Range Resources Corporation (RRC) Q3 2010 Earnings Report, Transcript and Summary

Greetings and welcome to the Range Resources Third Quarter 2010 Earnings Conference Call. [Operator Instructions] It is now my pleasure to introduce your host, Mr. Rodney Waller, Senior Vice President for Range Resources. Thank you, Mr. Waller, you may begin.

Thank you, operator. Good afternoon, and welcome. Range Resources reported its results for the third quarter 2010 with record production breaking the 500 million a day mark for the first time. Range reported increase production in our liquid-rich areas of the Marcellus, Midcontinent and the Permian Basin and announced the decision to market our Barnett Shale properties. I know that these items, along with our operations update last week, will generate a number of questions today. On the call with me are John Pinkerton, our Chairman and Chief Executive Officer; Jeff Ventura, our President and Chief Operating Officer; and Roger Manny, our Executive Vice President and Chief Financial Officer. Before turning the call over to John, I would like to cover a few administrative items. First, we did file our 10-Q with the SEC this morning. It's available now 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 non-GAAP measures of cash flow, EBITDAX, cash margins and the reconciliation of our non-GAAP earnings or reported earnings that are discussed on the call today. We've also added tables, which will guide you in forecasting our future realized prices for natural gas, crude oil and natural gas liquids. Detailed information of our current hedge position by quarter is also included on the website. Second, we'll be participating in several conferences and road shows in the coming weeks. Please check our website for a complete listing for the next several months. John will be speaking at the DUG East conference in Pittsburgh on November 4. Range will be attending the Morningstar Stock Forum in Chicago next week, the Boenning & Scattergood Energy Conference in New York on November 9, the Pritchard Capital Conference in Boston on November 10; the Bank of America Energy Conference in Miami on November 12; the UBS Energy Conference in New York on November 17; the Bank of America Credit Conference in New York on November 17; and the JP Morgan Conference in Boston on November 30. We hope we can see you at one of these conferences. Now let me turn it over to John.

Thanks, Rodney. Before Roger reviews the third quarter financial results, I'd like to take just a few minutes to review the key accomplishments in the third quarter. On a year-over-year basis, third quarter production rose 15% beating the high end of our guidance. This marks the 31st consecutive quarter of sequential production growth. In addition we reached, as Rodney mentioned, the 500 million per day production milestone for the first time in our company's history. Kudos goes out to our operating teams on that. Our financial results reflect the fact that the 15% increase in production was more than offset by a 22% decrease in realized prices. We are pleased on the cost side. As on a per unit production basis, three out of the four major cost categories were lower than the prior year period. D&A expense per mcfe came in at 18% lower than last year, which is really significant. Interest expense per unit saw a 4% decrease, direct operating costs per mcfe were 3% lower than the prior period. On the higher side of the G&A costs, we saw an 8% increase over last year. We're still building out our Marcellus team. And we'll see the impact of that for a couple more quarters or so in G&A, before we begin to see a decline or in unit production basis like the other metrics. For the first nine months of the year, we have spent $780 million or 65% of our capital budget. For the year, we certainly don't want to spend more than our budget. And if anything, we may end up spending a few dollars less than budgeted. With regard to our Marcellus Shale play, we continue to make significant headway in the quarter as we continue to drill fantastic wells, filling our acreage position, test the other shale formations and continue to build out the infrastructure. I'm particularly pleased with the Marcellus acreage trade we've accomplished so far this year. In the third quarter, we did our largest trade to date. The acreage trades are difficult and very time-consuming to complete but are extremely beneficial to help to block out our acreage positions, which in turn significantly increase our capital efficiency. The most encouraging aspect of the quarter is the 136% increase in our NGL volumes and the drilling results in our oil and liquid-rich plays in the Midcontinent and Permian areas. Our operating teams did an excellent job quickly shifting capital and getting these projects online. All in all, third quarter was a very solid one. We executed on the production side, continued to reduce cost, successfully shifted capital to higher-margin liquid-rich plays and maintained a strong balance sheet. With that, I'll turn the call over to Roger to review the financial results.

Thank you, John. Financially, third quarter 2010 saw significant progress in capital efficiency, balance sheet strength and incremental cash flow growth versus the second quarter of 2010. Third quarter natural gas, NGL and oil sales, including all cash-settled derivatives totaled $245 million, down 4% from last year due to lower prices, but up from last quarter on higher production. This figure also includes $15.7 million from the early settlement of hedged 2011 oil production that was subsequently re-hedged. Year-to-date natural gas, NGL and oil revenue, including all cash-settled derivatives, totaled $696 million. Cash flow for the third quarter was $141 million, 18% below last year and 9% higher than the second quarter this year. Cash flow per share for the quarter was $0.88, matching the analysts' consensus estimate, year-to-date cash flow over $418 million. EBITDAX for the third quarter was $173 million, 13% lower than the third quarter of '09 but 11% higher than last quarter. EBITDAX for the year-to-date period was $505 million. Cash margins for the quarter was $3 per mcfe. That's 28% lower than last year solely due to lower gas prices. With the Ohio asset sale behind us, there are only a few unusual revenue and expense items to highlight in the third quarter results. Our non-cash derivative mark-to-market losses totaled $15.9 million. And our deferred compensation plan actually had a $5.3 million non-cash income posting due to declining market values of assets held in the plan. An income statement category appearing for the first time was a $5.4 million loss on early extinguishment of debt. This amount represents financing costs from redeeming our old 7 3/8% notes slated to mature in 2013 and replacing them with new 6 3/4% notes maturing in 2020. Our nearest long-term bond maturity is now not until 2015. The $5.4 million expense consists of $2.5 million of call premium paid to redeem the old notes and a write-off of $2.9 million of non-cash deferred financing costs also related to the old notes. This $5.4 million expense will be made up over time, as the new long-term notes carry a considerably lower interest rate than the note they replaced. Third quarter earnings calculated using analysts' consensus methodology was $18.9 million or $0.12 per fully diluted share. That's $0.02 higher than the analysts' consensus estimate of $0.10. And as Rodney and I always mention, the Range Resources website contains a full reconciliation of these non-GAAP measures including cash flow, EBITDAX, cash margins and analysts' earnings. The third quarter saw a break in our one-year string of consecutive quarterly reductions in unit direct operating expense. Third quarter cash direct operating expense, which excludes non-cash stock based compensation but includes workovers was $0.73 per mcfe. That's down $0.03 from third quarter of last year but $0.05 higher than the $0.68 seen last quarter. And while the overall operating cost reduction trend remains, the third quarter saw an uptick in well service costs and maintenance expense for well locations, roads and supplies. Now, some of this increase is seasonal, as the summer is the best time to perform field maintenance in Appalachia. Now we believe that our cash direct operating cost still has room to decline. And we anticipate the fourth quarter direct operating cost, excluding workovers, will be around $0.68 to $0.69 per mcfe, before declining further into the low $0.60 range next year. Production taxes for the third quarter remained flat to last year and also flat with the first three quarters of 2010. These came in at $0.19 per mcfe. General and administrative expense, adjusted for non-cash stock compensation, came in at $0.52 for the third quarter. That's up $0.06 from last year. Unit cost increased in G&A is attributable to community relations and education expense occurring in the Marcellus Shale division and to a lesser extent, inventory adjustments in our professional fees. For the fourth quarter of 2010, we anticipate G&A expense to be flat in the low $0.60 range per mcfe range. Interest expense for the third quarter was $0.73 per mcfe. That's down $0.03 from last year. In September, we deployed the remaining idle cash proceeds in our 1031 like exchange accounts to reduce the bank debt and utilized in the 1031 account to reinvest a portion of our Ohio asset sale proceeds, and that allowed us to help preserve our $322 million NOL carryforward. Interest expense will increase slightly in the fourth quarter, and that reflects the refinancing during the third quarter of $300 million floating-rate short-term bank debt into long-term fixed-rate notes at a higher interest rate. Exploration expense for the third quarter of 2010, excluding non-cash stock comp totaled $14.2 million, or $4.3 million higher than last year due to higher delay rentals, rental expense and seismic costs. The fourth quarter is anticipated to be a heavy quarter for seismic expense, as we push to complete Appalachian seismic activity before winter sets in. The total seismic expenditures are tracking our 2010 budget. Exploration expense for the fourth quarter is anticipated to be $21 million to $23 million, depending on the timing of this seismic spending. In terms of dollar amount each quarter, depletion, depreciation and amortization expense runs almost 3x the next largest expense category. But because DD&A is a non-cash expense, even though it's so significant, it's often relegated to second-tier importance. However, in a capital-intensive industries such as ours, the DD&A rate provides a key ongoing measure of our capital productivity. And our DD&A rate for the third quarter is $1.98 per mcfe. That's down from $2.42 in mcfe last year. And the last time our DD&A rate was below $2 was back in 2007. We had a rapid decline in the DD&A rate, signals a channeling of our capital spending towards the highest-returning projects in our drilling inventory and the high grading of our asset base through selective property divestitures. There was just under $6 billion in depletable assets flowing through this measure. A $0.44 reduction in DD&A within a year's time, unaided by write-downs represents a big change. The fourth quarter DD&A rate is expected to decline further, and we anticipate additional reductions add in 2011. We account for unproved acreage explorations impairment in accordance with our successful efforts accounting method. Under this method, costs are not included in our DD&A rate. Now we recorded impairment expense of $20.5 million in the third quarter. That's $3.5 million below last year's number. We expect this recurring non-cash expense item will again range between $20 million and $22 million in the fourth quarter, as we continue to adjust our carrying values on the acreage to reflect our current drilling plans and market conditions. As we experienced a GAAP basis loss before taxes, Range had no current income tax liability for the third quarter. The resulting $5.9 million tax benefit is deferred. As I mentioned earlier, we continue to hold a $322 million net operating loss carryforward to help us to shield future taxable income, including potential gains from asset sales. Our effective tax rate going into the fourth quarter is anticipated to be 39%. Range improved its hedge position during the third quarter of 2010, with 76% of our remaining 2010 gas production hedged, with collars at a floor price of $5.56 in Mmbtu and a cap of $7.20. We have increased our 2011 hedge position to 84% of anticipated gas production, hedged with collars at a floor price of $5.56 and a ceiling price of $6.48. We have also added to our 2012 hedge position since quarter end with 120 million in Mmbtus per day of natural gas, now hedged with collars at $5.55 and $6.25. Our oil hedges consist of 1,000 barrels per day in 2010 hedges in collars of $75 by $93.75, 5,500 barrels per day in 2011 covered by a ceiling at $80, and 2,000 barrels per day hedged in 2012 with collars set at $70 by $80 and 470 barrels a day now hedged by a ceiling of $85. We ended the third quarter with several key balance sheet strengthening initiatives completed. First, we issued $500 million of 10-year senior sub notes at par with a fixed interest rate of 6 3/4%. That's our second lowest coupon ever. The proceeds were used to redeem $200 million of our 7 3/8% notes that were set to mature in 2013. Thus, the proceeds were used to refinance a portion of our floating-rate bank debt. And second, our 26-member bank group unanimously reaffirmed our $1.5 billion credit facility borrowing base and lent a $0.25 billion revolving commitment amount. This is despite significant reductions in the price forecast used by these banks to value their clients' oil and gas reserves. These credit actions provide a range of over $1 billion in committed liquidity, while strengthening the maturity profile of our long-term debt and reducing our exposure to interest rate increases. The debt-to-capitalization ratio at quarter end stood at 41.8%, exactly the same book leverage ratio we had on January 1 the start of this year. As John mentioned, and I'll talk about more of it later, Range remains committed to maintaining a strong balance sheet, with 2011 capital spending at or below some cash flow and asset sale proceeds. Summarizing the quarter, we saw a steady production growth and increasing cash flow over the second quarter and big gains in capital productivity as evidenced by the decline in DD&A rate. Our balance sheet was materially strengthened through opportunistic refinancing and the 2013 notes after 2020 and from this in the outstanding balance of our credit facility, which gives us over $1 billion in committed available liquidity. We also strengthened our already strong 2011 natural gas hedge position and doubled the natural gas we have hedged for 2012. John, back to you.

Thanks, Roger. I'll now turn the call over to Jeff to review our operations.

Thanks, John. I'll begin with the Marcellus update. Our exit rate for the third quarter of 2010 in the Marcellus was 191 million cubic feet equivalent per day net, with approximately 71% of the production being natural gas and 29% NGLs and condensate. At the end of the third quarter, approximately 34 million cubic feet equivalent per day of net production was shut in and waiting on gathering and compression facilities currently under construction. By year end, we expect all of these production will be online. We announced a series of great wells in the liquid-rich portion of the Marcellus play last week in our operations release. These 18 new wells look like they will exceed our five Bcfe average reserve estimate for the Southwest part of the play. The five Bcfe reserve estimate is comprised of 3.6 Bcf of gas and 239,000 barrels of liquids. At a $4 flat gas price for ever a $60 per oil price flat for ever, the rate of return from Marcellus well and the wet gas area is 60%. Fully loading this case with 100% of our current corporate G&A rate and with all land costs, the rate of return is still 47%. Running the base case with current script pricing versus the $4 flat gas and $60 flat oil, the rate of return goes from 60% up to 75% and looking at the fully loaded case and assuming script pricing, the rate of return goes from 70% up to 60%. Given a low gas price in our development plan to hold acreage, our plan is to drill fewer wells per pad with moderate lateral lengths and frac stages. Doing this will keep our cost to drilling complete at approximately 4 million in the Southwest, given the economics I just stated, and will keep our rate of return at 60%. We have tested longer laterals of the 5,000 feet and up to 17 frac stages. Others have experimented with even longer laterals. We'll continue to watch the long-term production data from these tests, which will help to determine a way to optimally drill and complete these wells from an economic point of view. The longer lateral wells are significantly more expensive and have higher mechanical risks. In the meantime, we know that in a multi-well development mode, we can drill and complete for approximately $4 million per well, which generates a 60% rate of return. We know that these economics are excellent. And we know by doing so, the wells are less expensive, and we will conserve capital. Like most others in this low gas price environment, we'll be capital-constrained. So for the same dollar amount, keeping our well costs down will allow us to drill more wells. More drilling, coupled with fewer wells per pad, will hold more acreage. There are other advantages as well. Drilling four wells per pad, for example, versus eight wells per pad will allow us to hook up wells faster. In practice, we drill all of the wells on a pad and frac them altogether. Logistically, it's also easier. For example, getting enough water at one time to frac four wells is easier than doing so for eight wells. We announced in our operations release last week that we recently completed the trade of Marcellus Shale acreage. We acquired 42,000 net acres in Washington County, Pennsylvania and transferred 55,000 net acres, of which 47,000 net acres were in West Virginia and 8,000 net acres were in Sullivan and Bradford counties in Pennsylvania. This trade worked well for both sides of the deal. From Range's perspective, we're not active in West Virginia. And the acreage positions in Sullivan and Bradford counties are scattered. The exact opposite is true from the perspective of the company we traded with. It helped them consolidate and block out in their core areas. For Range, the acreage we acquired in Washington County in essence filled in a lot of the missing pieces of the puzzle, or put another way, filled in a lot of the remaining gaps on our position there. Range has a very significant position in Washington County. We now have approximately 280,000 net acres there. This is an area where we have the most well performance, best gathering system and the most consolidated acreage position. In essence, all of this acreage is de-risked. Operationally, it's much more efficient for us to drill, complete and gather here. In addition to making Range's acreage position more operationally efficient with the trade, the term left on the leases we acquired is longer than the leases we traded. However, we acquired fewer acres than we traded. For Range, the benefits clearly outweighs the net loss of acreage. This is the fifth trade like this we've done in pursuing our long-term strategy of acreage consolidation in our key areas. Consolidating and blocking up our acreage makes our position more efficient in many ways. When we drill in a blocked up area, that one well holds more acreage than if it's not blocked up. It makes our gathering more efficient, and the wells are more concentrated and not as far apart, which makes our gathering cost less. The more blocked up position minimizes the cost to rig moves. It's also more efficient and a single water impoundment can service more pads than when the acreage is more consolidated. It's also easier on the land development and other groups in many ways, and it also benefits the community where we operate. And it allows us to better optimize our infrastructure to limit the impact on the surface. As a result of these trades, we now have fewer acres. But what we have is clearly higher quality, blocked, more efficient and increases our drillable acreage position in a number of available drill sites in the wet gas area of Southwest Pennsylvania. Our total number of acres in the fairway is now about 850,000 net acres. Of this, approximately 40% is held by production. About 600,000 of the 850,000 net acres are in the Southwest portion of the play, and the remaining 250,000 acres are in the Northeast. Going forward, In addition to drilling the whole acreage, we'll continue to work on acreage trades so we can continue to consolidate our acreage position. We also have and will in the future let some of our non-strategic and isolated acreage expire. These are smaller, scattered tracks that are more on the edges of the fairway or small positions in the dry gas area, which we cannot efficiently develop. Although we will have fewer acres, we believe that by concentrating in the highest productive areas, we will still have the same upside and make it easier to capture. Last week in our operations release, we disclosed the result of our first upper Devonian Shale test. The average seven-day test rate for this well was 5.1 million cubic feet equivalent per day. This is a very significant test for us. It shows that the interval that looked productive on logs and then had gas shows is indeed productive. Also for our very first try out-of-the-box in this horizon, the rate is pretty impressive. It's doubtful that on our first try, we landed the lateral with the optimum location. I'm also pretty confident that we didn't optimally stimulate it, so there's likely significant upside. It's encouraging that the reservoir pressure that we encountered is about the same as in Marcellus in this area, which is over-pressured. If thermal maturity is also similar to the Marcellus and should roughly track it in regard to the wet and dry portions. The gas in plays for the bulk or where we believe the play is most prospective ranges from 60 to 100 Bcf per square mile. Importantly, it directly overlies a lot of our Marcellus acreage in the Southwest, where the Marcellus gas in place averages 75 to 125 Bcf per square mile. Since it stacks together on our acreage, the aggregate gas in place in the Southwest is estimated to be 135 to 225 Bcf per square mile. It literally sits right on top of the Marcellus. We're still holding our Utica test results confidential for now. Range drilled the first horizontal Utica well in the Appalachian Basin. CNX is still holding [indiscernible] the well, and others are currently drilling. We feel that a lot of our acreage is prospective for the Utica Shale as well. The build-out of the infrastructure continues on schedule. Details were outlined in the operations report last week and are listed on our website. First production in Lycoming County is expected at year end. I'll now move to the Midcontinent and talk about some of our plays there. In our release last week, we announced a couple of outstanding Woodford wells that are in the Ardmore Basin in Marshall County, Oklahoma. The first well tested at an average rate of 801 barrels of oil and NGLs per day and plus 2.3 million cubic feet of gas per day or 1,176 barrels of oil equivalent per day. And the second well tested 1,064 barrels of oil and NGLs per day and 2.7 million cubic feet of gas per day or 1,514 barrels of oil equivalent per day. We have 19,200 gross acres and about 7,800 net acres in this play. About 3/4 of this acreage is currently held by production. There are 221 well locations on this acreage, of which Range would operate about half of them. We have drilled and completed 12 operated wells to date. And our more recent wells look like they will recover on a per well basis about four Bcf, 35,000 barrels of oil and about 625,000 barrels of NGLs. That is about eight Bcfe or 1.3 million barrels of oil equivalent per well depending on how you look at it. The wells have a TVD of about 7,000 feet and the current laterals are about 5,000 feet. The cost of drilling complete is about $4 million per well. At the current script pricing, the rate of return is 98%. The next play in our Midcontinent division that I want to discuss is our horizontal Mississippian play. In Northern Oklahoma, Range has announced another strong horizontal Mississippian well that tested at a rate 410,000 barrels of oil equivalent per day. We now have five wells in the area. Currently we have approximately 15,000 net acres in this play. This is a horizontal redevelopment of an old field that was drilled vertically. We have identified 108 wells to drill here. About half of our acreage in this play is held by production. The true vertical depth of the Mississippian section here is about 5,000 feet and the laterals are about 2,200 feet. The horizontal wells in the development mode will cost about $2.1 million to drill and complete. Reserves are estimated to be about 300,000 barrels per well. This is comprised of 536 million cubic feet of gas, 80,000 barrels of oil and 128,000 barrels of NGLs. At current script pricing, this results in an 80% rate of return. In addition, Range controls about 80,000 gross for 42,000 net legacy acres that are all held by production in the Cana Shale play in the Anadarko Basin. Roughly 2/3 of the net acreage is in Blaine and Canadian counties and roughly 1/3 is in the very southern part of Major County. The Blaine and Canadian County acreage is either in the heart of the play or directly on trend with industry activity. The southern part of Major County is where the Cana is in the oil window and shallower. In souther Major County, the true vertical depth of the Cana well would be about 85,000 feet versus about 13,000 feet in Blaine and Canadian counties. Recent Devon completions have reported sustained 30-day rates from seven million to eight million cubic feet per day and are located about three to four miles southeast of Range's holdings. Additional activity by Continental Resources has been reported at 5.1 million cubic feet equivalent per day and lies on trend within 10 to 12 miles of Range's legacy acreage. Numerous well permits have been issued adjacent to a large range block in southern and central Blaine County, which lies between both areas of activity. In the Southwestern division, we announced three new wells in the Barnett Shale and Denton County that were brought online with a gross combined rate of 15 million cubic feet equivalent per day. That's comprised of 8.1 million cubic feet of gas per day and 1,156 barrels of NGLs and oil. In addition, we've just recently completed five new wells at Tarrant County and are in the process of completing three more wells. In aggregate, we expect these wells to come online at rates of 32 million per day gross or 22.5 million per day net. We also continued our successful deepening of wells in Conger Field coupled with the successful Wolfcamp recompletion. These four wells averaged 561 barrels of oil equivalent per day each. We have been mapping the horizontal oil potential work properties in the Permian basin. To date, we believe we have about 155 gross and 118 net locations combined between our Conger Field and Powell Ranch properties in West Texas and Loving properties in Southeast New Mexico. Our first well will be in Powell Ranch and should spud early next year. The target formation at Conger and Powell Ranch is primarily the Wolfcamp Shale and the target formation in New Mexico is the Avalon Shale in Bone Spring. All of our acreage in these three field is held by production. In the Nora area, which is all dry gas and all either held by production or we own the minerals, we have significantly slowed down our drilling. For example, our CBM drilling this year is about half of our 2009 program, which was significantly less than the prior year. Our high graded efforts are focused on re-completions, optimizing the compression and gathering in the field and drilling in our most prospective areas. Back to you, John.

Thanks, Jeff. Good update. Looking to the remainder of 2010, we see continued strong operating results. For the fourth quarter, we're looking for production average roughly 535 million equivalents per day, representing a 17% increase year-over-year. Fourth quarter production will reflect the sale of the Ohio properties in March of this year. So the 17% fourth quarter production growth estimate equates to 23% after adjusting for property sales. As Roger mentioned, we expect fourth quarter unit cost to continue to decline. Importantly, we have 76% of our fourth quarter natural gas production hedged at an average floor of $5.56 and a cap of $7.20. Also we're confident that our all-in 2010 finding and development costs will come in at or below $1 per mcfe. This will help us to continue to drive down our DD&A rate in the fourth quarter and into 2011 as well. Let's now shift gears a bit and discuss our announcement that we have decided to market our Barnett Shale properties. Over the last three months, we've conducted a full review of all of our properties, including both producing and nonproducing properties. After considering all the alternatives, we concluded that selling the Barnett Shale properties best fits our strategy of growing production reserves on a per share basis at low cost. While we like our Barnett Shale properties, and our team has done a great job at developing them, we are in an enviable position of having a very deep inventory of high-quality projects. As a result, we believe taking the proceeds from the sale of the Barnett and redeploying that sales proceeds into our other projects over the next several years will accelerate the value generation process. Because of our $322 million of NOLs and capitalized IDCs, we don't expect any cash taxes on the sale. Other than being much larger, the Barnett Shale in many ways is similar to Ohio sale we completed earlier this year. In the Ohio sale, we sold properties producing approximately 25 million a day for $325 million or $13,000 per flowing Mmcfe per day. As a side note, when we announced the Ohio sale, the general consensus of the investment community is that we would received sales proceeds of $225 million to $250 million for the Ohio properties. The actual sales price we received was $325 million or 37% higher than the midpoint of the investment community consensus. It took us only three months to replace the 25 million that we sold in the Ohio sale, and we did it at price of $3,000 per flowing mcfe or roughly a third of what we sold the Ohio properties for. With the Barnett sale, our objective is the same. We expect to replace the 120 million to 130 million per day we lose in the sale by no later than year end 2011, which is at a faster replacement rate than we accomplished with the Ohio sale. In addition, we expect to replace production at roughly a third of the cost like the Ohio sale. And in addition to being able to replace the sole production reserves at a fast-pace, sales of this type also improved our ongoing cost structure. It's one of the reasons why we've seen our direct operating costs and DD&A rate decline sharply. With the Barnett sale, we will see a further drop in our cost structure. Obviously, we'll only sell the Barnett properties if we receive what we believe is a fair price. After discussing the sale with several outside advisors, combined with the recent inquiries we have already received from several potential buyers, we are confident that there is a broad market for the Barnett properties. Just this week, a sizable Barnett sale was announced, which shall validate the market value for our Barnett properties. In addition, over 80% of our Barnett properties are located in the core of the play and more than 80% of drilling locations are also located in the core of the play. So we believe it's a very high quality set of Barnett properties that will command a very solid price. Now assuming we receive a price we are satisfied with, we expect to close the sale sometime in the first quarter of 2011. While not a primary reason for the sale, given the size of the Barnett Shale, it should provide substantial clarity as to how we're going to fund our future growth over the next several years. In particular, while looking to 2011 and beyond, we believe we'll be very well-positioned. First assuming it sell at a good price, we'll have a rock-solid balance sheet. Second, we'll have substantial cash and liquidity to capture the opportunities we see before us. Third, our natural gas hedge position will protect us from low natural gas prices. And fourth, we can methodically develop our liquid-rich plays in the Marcellus as well as in the Midcontinent and Permian areas. To provide perspective, our Barnett properties consist of 53,000 net acres. As Jeff mentioned, in our Cana acreage, which is all held by production, we have 42,000 net acreage, almost the same as our Barnett acreage. So we do have a lot of opportunities in the Permian and in the Midcontinent that we're very excited about. I'll now take a moment to discuss the regulatory environment in Marcellus Shale play. The regulatory environment has improved in many ways over the past two years. First, the drilling permit process in Pennsylvania has gotten much, much more predictable. And we are regularly receiving permits within 30 days or less. Second, the water access and flowback process is much more predictable, especially given that Range is recycling 100% of its flow back water the southwest portion of the play. The Pennsylvania DEP is very supportive of our recycling program. It's not only a better environmental solution, but it saves Range money as well. We also received all the necessary air permits for all the compressor size that are currently under construction. With regards to a severance tax in Pennsylvania, the state has yet to enact the tax. During the past several years, we and the rest of the industry have worked very hard to educate and work with the Pennsylvania legislature about the issues surrounding the severance tax, encouraging them to take a holistic approach whereby any severance tax would come with balance of regulatory modernization. We believe that both candidates running for the Pennsylvania governorship will take a much more commercial and diplomatic approach towards the legislature versus the current administration. With the election less than a week away, we believe the chances of a holistic approach will increase significantly once the new administration takes office, irrespective of which candidate wins the governorship. Turning to the hedging front. Just to reiterate that we are well protected in terms of natural gas prices. For the fourth quarter, we're 76% of our anticipated natural gas productions hedged at a of floor $5.56. Importantly when you look at 2011, we have over 80% of our production hedged at a floor of $5.57. And this year, we have a nice hedge position already in 2012 as well. Lastly to expand on a point mentioned in our news release, our infrastructure build-out in the Marcellus Shale is sadly on schedule. While there is always some delay for surface facilities build-out at each pass side in and the Southwest portion of the play, we are at the point where pipeline and processing pass is no longer an issue. Our acreage trades, as Jeff mentioned, have really helped us out to get us into that position. In the Northeast, the first phase of the Lycoming County pipeline system is nearing completion. It will be exciting to see how our initial wells perform once we get them on production in late December or early January. As you recall, our first two Lycoming wells had some of the best test rates of all the wells we drilled in the Marcellus Shale play to date. Most wells had seven-day average test rates of over 13 million a day each. Once the Lycoming County production goes online, we'll have two separate core areas from which to accelerate our Marcellus production and reserve growth. This will provide us additional flexibility and will help us diversify our production base. Because our infrastructure build-out is progressing so well, coupled with excellent well results, there's little doubt that we'll achieve the 2010 Marcellus exit rate goal of 200 million to 250 million a day net. More importantly, it sets the stage for doubling production again to 400 million a day plus an exit rate for 2011. So that's very exciting news. With that, operator, why don't we turn the call over to questions?

[Operator Instructions] Our first question is from the line of Rehan Rashid with FBR Capital Markets. Rehan Rashid - FBR Capital Markets & Co.: Could you walk us through the direction of operating costs or unit operating cost as you've kind of rolled out the next four, six quarters' worth of production growth from the Marcellus?

Let me start at kind of high level, and I'll move down a bit. And Jeff and Roger, please chime in. There's really two reasons why you've seen a material drop in our operating costs over the last year or so. First the production we're adding, in particular the Marcellus, is a lot lower than the average production rate of our current properties. Currently in the Marcellus, LOE rate's somewhere in the $0.30 to $0.35 range. The other thing is the sale of our higher cost properties. So again as you take that money and recycle it out of the higher cost properties and move it into the lower cost properties, you get kind of a double whammy approach of LOE decrease. And as Roger mentioned, we had third quarter is $0.73, which is $0.05 higher than we had hoped for some reasons that Roger mentioned. But we should be back under $0.70 and the upper $0.60 range in the fourth quarter, which, especially in Appalachia, tends to be a little higher quarter because of all the road maintenance and all the weather issues you get in the winter time up there. But when you look at our 2011, we're going to be continuing to decrease it. Our goal is to be in the low $0.60 range hopefully for 2011, trending hopefully below that towards the end of the year. And then again as we move into 2012, we ought to see continued decrease of that as well. And as I mentioned, the Marcellus is in the $0.30 to $0.35 range. So as more and more of our production becomes Marcellus, you'll see that trend down. And again the key here is when you connect all the dots at the end of 2011 or end of this year, we'll be at 200 million a day plus, which is a double. Then the next year, 2011, we'll be 400 million a day plus. So you'll see that a big piece of our production will be Marcellus, so that will help drive down. The other thing is that as we build out the Marcellus, I think our guys will get better, and the operating process will get more refined. It will be more repetitive, and they'll just get better at it. They've done that in every field that we've ever operated. So we haven't built-in that into the any of the numbers. But it's going to be a process. It's not going to be an event, but I think you'll continue to see it. In addition to the LOEs, I think Roger mentioned one of the really big, big drivers, in my view, in this business is going to be watching all the respective companies' DD&A rates. I've heard a lot of talk about that we're going to be in a low gas pricing environment for a few years here. And I don't know whether, I'm not going to say the right or wrong. But I think one of the real keys is to be able to be consistently profitable, one of the biggest things to get there is going to be the DD&A rate. And if you have a really high DD&A rate, it's going to be very hard to be consistently profitable in a low-price environment. So one of the things that we're really focused on and has a lot to do with where we spend our money and also assets that we sell and whatnot is really forcing that DD&A rate down. I'm taking a very disciplined approach towards that and a very methodical approach towards that end, to be able to reduce the $0.40 already this year, I think you'll see a rapid decline as we move forward, especially when you think about a $1 F&D rate for last year and this year. And hopefully for 2011 as well, we'll be able to hopefully really force that DD&A rate down, which will allow us to be consistently profitable in a low-price environment, which will obviously add to shareholders' equity and increase assets. So it's all part of our strategy at Range. Rehan Rashid - FBR Capital Markets & Co.: As you think about capital allocation for next year, how much, and do we have to direct towards, let's just say, drilling in the Northeast Pennsylvania for holding acreage, which is of course dry gas versus being able to disproportionately allocate capital towards the more liquids-rich Southwest and Pennsylvania area.

The bulk of our drilling is still in the liquids-rich wet area. But I think we'll be adding -- now at Northeast will be coming online. It would be interesting to watch the performance of the wells and to change that from acreage value into PDP value. But we'll still directing the bulk of our activity found in the Woodford. Rehan Rashid - FBR Capital Markets & Co.: So 70% to 80% would be a good ballpark number?

Well, we'll come out with numbers later on in the year like we typically do when we released our budget, we'll have all that detail in there or early next year when we release that. But yes, it will be a significant portion.

Your next question comes from the line of Dave Kistler from Simmons & Company. David Kistler - Simmons & Company International: The choice of the Barnett assets versus maybe Permian assets or Cana Woodford assets, given the kind of relationship between gas and oil, the kind of 20:1, can you walk us through that? And should we be reading anything into your view on dry gas versus liquids-rich versus liquids in general?

Really, what we do, we did a really thorough analysis, looking into all of our assets, literally put everything on the table. And we went through that analysis, there's a lot of consideration. So one consideration is what assets are currently selling for, where you can market things, where we think we can get fair value relative to how we view them. We also looked at what we view or are the upside of the various properties that we have. And one of the things about the Fort Worth basin and the Barnett Shale is it's really a single-pay horizon. We have great properties, a lot of gas in play. But one of the advantages of things like really the Appalachian Basin and the Permian or Midcontinent is you have stacked pays and lot of water hydrocarbon in plays, new technology, horizontal drilling that's really unlocking, it allow us to recover a lot more horizon. So we felt with the valuations and particularly with the recent transaction that John said, we could raise a lot of money at we think a fair price. And it would really do a lot of us, and John talked about all those of different things. While at the same time from our perspective, retain a lot of the upside that we really like. So those are some of the considerations that were in there. David Kistler - Simmons & Company International: And then with respect to having additional capital come into the company and be redeployed towards the Marcellus, I believe on the last conference call, you talked about kind of peak Marcellus rates about 2 to 3 Bcf a day of production and kind of I think were targeting about a 2013 time frame for that. Does that potentially get accelerated? And how should we think about the growth? Obviously you've indicated, you'll backfill what you'll lose in the Barnett, but really thinking about trying to triangulate the capital spending going forward

Well, let's work at different pieces of that. Like we said, when you look at the Barnett at sale time, it will be 120 million to 130 million per day net. In the Marcellus next year, we're going to go from 200 million to 400 million net. So we'll more than make up the Barnett within 12 months. Going forward and on the last call, I did talk about, I believe, the most exciting part about the Marcellus, as we drill and other people drill, the quality of play keeps expanding. It gets better, it gets broader. So the acreage we have primarily, a lot of it looks really good. So we have the opportunity with the position we have to drive rates up to, I believe, two to three Bcf per day net. We have that kind of potential. We did not put a time frame on it, as far as I'm aware. But we'll come out, when we come out with our capital budget early next year like we do, we'll continue to paint out the picture and connect the dots so you can see what that is. We'll be very mindful of where we're drilling, and, the rates of return that we're getting will be very capital-disciplined. But we think we got a great opportunity to capture. And really, this sale will allow us to do that and do it in -- like John said, our focus is about growth per share at low cost; growth per share, both reserves and production that adjusted at low cost. And we think you'll see it continue to funnel a lot of money into the Marcellus. Eventually the Marcellus will go cash flow positive, and we'll continue to paint that up with time when we've captured than we have in a lot of the areas, a lot of great opportunities to continue to grow. When you look at the rates of some of the Woodford wells, those are impressive, 1,000 to 1,500 barrels of oil equivalent per day. And in Galum, [ph] Mississippi, 400 to 500 barrels per day. We think that our properties in the Permian have a lot of that Bone Spring, Avalon, Wolfcamp potential that others are doing. So we think we're in a great, great position. David Kistler - Simmons & Company International: Just in terms of trying to increase the predictability of the returns coming out of the Marcellus, as you talked about hedging et cetera, do you look at potentially vertically integrating there in terms of any services, businesses you'd want to get more deeply involved with, especially as we're looking at kind of a backlog of drilled uncompleted wells up there.

Our team's done a really good job of well one, planning ahead, not just one-year and two-year, but five-year and 10-year and looking the whole way through depletion. So we know the rigs we need and the fractures we need and the takeaway capacity and staff size and office space. And they've done a really good job of planning. And we think our strengths and what we're really good at is exactly what we're doing, building reserves and production per share at low cost. We're not drillers, we're not frac guys. But we've wind up and locked in the services we need in order to accomplish the task that we want to accomplish, and we've already done that. So I don't anticipate that we're going to end those businesses.

And plus, just add on to Jeff's comment there, it's just like the pipeline of processing business. We don't believe that's our strength. Other thing is, I think, obviously we're very mindful of the amount of capital it takes to do those things too. They're not free. It takes a lot of upfront capital to fund those and whatnot. So again, it's just trying to allocate your capital. But you're also trying to focus your expertise in areas where you think you can have the biggest impact. So I think it's a combination of both those things.

Your next question is from the line of Gil Yang with Bank of America.

Can you comment on after the sales of Barnett whether or not your bank line and credit would need to be reduced, by how much?

Gil, this is Roger. We don't anticipate any reductions there. That's best we can tell, we don't have the new $4 and slide escalation case the banks are using in this modern day season. We've got ample borrowing base capacity that we haven't elected to use over and above that $1.5 billion number. So I think we're going to in good shape there.

What is it exactly?

We're currently at $1.5 billion borrowing base. But we've probably got easily another $500 million to $700 million over that if we needed it. So I think we've got a big enough cushion in there over and above our existing commitment to accommodate the sale.

And you said something about earlier that the $34 million that they shut in would go away at some point. When would that go away?

By year end.

And is it usual that you won't have any shut-ins, so there's no sort of shut-in inventory, so to speak?

Whether any company, on any play, on any area, anywhere in the world at any point in time, would be actively drilling is going to have wells in various stages of completion and shut-in. There were some confusion in our operations released last week, hopefully not by too many people but least by one individual who said there's infrastructure problems. There's no infrastructure problem. That's just part of the normal build-out and flow that you see the team again is doing a good job of staying ahead of the drilling machine. So that will go away, but there'll be some other wells. And that's just part of a normal business and our normal business and everyone else's taboo.

Can you quantify what normally would be there? I know it will go off announced but it's a bit more like five Bs day shut-in or....

Well, you said Bs per day, let me clarify that. It's roughly $30 million. So when you bring a pad on, you have four wells on a pad, maybe 25 million or 30 million you have wells more, if you have one or two wells, it will be less so it will be in those ranges.

Can you sort of just say anything in terms of the 44 I guess wells waiting in completion? What would be sort of normal number, and when you get to expect to get the normal number?

That's probably going to slow up and down, maybe it will be somewhere in the range of 25 to 50 or something like that at any point in time. This isn't like the Bakken. We're not waiting or parts of the Permian, we're not waiting on frac crews or things like that, if that's what you're getting at.

And then, do you plan to update what your expected or what views are when you report reserves? When do you think...

Well we do year end reserves, and we typically I think put that on in February. We'll probably continue to update it. I think we've been very transparent showing you our team's progression and how we've driven out production for time and recovers per well with time, so we'll continue to try to do that.

And then in the quarter you said I think $60 or so on land and acreage, could you comment on where that is? Is that for the bonus extension that you've talked about for the labor and rental payment you talked about, or there's something else going on?

About $50 million of that is in the Marcellus. And of that, 2/3 of it or 65% are new leases. So the rest of it is extensions and renewals. And the other $15 million is scattered amongst the three divisions.

And the new leases, just to put some color on that, is picking the little bits and pieces in and around our big blocks where we're just filling in.

Those are all right. What we're saying the wells are 5 billions and fully loaded at strip pricing of 60% rate of return, it's all right there, three acres here, five acres there.

When you swap acreage or comment that you swap acres, there's no cash involved with that, right?

Sometimes we've actually, and we've done five trades. And so far all of them have been, no cash has been involved. I can assure you, there are no discussions. Oftentimes there were, a time or two in terms of there was some discussion of selling some cash into making the number of acres worked out and everything else. It's just at the end of the day, it's just been net acres for net acres. And try to put them together. And that's one good thing I think now that the play is getting more mature. All the operators are coming to the same conclusion I think that we have several years ago is blocking of their acreage it's really, really important. And the capital and the low price environment is really important. So that has facilitated a lot of the acreage trace. And quite frankly we've got four or five others that we're working on. And again, they take a really long time because everybody do their acreage slightly better than yours and negotiations and whatnot. So they just take a long, long time to work out. But the good news is the fact that we've done a five, and we got a number more that we're looking at. I think it tells you that the play's getting more mature, people are getting more comfortable with our technical views of different acreage. And it's allowing these trades to get done. And I just said, it's a win-win deal. One good thing about a trade is you're not selling out for cash, you're actually, in most cases, it's one plus one equals three because both sides getting something as benefit. And so that's why they work. Again they just take a long time to work out in most cases.

I want to finish this up, along those line with the roughly 40 million or 35 million that you're spending to buy new acreage to fill in those gaps, are you also selling something that are sort of out there, that you can't trade it but you just sort of don't really need it?

We did one very small deal like that a couple of years ago. And going forward, we'll look at optimizing our position as best we can. And that will be drilling the hole, renewing some stuff, filling in holes by buying, trading, it may be letting some stuff expire and maybe selling little bits here and there. It will be all of the above. uppertor: Our next question is from line of Leo Mariani from RBC.

In the Marcellus, just curious as to how the rig ramp is progressing, how menu horizontal rigs do you guys have today, and kind of where you expect to be in a year or two?

We have six big rigs today. And we'll probably pick up on another three by the end of first quarter next year and stay there for that of your. So we're still putting those plans together, and of course there's some small rigs in front of them. We're going to be very capital disciplined.

And obviously, you guys are slightly tweaking the way you approach it there in terms of fewer wells per pad and shorter laterals. How much does it take to take the return?

I think the jury is still out. Like I said with the laterals we're drilling, the economics are pretty spectacular and part of that is we're in the wet gas area and the quality of the wells and everything else. And we're looking at great rates of return, doing. We have drilled a number of wells and will watch the long-term production with time plus watch each others people's long-term production through time. And really at the end of the day, it's very how you economic loss and that's answered this in certainty of that answer, we'll know a lot more next year than we'll know now. For sure, you know that a longer lateral, if you put 30 stages in a well versus eight, you're going to get a higher IP. The question is if you get a better rate of return. We're still looking at laterals and that, they'll be in that 2,500 a little bit more that 3,000 eight stage, maybe 10 stage jobs and those are fantastic rates for return. We've got some of those experiments in there, We'll just watch wash them and look.

In terms of the Permian, how much total acreage do you guys have out there, and it seems like pretty early days in your investigation of a lot of these for the new horizons even though it's in the Marcellus quite a bit for the last couple of years. Is that a fair realization in terms of the Permian?

Well, no. We have different that were different things. We have quite a bit acreage, what I try to do is rather than just talk about acreage, talk about geology and deal focus. So those number that I just gave in terms of the Permian, were based on all of that work, and it's a 155 gross and hundred 18 that maybe we do have a lot of acreage out there and we're in a good hydrocarbon rich area. Like I said, we'll start our first wells there first quarter next year.

Your next question is from line of Ron Mills with Johnson Rice. Ronald Mills - Johnson Rice & Company, L.L.C.: Question on just the Barnett properties. If you compare those to the talent properties in terms of production mix, I know that they had plus almost 30% if you associate with their production, a lot of different properties I think with overlapped in some of your 120 million to 130 million a day of production, what's the production profile of that gas versus the deal.

If you have that talent properties, they're roughly, they're 29% liquid, 71% gas. If you look at ours, well, they're 71% gas, we're 81%, and the difference is liquid. So they have a little bit more liquid bur it's not tremendously higher. When you look at the overlap of property, they really don't overlap very well. Calen [ph] is predominantly west of us. Almost all of their acreage is in Parker County. And when you look at a lot of our acreage, it's more on the quarter to play to proven core and a lot of it is in Johnson counties. So when you look at the quality of the wells in those areas, and it's public wells, the quality of the well is clearly higher there. So that's important. When you look at they're 71% gas, we're 81%, they're a little more liquids. But when you look at acreage, our acreage is clearly more in the core. The other thing is when you look at, I'll just do gross to gross on acreage, they announced 20,000 gross acreage is what they had in the package. We have 64,000 gross acres and out to be net to net. But we have basically more than 3x the acreage in a higher quality area. So I think that's how it compares.

And Ron, the other thing I think is important is the production profile is slightly different either. As you know, we've only had one or two rigs Barnett for a good long time here. And so, our production kind of comes by the decline curve. They got those properties some other guys and put a bunch of money and ramp the production up, which is what I do in almost all properties too. But their production rate is at the higher end of that curve deeper into the current than ours. And you know, I think that has an impact in terms of relative value to somebody. So there's a lot that goes into it. We always been known to those properties pretty well. We actually look at that onetime. And our team obviously because we've spent him fair amount of time. So we're not saying that the properties aren't in good properties for most of the say what the financial terms as we can in terms of the relative quality of these assets. Still good quality assets and we've got some a lot of people talent call us announcing that want to know our thoughts on it and would it be to adjusted so we have a pretty good insight in terms of that as well as some it all comes that the decision that they made but at the end of the they come it all comes down in a "no" quickly a couple of months three months. So that's kind of where we stand. Ronald Mills - Johnson Rice & Company, L.L.C.: And I'm looking back to older presentations and press releases, both of your three plus Bcfe of crude reserves and the production percent plus or minus a quarter of the production is the reserve split pretty similar or is there a significant difference of Barnett deserves versus the production?

For obvious reasons, we're not going to get direct. One is a don't disclose reserves on a segment basis because it's not a segment business. Anything is not our best interest to do that in terms of the process. So we were looking that confidential for the time being. Ronald Mills - Johnson Rice & Company, L.L.C.: Just trying to back into on a relative margin of Barnett versus your Southwestern division versus Marcellus division, trying to back into what the EBITDAX margin is on the Barnett.

This is what we're going to do in the sales process and I don't want to go into detail, but I'll say on that sale, when we look at our lower cost, it will help lower our DD&A and it will help our elderly. It's positive for us in terms of getting to know. We're adding in getting to dollars for the Marcellus are just getting better plus an average and higher than the those areas. So have continued to drive down those costs. Ronald Mills - Johnson Rice & Company, L.L.C.: You talked about the redeployment of capital. One thing with the discussion of a number of liquids plays that you discussed in the past when you look at the redeployment of capital, we should an expectation be to redeployment of that in the liquid or some of the newer liquid phase you identified versus all of that being redeployed on the Marcellus.

We're going through a rigorous analysis of our budget and no look at where we will discussions like to turn trying new concepts holding acreage and all of those types of things. You see the bulk of the cap that goes even more works as John said in the past, will have one or two drilled in the Barnett obviously and we'll be looking at and not mindful of a aspects of our business. Ronald Mills - Johnson Rice & Company, L.L.C.: Jeff, but the CapEx budget that you've all talked about for this year, But the total CapEx this year, you've spent on development plus or minus $600 million so far. I think you had talked about $850 million and $900 million budget. I think John said you might spend a little less than that. Is that accurate?

The numbers are on our website and that's roughly $1.2 million budget. And we spent about $700 million, $765 million. But if you look on our website, the exact budget is that an if match at what's in there and you see where the exact numbers on that.

And our final question comes from the line of Dan McSpirit with BMO Capital Markets.

On the Marcellus, on the press release, can you talk about the conditions that was used to describe the IP-based of the 18 Marcellus well stood in the quarter? I think you're talking about six side but what chokes I'd vote for load and maybe just a deliberate move to maintain that pressure are really just to make it at the position you to restrict the volumes?

If you look at our wells, we had our best wells so far down there when you look at unconstrained. At the end of 2008, we knew we have $20 million a day and you decide to see what we can do. It came in at $26 million per day. And that's million is about a Bcfe well. So we've had other mouth as she that are really strong like that and the multiple wells could be over $50 million per day. so we decided to do after that first well is rather than design really everything is the highest rates and from the economic point of view, we believe it's better to design for what more of an average rate is versus what our wells make on peak. So it's about optimizing about maximizing rates and issues. So you can make it been like that Haynesville where you guys have pressure and really high pusher pressures so you have soft rock for crushing and all kinds of things in order to minimize that early on that district the rates. And it's a much different situation. We don't need high-strength profits were frac-ing bitterly with 100 other things like that and to standard that are inexpensive. So yes, all those have the capacity. We were just designing for ICs and the urge building and just producing a lot of fuss over 20 million per day and we started putting 20 stage fracs or 20 stage facts. We would get some fantastic growth and we're really looking at rates of returns and we have maximizing the project getting capital discipline and watching that over time.

Mindful of the sensitivity of that sale process on the Barnett Shale assets but just for the basis of comparison and get a better handle on what you're selling, is from a field level economics point of view, if you run the fully loaded economics of the Barnett Shale assets, like you run on the Marcellus, what the IRR at $4 or $5 gas and I assume that would exclude cash interest cost and cash taxes?

The easiest thing to do is just look at our website and report our economics out of the same gas prices whether the average who will be on the Barnett versus the Marcellus versus. So just open the book. So that $4, that 60% rate of return in the Marcellus at $4 on the Barnett is 23. So that's right off on our website.

What makes the trend $2.5 million in non-cash improve property in payments that was recorded in the quarter?

This is Roger. Our amortization for lack of a better word of our acreage is going to be expired over time or that is impaired by new developments maybe to drive a whole and impaired acreage. On a successful methods of counting comment on accounted for separately to improve properties. So you don't have that you can develop this in and then periodically pushed a big savings identity care of all your a push for successful in business under and you have for us otherness the past, we have to account for separately so you a list looking at your improved and assessing the value of your improve and adjusting your provision expense, which is a quarterly expense to basically forecast what your future impairment and exploration schedules going to be like. So that's where the $20 million comes from and that's really a realtime process that we undertake.

Are there specific properties that you can identify behind the $20.5 million? Is that the same set of properties each quarter that we're looking at here?

At this point, there's only one or two specific categories and improve groupings. Really it's all done by a division on a division basis ongoing basis and so it's a more up amortization approach for the puppets that you see there now are still going to be there.

I think the simpler way to say is this division have the number of visas that are going to expire over the next five years and we take that and divide that monthly and that's what the monthly or quarterly amortization is. It's a very simplistic approach to that end in the race that's what we're doing. To some specific identification as Roger mentioned some of the fastest time to take kind of a long-term approach and pay me now, pay me later and amortize it over time. Well with that, I guess that concludes our call. We really appreciate everybody taking the time to join us today. It's really a very exciting time at Range. Think of Range and even going back two or three years, is the idea that we would sell our Barnett properties is pretty amazing. And I think it really tells you how far the company has come over the last two or three years for the management team and as Jeff and I think it would also extend to we've taken a lot of time to think through this discussion or decision. We spent a lot of time with the Board in terms of making this decision. But I think it's really exciting. I think what that tells you it's the confidence level for us to think that we 120 to 130 million of production for 12 months or less, we couldn't get any closer to that two or three years ago. So I think it's a complete sea change in terms of the capability of the company and the capital efficiency. Also I think it really beckons the fact that management really is very confident in not only Marcellus but these other projects that we've got and our ability to execute. And I think that really reads well and reads, shines through in terms of our decision here with the Barnett. And at the end of the day, we look at the business fairly simply. We want to drive up production and reserves on a per share basis, just adjusted it low cost. And our view here is if we can do that time and time again over time, we'll drive up value. And we're obviously mindful of prices. I think we've got one of the best hedged positions of anybody in the sector for the rest of this year and for 2011. And we've got one of the more economic plays. We've got the largest position in what a lot of people believe is the most economic oil and gas play in North America. So it's a very exciting time here at Range. We're extremely excited. And lastly, I think that from a shareholder perspective, I think it's a bit bold. I think it puts us here and put to rest the fears of how we're going to fund our capital over the next couple of years.. Clearly, if we sell the Barnett at a good and reasonable price -- and obviously we're hoping for a very good price. But even at very good deferred price, that the amount of capital that brings in will be enormous. We only have $165 million of bank debt. So Roger will have his biggest issue is how to invest all that cash, until we can redeploy it. And we're going to take some time to redeploy. We're not going to obviously going to rush out and do it all at once. So it's really an exciting time, and we've talked to a number of the large shareholders. And it seems most people really like the decision we made. For those of you all that are still might view it differently, we tried to be as transparent as we possibly can. Call Rodney and I and Jeff and Roger will be happy to take you through we think it makes sense and why we think it's in the best interest of all the shareholders of Range. Thank you again and we'll talk to you at the year-end earnings.