laterals up to 9,000 feet and put a bunch of stages in them. So we can learn not only from our wells but from other people, and we'll look at optimizing going forward. So where we are today is we think we've got, like John said, one of the best plays out there, even at $4 flat gas forever, it's a 74% rate of return. At $5, it's 99% and it can go beyond. So we'll look at, can we get better than where we are today? And I believe we can. The way to get better by drilling and completing the wells better, which I think will happen or we're going to drive the cost down. Either of those are really significant upsides for the play. The other thing that I think is important to look at is, not only does it vary, Northeast, Southwest, or vary within a county, I think, whether you're wet or dry is important too. If you look at the liquids-rich part, which we really dominate and have the tremendous position in, and like I said, the wells are, that 5 Bcfe is 3.6 feet of gas and 239,000 barrels of liquids. We did experiment in one of the wetter areas and we've got a lot of wet area to continue to drill in. And it so happens that, that one well that had a 3,500-foot lateral and a 12-stage frac made 6.7 Bcfe, which is up 4.1 Bs and 425,000 barrels of liquids. So that's a big increase going from 239,000 to 425,000, maybe by more optimally landing it or completing it or some of those things that I've said we're going to test, maybe we can turn that into 500,000 barrels a well with gas, with the associated gas. So that would really drive economics and it really drive rate of return particularly where oil prices are relative to gas prices. If you look at our potential, John talked about, in aggregate, we have 35 to 52 Tcf of upside. We're a 4.1 Tcf company. Out of that, 20 to 31 Ts is in the Marcellus and 15 to 23 Tcf of that is in the Southwest part of the play. But again, if you break it down, you're looking at 13.5 to 20.5 Tcf of gas, that's 307 million to 463 million barrels of liquids, net to Range. In my mind, if you look at our performance year after year after year, and we put all of our horizontal wells in there in terms of 0 time plots, you can see the performance climbing with time. So I would expect the performance could continue to climb with time as we get better and better about what we're doing. So it's not unreasonable to think we'll reach the high end of those reserves, which is a 20.5 Ts just in the Southwest with 463 million barrels of liquids. The other key part of that is that's leaving all the ethane and the gas. Once we start extracting ethane, it's going to double our liquid yields. So the 463 million barrels becomes 926 million barrels net the range. And then, if we can get better about where we land and how we drill and complete, really, you're approaching 1 billion barrels of liquids, net to Range. So we think it's really exciting upside. We've got a dominant position in it and a great team working on it. That was a really long answer. But I think it's important to look at, I think, where we were, where we are today and where we might be going in the future. Michael Scialla - Stifel, Nicolaus & Co., Inc.: I appreciate that. I wanted to ask you too on the Upper Devonian. Did I hear you right, you said the gas in place is similar to the Marcellus?

Yes. If you think -- and predominantly, we think the Upper Devonian is most perspective in that west to really the southwest part of the play. It doesn't exist over all the areas. But it does stack in the southwest part of the play. If in a particular area, gas in place is 100 Bcf per section, in the Marcellus, the gas in place in the Upper Devonian in aggregate would be 100 Bcf. So it about doubles what you have in that area. Michael Scialla - Stifel, Nicolaus & Co., Inc.: And how is the rock quality between the 2 compare?

It's really early. I mean, and that's something we need to look at and that's why I try to put in perspective, after a couple of wells in the Marcellus, where were we? After a couple of wells in the Upper Devonian, where were we? We need more data. But the neat part is we know we have hydrocarbon. We know we have wet gas. We know it can produce commercial rates even after our first 2 tries. It's highly unlikely that we landed it right in the optimal intervals on our first 2 tries. I can give you examples in the Marcellus, we're right next to each other, and it's easy to take our first few tries in the Marcellus. We're in a particularly, we landed our first well low in the section, the second one in the middle and the third one is the top. Progressively, as we got higher, the wells got higher. I mean, it went from 20 Mcf a day to about 1 million. And then we just moved it a little bit above the section and got 36. And now in that same area, we're getting 10 to 15, our best well was 26 million per day. And that's just moving where you land the well in the section and has nothing to do with lateral length or frac stages. So I think the same thing will be true of Upper Devonian. Understanding the rock and the quality of the rock and how to optimally land it that's really important but we're off to a better start really in the Upper Devonian than we were in the Marcellus.

Our next question is from Ron Mills with Johnson Rice. Ronald Mills - Johnson Rice & Company, L.L.C.: Just one clarification on Utica and Upper Devonian. It looks like one of your Upper Devonian was more dry gas, one had liquids component. Would you expect though on an average, the Upper Devonian, where you're in a more liquids portion of the Marcellus that you would also have liquids in the Upper Devonian?

Yes, the wet dry area for the Upper Devonian more or less is exactly or approximately mirror the Marcellus. Ronald Mills - Johnson Rice & Company, L.L.C.: You mentioned your acreage up in Northwest Pennsylvania. You start testing potentially later this year with horizontal wells. Do you think at that point that to the extent the Utica is present in Northwest Pennsylvania that you may actually bring some of the Utica into the liquids portion of the window as well?

It's possible. The difference is -- when you look at the different horizons, there is now thousands of wells that are drilled in the Marcellus. And each Marcellus well have to drill through the Upper Devonian because it's right on top of it. But if you go down to the Utica, very few wells in the basin penetrate the Utica. So, yes, it could be that a portion of that acreage is perspective for the Utica as well. And we have great Utica potential on our acreage, and big reserve outside. But you're right, a lot of it is going to be dry. To the extent that stuff in the northwest works in the Utica, then it would be, could be wet. One other thing, the other neat part of where our acreage is predominantly in the Southwest, you can stack Upper Devonian, Marcellus and Utica. If you go way to the east, you're going to the Utica, if you go away to the west, you'll lose the Marcellus and Upper Devonian. They aren't sort of like, think of, concentric circles and working and you line them all up, that's the one part where you can line up those play. So a lot of our acreage in the Southwest could have stack pay potential in all 3 horizons. Ronald Mills - Johnson Rice & Company, L.L.C.: Okay. Just any update or any more information, you had mentioned, I think, on one of your latest calls, you'll test the Pennsylvania shale in the Permian. What's the timing of that and have there been any other test of that formation in the Permian to date?

Yes, on our Conger field area out in the Permian basin, we've got about 91,000 to 92,000 net acres. We drilled a couple of vertical wells into it a few years back and they made on the order of 15 to 20 barrels of oil per day out of the vertical well. So we've got a nice big shale section that's full of oil and we know there's oil in it because we had a couple of vertical wells in them on our acreage and we know it will flow oil. It's not very good for a vertical well but the question is, if you drill that horizontally, what will it do? To my knowledge, there's only one well in the entire Permian Basin that's drilled horizontally into that section, and it's probably 15 miles, 10 to 15 miles away from our acreage. And that well had an IP of 350 barrels per day and fell off pretty steeply. But the question is, it's a first well and it's a ways away on our acreage. We know we got a big, big section full of oil, can we make it commercial with horizontal drilling? And we've drilled and cased our first well, we'll probably frac it sometime this summer and test it and probably have results in the fall. So we have a nice big block, the HPC position. Conger has been a great area for us. It's typical of what Range likes. It's stack pays. It produces -- it's hydrocarbon rich, hydrocarbon charged, a good technical team working it. So it fits the model of things we like to work on. Ronald Mills - Johnson Rice & Company, L.L.C.: Okay. In the Mississippian Lime, it sounds like since you first talked about it, you almost doubled your acreage position. You've drilled fewer wells than what operators to the west have drilled. But comparing your thoughts or how would you compare your expectations for the play versus what the operators to the West have outlined in terms of well cost and/or EURs as you accelerate your activity there?

We've gone from 14,000 acres to 28,000. And we're continuing to pick up acreage, and we'll continue to update that number. It's been a good play for us. It's a field we started redeveloping a while back. So we're looking at we think well cost there, 2.1 million EURs of 300,000 to 500,000 barrels. 140 locations on the acreage we have and like I said, that will grow. So it's a nice play for us. To the west of us, predominantly is SandRidge and Chesapeake and they're having good success in the play. At IPAA, fortunately, there were a lot of people that wanted to meet with us, so we were in one-on-ones and breakout rooms and such, running around New York. So I didn't get to sit through their presentation but from what I hear, I think they're claiming the similar range of reserves, 300,000 to 500,000 barrels is I think what they're claiming. I think the well cost they're claiming are similar. But I would encourage you to ask Chesapeake and SandRidge. But it's a good play and it's oil. It's worked real well for us and we like it. Ronald Mills - Johnson Rice & Company, L.L.C.: And then just if you can say anything else on the MOUs, on the ethane sales, there have been discussions not just of taking it to Sardinia but you -- there was also been discussions of pipeline reversals to the Gulf Coast, and/or getting the ethane out to Philly, which then becomes a world commodity. These MOUs that you're going to be working towards getting agreements in place over the next coming months, I'm assuming all those different options are in the mix in terms of leveraging your position and/or ethane pricing?

Yes. When you look at kind of going up to 100,000 feet, when we first look at the play, the ethane, we thought long term was going to be a gain item in terms of being able to ramp up our production. We put a team on it several years ago to work on this. And they've done a great job. Greg Davis and Kurt Tipkin [ph] and the other guys, who have just done a fabulous job, and along with Rodney Phelps [ph] is a big player in that team as well. And where we've really gotten to is, a couple things: One, pretty early on, we've made the conclusion that instead of us just working it alone, it made sense to team up with the other wet gas producers. So we've kind of cubbied up, create our own little ethane group. And so, we're really -- while the teams -- the companies are working it individually, we're also working on a collective basis, so we can use our collective purchasing power, if you want to call it that, to leverage what we're doing with the users of the ethane. And I think that was really strategic and really well thought out. And that's really helped us, all of us, all the ethane producers. The other thing that what's happened is the confidence that the ethane users are starting to have that this is going to be a hell of a lot of ethane. And that what relative value they have of having that ethane produced in the U.S. and the relative value that creates in terms of them being able to take that ethane and make the products they want to produce, that most of those products are used in the U.S. So to the extent that now, they can create those -- buy the ethane in the U.S., create the projects in the U.S. and sell it in the U.S., things like transportation cost and all the other things that they had to deal with get taken off the table. So I think it's one of those things where, I think, they're getting more comfortable clearly, the Dow Chemical press release was pretty bullish on their view of that. And I think it's just taking time for those users of the ethane to really get their arms around how much we are going to have and whatnot, and getting confidence in what they are being told by the producers made sense and that's something they could "hang their hat on" and whatnot. And that's part of what -- they're going to continue to have to get comfortable on as we go from the MOU stage to the definitive agreement stage, which is a natural progression. But the good news is, I think, overall, the good news is that the number of potential customers for the ethane continues to go up almost daily. And so, it's probably a very competitive situation. At the end of the day, we'll get gas plus for the ethane, which is something that never thought of that was going to happen 2 years ago. We we're hoping it was. But now, it's clearly going to happen. And as Jeff mentioned, once you start stripping that out, and that's a huge impact in terms of our liquids volumes, and it will have a big impact on our realizations and our margins and it will obviously, just enhance the intrinsic rate of return of the project.

The next question is from Leo Mariani with RBC Capital Markets. Leo Mariani - RBC Capital Markets, LLC: A couple of questions for you on the Upper Devonian, trying to get a sense of the lateral length on those first couple of wells and a number of frac stages you guys have drilled.

Yes, they were the standard 2,500 foot effective lateral with 8-stage fracs. It could be that there's more optimum place to land them, I'm absolutely convinced there is. And it could be that longer laterals and more stages could make a difference than we'll see with time but encouraged by where we are so far. Leo Mariani - RBC Capital Markets, LLC: Okay. and you guys made a comment that you thought the second well is going to have a better EUR. That's just based on kind of what you're seeing in production history there I imagine and did you do something different with the second well?

Yes, the second well was constrained when we brought it on. But just looking at the production history that we have so far, it hasn't flat or declined, so it projects out a higher recovery. And again, we'll continue to look at those numbers with time. And it's interesting, if you look at our reserves with time over the last few years, they tend to come up with time, which has been very positive too. So we'll continue to watch and look at that. In terms of completions, they were the same. There's -- and I'll just leave it at that. Leo Mariani - RBC Capital Markets, LLC: Okay. How far apart were those first 2 wells that you guys drilled?

They were a long ways apart. I don't have the exact distance but probably it's going to be at least on the order of 5 miles or more, 5 to 8 miles, something like that. And we really haven't put a well into the real wet area, the Upper Devonian either yet. Leo Mariani - RBC Capital Markets, LLC: Okay. I guess just in terms of your acreage in Southwest PA, you've got 550,000 acres there. Just trying to get a sense of how much of that you think is potentially in the dry gas area?

I'll use a simple cut off. If you use something like 1,000 BTU and, say, anything over 1,000 BTU is a plus because we get paid for that. And eventually, it grades up to where it's over 1,400 BTU. So you probably have roughly on the order of about 2/3 of the acreage would be greater than 1,000 BTUs. And again, you're looking at not just the Marcellus but the Upper Devonian. So you've got 2 horizons there, so you'll get a 2:1, a little bit like the men's warehouse there. It's a twofer.

We are nearing the end of today's conference, we will go to Dan McSpirit from BMO Capital Markets for our last question. Dan McSpirit - BMO Capital Markets U.S.: Roger spoke about exploration expense at the top of the call and it being driven by higher seismic expense in the period. Where was that seismic shot mostly?

Most of the seismic is in the Marcellus. We have acquired seismic now either through group shoots or spec shoots over almost everything we have or we will have by the end of the year up in the Northeast. But we're also acquiring a lot of seismic in the Southwest. We started drilling early on without 3D and clearly, you can do that. But like I said, the more we shoot 3D, there's a lot you can get out of it. And you can apply it not only to the Marcellus but you can apply it to the Upper Devonian and to the Utica, more optimally placing the wells and understanding the better areas and things we can see from seismic, we think will really help to continue to drive our well results up, but it's Marcellus. Dan McSpirit - BMO Capital Markets U.S.: Okay, great. And second question here, if we could return to the St. Louis well, what is it about that well that the rates are still strong after 12 weeks of production? Is it more about the rock, the completion technique here? And are you getting contribution from another horizon, maybe?

No. It's just really a high-quality rock. It's really interesting play. When you look at that off of conventional well logs and you can't really see it. It's a play that people have drilled through for years. And it's interesting, you think a lot of those, call it, bypassed or misplay type of things tend to be low quality rock that either needs better technology or something to make it work. In this case, it was recognition that the interval is productive and then once you see it, then you can take that concept and expand off of it. But basically, you got a really highly permeable rock and a lot of it. So you've got a lot of KH. And then when you put a horizontal well in it, you got a lot of KH. So even though the initial rate was a little over 13 million per day and over 900 barrels of liquids per day, that was with about 10% drawdown. So were making 19 million per day with about 10% drawdown. So as we continue to produce it, you're only taking 10% of the productive capacity of the well to get that right. So you can produce at a flat rate for a relatively long period of time. Dan McSpirit - BMO Capital Markets U.S.: Okay. Do you have the name of that well handy?

No, because all of our competitors are also on the phone. I'm sure they're already looking at all state records and everything to figure it out, and then to try to figure out. We're continuing to lease as well, and we're picking up leases up there for that kind of potential. Dan McSpirit - BMO Capital Markets U.S.: I understand. And then if we could, one last question here, return to the ethane sale agreements here, recognizing that you have a CA in place and that you're limited in what it is you can relay to us. But if you could take a step back here and just give some context on what gave rise to the contemplated agreements? And that is, how did the option originate? I guess, what's the precedent for the agreement?

I guess I'm not following you, Dan. Can you be a little bit more specific? What do you mean in terms of precedent? Dan McSpirit - BMO Capital Markets U.S.: What is this agreement based on? Is there an industry agreement out there that you're basing the terms of your agreement with Dow or another company on?

All our agreements will be simple purchase agreements for ethane that you would typically have anywhere along the Gulf Coast or if you ever had a product, the challenge is we're the producer, they're the end user. How are we going to get the ethanes to them. That is going to have multiple ways in which you could solve that problem. We could deliver to Dow under 2 or 3 different arrangements. Obviously, you'll have a cost impact as to which one you use. So we'll work with Dow to figure out which way to give them their ethane at the lowest price of transportation to them, but what is happening is, as John was speaking about, as there's more confidence that there really are ethanes here and you have a global economy that's using naphtha, now you have this huge push of how do I get off of naphtha and get to ethane. I think what you see is this global movement to the cheapest feedstock that you can. And you'll do all the ethane that you can, and then you'll start doing propanes to get off the naphtha. And so we have a huge source of customers that become much more familiar with what we have to offer. Range's benefit is that we actually now have so many competing offers that I say the ethane price that we will realize keeps going up. So therefore, as Greg Davis told me this morning, our biggest negotiating factor has been in the last year is simply say no, and you get more offers at better prices. So we're just having to methodically go through there because again, all the infrastructure will need to come through and it will have implications as to where the ethanes will be going for the next 10 to 15 years. So it's a big, huge opportunity for us, we're going to maximize that. But some of the unknown ability that people don't appreciate is that once you put the fractionator in and we're actually fractionating and taking the ethanes out, we'll have 12% greater recovery on the propanes. That's going to add to our propane margin simply because now trying to fractionate the propanes because of the quality in which we have to deliver the propanes, which are not fully extracting out the propanes. We'll get another 12% recovery on the propanes once we extract the ethane. So it's a plus, plus, plus and the story continues to get better as you look at all the alternatives and you got a global demand for this product. Dan McSpirit - BMO Capital Markets U.S.: Right, right. In any of these agreements, do you expect to be held to any minimum delivery volume or other such commitment?

You will probably have a minimum delivery, you would have under any agreement. But we will also provide for swing volumes over that minimum agreement, so to be able to work that effectively.

This concludes today's question-and-answer section. I'd like to turn the call back over to Mr. Pinkerton for his concluding remarks.

I know we've gone over a little bit, so we apologize for that. But we really wanted to take as many questions as we could to the extent that you did push the buttons and lined up and weren't able to get to the queue here, I apologize. But Jeff and I and Roger and Rodney and the team will be around the rest of this week. So feel free to call us and we'll be happy to answer any questions or try to answer any questions that you may have. We really appreciate everybody being on the call. To kind of summarize, I think the first quarter was an exceptional quarter for us, 17% increase in production volumes and we're in a terrible winter season, some of the worst that I've ever seen and a 17% increase in per share production, which is what, quite frankly, all I care about is what we're doing on a per share basis. I think it's exceptional, I think we'll get on the cost side, we'll continue to beat that and focus on it everyday. As I mentioned in my call notes, our decision to sell the Barnett was a -- and I had a couple of people say, you got to be crazy. But I think it was bold. But I think it was an appropriate move. I mean, clearly, from the opportunity we have in the Marcellus, and what drove that decision was the Marcellus is getting better. The Upper Devonian is getting better, the Utica is starting to, that bloom is starting to open. Clearly, our success in the Mississippian play, Lime play up in Northern Oklahoma is encouraging. The St. Louis play that we've got is clearly, that's the best well this company has ever drilled. That's fantastic. We've got some opportunities to expand that play. The upside from the Pennsylvania project out in the Conger is clearly has got a lot of risk to it. But that's just a question, I think, our guys over time will figure and like that. And then we didn't talk about Nora and some of the horizontal drilling in the Berea here on there. Nora continues to be one of my favorite fields. So the decision to sell the Barnett was really to, from a position of strength in terms of drilling portfolio, and also creates a position from strength from the balance sheet perspective. So I think, again, I think that sale is huge for our company. And when you look at Range today post that compared to where we were 5 years ago, it's just amazing to see the transformation in the company, but I think it all comes down to the quality of people that we have, that are doing it everyday. So it's a really, I think, a testimony to the entire Range team. And it's -- like I said, we are extraordinarily excited and extraordinarily motivated. This company has got enormous value. As Jeff just went through some of the liquids issues in terms of where liquids component in this company is. We have an extraordinary opportunity and the thing I can assure all our shareholders, we are focused 150% of our effort to ensure that our existing shareholders get every bit of that value that we can possibly squeeze out of this onion. So that's what we're focused on. And again, we look forward to reporting our second, third and fourth quarter results. It's a really, really exciting time for us and we appreciate your continued support and we'll see you either on the road or on the second quarter call. So thank you very much.

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