山脈資源 (RRC) 2010 Q3 法說會逐字稿

Welcome to the Range Resources third quarter 2010 earnings conference call. At this time all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator Instructions) As a reminder, this conference is being recorded. 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 of 2010 with record production breaking the 500 million a day mark for the first time. Range reported increased production in our liquid rich areas of the Marcellus mid-continent and the Permian basin and announced a decision to market are 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 is 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 to guide you in the calculation of the non-GAAP measures of cash flow, EBITDAX, cash margins and the reconciliation of our non-GAAP earnings to reported earnings that are discussed on the call today. We have 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 and Scattergood energy conference in New York on November 9, the Pritchard Capital conference in Boston on November 10, the Banc of America energy conference in Miami on November 12, the UBS energy conference in New York on November 17, the Banc of America credit conference in New York on November 17, and the JPMorgan 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 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 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, running on the higher side was G&A cost, which saw an 8% increase over the last year. We're still billing 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 it decline on a unit production basis, like the other metrics.

Through 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 -- won't spend more than our budget. And if anything, we may end up spending a few dollars less than budget.

With regards 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 trades we have 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. They help to block up our acreage positions, which in turn significantly in turn 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 mid-continent Permian areas. Our operating teams did an excellent job quickly shifting capital and getting these projects on line.

All in all, third quarter was a very solid one. We executed on the production side, continued to reduce costs, successfully shifted capital 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, totalled $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 rehedged. Year-to-date natural gas, NGL and oil revenue, including all cash settled derivatives, totalled $696 million. Cash flow for the third quarter was $141 million. 18% below last year, 9% higher than the second quarter of this year. Cash flow per share for the quarter, was $0.88, matching the analysts' consensus estimate. Year-to-date cash flow totalled $418 million. EBITDAX for the third quarter was $173 million, 13% lower than the third quarter of 2009, but 11% higher than last quarter. EBITDAX for 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 few unusual revenue and expense items to highlight in the third quarter results. Our non-cash derivative mark to market losses totalled $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 7.375% notes slated to mature in 2013, and replacing them with new 6.75% 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 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 notes they replaced.

Third quarter earnings, calculated using analysts consensus methodology, was $18.9 million, or $0.12 per fully diluted share. That is $0.02 higher than the analysts consensus estimate of $0.10. And as Rodney and I always mention, the Range Resources website has 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 work overs, was $0.73 for Mcfe, that's is down $0.03 from third quarter last year, but $0.05 higher than the $0.68 seen last quarter. While the overall operating costs 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. We believe that our cash direct operating costs still has room to decline. We anticipate that fourth quarter direct operating costs, excluding work overs, will be around $0.68 to $0.69 in 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. This came in at $0.19 in Mcfe. General and administrative expense, adjusted for non-cash stock compensation, came in at $0.62 for the third quarter, that's up $0.06 from last year. Unit cost increase in G&A is attributable to community relations and education expense occurred in the Marcellus Shale division and to a lesser extent inventory adjustments and higher professional fees. For the fourth quarter of 2010, we anticipate G&A expense to be flat in the low $0.60 per Mcfe range.

Interest expense for the third quarter was $0.73 in Mcfe, that is down $0.03 from last year. In September, we deployed the remaining idle cash proceeds in our 1031 like-kind exchange account to reduce the bank debt and utilizing the 1031 account to reinvest a portion of our Ohio sale proceeds, that allowed us to help preserve our $322 million NOL carry forward. Interest expense will increase slightly in the fourth quarter and that reflects the big financing during the third quarter, a $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, totalled $14.2 million. That's $4.3 million higher than last year due to higher delay rentals, [drill hole] 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. 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 the seismic spending.

In terms of dollar amount each quarter, depletion, depreciation and amortization expense runs almost three times the next largest expense category. But because DD&A is a non-cash expense, even though it is so significant, it is often relegated to second tier importance. However, in a capital intensive industry such as ours, the DD&A rate provides a key ongoing measure of our capital productivity. Our DD&A rate for the third quarter is $1.98 per Mcfe. That is down from $2.42 in Mcfe last year. Now the last time our DD&A rate was below $2 was back in 2007. The rapid decline in the DD&A rate, signals a channelling of our capital spending towards the highest returning projects in our drilling inventory and hydrating of our asset base through selective property divestitures. With 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 it's downs represents a big change. The fourth quarter DD&A rate is expected to decline further and we anticipate additional reductions out in 2011.

We account for unproved acreage explorations and 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 is $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 the 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 carry forward to help us 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 quarter -- the third quarter of 2010 with 76% of our remaining 2010 gas production hedged with collars at a floor price of $5.56 MMBtu and a cap of $7.20. We have increased our 2011 hedge position to 84% of our 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 $5.50 by $6.25. Our oil hedges consist of 1,000 barrels per day in 2010, hedges and collars at $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 4,700 barrels a day now hedged by a ceiling at $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 6.75%. That is our second lowest coupon ever. The proceeds were used to redeem $200 million of our 7.375% notes that were set to mature in 2013. The rest of the proceeds were used to refinance a portion of our floating rate bank debt.

Second, our 26-member banquet unanimously reaffirmed our $1.5 billion credit facility borrowing base and $1.25 billion revolving commitment amount. This is despite significant reductions in the price forecast used by these banks to value their clients' oil and gas preserves. These credit actions provide range of over billion dollars 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 more about later, Range remains committed to maintaining a strong balance sheet with 2011 capital spending at or below the sum of cash flow and asset sale proceeds.

Summarizing the quarter, we saw steady production growth, an increase in cash flow over that of 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 of the 2013 notes out to 2020, and by reducing the outstanding balance of our bank credit facility, which gives us over a billion dollars of committed available liquidity. We also strengthened our already strong 2011 natural gas hedge position and doubled the natural gas volumes 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 a 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 this production will be on line.

We announced a series of great wells in a liquid rich portion of the Marcellus play last week in our operations release. These 18 new wells look like they'll exceed our 5 Bcfe average reserve estimate for the southwest part of the play. The 5 Bcfe reserve estimate is comprised of 3.6 Bcf of gas and 239,000 barrels of liquids. At $4 flat gas price forever and a $60 barrel oil price flat forever, the rate of return for Marcellus well in 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 strip 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 strip pricing, the rate of return goes from 47% up to 60%.

Given the 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 of drilling complete at approximately $4 million in the southwest. Given the economics I just stated, it will keep our rate of return at 60%. We have tested longer laterals up to 5,000 feet and up to 17 frac stages. Others have experimented with even longer laterals. We'll continue to watch a long-term production data from these tests, which will help to determine the 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 risk. 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 -- 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 drilled all of the wells on a pad and frac them all together. Logistically it is 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 a 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 up 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 in our position there. Range has a very significant position in Washington County and 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 derisked. Operationally it is 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 lease as 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. Consolidated, or 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 that the wells are more concentrated and not as far apart, which makes our gathering costs less. The more blocked up position minimizes the cost of rig moves. It is also more efficient that a single water impoundment can service more pads than when the acreage is more consolidated. It is also easier on the land development and other groups in many ways, and it also benefits the community where we operate in that 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, blockier, 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 to hold 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 tracts that are more on the edges of the fairway, or a small positions in the dry gas area which we can not efficiently develop. Although we will have fewer acres, we believe that by concentrating in the highest productive acres, 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 it is indeed productive. Also, for our very first tryout of the box in this horizon, the rate is pretty impressive. It is doubtful that on our first try we landed the lateral at the optimum location. I'm also pretty confident that we didn't optimally stimulate it, so there is likely significant upside. It is encouraging that the reservoir pressure that we encountered is about the same as the Marcellus in this area, which is over pressured. Its thermal maturity is also similar to the Marcellus and should roughly track it in regard to the wet and dry portions. The gas in place for the bulk of where we believe the play is most perspective ranges from 60 Bcf to 100 Bcf per square mile. Importantly, it directly overlies a lot of our Marcellus acreage in the southwest where the Marcellus gas in plays averages 75 Bcf 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 Bcf 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 holding and announced 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 mid-continent 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, plus 2.3 million cubic feet of gas per day, or 1,176 barrels of oil equivalent per day. 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 three-quarters 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'll recover on a per well basis about 4 Bcf, 35,000 barrels of oil and about 625,000 barrels of NGLs. That is about 8 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 to complete is about $4 million per well. At current strip pricing, the rate of return is 98%.

The next play or mid-continent division I want to discuss is our horizontal Mississippian play. In northern Oklahoma, Range has announced a strong horizontal Mississippian well we tested at a rate 410 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 we've 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 a 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. With current strip pricing, this results in 80% rate of return.

In addition, Range controls about 80,000 gross or 42,000 net legacy acres that are all held by production in the Cana shale play and the Anadarko Basin. Roughly two-thirds of the net acreage is in Blaine and Canadian Counties and roughly one-third 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 southern Major County the true vertical depth of the Cana well would be about 8,500 feet versus about 13,000 feet in Blaine and Canadian Counties. Recent Devonian completions have reported sustained 30 day rates from 7 million to 8 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 Barnett Shale and Denton County that were brought on line at 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 in oil. In addition, we've just recently completed five new wells in Tarrant County and are in the process of completing three more wells. In aggregate, we expect these wells to come on line at the 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 to the Strawn, coupled with the successful Wolfcamp recompletion. These four wells average 561 barrels of oil equivalent per day each. We have been mapping the horizontal oil potential of our properties in the Permian Basin. To date, we believe we have about 155 gross and 118 net locations combined between our Conger Field and Pal Ranch properties in west Texas and Loving properties in southeast New Mexico. Our first well will be in Pal Ranch and should spud early next year. The target formation at Conger and Pal 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 fields 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 focussed on recompletions, 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 to average roughly 100 -- I mean, 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 costs to continue to decline. Importantly, we have 76% of our fourth quarter natural gas production hedged at a floor, average floor of $5.56 and a cap of $7.20. Also, we're confident that our all in 2010 fine 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 have conducted a full review of all of our properties, including both producing and non-producing properties. After considering all of 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 of developing them, we're 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 sale of 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 sale in many ways is similar to the 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 was that we would receive 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 a day we sold in the Ohio sale and we did it at a 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. 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 is 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 sizeable Barnett sale was announced, which held 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 is a very high quality set of Barnett properties that will command a very solid price. 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 sale, it should provide substantial clarity as to how we're going to fund our future growth over the next several years. In particular, we're looking to 2011 and beyond, we believe we'll be very well positioned. First, assuming a sale 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 ridge plays in the Marcellus, as well as in the mid-continent 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 mid-continent that we're very excited about.

I'll now take a moment to discuss the regulatory environment in the 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 flow-back process is much more predictable, especially given that Range is recycling 100% of its flow-back water in the southwest portion of the play. The Pennsylvania DEP is very supportive of our recycling program. It is not only a better environmental solution, but it saves Range money as well. We also received all the necessary air permits for all of the compressor sites that are currently under construction.

With regards to severance tax in Pennsylvania, the state has yet to enact a 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 where by any severance tax would come with balanced of regulatory modernization. We believe that both candidates running for the Pennsylvania governorship will take a much more commercial and diplomatic approach towards a 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 are 76% of our natural gas production's hedge, at a floor of $5.56. And importantly when you look at 2011, we have over 80% of our production hedged at a floor of $5.57. And in addition we have a nice hedged 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 play is solidly on schedule. While there is always some delay for surface facilities build-out at each pad site, in the southwest portion of the play, we are at the point where pipeline and processing capacity is no longer an issue. Our acreage trades, as Jeff mentioned, really helped us out to get us to that position. In the northeast the first face 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've drilled in the Marcellus Shale play to date. Both wells had seven-day average test rates of over 13 million a day each. Once the Lycoming County production goes on line, we will 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 the excellent well results, there is little doubt that we'll achieve the 2010 Marcellus exit rate goal of 200 million a day net. More importantly, it sets the stage for doubling production again to 400 million a day plus exit rate for 2011. So, that's very exciting news. With that, Operator, why don't we turn the call over to questions

Thank you. (Operator Instructions) Our first question is from the line of Rehan Rashid with FBR Capital Markets. Please go ahead.

Morning, John -- afternoon, rather. Sorry. Could you walk us through the direction of operating costs by unit operating costs as you kind of roll out the next four, six quarters' worth of production growth from the Marcellus? And then I've got one more question.

Well, let me, let me start kind of high level and then I'll move down a bit. And, Jeff, and Roger, please chime in. There is 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 LOA rates somewhere in the $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 the double whammy approach of LOE decrease. As Roger mentioned, we had our cost of third quarter was $0.73, which was a nickel higher than we had hoped for some reasons that Roger mentioned. But we should be back under $0.70 in the upper $0.60 range in the fourth quarter, which is, 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 out at 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 of the dots, at the end of 2011, our -- into this year it will be 200 million a day plus, which is a double. The end of next year, 2011, it will be 400 million a day, plus. So, you'll see a big piece of our production will be Marcellus. So, that will help drive down it.

The other thing is, is that as we build out to 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 have done that in every field that we've ever operated. So, we haven't built any of that into the numbers. But it is going to be a process. It is not going to be an event. But I think you'll continue to see it.

In addition to the LOEs, I think Roger mentioned, I think one of the really big, big drivers, in my view, in this business, is going to be watching all of the respective companies DD&A rates. I've heard a lot of of talk about we're going to be in a low gas price 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 consisting profitable, one of the biggest things to get there, is going to be your DD&A rate. If you have a really high DD&A rate, it is going to be very hard to be consistently profitable in a low-price environment.

So, one of the things we've really focussed on, and it has a lot to do with where we spend our money and also the assets we sell and what not, is really forcing that DD&A rate down and taking a very disciplined approach towards that, and a very methodical approach towards that. And 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 that. So, all part of the -- our strategy at Range.

Quick one for Jeff, and then I'll hop off. As you think about capital allocation for next year, how much do we have to direct towards let's just say drilling in the northeast, Pennsylvania, for holding acreage, which is, of course, near dry gas versus being able to disproportionately allocate capital towards a more liquid rich southwest Pennsylvania area?

Yes, we'll still -- the bulk of our drilling is still going to be in the liquid rich wet area. But I think we will be adding -- now that the northeast will be coming on line, it will be interesting to watch the performance of the wells and to change that from acreage value into PDP value, but we'll still be directing the bulk of the activity down in the wet part.

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 release our budget we'll have that detail in there, or early next year when we release that. But, yes, it will be a significant portion. Up there like that.

All right. Thank you.

Next line comes from the line of Dave Kistler with Simmons and Company. Please go ahead.

Good afternoon.

Good afternoon.

Sorry about that. I think I still had it on speaker. I apologize. Real quickly, the choice of the Barnett assets versus maybe Permian assets or Cana Wood Ford assets, given the kind of relationship between gas and oil kind of 20 to one, can you walk us through that and should we read anything into your view on drive gas versus liquids rich, versus liquids in general?

Well, really what we do, we did a really thorough analysis looking at all of our assets, literally put everything on the table, and we went through that analysis. There is a lot of considerations, 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 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 that it is really a single pay horizon.

We have great properties and a lot of gas in place, but one of the advantages of things like the Appalachian Basin or the Permian or mid-continent, you have stack pays, a lot of hydrocarbon in place, new technology, horizontal drilling that is really unlocking and allowing us to recover a lot more horizon. We felt with the valuations and particularly with the recent transaction that John said, we could raise a lot of money at what we think a fair price and it would really do a lot for us. John talked about all of those different things. 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.

Okay. That's helpful. And then with respect to having additional capital come into the Company and be redeployed towards the Marcellus, I believe in the last conference call you talked about kind of peak Marcellus rates of 2 to 3 Bcf a day of production and I think we're targeting 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 lose in the Barnett, but really thinking about, thinking about it trying to triangulate to capital spending going forward.

Well, lets look at different pieces of that. Like we said, one is -- when you look at the Barnett at sale time it will be, 120, 120 million to 130 million per day net. In the Marcellus next year we'll go from 200 to 400 net. We will more than make up the Barnett within 12 months.

Going forward -- on the last call I did talk about -- I believe the exciting part about the Marcellus as we drill and other people drill, the quality of the 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 2 to 3 Bcf per day net. We have that kind of potential. We didn't 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 will 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 we're getting, we'll be very capital disciplined. But we think we've got a great opportunity to capture and really this sale will allow us to do that.

Like John said, our focus is about growth per share at low cost. Growth per share, both reserves and production debt adjusted at low cost, and we think by -- you'll see us 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 out with time. And we've captured, and we have in a lot of the other areas, a lot of great opportunities to continue to grow, and we've -- when you look at the rates of some of the Wood Ford wells, those are pretty impressive, 1,000 to 1,500 barrels of oil equivalent per day and the shallow Mississippi in at 400 to 500 barrels per day, we think a lot of 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 position.

And then one last question 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 drill done, completed wells up there?

Our team has done a really good job of working -- well, one, planning ahead. Not just one year and two year, but five year and 10 year and looking the whole way through depletion. We know the rigs we need and the fractures we need and the take-away capacity and staff size and office space. And they're doing a really good job of planning and we think our strength 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 have lined 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. I don't anticipate we'll get into those businesses.

Great. I appreciate the color, thank you.

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

Thank you. Our next question is from the line of Gil Yang with Banc of America. Please go ahead.

Good afternoon. Could you comment on after the sale of the Barnett whether or not your bank line of credit would need to be reduced by how much?

Gil, this is Roger, we don't anticipate any reductions there. As best we can tell, the new $4 and slight escalation case the banks are using this borrowing based season, we have ample borrowing base capacity that we hadn't elected to use over and above that billion five number. So, I think we're going to be in good shape.

What is the capacity?

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

Okay. Great. In -- you said something about earlier that the 34 million a day shut-in would go away at some point. When would that go away? I'm sorry, I missed that.

Oh, by year end.

By year end. Is it usual that you wouldn't have any shut-ins, so there is no sort of shut-in inventory, so to speak?

No, I'm glad you pointed that out. Any company, in any play, in any area, anywhere in the world, at any point in time who is actively drilling is going to have wells in various stages of completion and shut-ins. There was some confusion in our operations release last week. Hopefully by not too many people, but at least by one individual who said there was infrastructure problems. There is no infrastructure problems, it is 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. That will go away, but there will some other wells and that is part of normal business, our normal business and everyone else's to boot.

Can you quantify what normally would be there? I know it will go up and down. Is it more like five B' a day shut-in?

You said Bs per day. Let me clarify that. You said it was roughly 30 million. When you bring a pad on, if you have four wells on a pad, it may be at 25 million or 30 million. If you have eight wells, more, if you have one or two wells, it will be less. So, it will be in those ranges.

Okay. Could you sort of address the same thing in terms of the 44, I guess, wells waiting on completion? What would be sort of normal number and when you get the normal number?

That is probably going to float up and down. Maybe it will be somewhere in the range of 25 to 50, or something like that, at any point in time.

Okay. So, you're not--

We're not -- 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 is what you're getting at.

Okay. That's fine. And do you plan to update what you're expected -- what your EURs are when you report reserves or when do you think --

When we do year end reserves, we typically, I think, put that out 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 up production per time and recoveries per well with time, so we will continue to try to do that.

Okay. And in the quarter you said I think $60 million or so on lands, on acreage. Can you comment on there that is? Is that part of the lease bonus extensions that you talked about, the delayed rental payments you're talking about or is there something else going on?

About 50 million of that is in the Marcellus. And of that, two thirds of it, or 65% of it, are new leases. The rest of it is extensions and renewals. And the other 15 million is scattered amongst the other three divisions.

Okay.

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

Yes, those are all right. Where we're saying the wells are 5 B's and fully loaded at strip pricing, or 60% rate of return, it is all right there. Three acres here, five acres there.

And are you -- so when you swap acreage, that company that you swapped acreage with, there is no cash involved with that, right?

Yes. Well -- sometimes. We've actually -- we've done five trades and so far all of them have been -- no cash has been involved. I can assure you during those discussions there was often times there was, a time or two there was -- in terms of -- there was some discussion of throwing some cash in of making the number of acres work out and everything else. Just at the end of the day --

Just net acres for net acres.

Just net acres for net acres. And trying to put them together. And that's one good thing I think, now that the plays getting more mature, all the operators are coming to the same conclusion I think than we have several years ago, is that blocking up your acreage is really, really important. And that capital efficiency, and in particular in a low-cost -- low-price environment, is really, really important. So, that has facilitated a lot of the acreage trades. And, quite frankly we've gotten four or five others we're working on. And again, they take a really long time, because everybody views their acreage is slightly better than yours, in negotiations and whatnot. So, they take just a long, long time to work out.

But the good news is, the fact that we've done five and we have a number more that we're looking at, I think tells you that the play is getting more mature, people are getting more comfortable with their technical views of different acreage, and it is allowing these trades to get done. And like Jeff said , it is a -- the other thing, it is a win-win deal. One good thing about a trade, you're not selling that for cash. You are actually, in most cases, it is one plus one equals three. Because both sides getting something as a benefit. So, that's why they work. But, again, they take a long time to work out, in

Right. But just to finish this up, along those lines, with the -- on a roughly 40 million or 35 million that you're spending to buy new acreage to fill in those gaps, are you also selling things that are sort of out there that you can't, 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 we'll -- going forward, we'll look at optimizing our position as best we can, and that will be drilling the hold, renewing some stuff, filling in holes by buying, trading, maybe letting some fringe stuff expire. It may be selling little bits here and there. It may be all of the above.

Okay. Thanks.

Our next question is from the line of Leo Mariani with RBC. Please go ahead.

Good afternoon here. In the Marcellus, just curious as to how the rig ramp is progressing? How many horizontal rigs do you have today and where do you expect to be over the next quarter or two?

We have six big rigs today and we'll probably pick up another three by the end of the first quarter next year and stay there for the rest of the year. But we're still putting all those plans together, of course, there is some small air rigs in front of them.

Okay. Great.

We're going to be very capital disciplined.

Okay. And obviously you are slightly tweaking the way you approach it there in terms of fewer wells per pad and shorter laterals, how much do you estimate that cuts into your return?

I think the jury is still out. We have -- 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. But, we're looking at great rates of return doing what we're doing. We have drilled a number of wells and watched the long term production with time, plus we'll watch other peoples long term production with time. And really at the end of the day it's about how do you optimize economically, and that answer and the 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 is -- if you put 30 stages in a well versus eight, you're going to get a higher IP and I'll make a far reaching example, things like going in the Bakken If we would pump 25 to 30 stages, we'll get a lot higher IP. The question is, do you get a better rate of return? We're still looking at laterals in that, they will be in that 2,500-foot, 3,000, a little more than 3,000, eight-stage, maybe 10-stage jobs. Those are fantastic rates of returns. We have got some of those experiments in there and we'll just watch them and look.

Okay. In terms of the Permian, how much total acreage do you have out there? Seems like it's pretty early days in your investigation of a lot of these new horizons even focussed on the Marcellus quite a bit for the last couple of years, is that a fair characterization in terms of your study of the Permian?

Well, no. We have different teams that work different things. We have quite a bit of acreage. What I tried to do is rather than just talk about acreage talk about (Inaudible) geology and engineering and geophysics and specific wells that we have identified. So, those numbers that I gave in terms of the Permian were based on all of that work. It is 155 gross and 118 net locations. I think maybe that is more relevant to acreage. We do have a lot of acreage out there though, and we like it. It is all HBP and good hydrocarbon-rich areas. So, like I said, we'll spud our first well there first quarter of next year.

Okay. Thanks.

Sure.

Thank you. Our next question is from Ron Mills with Johnson Rice. Please go ahead.

Good morning. Question on just the Barnett properties, if you compare those to the Talon properties in terms of production mix, I know that they had plus almost 30% liquids associated with their production. A lot of their properties I think overlap with some of yours. Of your 120 million to [130] million a day of production, what is the production profile of that gas versus, versus NGLs?

If you look at the Talon properties they're roughly, they're 29% liquid, 71% gas. If you look at ours, we're 8 -- we're there 71% gas for 81 and the difference is liquid. They have a little bit more liquid, but it is not tremendously higher. When you look at the overlap of properties. They really don't overlap very well. Talon is predominantly west of us. Almost all of their acreage is in Parker County. When you look at a lot of our acreage, it is more in the core of the play, the proven core and a lot of it is Tarrant and Johnson Counties.

When you look at the quality of the wells in those areas and it is public data, the quality of the wells is clearly higher there. So, that's important. When you look so -- so they're 71% gas for 81%. They're a little more liquids. When you look at acreage, our acreage is clearly more in the core. The other thing is when you look -- I'll do gross to gross on acreage. They announced 20,000 gross acres is what they had in their package. We have 64,000 gross acres and I can't net theirs out to be able to compare net to net. But we have basically more than three times the acreage in a higher quality area. So, I think that's how it compares at a high level.

Okay. And on --

Ron, the other thing I think is important is that the production profiles are slightly different, either. As you know, we've only had one or two rigs out in the Barnett for a good long time here, and so our production has kind of come down that decline curve a bit. Talon guys, who we know pretty well, they have those properties from Denbury and some other guys and went in there and put a bunch of money into it and ramped the production up, which is what I would do if I owned those property, too. But their production is at the the higher end of that curve, steeper end of the curve than ours. And I think that has an impact in terms of relative value, too, when somebody, when somebody looks at it and evaluates the properties, as well. So, there's a lot -- there is a lot that goes into it.

We've obviously know those properties pretty well. We actually looked at them to buy them one time. And our team obviously because it is all public data, spent a fair amount of time on it. We're not at all saying that the Talon properties are not good quality properties. They commanded what we thought was a very fair, reasonable price and we're just trying to answer your question in terms and be objective as we can, in terms of the relative quality of those assets. I still think they're good quality assets and if you -- and we've got some -- a lot of people look at the Talon stuff and called us as well, prior to us announcing that, wanting to know our thoughts on it and whether we'd be sellers too. So, we have a pretty good insight in terms of that and as well as some others. So, we're, again, it all comes back to this decision that we made. But at the end of the day it always comes down to, we'll know pretty quickly in a couple of months, two or three months that. So, that is kind of where we stand.

Okay. Looking back to older presentations and press releases, of your three-plus TCF of crude reserves at the end of the year, another production represents plus or minus a quarter of your production, is the reserve split pretty similar or is there a significant difference of reserves, Barnett reserves percentage versus the production?

For obvious reasons we're not going to get into that. One, is we don't, we don't disclose reserves on a segment basis. Because it is not a segment business. The other thing is it is not in our best interests to do this in terms of this process. So, we'll keep that confidential for the time being.

Okay. And then just following on just trying to back into on a relative margin of Barnett, versus your southwestern division, versus Marcellus division, trying to back into what an EBITDAX margin is in the Barnett.

Let make take a crack at it, and as John senses, we're going to be going through a sale process. We wouldn't want to give a lot of detail. I will say with that sale, it will help when we look at our unit costs that we do focus on growth at low cost, it will lower our DD&A, it will lower our LOE. It is positive for us in terms of -- we're adding in and directing the dollars into the Marcellus which is better, plus on average they're higher than those other areas. So, it will help to continue to drive down those costs.

Got you. One last one, you talk about redeployment of capital. One thing that stood out in your ops update was the discussion of a number of liquids plays that you all had not discussed in the past. When you look at the redeployment of capital, shouldn't the expectation be to redeploy some of it into some of the newer liquids plays you identified, versus all of that being redeployed really up in the Marcellus?

We're going through a rigorous analysis of our budget and we'll decide where to spend those dollars based on a bunch of considerations, like return, trying new concepts, holding acreages and all those types of things. You're still see by and far away, the bulk of the capital go into the Marcellus, but even words like John said in the past, we've had one to two wells drilling in the Barnett, obviously that will go away. And we'll looking at funding our best return projects, but mindful of all aspects of our business.

Jeff, the CapEx budget that you all have talked about for this year, it's --

Ron, I have to pee. Go ahead, you said one more question like three times.

I can't count. But the total CapEx this year you spent on development plus or minus $600 million. So far, I think you had talked about $850 million, $950 million budget. I think John said you may spend a little bit less than that, is that --

The numbers are out on our website and it is roughly $1.2 million against the budget. And we spent, about 700, 765. Look, on our website. The exact budget is there and it matches what has been out there and now you see where our current capital is. You can get the exact numbers from that.

No more questions.

Thank you. And our final question comes from the line of Dan McSpirit with BMO Capital Markets. Please go ahead.

Gentlemen, good afternoon and thank you for taking my questions.

Hi, Dan.

On the Marcellus, in the press release, can you explain the quote-unquote somewhat constraining conditions wording that was used to describe the IP rates of the 18 Marcellus wells drilled in the quarter? I assume you're talking about choke size, and if so, at what choke size the wells were flowed and, really, is this a deliberate move to maintain back pressure or really just an economic decision here to restrict the volumes?

That's a great question. If you look at our wells, we had -- our best wells so far down there when we flowed one totally unconstrained and it is when we brought on our first plant at the end of 2008, we knew we had 30 million a day capacity in the plant, so we decided to load it with one well and just see what it would do. It came on at 26 million per day. That well is about a 10 Bcf well. So, we've had other wells actually that are really strong like that and I'd say multiple wells that could be over 15 and some over 20 million per day. But what we decided to do after that first well is rather than design, literally everything to produce at those higher rates, from an economic point of view, we believe it's better to design for what more of an average rate is, versus what a well can make on peak. So, it is about optimizing rate of return, or MPV, not about maximizing rate. That is a really important issue.

The other thing I want to clarify, too, and you may have been hinting at it a little bit. It is not at all like the Haynesville where these guys are at 11,000 feet with super high reservoir pressures and really high closure pressures, so you have soft rock or crushing, or all kinds of things, so in order to minimize that early on, they restrict the rates. We're at 6,500 feet. It is a much different situation. We don't meet high strength [croppings], we're fracking with 100 mesh and other things like that, just sand, that are inexpensive. So, yes, our wells have the capacity. If we were just designing for IPs and if we were drilling and just producing at max rates, I'm sure we would have a lot of wells over 20 million per day, or if we started putting 20-stage fracs or 15-stage fracs, we would get some fantastic wells, but we are really looking at rate of return and we are looking at maximizing the project, being capital disciplined and watching that versus time.

Okay. Great, thank you. Mindful of the sensitivity on the -- of the sale process for the Barnett shale assets, but I'll ask this question just to form a basis of comparison and get a better handle on what you're selling, at least from a field level economics point of view, if you run the fully loaded economics of the Barnett shale assets like what you run on the Marcellus, what's the IRR at $4 or even $5 gas, and I assume that would exclude cash interests costs and cash taxes?

If you -- the easiest thing to do is just look on our website and there is -- we put our economics out at the same gas prices for what an average low would be in the Barnett, versus Marcellus, versus Nora. So, you -- and Rodney just opened the book. At $4, that 60% rate of return in the Marcellus at $4 in the Barnett is 23. That's right off of our website.

Got it. Thank you. And one last one, if I could. What makes up the $20.5 million in non-cash unproved property impairments that was reported in the quarter?

Yes, Dan, this is Roger. What that is, is our amortization, for lack of a better word, of our, of our acreage is going to be expired over time, or that is impaired by new developments, maybe an offset operator drills a dry hole and you have to impair the acreage. Under successful [reference] accounting, it is all accounted for separately from your proved property. So, you don't have this big full cost pool that you get to dump everything in and then periodically push through a big ceiling test right down to take care of all of your acreage. The successful reference, and there is only a few of us out there in the shale patch, we have to account for separately, so you're always looking at your unproved and assessing the value of your unproved and adjusting your provision expense, which is a quarterly expense, to basically forecast what your future impairment and exploration schedule is going be like. That is where that $20 million comes from and it is literally a real-time process that we undertake.

Right, I guess I should of reworded my question in that are there specific properties that, that you can identify behind the $20.5 million, is it the same set of properties each quarter that we're looking at here?

At this point there is only one or two specific identification properties in the unproved grouping. Really, it's all, it's all done by a division -- by division basis, on a pooling basis, so it is more of an amortization approach. So, the properties you see there now are going to still be there.

Got it. Okay. Thank you.

I guess a simpler way to say is we take, this division has X number of leases that are going to expire over the next five years and we take that and divide it monthly and multiply it times three and that is what the monthly -- that is what the quarterly amortization is. That is a very simplistic approach, but that in a way is what we're doing. We're not -- there is some specific identification. As Roger mentioned, most of it is trying to take a long-term approach and pay me now, pay me later and just -- and amortize it over time.

Thank you.

With that, I guess that concludes our call. We really appreciate everybody taking the time to join us today. It's really, it's a very exciting time at Range. To think of Range and even going back two or three years, 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, both explained, we have taken a lot of time to think through this discussion. I mean this 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 it tells you is that the confidence level for us to think that we could replace 120 million to 130 million a day of production with 12 months or less to date, we couldn't get close to that two or three years ago. So, I think a complete sea change in terms of capability of the Company and the capital efficiency.

Also, I think it really beckons the fact that management is really very confident in, not only the Marcellus, but these other projects that we've got and our ability to execute. And I think that really reads well and shines through in terms of our decision here with the Barnett, and at the end of the day, we look at the business very simply. We want to drive up production and reserves on a per-share basis, and then adjust it at low cost. Our view of it is, if we can do that time in 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 most 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 very exciting time here at Range. We're extremely excited.

And, lastly, I think the -- from a shareholders' perspective, I think the other thing that I think is a little bit bold with this move, I think it ought to put to rest any fears in terms of how we will fund our capital over the next couple of years. Clearly if we sell the Barnett at a good to reasonable price, and obviously we're hoping for a very good price, but even at a good to fair price, the amount of capital that brings in, will be, will be enormous. We only have $165 million of bank debt, so Roger will have his biggest issue will how to invest all that cash until we can redeploy. And we'll take some time to redeploy. We're obviously not 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, it seems like most people like the decision we've made. For those of you that might view it differently, we try to be as transparent as we possibly can. Call Rodney or ,I or Jeff, or Roger will be happy to take you through why we think it makes sense, and why we think it is in the best interest of all the shareholders at Range. Thank you, again, and we'll talk to you at the year-end earnings.

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