Range Resources Corporation (RRC) Q4 2010 Earnings Report, Transcript and Summary

Welcome to the Range Resources Fourth Quarter and Full Year 2010 Earnings Conference Call. [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. Yesterday, Range reported results for 2010, announced the sale of our Barnett Shale properties and announced our capital spending for 2011. We want to leave as much time as possible to answer questions today, so we're going to move directly into our speakers. On the call with me today 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. Let me turn it over to John. John?

Thanks, Rodney. Overall, we're very pleased with fourth quarter and full year 2010 results. On a year-over-year basis, fourth quarter production rose 18%, beating the high end of our guidance. Fourth quarter production averaged $541 million a day, a record high for Range. This also represented our 32nd consecutive quarter of sequential production growth. For the year, production rose 14%. Adjusting for the property sales, production would have risen by 19%. At year end, crude reserves totaled 4.4 Tcf, a 42% increase over 2009. This represented a reserve replacement of 931% from all sources. Our SG&A cost averaged $0.71 per mcfe, the lowest in our history. Our drilling program delivered 840% reserve replacement at a cost of $0.59 per mcfe. These results reflect selling properties which contained 189 Bcfe and removing 230 Bcfe due to the five-year development rule. Based on what we see to date, these look like some of the best if not the best results in the industry. We combined exceptional growth in production reserves with low find and development cost. That is the hard part of our business, combining high growth with low costs. Again, this performance is attributable to our high-return, low-cost drilling inventory coupled with a very talented and dedicated technical team. Importantly, once again, both production and reserves per share on a debt-adjusted basis increased by over 10%. At Range, it's all about per-share results, as we believe that is what drives valuation. From a financial perspective, we continued our disciplined and simple approach. Bank debt declined, while total debt rose modestly. Debt per mcfe of reserves declined both on total proved and on a proved developed basis. We ended the year with almost $1 billion of liquidity under our bank credit facility, and, importantly, as the largest individual shareholder of Range, I was very happy and pleased to see that the average shares outstanding rose only by 1.1% during 2010. I'm also pleased what we didn't do in 2010. Other than a small $135-million very attractive acquisition of properties directly offsetting our Nora field, we stayed disciplined and focused on developing our Marcellus position and our other key projects. In summary, 2010 was a value-creating year in that production reserves per share both rose more than 10%. Our find and development cost of $0.71 looks to be the one of the lowest in the industry. We continue to drive down our unit cost, in particular, our find and development cost and our lease operating costs both materially decreased. Lastly, we maintained a strong balance sheet and ended the year with the most liquidity in our history. I want to take a moment to congratulate the entire Range team for a job very well done in 2010. Now instead of following our more traditional conference call format, I'm going to focus on what we believe are the key issues facing Range today. Said another way, I'm going to try to attempt to connect the dots as we look forward. First, let's focus on the balance sheet. We expect to close the Barnett sale in late April. Upon closing, we will pay down our bank debt facility, or bank credit facility, to zero and have roughly $400 million of invested cash. As recently announced, we have renewed and extended our bank credit facility. Despite eliminating the Barnett property, our borrowing base increased by $500 million. In addition, we extended the term to 2016, reduced the cost and added more flexible covenants. So with the completion of the Barnett sale combined with the new credit facility, we will have by far the strongest balance sheet in our history. We will have go-forward liquidity of $1.9 billion and no debt maturities until 2015. Second, let's discuss the Barnett sale we announced yesterday. We have recently announced our intention to sell the Barnett properties in October of last year. We looked at all the alternatives and concluded selling the Barnett properties was the most accretive course of action. Our decision to sell the Barnett property was strengthened by the exemplary results we were having in the Marcellus, Nora, Midcontinent and Permian basin. Given our results in these areas and our extensive inventory of opportunities, we believe recycling the Barnett sales proceeds into these higher-return projects was the right thing to do for Range and its shareholders. While we prefer to sell properties in a higher price environment, our thought was that we would reinvest the proceeds back into higher-return projects in essentially the same relative natural gas price environment. Said another way, if we felt the futures prices for natural gas were going to move materially higher in the near term, we would have waited for prices to rebound before selling the Barnett properties. Very simply, we view the sale as recycling capital from lower-return properties into higher-return properties. While many analysts had a view back in October of what we would receive, my view was that a reasonable price would be in the $1.1 billion range. So at a sales price of $900 million, it is roughly $200 million below my expectations. I believe the drop in the futures price for natural gas was a material factor in not meeting my original price expectation. However, in $900 million, the sales price is above our minimum, and the recycling effect is materially accretive to our NAV. We are familiar with the purchaser and are quite confident they will close. The purchaser has their financing lined up, and there is no financing out in the purchase and sale agreement. As mentioned previously, we anticipate the sale to close in late April. As a minor point, we retained two non-producing properties in the Barnett that we believe to have approximately $50 million of value. Now turning to the financial impact, because of the executed the purchase sale agreement prior to filing our 10-K, we deemed it appropriate to mark the Barnett properties to market. As a result, we recognized a $463 million non-cash impairment in our year-end 2010 financial statements. As I think about the impairment, it makes sense in that we invested all of our Barnett capital in a multiyear period when gas prices averaged roughly $8 per mcf. While accounting rules required that we record the impairment, we look at the sale more along the lines of a lifetime exchange, where we're exchanging Barnett properties for essentially Marcellus properties. The difference is that we're selling the Barnett properties at a single point in time, and we'll be reinvesting the proceeds over a one-and-a-half- to two-year period. From a tax perspective, we will recognize a gain of approximately $200 million which will be shielded by our $415 million NOL, so we will incur no cash taxes on the sale. Looking at the sale, our Barnett production is currently running at $113 million a day. So we're selling the properties at approximately $8,000 per flowing mcfe. We're receiving over 8x annual cash flow. Based on recent transactions, these are very reasonable metrics. I know some may compare our sale to the recent Chesapeake-announced Fayetteville sale. I think that the Chesapeake sale is a superior transaction based on the fact that they're receiving approximately $10,000 per flowing mcf. However, quite frankly, I think their properties, taken as a whole, are more attractive than ours. Their Fayetteville properties cover 487,000 net acres while our Barnett properties are 9x smaller, at 52,000 net acres. Also Chesapeake's Fayetteville acreage is much more blocked up than our Barnett acreage. Additionally, the Chesapeake-Fayetteville properties are producing 4x the volume as our properties and have 7.5x the number times more drilling locations than our properties. Although it's an asset deal, the purchaser of the Chesapeake properties appears to be paying a size and scale premium as well, which I think made the difference. Once we close the Barnett sale, we will lose approximately $113 million a day of production. Based on our model, we expect that we'll fully replace the lost production by the end of the third quarter this year. This illustrates why we are convinced that selling the Barnett and recycling proceeds is the highest and best use. Despite selling approximately 20% of our current production, we also anticipate generating double-digit year-over-year production growth for 2011 in the 10% range. As a point of reference, adjusting the Barnett sale, we anticipate the 2011 production would be more in the 25% range. Let's now turn and take a look at the Barnett sale, how it sets us up for 2011 and beyond with regard to capital spending and capital funding. The Barnett sale will generate $900 million of proceeds. We also have identified $200 million to $250 million of additional asset sales we plan to complete in the next 12 months, primarily in 2011. These are small miscellaneous properties and acreage that are not strategic, and their disposition has already been taken into account with regards to impact on production, growth, et cetera. We plan to spend $1.38 billion of capital expenditures for 2011. But at the end of 2011, we anticipate having approximately $400 million of excess proceeds to carry into 2012. Based on current futures prices for 2012, we currently estimate generating $850 million of cash flow. So when you combine that with the $400 million of carryover from 2011, we will have $1.25 billion. We currently anticipate that capital spending for 2012 will be equal to 2011. That will leave us approximately a $150 million gap for 2012, which can easily fund our new bank credit facility. Looking still further ahead, based on current futures prices, we currently anticipate we can fund 2011 and 2013 capital spending fully with internally generated cash flow and no asset sale. This plan was based on natural gas futures prices of a couple weeks ago that averaged $4.50 for 2011, $5 for 2012 and $5.25 for 2013. To connect more of the dots, as I mentioned, we anticipate that year-over-year production growth of 2011 will be 10% after deducting the production loss with the asset sales. I stated previously we anticipate the Marcellus production to grow from just over $200 million a day net at the end of 2010 to $400 million a day net at the end of 2011. We expect 2012 company-wide production growth to be in the 25% to 30% range, and we anticipate the Marcellus production will exceed $600 million a day net by the end of 2012. From both 2011 and 2012, we currently anticipate find and development costs to be $1 per mcf or lower. I'll say that again, because it is a very important point when you think about how we get to positive cash flow. We anticipate find and development cost of 2011 and 2012 to be $1 or lower. I think that will be well below the industry average and probably the top in our industry. This plan I just described is also balance-sheet friendly. At the end of 2012, we estimate that our debt-to-capital ratio will be lower and our debt per proved reserve will be materially lower than where we stand today. Clearly, what is driving these expected results is the Marcellus Shale play. As I noted above, we anticipate the Marcellus production actual rate will go from just over $200 million a day at year-end 2010 to over $600 million a day at the end of 2012. Currently, we have 790,000 net acres in the fairway of the Marcellus. Our current plan shows that we will alternately develop approximately 700,000 net acres. Some of our existing acres will likely be sold, traded, expire or may never be drilled to surface and other issues. In addition, we will spend capital dollars over the next several years renewing and extending leases. The resource potential numbers that we have published earlier this month are based on this plan and take into account the acreage numbers I just discussed. We also believe that approximately 60% of 700,000 net acres that we plan to develop for the Marcellus has potential for the Upper Devonian and Utica Shales. So by developing and holding the 700,000 net acres for the Marcellus, we are also capturing the Upper Devonian Utica resource potential. The size of Marcellus being one of the most economic plays in North America, we like it because it's really three plays in one. Because all the other share plays are essentially single-horizon plays versus the Marcellus, where we believe our acreage holds resource potential in the Upper Devonian and Utica as well as the Marcellus. We view the 700,000 net acres we plan to develop to be more like 1.5 million acres when you compare to the other plays. A very significant advantage we will have in developing the Upper Devonian Utica will be that we will be drilling, where we've been drilling Marcellus Wells, we've already incurred the cost for acreage, roads, surface location, water management, gas lines and compression. Therefore, the incremental costs to develop the Upper Devonian Utica will be reduced by approximately 1/3 versus developing these zones on a stand-alone basis. We believe this will allow us to continue to drive down the cost of the entire play. Now this is a good segue into the whole cost structure issue. Our strategy is to consistently generate double-digit per-share growth at top-quartile or better cost structure. Over the past five years, Range has had one of the better cost structures in the industry. However, as natural gas prices rose significantly, 2006, '07 and '08 time period, so did our unit cost. Most of the industry sold their unit cost rising even faster than ours. As a result, our DD&A costs, which is a reflection of your aggregate F&D cost over time, rose to a high of $2.48 per mcfe. Likewise, our leased operating costs rose to a high of $1.05 per mcfe. By selling our higher-cost properties and reinvesting in our higher-return, lower-cost properties, we have driven down these costs. Our DD&A costs had decreased from the high of $2.48 to $1.85 in the fourth quarter of 2010, a 25% reduction. We expect DD&A to decline to $1.75 for 2011 and reach $1.65 for the fourth quarter in 2011. Generally, lease operating costs have decreased from a high of $1.05 per mcfe to $0.72 for 2010, a 31% reduction. We anticipate lease operating cost to continue to decline to $0.65 in 2011, reaching $0.60 by the fourth quarter of the year. My current view is, to be consistently profitable in this business, your DD&A and lease operating costs combined need to be trending down to the $2 to $2.25 per mcfe range. We are clearly moving there, and I'm confident that our operating teams will get it there, and probably faster than I expect. With that, why don't I turn the call over to Roger, our CFO, to give you his thoughts and perspective? Roger?

Thank you, John. Normally, I lead with the income and expense items and close with the balance sheet liquidity update. However, since we only renew our bank credit facility every four years and there's so much more to the new credit facility than just the 2016 maturity date, I'll follow up John's comments with some additional color. Also to allow more time for questions, I'll be very brief in my income and expense commentary, focusing primarily upon trends and first quarter 2011 expense guidance. The new Range bank group consists of 27 experienced oil and gas lending institutions, each of which employs one or more petroleum engineers to evaluate the borrowing base lending capacity of each company's proved reserves, and they do this twice a year. The bank engineers are deemed insiders, so they have complete access to all requested internal data as well as public data reported to the various regulatory agencies. The bank evaluate our cost figures, reserve replacement performance, the quality of our reserves field by field and, in many cases, well by well. Changes in the E&P company's bank borrowing facility can be an excellent barometer that signals changes in proved reserve quality, cost structure, capital productivity and overall business outlook. Accordingly, we were keenly interested in the bank's determination of our pre- and post-Barnett sale borrowing base. See, we view the Barnett as one of our core properties, but the banks view it as some of their core collateral. So selling an asset this significant can be problematic for both lender and borrower as these opposing views must be reconciled. The fact that 100% of our existing banks plus one new bank committed to a 33% increase in our borrowing base, from $1.5 billion to $2 billion, without the Barnett asset is a significant ratification for the value and confidence they place upon the post-Barnett range. The credit facility was oversubscribed. We received $3.3 billion in commitments from the bank, even though the facility interest rate was reduced and covenant flexibility was increased. Needless to say, we're thrilled with the new credit facility and the positive story it tells. And with the Barnett proceeds reducing the outstanding loan balance to zero, Range will have $1.5 billion of committed liquidity under the facility throughout 2011. Many thanks to our bankers who may be listening to this call for their continued support. Moving to the income statement. Cash flow for the fourth quarter was $159 million. This marks the second consecutive quarter of improving cash flow. Per-share cash flow for the quarter was $0.99, $0.02 above the analyst consensus estimate of $0.97. Cash flow for all of 2010 totaled $577 million, or $3.64 per fully diluted share. EBITDAX for the fourth quarter was higher than the previous four quarters, totaling $189 million. EBITDAX for the entire year was $694 million. Fourth quarter cash margin was $3.06 per mcfe, that's up $0.06 from the prior quarter. Quarterly earnings calculated using analyst methodology for the fourth quarter, which excludes nonrecurring and noncash items, was $30.4 million, or $0.19 per fully diluted share. That's $0.05 higher than the analyst consensus estimate of $0.14. Analyst earnings for the entire year were $89.3 million, or $0.56 a share. Please go to the Range Resources website for a full reconciliation of these non-GAAP measures, including cash flow, EBITDAX, cash margins and analyst earnings. Turning to the cost structure for a minute. The most critical cost item was announced just last month: our $0.71-per-mcfe all-in reserve replacement cost for 2011. The fourth quarter DD&A rate again declined to $1.85 per mcfe, just as one would expect with such significant capital productivity improvement. And that brings the DD&A rate down for all of 2010 by 14% from last year's $2.35 figure. Though the DD&A rate varies with production mix and is, therefore, challenging to predict, we anticipate the DD&A rate will decline further in 2011 to approximately $1.75. And, should our 2011 drilling results mirror those of 2010, the DD&A rate would decline to approximately $1.65 at year end. The Barnett assets clear all impairment tests under the successful efforts accounting method. However, with a signed purchase and sale agreement in hand, even though the transaction is not yet closed, we have impaired the Barnett property value to reflect the possibility of the sale. This noncash impairment is the economic equivalent of a full-cost ceiling test write-down. Fourth quarter direct cash operating expense before noncash compensation but including workovers was $0.72 an mcfe. That's equal to the previous quarter and down $0.03 from last year. Now we anticipate cash direct operating expense in the first quarter of '11 to be approximately $0.69. That will decline further through 2011 to the low $0.60 range by the fourth quarter. It's interesting to note that although production was significantly higher in 2010 than 2009, total cash-direct operating expense for this year of $129.3 million was actually $1.3 million lower than last year. Production taxes for the fourth quarter were $0.17 an mcfe, and that's down 19% from the fourth quarter of last year. As production taxes are a function of production mix and oil and gas wellhead prices, we do expect to drop another $0.01 per mcfe in the first quarter of 2011. G&A expense adjusted for noncash stock comp and other non-recurring items was $0.57. That's down $0.04 from last quarter. Now for the first quarter of 2011, we anticipate G&A expense to be in the $0.60 to $0.62 range. Interest expense for the fourth quarter of 2010 was $0.73 per mcfe, and that's flat with the third quarter. Interest expense should decline slightly once the Barnett sale proceeds are applied to pay off the outstanding bank debt. Exploration expense for the fourth quarter of 2010 excluding noncash stock compensation expense was $15.8 million, and that's up slightly from prior quarters due to higher seismic expense. And with higher delay rentals and seismic expenditures budgeted for 2011, first quarter of 2011 should see expiration expense in the $22 million to $24 million range. Moving to abandonment and impairment of unproved properties, this number for the fourth quarter was $23.5 million. That's $3 million higher than last quarter but $5 million lower than the fourth quarter of last year. With the Barnett sale behind us, our steady-state 2011 quarterly unproved property impairment should run $15 million to $17 million. Range ended 2010 with a $415 million NOL carryforward to help shield future taxable income. And as John mentioned, this tax shield will more than offset the approximate $200 million taxable gain from the Barnett sale plus the miscellaneous asset sales anticipated over the next 12 months. This will ensure that there will be no tax leakage in the cash sale proceeds. Now from day one, it was decided that we would include a portion of our 2011 hedges with the Barnett sale, because to not do so would result to over 100% of our remaining production being hedged. The value of the hedges as of January 31 that are included in the sale total $42 million. Now post-Barnett sale, we expect to have approximately 80% from our 2011 gas production hedged with a floor price of $5.39 per MMBtu. So to summarize, we're ending 2010 with improving trends in reserves, production, cash flow and expense control. The new bank facility underscores these trends and, when combined with the proceeds from the Barnett sale, provides Range the strongest balance sheet and the most financial flexibility it has ever had. John?

Thanks, Roger. Now I'll turn the call over to Jeff Ventura, our Chief Operating Officer, to give you his thoughts.

Thanks, John. I'll begin by discussing our year-end reserves. Range's 2010 reserve growth was the best in our history and, I believe, the best in our peer group. We grew reserves 42% to 4.4 Tcfe with all-in finding and development cost of $0.71 per mcfe. Our drill bit reserve replacement was 840% at a cost of $0.59 per mcfe. Reserves per share, debt-adjusted, grew 32%. Proved developed producing reserves grew 25%. Importantly, this was accomplished despite removing 230 Bcfe of proved undeveloped reserves in our historical Pennsylvania tight gas sands in lower CBM locations. Although these reserves are still economic, given the great success we're having in the Marcellus and elsewhere, we do not plan to develop them within the next five years. It's important to note that not only did our 42% growth overcome removing 230 Bcfe of historic tight gas sand in CBM locations, it also overcame selling 189 Bcfe of reserves. Thus removing a total of 419 Bcfe and producing 181 Bcfe, we still grew 42%, and did so with peer-leading F&D. During 2010, we focused 81% of our capital on the Marcellus, and the results were excellent. Utilizing performance history from 139 Range horizontal wells, our average well was 5 Bcfe. At year end, our Marcellus PUD location to proved developed ratio was 1.9. This year, we will focus about 86% of our capital into Marcellus. Given the large derisk acreage position we have in the play, 2011 should be an exceptional year. Despite our plans to sell the Barnett properties, we expect that we will achieve double-digit reserve growth in 2011, even without the Barnett properties. We should also achieve approximately 10% production growth. We believe we will overcome the lost production that is expected to go with the Barnett sale. Current Barnett production is 113 million per day. We exited the Marcellus at a net rate of approximately 200 million per day last year, and we forecast that we will exit the Marcellus at a net rate of 400 million per day this year. I believe we have adequate production capacity from the wells that we have drilled and will drill this year to achieve the 400 million per day. 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 155 million per day at the Houston I and II plants. The Houston III plant is expected to come online in mid-April, and Range's capacity in that plant will be 165 million per day, which will make our total processing capacity at that site 320 million per day. At the Majorsville I plant, Range's current processing capacity of 30 million per day, which should increase very shortly to about 45 million per day with some minor modifications that are currently under way. By mid-third quarter, the Majorsville II plant should be in service. This will increase Range's processing capacity at that site to 85 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, at 375 million per day, will be expecting well ahead of our production volumes throughout the year. We are well-positioned to be able to move the gas from the wellhead to the processing plants. In Lycoming County, our current gathering system capacity in Phase I is 50 million per day. The remainder of Phase I and II gathering systems are planned to be complete 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 the end of 2011, between 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 need this year, with plans to stay well ahead of our production ramp over the next few years. At this point, I'll turn the call back over to John, and I'll be happy to answer any of your operational questions in the Q&A.

Thanks, Jeff. I'll now provide some more details for 2011. For the first quarter of 2011, looking for production to come in at 540 million to 550 million a day. The midpoint represents a 19% production growth versus the prior quarter, and, if successful, it will represent our 33rd consecutive quarter of sequential production growth. Range, like many other companies, experienced material freeze-offs and shut-ins production in January and February. The weather impact as we currently know it has been reflected in this production guidance. Assuming the Barnett sale closes at the end of April, our second quarter production will be lower than first quarter. Third quarter production should be back up close to the first quarter, and we anticipate fourth quarter production to be well-above 600 million a day. We anticipate unit cost to continue to decline in 2011 and refer you to the guidance that both Roger and I gave you previously. Getting back to the capital budget, given the high degree of operational control, we can and will remain flexible as to the capital spending. As you recall, we underspent last year's budget by $100 million and still exceeded our production and reserve guidance. The good news is that at $4.50 flat NYMEX gas prices, our drilling projects in the Marcellus, where we are spending 86% of our capital budget, generate over a 50% rate of return. It's pretty amazing. In summary, while the Barnett sale is a couple of hundred million dollars less than we anticipate, it is a significant catalyst for Range ramping up the funding for our Marcellus play, which, as I mentioned, has really robust returns. And it's also a catalyst for reaching a cash-flow-positive position in 2013. As outlined in our operations release that we released a week or so ago, our drilling program is off to a tremendous start, having recently drilled our best wells in the Marcellus and Nora/Huron, Mississippian Lime and the St. Louis plays. We are confident that we can once again deliver double-digit production growth in 2011 and are also confident that we can achieve this growth at a find and development cost of $1 or less. If we achieve our plan, it will be another value-creating year in 2011. That concludes our prepared remarks. Operator, why don't we open up the call for questions?

[Operator Instructions] Our first question comes from the line of Ron Mills with Johnson Rice. Ronald Mills - Johnson Rice & Company, L.L.C.: A couple of questions for you. You described the Barnett sale as almost one of your like-kind exchanges and able to really focus your activities on the Marcellus. Of the 86% that's being spent on the Marcellus, can you give a breakdown of what you expect to spend in the Marcellus versus the Upper Devonian versus the Utica?

Yes, let me take that question. Our focus is going to be almost all on the Marcellus. We're really encouraged by what we see in the Upper Devonian. We've drilled and completed a couple of wells. We're in the process of testing the second well. And the same with our first Utica well, which we disclosed this month also. So the first Upper Devonian with over 500 million per day and the first Utica 4 4 for a seven-day average. But this year, we're looking at, we'll probably drill on the order of, literally, just a couple wells in each this year to continue to look at the potential and derisk parts of our acreage. Our focus is going to be on driving up value in the Marcellus. That being said, I think you're going to see a lot more of our -- the other E&P companies in the area drilling wells through the Utica and through the Upper Devonian. So just like originally, it was Range alone leading the charge in the Marcellus and then several other companies coming in and help to de-risk our acreage. You're going to see the same thing I think happen with the Utica and Upper Devonian. And in the meantime, we're going to stay focused on driving up rates in the Marcellus. Like John said, we entered this year at 200, and we're looking at exiting the year at about 400. Ronald Mills - Johnson Rice & Company, L.L.C.: And from the Southwest to Northeast with the gathering system in line, is the Northeast going to have a bit more capital allocated to it this year?

Yes, it will be a bit more, but the bulk of our drilling is still going to be, by far and away, down in the Southwest and in the wet area. Ronald Mills - Johnson Rice & Company, L.L.C.: And lastly, on the production, you talked about the production ramp, John, the quarterly ramp including the impact of the sales. What was the split of gas versus NGLs on the Barnett sale? And as we look forward to that ramp, particularly as you get to the fourth quarter and into 2012, what should we expect your gas-versus-NGL component to be?

Rodney, do you want to take that?

We're running right now about 79% gas, and the Barnett was about 20% liquid. So we expect same kind of composition of 79% gas. The NGLs will be twice what the crude oil is as you model it forward. And then we can kind of give you guidance as we drill in the Southwest and the Northeast.

Yes, I would just suggest any specific modeling questions that you have that you call Rodney and his team. Ronald Mills - Johnson Rice & Company, L.L.C.: Perfect. And then lastly on the Mississippian, that's obviously become a pretty hot topic. You have in your last presentation about 15,000 acres in that play. Can you provide any additional color in terms of what your activity levels are in that area and whether or not you're still ramping activity? Because the talk has been that you all have had some pretty strong results in your early activity there?

Yes, we've had good success. We announced a couple wells that tested, combined, 807 barrels of oil, 298 barrels NGLs, and 1.3 million per day. So we're 1,314 barrels per day combined, 657 barrels each. And when you look at the play, and we have it in the appendix that's out on our website, you're looking at really strong economics, cost of those is about $2.1 million to get about 300,000 barrels, 80-plus percent rate of return. So we have a good position. We've added to our acreage position, actually, we're a little over 20,000 acres now. So we have a good position. But like we said, for this year, 86% of our capital is going to be going into the Marcellus. And out on the website, I think, we have a book that breaks out the remainder of the capital in the other divisions. And you're looking at a relatively small allocation for the Midcontinent this year. It will be 6% of our total budget. And the reason is a lot of our acreage there and in other areas is held by production. So we got a great position, a great team, and really, if you look at the Range wells, I think, they're some of the best wells in the play so far, if you look at not only IPs, but 30-day averages.

Our next question comes from the line of Biju Perincheril from Jefferies. Biju Perincheril - Jefferies & Company, Inc.: Could you talk to me about the well that you mentioned, the Marcellus well that you mentioned in the release last week and the 18 million a day? Was that drilled with any -- was there any change in how you drilled and completed that well? Or was that result a function of location?

Yes, let me talk about that well. Rod mentioned the Mississippian. So let me just talk about some of our wells in general, maybe give you a little more color for the wells that were in the operations release a week ago. Let me start with that well. That well, that was a standard, basically 2,500-foot lateral, eight-stage frac, sort of a plain vanilla well. And really I think what speaks to it is the quality of acreage that we have there and also as we continue to go up the learning curve and how to drill and complete. When you look at that well, that was a really important well with a step-out well in a Southwest part of the play. It was 35 miles from our core area in Washington County. So that's a big distance away. The well tested 18.6 million per day on a five-day test. It may be our best well to date, or clearly it's one of our best wells to date, so we're really excited about that. When you look at that well, stepping out 35 miles plus some of our drillings plus the industry's drilling and you look at our position in the Southwest now, we estimate about 85% of our acreage in the Southwest has been derisked through our wells and others. So it's more than 800 wells that have derisked and defined that area. So we feel really good about that, and those are the economics that John mentioned. And again, look on our website and various analysts show that the rate of return when you're in the Southwest during the core part, like a lot of our acreages have, perhaps the best rate of return anywhere in any play in the U.S., or it's clearly in the very tippy top of it. So that was a really important well and a key well, and I would expect by the end of the year that we'll probably have derisked 100% of the acreage, in essence. When you move on to that release, we also talked about 11 horizontal wells we brought on in the Southwest part of the play in the fourth quarter. And in the release, it's said BUR [ph], we're expected to exceed 5 Bcfe. If you look at our reserve estimate today on those 11 wells, it actually look like they're going to exceed 6.5 Bcfe. So they look like they are really strong wells, for that, that's an 11-well average of those most recent wells. So very exciting again. Great rock, team's doing a great job. Midcontinent, I just mentioned to Ron, we're talking about the horizontal Mississippian wells, and I won't repeat that, but good economics, oil looked good. But I will mention an additional well that I want to talk about up in the Midcontinent division, and it's a horizontal St. Louis well. And I really want to give the team credit there. That's the industry's first successful horizontal St. Louis well. And going back to the release, it's IP-ed at 360 barrels of oil per day, 593 barrels NGLs, plus 13.8 million cubic feet of gas, or 903 barrels liquids and 13.8 million per day. After being online for three weeks, it's still producing 872 barrels, it averaged 872 barrels per day and 13 million barrel per day. So very, very low decline, very strong well. One of the best wells Range has ever drilled. That well cost us about $4.5 million to drill and complete. Probably we'll recover on the order of 8.5 Bcfe. So just like Range pioneered the Marcellus in general, the first horizontal well in the Utica, first horizontal well in the Upper Devonian, it's the industry's first horizontal St. Louis well. So the technical teams are doing a great job and drilling some excellent wells really across our whole -- across the company. And the last one that I want to mention that was in the release is also a key well, it's in the Nora area. Now we mentioned the horizontal Huron Shale well, which drilled 25 miles away from our production in Nora. And that's really, again, a big step-out. But when you look at all the vertical well control that exists across that acreage block, and this is on the new acreage that we acquired, as John mentioned earlier, last year in Virginia. Given the vertical well control and looking at the wells in Big Sandy and the wells to the south in Nora, we stepped into what we thought was going to be a really good area 25 miles away. And the Huron there looks really good. It looks like it's probably better rock quality than Nora, plus it's all virgin pressure. So when you look at that IP, 2.6 million per day, and these are relatively shallow wells and relatively inexpensive. And most likely, it will add somewhere in the order of 400 to 500 Bcfe net, or derisked that amount of gas with that well. Of course, that's all great news on the operations side.

Our next question comes from the line of Marshall Carver with Capital One Southcoast.

I have a couple questions. One, on the St. Louis well, the horizontal well, how many locations do you think you have on your acreage? Do you have any sense of that yet?

Yes, when you look at -- it's on the website and in the appendix. We actually have the locations that we have out there. And we think right now we've identified an additional 71 horizontal locations and six vertical. Plus we've identified other areas where we think that's perspective that we'll attempt to lease and pick up.

And what would your working interest be there, or was that a net number?

No, that was 100%. On the first well, our working interest was about 50%.

So that was 71 gross or net locations on that?

Those are 71 gross locations. Our working interest on average, we'll probably have to get you, it's probably better than that on average, because a lot of it is 100% when we drilled the first well, it was -- we drilled the less risky well on in place where we had a partner carry or take part of the cost. So we have, on average, the working interest is higher. We can get you that number and we'll give it to Rodney.

A couple more questions. On the $200 million to $250 million in additional sales, how much production is associated with that? I know your production guidance is net of the sales number, but I wanted to get a feel for how much production you're planning on selling and whether that was oil or gas.

Yes, Marshall, this is John. It's a combination, quite frankly, of a lot of the little property, some in Texas, some in Mississippi, Louisiana and some kind of some scattered acreage that we own. So it's really not all that much production associated with that. Because honestly, I don't have that number in front of me, but it's relatively immaterial.

You gave your gas price forecast with your cash flow assumptions and balance sheet assumptions for the next couple of years. What were your NGL assumptions that you used in terms of NGL pricing for this year and next year?

Well, first of all, that wasn't really my, or Range's, or John Pinkerton's, or Jeff Ventura's, or anybody's. It was really just the future strip price that we could have locked it in on when we did the runs back in, I think it was mid-February, a week or two ago. So it's really that price. I'll let you all determine what you think gas price is going to be in the future, you probably have as good, if not better, idea than I do. In terms of the liquids and the oil, we base that off $80 oil and then we base the liquids off that as a percentage just using historical references. Fundamentally $80 oil.

Our next question comes from the line of David Heikkinen from Tudor, Pickering. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: John and Jeff, just given your successful testing of multiple new areas in Texas and Oklahoma this year and what you've had, what's your success case CapEx for those areas in 2012?

Well, for 2012, we are going to stay really disciplined. We're going to stay focused on the Marcellus. Really what we're doing is spending enough money to derisk and understand the play. So the plans John laid out, I mean, there's an allocation of capital for those areas. But the good news is the bulk of all those areas are held by production, so we can really control the timing and such.

We're spending $1 billion, $1.38 billion, we said the same, but I would round it to, let's say, $1.4 billion. And I think we'll spend probably again, we'll spend 80% to 85% of our dough in the Marcellus with the idea that, that is the one area where we don't have most of the acreage held by production. And so that's one of the primary reasons we want to sell the Barnett, is to term out all those leases. We're about 46% held by production in the Marcellus, and based on the plan that I gave you, we will hold 700,000 acres through the plan. And again, that's what the resource potential numbers are based on and everything else. So it all kind of ties together in terms of method to the madness. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: So then if you think about the focus on the Marcellus as you think about improving efficiency, improving plant capacity and as your cash flows grow and you have the debt capacity, I'm trying to understand why you wouldn't then accelerate into an improving efficiency in the Marcellus. Where are the governors there? As you get the cash flow growth, it seems like your CapEx could go up with it.

Well, hopefully, what we can do is spend more for less or keep it the same and get more out of it. And quite frankly, that's what happened this year and that's what happened last year, and that's what we're expecting for 2011 and a little bit of 2012 as we move forward. But again, I want to walk the walk before I talk the talk. So as we see those improving metrics, we'll deliver them to you. I mean I think in the overall sense, we've delivered pretty fantastic reserve growth at really low numbers. And I think if we can do $1 or less find and development costs for this year and next year, you're going to see our DD&A rate continue to go down. You're going to see our LOE rate continue to go down over time. And I think that's really the proof in the pudding, and it's interesting. I looked at what you all put out in terms of the four key criteria, which was make money in the current environment. And we really think that's important, too, is to be able to make money in a $4.50 or $5 environment. And that's where I get back to this whole thing where I think your DD&A rate and your LOE need to be about $2 to $2.25. So I think we're getting there. Your second point was focus on costs, we're really, I think more than anybody else, we're cost-focused. And then third, obviously, invest in the highest-return projects. I mean simply, and I've got a lot of questions today on the Barnett and have had over the last month, it's really simple to me, we've got drilling locations in the Marcellus that at $4.50 gas generate over a 50% return. Those same drilling locations in the Barnett are high teens, 20-type-percent rates of return. So the question is pretty easy for me. Not being the brightest bulb in the package, I'd rather spend the money in the Marcellus and the Barnett. So that's why I sold the Barnett. Pretty simple. And then your fourth point, and this is why I really agree with you guys, is driving up production and reserves on a debt-adjusted, per-share basis. As we've said on and on again, what we think really drives value in this business is per-share growth, debt-adjusted at low cost. And if you can do that consistently over time, you'll make your shareholders a lot of money. So we're all in, in terms of those four metrics. And hopefully, we'll continue to do that. It's a big challenge, but we'll see. And I think, Dave, to get to really what you're getting at, do we think our cost will improve, do we think our efficiencies will improve? Yes. I really think they will. I think we've got really good people. We've got over 325 people now in Pittsburgh running that program. So I think we'll get better at it. But as we do, we'll tell you about it. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Effectively, what I heard is you've got an acceleration an efficiency gain built into your expectations, but it isn't necessarily reflected in your production numbers at this point.

Absolutely. That's a great way to characterize it. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And then, as I think about each of those other areas where you're just spending that 14% of your capital, how do those get sold? It seems like they're just naturally lined up for recapitalizing and selling small amounts of acreage production and the like. I mean, what's the time frame to appraise this?

Well, like what Jeff said, the good news is almost all of that is held by production. So there's really no -- we don't have a gun to our head in terms of having to develop it. I know it's hard for some of our listeners to really imagine, but in 2013, once we get to positive cash flow, when you look at '14 and '15, at least our numbers suggest we're going to be throwing off a whole lot of cash flow. So we're going to need projects like the Cana, projects like the St. Louis, projects like the Mississippi and Lime, some of the other projects we're doing out in the Permian. We're going to need those projects to continue to fuel our growth. That being said, I do think over time, just like anybody does, if somebody comes and makes us a great offer for one of these projects and we think it's NAV accretive, we'll take a hard look at it. So we try to be flexible, we do try to keep in terms of how we run our business -- fundamentally, it's really easy. Jeff and I and Roger really view our jobs as we allocate capital, and as we see it, we try to allocate capital to the highest-return projects each and every day. We still sign every AFE in this company over $200,000, all three of us still sign it. So we've got our hands firmly on the steering wheel. We think we've got a very good view on what drives value, and we got some really, really good people that are drilling some really, really good wells. And at the end of the day, we think that will all wash out, and we'll have top quartile performance. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Just one final question. As you think about management compensation, you've tied management compensation to debt-adjusted growth rates and efficiency. Do you adjust your debt-adjusted growth rates in the baseline whenever you sell assets? Or do they remain in that base and then is it off an annualized number?

What we do -- our compensation committee looks at our budget and our projection for the year, and that's the baseline. And to the extent that if we sell something after that baseline has been developed, then we have to live with that. But again, that's part of it, and we'll have to live with it. But as I tell all the management, that's life in the big city at Range.

Our next question comes from the line of Scott Lamont [ph] with Simmons and Company.

Just thinking a little more specifically about the Marcellus acceleration. What level of rig activity are you guys planning in 2012 to get to the 25% to 30% growth? And can you give me the split between Southwest and Northeast?

Yes, if you look at 2012, we're looking at a total of 17 rigs. And then you have to add the Talisman too, though. See, there's 17 Range-operated rigs. We will have 12 in the Southwest and five in the Northeast, and then two that get add the Talisman piece, the Bradford County stuff.

And your total in '11 is what?

Total in '11, we expect to end the year in '11 at 14 plus Talisman. So currently, we are at 13, we'll end this year at 14. We'll end '12 at 17. Talisman is currently at two. We expect them to end the year at four, and they should have four in 2012.

Can you give us an update on current well costs in the Marcellus, what your expectations are throughout the year and then kind of what's baked into your CapEx?

Yes, we can talk about that. When you look at, we really have three types of wells. And let me talk about them conceptually and I'll give some more specific numbers. You've got development wells in the Southwest part of the play. Then you've got step-out wells in the Southwest, and then you got wells in the Northeast. And then eventually, you'll role into that same category there. When you look at a development well, a pad well in the Southwest, we're approaching $4 million, like we said, in the development mode. Current AFEs are actually $4.2 million, so we're getting pretty close. And then when you step out, like I said I mentioned a well earlier that's made just over 18 million a day, 35-mile step-out. When you step out, those wells are going to be a lot more expensive. One, you've got -- instead of allocating the pad over multiple wells, it's on one well. When you drill step-out wells, you typically, you may cork part of the well, run a bunch of micro-seismic, run a bunch of experiments and all those kinds of things. Plus you aren't allocating the water impoundments [ph] and rows and stuff across multiple wells, either. So those are two kinds of wells. Then when you go to the Northeast in Lycoming County, the wells are roughly 2,000 feet deeper. So when you look at current drilling, we're looking at, for this year in the Marcellus, we're looking at 195 wells, roughly. That's our expectation of that. 172 would be in the Southwest, 23 in the Northeast. If you look at the average of the 4.2 plus the higher-cost step-out wells and delineation plus some science, those wells are going to average on the order of 4.4 million probably per well in the Southwest. And you could add roughly 1 million for the wells in the Northeast. And I expect with time, literally, again, if you go back and look at what we have, 85% of that acreage in the Southwest has been derisked, so when you look at our acreage position, you use 80-acre spacing there and you use -- and just assume 80% of the acreage is drilled, that's over 4,600 wells in the Southwest. I guarantee you, with the technical team we have, when you let them drill year in and year out over, literally, thousands of wells, I have high hopes that those guys are really going to drive those costs down dramatically from not only where we are today or our expectation, of course [ph] they'll break through that. Sort of what John was saying earlier, there will be a lot of capital efficiency gains that will come with time, and I believe the same thing will happen up in the Northeast also.

Great, I appreciate the color. And lastly, just can you give us an update on your acreage swaps, how much of those are ongoing? Do you continue to expect to do them in 2011?

What has gone on in the industry up there is that all, I think most of the companies that come to the conclusion that the key to life is blocking up your acreage, because you can gain -- that's where you gain these efficiencies. If you have to drag rigs all over creation up there and then your pipelines, and your gathering, your water, impoundments and your water gathering it really drives up your cost. So I think most people, like us, and you learn it just by doing it, you learn that if you can covey up part of your acreage together, you really drive down those costs. So I think that's -- the good news is we've had a number of discussions and continue with the industry participants up there. And we actually see the attitude for doing acreage swaps actually increasing dramatically. We've had a number of meetings with companies that heretofore weren't too keen on it, but I think has realized what the potential is, that it's really good for both sides. And the good news now is that some of these other companies, I think, quite frankly, the reason they didn't do it is because they probably, to some degree, viewed that we had a technical competitive advantage. So they were a little bit fearful. I think now, they drill the number of wells, their own technical teams have confidence in what they're doing. So it's really just trying to swap acreage, in most cases, like-kind for like-kind, but even when they're pretty far away I think there's a pretty good reasonable expectations in terms of quality of the acreage. So the ability to use that as currency, both from an add-to perspective and then have a technical understanding of it, I think has gone up dramatically. So we've had a number of conversations with companies, and we probably got four or five trades anywhere from 500 acres up to 50,000 acres, a number of trades that we're working on at any one point in time. And so again, I think those will happen. The smaller ones will just happen in normal course. If we do some bigger ones like the ones we've done before, we'll make note of that in the conference call. But the good news is I think the industry as a whole has figured all this stuff out, and so now, there's a lot, I think, bigger desire among the companies to do it. In particular, I'll say, in particular with some of the bigger companies up there that might have bought out some of the smaller operators, they're big believers in that, and they don't have near the emotion that some of the smaller companies had in terms of their acreage. So that, again, will help facilitate acreage trades as we move forward. The other thing, if I can just segue into how that affects your acreage, is that in any big giant play like this, and Barnett's the same way, is that you're always going to have acreage that you have to renew and extend. No matter, really, no matter how mature the play is, there's always going to be some amount of acreage you've got to renew and extend. And as companies block up their acreage, you can, your ability to renew and extend within your little corral within your neighborhood goes up over time, because other companies then focus on their acreage and are less focused on trying to come into your areas and poach, if you want to use that word. So I think that's happening as well, and we're able to renew and extend a bunch of the leases that we're doing for this year, because we have leases that are expiring throughout the year. But most of the stuff that we need to renew for this year, we've already done so. But even looking at 2012, the cost to do that is really pretty modest. And to give you an idea, we still have less than $1,000 per acre on average cost into all of our Marcellus acreage. So even if we had to renew it all at something that was 2x or 3x what we recently paid for it, you can still see that the overall cost of that acreage is going to be really, really reasonable compared to some of the other plays that we've been in and some of the other shale plays that have kind of taken off and gotten real hot. So again, I think all that matters when you're looking at these plays and thinking about the economics and what really -- what makes sense in terms of economics.

Our next question comes from the line of Mike Scialla with Stifel, Nicolaus. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Question on the southwest part of the Marcellus play. Jeff, those 11 wells you talked about that you think now are exceeding an EUR of 6.5 Bcf. I'm trying to get a sense for if you think that's a good average going forward. So can you talk about where those were drilled, were they in one concentrated area or were they scattered across your acreage? And then it looks to me like you booked about 4 Bcf a well in the southwest part of the play. I want to know if that's right. And then how do those numbers reconcile?

Those wells, some of them are off the same pad and some of them were scattered. And I think it's a reflection of the quality of the acreage. So those wells -- those 11 wells look like they're better than 6.5 Bcf. Our best well, just to remind people, is probably about 10 Bcf. So there's definitely high-quality Wells on our acreage and around our acreage. So I feel good about that. I think what we like to do, and Alan Farquharson that runs that effort for us, we book reserves, and then we like to just watch performance with time. And to the extent we see those wells year after year coming up, you'll see those increases in there. And that's the way we'll march forward. Actually, again, referring you to our most recent IR presentation, it's on the website. Rodney's looking for it. There's actually a graph that shows every single horizontal well we've drilled with time in the form of a zero-time plot. So you can see the performance coming up with time. And it's on Page 18 of the current IR presentation you can see on the website. Yes, you're right. I mean with booked, when we book some of those puds and stuff, they're booked at a lower number. I expect with time as we continue to drill them, and I'm hopeful, that we'll continue to see that positive increase that we are seeing. Michael Scialla - Stifel, Nicolaus & Co., Inc.: That's fair. Did you do anything differently? It sounds like you're leading us down the road that 5 Bcf is probably not going to be the last of those curves on that Page 18, that there's another step up to be anticipated down the road.

I think there's two things to look at. One, can the guys do things to improve performance to them. I'm really convinced in time, we'll do things to drive down cost. And at the end of the day, it's really about rate of return and repeatability. Again, we've got at 80-acre spacing, using 80% of the acreage, 4,600 wells to drill. And when you look on that same presentation on the website, you can see what our current rate of return is for those wells and we did it fully loaded as well, taking all the lands and the corporate G&A and putting it all on an individual well. That's on Page 15. So we've got strong rate of returns, even if we don't change what we currently have, at $4 gas, the 5-Bcfe well currently is 74%, fully loaded is 58%. I believe our team is going to do better than that with time, but those are pretty strong economics. Plus, medium to long term, personally, I think gas prices are going to be better than $4. You go to $5, you're approaching 100% rate of return.

This is John. I think just to be completely transparent, there are some people who view the Marcellus as a mature play. In some respects, it's still, compared to the other plays out there historically, it's still -- you'd have to put it in the relatively new category. There's really very few wells with over three years' worth of production. I think most of them, or nearly all of them, are our wells. So with all that being said, these 11 wells are pretty exciting. And I think we got a really good team that's executing, but 11 points is not what I'd call a huge statistical sample. So I think what we're telling you is that we're off to a great start for 2011. We drilled some really good wells. Stay tuned. We'll keep you up to date. We'll continue to post on that chart every single well we drill and do that zero-time plot. So we'll all get to see it realtime, and then we can, over time, we can look at it and see whether this ought to be 5 Bcf, 5.5 Bcf, 6 Bcf, 6.25 Bcf, 7 Bcf, I don't know where it's going to end. And the other thing about it is...

But again, I'd re-emphasize, if it ends where it is today, it's pretty darn good. And according to some people, right where it is today, it's the best play out there, including some of the oil plays.

I agree. So at the end of the day, we're in great shape. We'll be as transparent as we possibly can in terms of laying those things out for you and letting you all decide whether you think they're going to end up -- we got a view, but I think it's important, we're going to be -- we're going to keep it the Range way. We're going to start out, and like Jeff said, Alan Farquharson, who runs our reserves, is a very talented guy. And one of my views in life is, you want to have modest, upward performance revisions every year. I don't like it when we have negative performance revisions. Doesn't make me feel good. So we're going to take that position, and it's something that's just built into our culture and our DNA. Michael Scialla - Stifel, Nicolaus & Co., Inc.: I want to ask one quick one on the Upper Devonian. It seems like you may be a little bit more optimistic on that than Utica at this point. One, I wanted to see if that is a fair statement. Then secondly, I know the Upper Devonian is pretty widespread in Appalachia. That 10 Bcf to 14 Bcf of potential you talked about in that formation, do you think you've identified an area where the Upper Devonian is different geologically than most the rest of the basin? Or should we -- could you extrapolate those kind of numbers to a broader area?

On the Upper Devonian, I'd characterize it this way. The Upper Devonian -- the Marcellus is a Devonian-age shale, and it's at the base of the section. So when we drill to the Marcellus, you drill through the Upper Devonian. So we've got over 200, between the vertical Wells and horizontal Wells, over 200 of our own control points plus a lot of other control points in the basin. So we've got good data, pretty good data, in terms of well logs and gas shows and that type of information in the Upper Devonian. The neat part is our first well in the seven-day test made over 5 million per day. And now, we frac the second one and we're flowing it back. And then if you look at the Utica, the Utica's 2,000, 2,500 feet deeper than the Marcellus. And very few wells in the basin go to the Utica. So by definition, the Upper Devonian is lower-risk, there's a lot more control, a lot more data than in Utica. Plus, it's somewhat of an advantage in that it's shallower. So the wells are going to be less expensive. The other thing you mentioned -- so I feel -- so from that perspective, you have to feel better about, on a risk basis, at this point in time, the Upper Devonian. But it's early, and I'm sure there's going to be a number of Utica wells drilled this year by others plus the couple of wells we may drill. The other thing, we've mapped all these plays all over the entire basin. When you look at the Upper Devonian and the section we're talking about, it does not cover the entire basin. It's more specific, we feel, based on our mapping, sort of towards the southwest part of the play is primarily where it covers. So you don't have, when you look at all the things that you need for shale play, and you look at the gas shows and you look at the logs, primarily that's where we think it's perspective. We've mapped it. We've looked at -- we've mapped gas in place. We've applied reasonable recovery factors. Those are the reserve numbers that we came out with -- or our resource potential numbers that we came out with earlier this year. So that's what it’s based on, but it does not cover a widespread area. And relative to the basin it's unique more to the southwest part of Pennsylvania -- southwest, west part of Pennsylvania. Michael Scialla - Stifel, Nicolaus & Co., Inc.: I guess just one quick follow-up on that, too, is that well you said you had, it looked like it was overpressured. Do you expect that for most of your acreage in the Upper Devonian?

Yes, for the acreage and where we feel with perspective, the answer would be yes.

Our last question comes from the line of Dan McSpirit from BMO Capital Markets.

Recognizing it's not core to the Range story, but can you revisit the horizontal Huron shale well, specifically the depth and pressure as well as how the success rate of 2.6 million a day, I believe, compares to others, either horizontal or vertical wells and what this means for an EUR? And whether or not that rate is repeatable, or is it all about finding the virgin pressure?

Well, when you look at that, the Nora area is an important part of our company, it's a stacked-pay area, a lot of hydrocarbon in place specifically in terms of the Huron shale. There's been great success with EQT on the Kentucky side. And we, Range, led the way on the Virginia side, I believe, drilled the first horizontal Huron shale in Virginia. And all of our Wells have been in and around Nora. We picked up the acreage last year. North of there are extension properties that we acquired for $130 million. And we were pretty excited about it because, one, it's very sparsely drilled, but it's in the center of a giant gas field which ranges all the way from Virginia and Kentucky on up into West Virginia. But when you look at the acreage we picked up, it was very lightly drilled. But there were penetrations that went through the Huron Shales, we knew the Huron Shale had gas in it and had good thickness and all those characteristics. But what you never know until you drill it is sort of rock quality. So we drilled our first horizontal well in there, and the wells are roughly 5,000 feet deep, plus or minus. And we got a well at 2.6 million per day. That a typical Nora well probably on average is a little under $2 million per day, maybe around $1.8 million. Our better ones, take the high-end ones, they were up in that range. But most of them on average are probably 500,000 a day or 700,000 a day less than that. Those wells look like they'll make on the order of Bcf cost somewhere around 1.2 million to drill and complete. And so what's exciting is we have good control. We got good thickness. The rock quality up there looks a little better. It's more fractured, maybe more like Big Sandy is in Kentucky, the difference being that we're at virgin pressure because it's never been developed, where Big Sandy was developed back in 1920s, 30s, 40s and up until present day. So you have -- pressures there are a lot lower. So it's an important well and, like I said, it could add resource potential 400 to 500 Bcf net to us. Again, we're only a 4.4 Tcf company at year end. So that's a big number. And I think those numbers will grow with time.

And then turning to the Marcellus for two more questions here. If by the end of this year, 46% of your acreage will be held by production, what does that mean? What is that number at year end next year?

Well, currently we're at about 46%. I'd say, around the middle of next year, the number will, by the end of next year, will approach 60%. And literally, within a year or two after that, we'll be up into the 80% range. Remembering the number's probably never going to be at 100%, because it's a great play, and you're going to be picking up leases and renewing and trading. So we're well on our way to drilling and holding what we believe, like John said, will be 700,000 acres. And the important part again with the acres is what's perspective for us in the Marcellus also captures the upside and resource potential that we laid out for the Upper Devonian. We'll capture all of that and then whatever there is in the Utica blow. So far, we are encouraged there's gas down there for sure. And the other thing with the Upper Devonian, before I leave it -- I'm trying to give you a little color. The neat part about our position in the Marcellus -- not only do we have great acreage position, a large position with high quality, a big part of it is in the wet gas area, which clearly helps with today's economics. The Upper Devonian is going to be like the Marcellus, The wet dry line will be like the Marcellus. So where our acreage is wet in the Marcellus, most likely the Upper Devonian will be like that. So you get the liquids uplift as well. But let me put that in perspective, if you look at -- and this is out on Slide 19, you'll see it in the book, we're seeing the resource potential just in the Southwest and the Marcellus, 15 to 23 Tcfe. If you break that down, that's 13.5 to 20 Tcf of gas and 307 to 463 million barrels of liquids. So that's really like a giant oil field right there. And then you can add the Upper Devonian and liquids to that on top of it.

I understand, and one last one, if I could. Forgive me if this question has already been answered. Given the gross proceeds from the Barnett shale asset divestiture, where does this leave us with respect to a JV? How does that rank now? Or is that no longer relevant? That is, a JV on the Marcellus Shale acreage?

Well, I think the Barnett sale tells you a couple things. One, we felt like selling the Barnett was much more accretive than doing a JV in the Marcellus. And I think that's pretty easy math, and I think it's pretty easy to understand that. Now what we try to do is connect the dots and show you that at least we believe that we can be cash-flow positive by 2013. And I didn't mention the word JV in any of those discussions. So again, what the Barnett sale does, it gives us a rock-solid balance sheet, irrespective of where gas prices ago, whether they go to $0.50 or $10. And it allows us to really ramp forward the Marcellus at a much faster pace than we went last year. And we're going to go from $200 million a day to $400 million to $600 million, that's about as the fastest ramp-up as one could imagine in these plays on a relative basis. So it allows us to ramp up, but really what it does, what it also does, is allows us, at least we believe, if we stay disciplined, to be cash-flow positive by 2013 and retain 100% of the resource potential from the Marcellus, the Upper Devonian and the Utica for Range's existing shareholders. I'm in the business, I'm an existing shareholder. I still think I'm the largest individual shareholder. Where I'm really focused and anchored is I want my existing shareholders to get as much of the resource potential you possibly can out of this Marcellus. And I'm telling you, it's a world-class field. We've got the tiger by the tail. The good news is I think we've got a plan, and I think hopefully that we connected the dots. And therefore, you're going to see how we we're going to get there. And if we are, we're going to -- like Jeff has said, we got a feel here that we think ultimately we'll get to 2 Bcf or 3 Bcf a day net to our interest. That will be huge, and our shareholders are going to make a whole bunch of dough from that, including yours truly, including all of our employees that have a lot of stock as well. So it's really trying to retain as much of the upside as possible for our existing shareholders. Does that mean we'll never do a JV? I'm never going to say that, because if somebody comes in and offers us a number that blows us away, we'll do it if it's in our shareholders' best interest. And again, it's really simple at Range. Double-digit per-share growth on a debt-adjusted basis at low cost. And what's going to drive that is putting our money in the highest-rate-of-return project that on a risk-adjusted basis we feel like has the highest rates of return. We're not interested -- a lot of other companies would have kept the Barnett. Would've put just enough money in to keep it flat and then taken their money and gone to do something else with it. I'm not saying that's a bad strategy, but I think if you really focus on per-share growth, what you ought to be doing is taking your dough and putting it in the highest-rate-of-return projects. And what drove us to the Barnett sale is, is that the Marcellus returns for each drilling locations are 3x to 4x better than what's in the Barnett. To us it was just easy math. And on the other side of it, it does put more pressure on our technical and operating teams. They need to be right. They have to perform. But I got to tell you, at $0.71, $0.59 drill bit mining cost and better than $1 the next couple of years, I got to tell you I think that's world-class performance. And because we've got a world-class team in the world and we got really good rock. So that's what gave us the confidence along with the Mississippian well, the St. Louis well, the Huron well. It's those results that gave us the confidence to go ahead and sell 20% of our production. 12%, 25% of our production, that's pretty -- not a lot of companies do that. It's a very bold step, a very bold message to our shareholders that we really, really believe what we're doing here and we're absolutely convinced that this is the right thing to do and we're going to get there. There's no doubt in our mind we're going to get there. Now, what are gas prices going to be? I don't know. But again, the good thing is if gas prices really tank, I'm really glad we sold the Barnett. If gas prices go up, I'll be a little bit -- that we probably left a little money on the table. But where it gets us in terms of being able to ramp up and hold that 700,000 acres. There's just no comparison that it was the right thing to do.

Ladies and gentlemen, we have run out of time for questions. I'd like to hand the call back over to management for closing comments.

Well, on behalf of -- this is John Pinkerton. On behalf of the Range management team, Board of Directors and employees, we really appreciate you all being on the call today. We had, at least in our view, a very, very solid and value-creating 2010. We are pleased as punch to have the Barnett sale inked up where we could connect the dots for everybody, because I know I get that question -- that's the question I get from all the shareholders, and I really appreciate that. Hopefully, we've done a good job of connecting the dots. I know there were a number of callers that didn't get their questions answered, or if we need to connect a few more dots for you, feel free to call any of us, including Rodney and his top-notch IR team, and we'll try to do that. At the end of the day, regardless how you feel about the Barnett sale, we think it does two things. One, it allows us to ramp up development in the Marcellus in a big way. And two, it allows us to be cash-flow positive by 2013, which is just right down the road here. And we think those are two huge catalysts for our company, and really exciting catalysts. And then, obviously, to the extent that the other plays that Jeff talked about continue to fruition and some of the other things we're working on, I think the future for Range and shareholders is really bright, and we look forward to a terrific 2011. We are off to a terrific start, and we'll look forward to giving you another update in April when we have the first quarter results. So with that, we'll sign off. 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.