山脈資源 (RRC) 2006 Q4 法說會逐字稿

Greetings, ladies and gentlemen, and welcome to the Range Resources 2006 earnings conference call. [OPERATOR INSTRUCTIONS] Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements. [OPERATOR INSTRUCTIONS] At this time, I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, operator. Good afternoon and welcome. Range reported record results for calendar year 2006 with a 15% increase in production and marking our 16th consecutive quarter of sequential production growth. More importantly, the 2006 capital program was successful not only in its drill bit finding costs of $1.61, but also its impressive 377% drill bit reserve replacement for the year. We're pleased to discuss those results with you today. On the call today with me are John Pinkerton, President and Chief Executive Officer, Jeff Ventura, Executive Vice President and Chief Operating Officer, and Roger Manny, Senior Vice President and Chief Financial Officer. Before turning the call over to John, I would like to cover a few administrative items. First, our 10-K is in the queue and should be filed by the conclusion of the call today. It will be available on the home page of our website or you can access it through using the SEC's EDGAR system.

In addition, we've posted on our website supplemental tables which will guide you in the calculation of the non-GAAP measures of cash flow, EBITDAX, cash margins, and the reconciliations of our non-GAAP earnings to reported earnings that are discussed on the call. We've also posted on the website our calculations of finding and development costs and reserve replacement, which also reconciles such calculations with the guidance from the SEC's Division of Corporate Finance. Tables are also posted on the website that will give you detailed information of our current hedge position by quarter. Second, let me update you on our conference schedule. Later this week we'll be at Simmons Energy Conference in Las Vegas and next week we'll be speaking at the Raymond James investor conference in Orlando, Florida. Now let me turn the call over to John.

Thanks, Rodney. Before Roger reviews the financial results, I'll review some of the key accomplishments for 2006. Overall, we're very pleased with the year-end results. As Rodney mentioned, our year-over-year production rose 17% in the fourth quarter and 15% for the entire year. That was above our target for the year. At year-end our proved reserves rose to 1.8 Tcf, a 25% increase over 2005. The reserve replacement was 450% from all sources. Most importantly, the reserve growth was accomplished at an all-in finding costs of $2.10 per Mcfe. Again, as Rodney mentioned, our drill bit only costs was $1.61 per Mcfe. Based on what we have seen to date the $1.61 and the $2.10 look to be in the top 10% of our peer group. These finding cost numbers are a few cents lower than what we previously reported as the final cost numbers came in slightly lower.

On the drilling side, we were very excited and very pleased with the rate's return that we're seeing on our drilling program, what we saw in '06, and what we are continuing to see in '07. This is obviously evidenced by the drill bit growth rates that Rodney mentioned of 377%, clearly the highest in our history. We combined excellent growth in production reserves of low find development costs in '06. And that's really the hard part of our business is combining high growth with low cost. This performance is attributable directly to our very talented technical and operating teams. They deserve the credit. I'm also very pleased that we continue to deliver predictable, transparent production growth. We've now extended our sequential production growth to 16 consecutive quarters. This consistently -- consistency is attributable to the solid base of long-life reserves, a large inventory of low-risk drilling opportunity, and an organization focused on delivering. At the end of 2006 our drilling inventory had risen to over 9400 drilling locations.

For 2007 we plan to drill roughly 1,000 wells, which is anticipated to once again deliver another year of predictable production growth. Previously, we set our 2007 production growth target at 15%. In addition to that, Jeff will discuss our emerging plays and some of the solid traction we're making on their behalf, pretty exciting stuff. Lastly, just looking to get a glimpse of '07, we'll talk about that a little bit later, but with the rising production and the very attractive hedge positioning we've got, when you put those together, it clearly equals a terrific '07. Clearly you'll have the highest financial results in our history. With that I'll turn the call over to Roger to review the financial results. Roger?

Thank you, John. 2006 marks another year of exceptional performance for Range. 2006 revenues, EBITDAX, cash flow, net income, production, and reserves all reached record highs for the Company. Net income from continuing operations totalled $198 million compared to $111 million last year, a 78% increase. Not only is this the highest net income in the Company history, our 2006 net income from continuing operations was more than the prior three years combined. Improved year-over-year financial performance is attributable to a 15% increase in production volumes, but also a 13% improvement in realized price per Mcfe. Despite higher operating costs, our cash margin for '06 increased 11% to $4.63 per Mcfe. EBITDAX for 2006 was a record high $524 million, a 31% increase over the $401 million EBITDAX total from last year. 2006 cash flow totalled a record high $466 million, 28% higher than the comparable $364 million figure from last year. Cash flow per share for the year was $3.36, 19% higher than last year.

Range continues to enjoy a favorable tax position as our NOL carry forward totaled $230 million at year-end '06 and the earliest NOL expiration occurs in 2012. So our successful drilling program continues to generate attractive levels of deductible IDC's, thus that even with a record year profitability, we were not yet required to utilize our NOLs. I'll speak more to how these positive results will carry into 2007 results in a moment, but first let me talk about the fourth quarter. Fourth quarter production was up 17%, as we realized steady growth from our drilling program and mid-'06 acquisition of Stroud Energy. Higher production volumes enabled us to post a new quarterly record high oil and gas revenue figure of $177 million. Fourth quarter EBITDAX at $133 million and fourth quarter cash flow at $115 million are the second highest quarterly totals in our history. Cash flow per share for the quarter was $0.81, $0.01 higher than the consensus estimate of $0.80.

Revenue, EBITDAX, and cash flow for the fourth quarter were all record or near-record highs, but they have something else in common also. They're all cash measures, not impacted by the various non-cash charges that make the fourth quarter results somewhat difficult to compare with prior quarters. Now before addressing these various non-cash items, I would like to reconcile our adjusted earnings of $0.21 per share to the consensus estimate of $0.25. The variance from consensus estimate is attributable to a one-time, $4.6 million non-cash Appalachian salvage value adjustment and a $3.5 million increase in whole year deferred income taxes taken in the fourth quarter. The Appalachian salvage value adjustment caused the fourth quarter DD&A rate to increase from $1.75 in Mcfe to $1.93 per Mcfe. Again, this is not a permanent DD&A change, but a catch-up entry. Our estimated DD&A rate for 2007 is $1.87 per Mcfe. The tax adjustment consisted of ordinary year-end true up entries. Our corporate tax rate still rounds to 37%. These two onetime non-cash entries explain why we exceeded consensus estimates for cash flow but fell $0.04 short on earnings.

Now I'd like to turn back to the four non-cash charges flowing through the fourth quarter. They are -- number one, the loss on discontinued operations from the sale of the Austin Chalk assets; number two, the non-cash compensation expense recorded as a result of the new accounting rule for equity awards, known as FAS 123R; three, the mark-to-market non-cash derivative gains, required under hedge accounting rules; and four, the just mentioned non-cash revision in Appalachian equipment salvage value and the deferred tax catch-up entry. Going back to the first item, it deals with the results from discontinued operations. Discontinued operations, also referred to as assets held for sale in our financial statement, consist of the Austin Chalk properties that were acquired last June with the Stroud acquisition. These non-core assets held for sale were sold earlier this month for cash proceeds of $82 million. Because of the non-core nature of the assets held for sale and the proportion of nonproducing reserves present at purchase, our acquisition price of Stroud contributed $80 million to the property. However, when we closed the Stroud transaction, the assets held for sale were recorded at $140 million in fair value, based upon an independent third party assessment.

With $82 million of cash proceeds received, a $25.4 million after-tax non-cash loss from discontinued operations was recognized in the fourth quarter. The sale of these properties will not impact our published oil and gas production or reserves, because as discontinued operations, the assets were never included in our results from continuing operations to begin with. The $82 million in cash proceeds, however, will be captured in our financial results, as we redeploy the proceeds into our core operations going forward. The second item to discuss is the non-cash compensation expense associated with our equity awards. As was the case with our third quarter results, meaningful cost comparisons with prior periods have been made difficult with the mark-to-market treatment of stock held in our deferred compensation plan and the adoption of FAS 123R, the new accounting rule for equity awards. Now for many years, Range has recorded non-cash compensation expense associated with its deferred comp plan on a separate line item labeled non-cash stock compensation.

Now this non-cash expense represents the quarterly mark-to-market adjustment of securities held in the Range deferred comp plan. And in the second half of 2005, it included some equity settled stock appreciation rights. Expense item is essentially a by-product of the price arranged stock and the other securities held in the plan. When the stock price goes up, the expense increases and when Range's stock price goes down, an offset to expense is created. This expense amount was $7.2 million in the fourth quarter of this year and $2.7 million in the same period last year. Now going forward, to help avoid confusion, this expense is going to be labeled deferred compensation plan expense on the income statement. Looking at FAS 123R, the new stock option and stock equity award accounting rule, non-cash equity award expense was recorded in the financial statement footnotes and not in the income statement under the old rules.

The rational behind the new rule is to move the expense from the footnotes to the income statement to better align the treatment of non-cash equity award expense with cash compensation expense. Now the rule change is especially significant to Range, because at Range all full-time employees receive equity awards, not just senior management. The reclassification of this non-cash expense ends up impacting every cost line on the income statement that contains employee wages, makes it very difficult to track our true cash costs from quarter to quarter. The total fourth quarter 2006 pretax non-cash expense from equity awards was $5.3 billion. The MD&A section of our 10-K, the earnings press release, and the financial schedules hosted by Rodney's Investor Relations team provide a breakdown of the non-cash expense reclasses to assist you in establishing comparability with prior periods. The third item that was non-cash that impacted our 2006 results may be attributed to the accounting rule for oil and gas hedging, known as FAS 133.

Following the '05 hurricanes and the resulting disconnect between the hedged gas index price and the gas price received, our Permian and mid-continent gas hedges no longer qualified for FAS 133 hedge accounting treatment. That means they must be marked-to-market going forward. Now while there were no changes to the underlying hedges themselves, any mark-to-market gain or loss on the hedges must be run through our quarterly operating results. So in the fourth quarter of '06, a $2.8 million pretax gain was reported compared to a $10.9 million pretax gain in the fourth quarter of last year. As for the cash revenue and expenses for the fourth quarter, our hedge position helped produce a realized wellhead price for Mcfe for the quarter of $6.57. That was $0.08 higher than last quarter, but $0.24 lower than the fourth quarter of last year. After adjusting for the non-cash equity award expense reclass, direct operating expense was $0.99 per Mcfe, up $0.22 from last year's fourth quarter and up $0.07 from the third quarter of this year. While we've seen costs moderate and begin to decline on the drilling side of our operations, production costs have remained a bit more stubborn.

The largest increases in direct operating expense have been in field service costs, primarily electricity and water hauling, insurance premiums, post-hurricane related, and field personnel, generally higher wages. Lower production taxes of $0.32 per Mcfe in the fourth quarter did help offset $0.13 of the $0.22 increase, and direct operating expense, excluding non-cash comp expense and production taxes combined, went from $1.22 in the fourth quarter of last year to $1.31 per Mcfe this quarter, a 7% increase. Looking forward to 2007, we expect direct cash operating costs to range between $0.90 and $0.95. The first quarter will be in the high end of this range, while the following quarter should be on the low end of the range, due to reductions in water hauling expense from new injection wells, higher production volumes from lower operating cost areas, and potential reductions through asset divestitures. Turning to overhead costs, G&A expense per Mcfe for the quarter, adjusted for the non-cash expense reclass, was $0.37, that's down $0.03 from the fourth quarter of last year. G&A expense is down on an Mcfe basis primarily due to lower professional fees and franchise taxes.

Jeff will talk in a little bit about our opening of the new Pittsburgh office. It's a very exciting development for us, but it's expected to initially add $0.02 to $0.03 per Mcfe in '07 G&A expense. With this increase, looking forward to the first quarter of '07, G&A expense is expected to be in the $0.38 to $0.48 per Mcfe range. Interest rates moderated in the fourth quarter, but higher debt levels from the Stroud acquisition and the '06 refinancing of $250 million of our short-term floating rate bank debt caused interest expense per Mcfe this quarter to increase $0.20 from last year. Our leverage, as measured by the debt-to-cap ratio, increased by 1% from the third quarter to 45%, but remains lower than year-end 2005, which was 47%. Now we continue to have a 40% debt-to-cap target and the $82 million sale proceeds from the Austin Chalk properties will help us move towards this target in '07. Most importantly, we will not require incremental borrowings to fund our capital program in 2007. Cash flow and proceeds from asset sales will be sufficient. Looking at exploration expense, adjusted for the non-cash comp expense reclass, it was $10 million in the fourth quarter compared to $9.8 million last year.

Slightly higher dry hole costs for the quarter offset slightly lower seismic expenses compared to last year. Based on our drilling plans for 2007, we do not expect exploration expense to increase this year. And please remember, Range does not capitalize seismic costs, interest expense, or G&A expense. No appreciable cash taxes were paid in the fourth quarter and net income from continuing ops for the fourth quarter of '06 totaled $25.8 million. Fourth quarter EBITDAX was $133 million, 11% higher than last year's figure of $120 million, and cash flow for the fourth quarter was $115 million, up 4% from last year. As is always the case, full reconciliations of these non-GAAP financial measures, as Rodney mentioned, are available on the Range Resources website. To recap our hedge position, Range has traditionally hedged a significant portion of its near-term production volume to ensure a predictable level of cash flow for capital spending and to lock in favorable rates of return on invested capital. Now we currently have approximately 80% of our gas production hedged in 2007, with a floor price of $8.11 per Mcfe.

For 2008 we have approximately 60% of our gas production hedged, with an average floor price of $8.92 per Mcfe. Hedge position that Range currently holds for '07 and '08 will allow us to fund the drilling program and expansion of our emerging plays through cash flow without having to borrow. Those wishing to update their financial models can always find a detailed summary of our hedge positions on the home page of Range's website. In summary, 2006 was an exceptional financial year for Range. Record levels of net income, EBITDAX, and cash flow, combined with a decrease in our debt-to-cap ratio and more leverage improvement on the way from asset sales, despite costs rising we still continued to increase our cash margin. My only disappointment with '06 is the static caused by the new accounting rules and related non-cash expense reclasses, which make everyone's job a bit more difficult. This disappointment fades, however, when one considers that cash margins increased 11% to 4.63 per Mcfe in '06, with even higher cash margins to come in '07 thanks to our hedges. Add to this an anticipated 15% year-over-year production increase and 2007 should be another record year for Range. John, I'll turn it back to you.

Thanks, Roger. I'll now turn the call over to Jeff Ventura to provide an update on our operations. Jeff?

Thanks, John. I'll begin by reviewing production. For the fourth quarter, production averaged 294 million cubic feet per day, a 17% increase over the fourth quarter of '05. This represents the highest quarterly production rate in the Company's history and the 16th consecutive quarter of sequential production growth. For all of 2006, we had 15% production growth. We're also targeting 15% production growth for 2007. For 2006, we achieved 25% reserve growth or 450% production replacement at an all-in cost of $2.10 per Mcfe. Through the drill bit we replaced 377% of production at a cost of $1.61 per Mcfe, which includes $0.21 for acreage purchases. This combination of great reserve growth and low finding and development costs is amongst the best in the industry. I'll now review some of our key projects. A very impactful, low risk project for us is the Barnett shale in the Fort Worth Basin.

We had built a position of about 18,000 acres prior to acquiring Stroud in June of 2006. When we acquired Stroud, we doubled our acreage position to 38,000 acres and picked up about 16 million per day, along with a great team of Barnett experts. At year-end 2006 our Barnett shale production had more than doubled to approximately 35 million per day and our acreage position had increased to 58,000 net acres. We just recently brought online two high rate wells in Tarrant County that were simul frac. One well is producing 7.8 million per day gross or 5.9 net and the other is producing 12 million per day gross or 9 million per day net. The 12 million per day well, to the best of our knowledge, is the best well in the entire Fort Worth Basin Barnett shale play so far. Results like this are a combination of having excellent acreage and a team that is second to none. Our team applied state of the art technology to excellent Barnett rock and the result was the best well so far in the trend. Risk on our Ellis County Barnett acreage extension has also decreased substantially over the last year.

As you recall, this project is an attempt to push the eastern extent of the Barnett trend from Johnson County, across the county line into western Ellis County and northeast Hill County, where Range has 28,000 net acres. The risk on our prospect is lower for two reasons. One is that we've completed our 3D work on our acreage. And the second is the result of recent drilling activity, which moved the eastern extent of the play closer to our acreage. In regard to the seismic, we completed shooting, processing, and interrupting the 3D on our acreage. The good news is that the area looks quiet. That is it is not [carstad] and has relatively wide space faults across it, similar to our nearby East Zenith plot. It also looks like it will have a thick Barnett section on it, which could be up to 400 feet. In regard to Range's activity, we've recently successfully drilled and completed our [Wordley] well on our east Venus acreage, which is on the far eastern edge of Johnson County. Early results from this well look like it could ultimately produce gross reserves of about 3 to 4 Bcf of gas, which is in line with Range's [western] plot.

EOG has recently completed three wells in northeast Hill County that produced 2.2, 2.7, and 3.2 million cubic feet per day each. These wells and Range's Wordley well have moved the commercial edge of the Barnett to within 4 to 5 miles of our Ellis County acreage. Our prospect there alone represents about one Tcf net of net upside for Range. The test well for this prospect will spud in late March. Overall, our acreage in the Barnett is continuing to grow. We've picked up additional acreage that brings our total Fort Worth Basin Barnett position to over 73,000 gross or 64,000 net acres. Importantly, almost all of our acreage, about 94%, is in the core or expanding core part of the field. Our acreage, coupled with our talented, experienced team will continue to build value for our shareholders. For 2007, we're looking to drill 60 Barnett shale wells versus 24 in 2006. So as you can see, we're in a great position to significantly increase our Barnett production during 2007. Another very impactful, low-risk project for us is our coal by methane position in Appalachia.

Production has grown from approximately 14 million per day at the time we acquired these properties to about 29 million per day currently. This is about 55% higher than what we originally projected. This has been a great project for us, finding costs for the new wells are typically less than $1 per Mcf, which is outstanding. As good as the properties have been, I believe the future will be even better. We've identified a half Tcf net of low-risk, un-booked upside in the Nora Haysi area and with successful down spacing, could be double that. To put that in prospective, Range's total proved reserves are about 1.8 Tcf. So far, we've drilled 16 infill wells on 30-acre spacing. Early results for these wells are encouraging. Plans are to drill at least 35 additional 30 acre infill wells this year. Third project, while higher risk, represents the opportunity to more than double the Company by itself.

As to our Devonian shale play in the Appalachian Basin, it represents 2.5 to 5 Tcf of upside and currently we have more than 410,000 net acres in the play. We now have 15 vertical wells and one horizontal well online. Our oldest vertical well has been online for about 15 months and two additional vertical wells were brought online shortly thereafter that. Results for these wells still indicate an estimated reserve potential of between 0.6 to 1 Bcf per vertical well. We've experimented with four types of hydraulic fractures in the 15 vertical wells that we've completed so far. We've learned a lot since we started. Given that we're the lead Company in this play and that we're still acquiring acreage, I cannot at this time discuss the details of exactly what we're doing. It's interesting to note that in the Barnett shale, Fayetteville shale, and Woodford shale, the early vertical wells were either marginally economic or uneconomic. I am encouraged that we are starting off our Devonian shale program with good results. It's also interesting to note, that after roughly more than 100 vertical wells in each of these three plays, the Barnett, the Fayetteville, and Woodford, that they eventually turned into horizontal plays.

We've drilled three horizontal wells to date and have completed one. The initial rate on the first horizontal well was disappointing, but the well has continued to clean up and its production has been steadily inclining. Now been on production for about seven months and our current estimate of reserves for the well is about 1.5 Bcf. We'll attempt completions on the other two horizontal wells within the next three weeks. We'll also be drilling seven more horizontal wells in a row, starting in late April. We'll be experimenting here as well. Some of the wells will be cemented, perforated and treatable with multistage fracs and some of the wells will be a packers plus type completion. We'll also be experimenting with the orientation of the horizontal wells. Also important to note that in the areas we've identified, there have been approximately 400 wells drilled to or through the shale historically. Based on the historical data, we have confidence that the acreage we're acquiring is in the gas window, has good shale thickness, has good gas in place, and is at a reasonable depth.

What we're doing is applying state of the art technology in a good gas price environment to unlock a huge gas resource. In 2007 we plan to expand the shale development program to at least 60 vertical wells and eight horizontal wells. To provide both support and focus for the play, we've also opened an office in Pittsburgh. I talked about the three plays with huge upside and now I'll switch and talk about how having a talented technical team coupled with state of the art technology and a good oil and gas price environment can impact old fields. We won the oil and gas investor award for the best field rejuvenation based on the results of the Westfirm and Moscow unit. That's a field that was discovered in the 1930s and the unit operated by one major and two independents before Range acquired it. Since we began redeveloping it, we've increased production from less than 300 barrels per day to over 3,000 barrels per day. That performance speaks to the quality of the people we have at Range. Most of the increase was from down spacing to 10 acres coupled with some refrac. We're currently testing five acre down spacing with water flooding and both look encouraging. If successful, this can more than double the recovery from the field.

Another example is our Eunice field. We acquired these properties in June of 2005, and at the time they were producing about 7 million cubic feet per day equivalent. Since then we've driven production up to 24 million per day. That's well ahead of schedule and is an outstanding job by the team. Third example is our shallow project in northern Oklahoma. This field was discovered about 1920 and essentially abandoned in the 1930s. During its peak, it was the largest producing oil field in the U.S. Our guys again have done a great job redeveloping it and production has risen from essentially zero to 8.1 million per day gross or 6.3 net. We have now identified more than 400 new drilling locations and production will continue to grow. Again, outstanding technical work. We recently acquired the minority owner's interest here for $30.5 million, approximately 15.7 Bcfe approved reserves were acquired at a cost of $1.94 per Mcfe. Range now owns 100% of this project. In addition to these old fields, let me bring you up to date on some of our other drilling.

In the deep Anadarko Basin, we recently brought online two deep springer wells at a combined rate of 6.9 million per day gross or 1.3 net. So far, the deep play has not turned out to be as prolific as hoped for. The reservoir sands encountered to date have low permeability. But it appears to have better potential than some of the shallower behind pipe pay, in particular we've encountered a thick granite wash pay at about 8700 feet. We'll be testing this in the second quarter. If successful, there are multiple offset. We did drill a high rate Upper Morrow discovery in the Texas Panhandle. This well is currently making 9.6 million per day gross or 4.9 net from about 8800 feet. This is our most prolific Upper Morrow well yet in the Panhandle after four years of successfully drilling on our acreage position there. We will be spudding the offset to it this week. We previously announced that our high-risk, high-potential Norphlet well was a dry hole.

We had a 25% working interest in the well. We're currently analyzing all the data that we acquired while drilling the well. Based on that, we'll decide whether or not to do additional drilling. Most likely, I believe we'll drill an additional well either late this year or next. We have many other high-quality, exciting projects, which I'll be glad to talk about during the Q&A, but to summarize, Range is in a great position. We have a proved reserve base of 1.8 Tcf. On top of that, we've identified upside of between 6.7 to 9.2 Tcf, primarily in low risk coal bed methane shale gas and piped gas [INAUDIBLE] plays. We have a great track record of converting that to value for our shareholders. We have 16 consecutive quarters of production growth and I believe no other company in our peer group can say that. Also, according to the Bank of America study of their high yield group, which includes 18 large independent companies, Range had the lowest all-in unit cost for the last two years. The unit costs include finding and development, LOE, G&A, and interest expense. Range is where we want it to be, a low-cost producer with a lot of low risk built-in growth with great hedges in place. In summary, we're in a terrific position to continue to build shareholder value on into the future. Back to you, John.

Thanks, Jeff. Now let's spend a little time looking at 2007. For the year we see continued strong operating performance. As I mentioned previously, we targeted 15% production growth for the year. For the first quarter, we're looking at production to come in at approximately 296 to 299 million a day, representing a 16% increase year-over-year. First quarter of 2007 revenues are expected to continue to rise due to higher production, stronger realized prices. As Roger discussed, we have some very attractive hedges in place. So based on the current future's prices, our realized prices should move up nicely in 2007. Assuming the current price strip and the hedges in place, we anticipate first quarter 2007 price realizations to be in the $7.90 per Mcfe range. This is 30% higher than the $6.57 realized in the fourth quarter of '06 and 4% higher than the first quarter of 2006. When you look at it, we see the first quarter of 2007 on a year-over-year comparison basis will be very important in that it will bring together in a very tangible fashion all that we've achieved over the last 12 months.

It starts with production, which as I previously mentioned, is anticipated to raise -- or to increase 16%. Second, first quarter 2007 realized prices are estimate to increase by over $1.30 per Mcfe versus fourth quarter 2006 and $0.30 higher than the first quarter 2006. As a result, revenues are projected to be in the $210 million range for the first quarter of 2007 representing the highest quarterly revenue in history and breaking the $200 million hurdle for the first time in our Company's history. The increase in revenues is anticipated to more than offset any increase in expenses and as a result we should report record financial results again in the first quarter of 2007. Looking beyond the first quarter, looking to the full year, we expect production to increase each quarter on a sequential basis toward our full year target of 15%. If we can do that, then we'll have 20 consecutive quarters of sequential production growth. Based on the current futures prices, we anticipate 2007 cash flow from operations will increase by more than 35% over 2006. Also, I think is important, as we -- we look at our full cycle margins, including FD&A, we expect the 2007 number margin to be over $4.00 an M, which is over 40% higher than 2006. So you can see it's a sharp increase in our margins year-over-year.

So the net of all that is that as you can see, 2007 shapes up to be another record year for Range and should be a terrific year for our shareholders. While we've accomplished a lot in 2006, I believe the majority of our efforts will benefit 2007 and beyond. As you've heard from Jeff, we now have projects in the pipeline that have anywhere from 6.7 to 9.2 Tcfe of net unrisked reserve potential. That equates to three to five times our existing [INAUDIBLE] reserves. Over the long-term we believe shareholder value is determined by the degree of success an oil and gas company has in determining and generating attractive returns to the wise investment of capital. The efforts and quality of the technical teams are critical to this process. At Range, we have a high-quality technical teams that are generating attractive opportunities in each of our areas of core operations. We entered 2007 with the largest drilling inventory in our history with over 9400 projects. We believe Range is unique in that for our size, we have a very large transparent drilling inventory, a growing number of exciting emerging plays, and a very large acreage position exceeding 3 million gross acres.

While we've talked a lot about growth, our focus really is primarily on increasing our NAV per share, not just growing for growth's sake alone. To maintain an attractive per share growth rate in production reserves, it's really important that we focus our capital and our people on the right projects. This is precisely the reason we recently sold the Austin Chalk properties we acquired in the Stroud acquisition. Is also the same reason we're considering the sale of our Gulf of Mexico property. Neither were producing nearly 300 million a day and our proved reserves are approaching 2 Tcf. We have enough size and scale to aggressively compete in all of our core areas. Also, given our extensive drilling inventory, we don't need to complete acquisitions to achieve our growth production targets. We'll only intertake acquisitions if it is materially additive to our NAV per share. By undertaking the asset sales that I've discussed above, we'll be able to execute our 2007 drilling program knowing that we will not have to increase our leverage or issue additional equity.

One of our goals for 2007 and beyond is to be better sellers. What I mean here is that we need to do a better job of reviewing our property base for properties that are nearing their fully-developed stage and monetize them. The proceeds from those sales we can use to fuel our growth, again, without adding to leverage or increasing the share count. In that regard, the Austin Chalk property sale is now behind us. The next order of business is the sale of the Gulf of Mexico properties. We hope to announce progress on that front very shortly. Lastly, we at Range fully understand the key to continued success is the continued execution of our strategy. Day to day, our team of professionals is focused on continuing to execute our strategy in delivering attractive returns for our shareholders. As shown in a methodical building of our drilling inventory over many years, we will not sacrifice the long-term for non-repeatable short-term gain. We are in this in a superb position, as Jeff said, to add materially to our shareholder value over the next few years, are keenly focused on delivering.

Finally, I would like to publicly congratulate and thank our talented team of roughly 650 employees for a job exceedingly well done in 2006. We have set a high bar for 2007, but I am confident that with the talent, dedication, and passion of the Range team, we'll meet or exceed our goals for 2007. Operator, with that, that finishes our prepared remarks. Why don't we turn the call over to questions and answers?

OPERATOR INSTRUCTIONS] Our first question comes from Ron Mills of Johnson Rice. Please proceed with your question.

Good afternoon, guys. Question on the Barnett shale, maybe for you, Jeff. The two wells in the Tarrant County area, can you expand a little bit on the infrastructure in the area, if there are any limitations there, and in how many wells or potential locations do you have in that Tarrant County area, which obviously looks to be a sweet spot for y'all?

Yes, let me talk a little bit about that. Right in and around, we have a nice block of acreage there around those wells, totals about 2400 acres. We've got good takeaway capacity there. If you drill the wells 500 feet apart, and I'll get into what that equates to spacing in a minute, currently we've got eight wells on that track with 500 foot distance between the wells, between the laterals, that allows for another 33 wells, which would give us a total of 41 wells on that 2400 acres. If you calculate that, that's about 60 acres per well, which is fairly conservative. So we're excited about that area.

There could be upside beyond that, but when you look at that area, again, you've got really high quality rock there, you've got excellent rock, and we've got an excellent team who's using really state of the art technology to make great wells. Again, as big as the Barnett is, that well, I believe, at 12 million per day is the best well ever in the trends to date. Somebody may break better, we may break that. But we are thrilled with that well as well as the other wells in the area, the other eight existing wells are just great wells. It's a great area for us. We'll basically have a rig there for the bulk of the year and we'll have 11 more of those wells that we will be drilling between now and year-end.

So you'll drill about a third of those remaining locations in that area this year?

Correct.

In terms of the performance of those wells, are those two wells both still cleaning up in terms of the frac load?

That 12 million per day is probably about the peak rate for that well. But the wells in that area perform real well. Those are going to be big wells. You don't have steep initial drop-offs. They've been online now for three weeks and are performing really well. So excellent quality production.

Okay, just touch on the Ellis County for one second. As you have now, do you risk that a little bit to get production or wells drilled within four or five miles of where you're going to start drilling next month. Can you elaborate a little bit on what it takes to drill in that area, because I think there were some up thrusted beds in the past and what you've done to mitigate the drilling risk as well.

One other thing, again, I'd like to point out that is on that Ellis County acreage, one of the things that keyed us off on that acreage was a well drilled in the 1960s by Mobil called the Cokerham Well, which is on the far eastern side of our acreage position, so we know that the formation exists the whole way across our acreage to the Cokerham Well. Now you can connect that with our Wordley wells and our East Venus wells and EOG's recent wells in northeast Hill County coupled with the 3D. We've got a good geologic picture of what's going on. We should get a thick section. We know that that Barnett goes the whole way across the acreage position there. I'm real excited about that. The other part is drilling. With the recent drilling that we've done on our east Venus acreage, technically I think we're there. I feel confident we've got the technology to drill the well, the equipment to drill the well, and the people. I'm real excited to see that well spud and to get a good test on it.

And then finally, with the Pennsylvania shale, the activities that you have up there this year, at what point do you think we'll be able to narrow the potential upside ranges? Will that take a couple years' worth of testing, or will you have a pretty good sense after drilling the 60 vertical wells and eight horizontal well this year?

I think what we'll have at the end of this year, we'll have a real good feel come the end of this year, I think, as to -- again, this is going to be at an accelerated pace, if you look at it relative to the Barnett, the Woodford, or the Fayetteville. I think we'll have a good feel for what the play is and the commerciality across a pretty good chunk of that acreage position. But your other comment is probably a little more accurate. To drill the whole 410,000 acres and scatter wells across that, we're at least a couple years out. Also, remembering, we're continuing to add acreages as we speak. We've got a dedicated land team out there that's building our acreage in the Devonian shale and also here in the Fort Worth Basin, we're continuing to add acreage as well.

Thank you, guys.

Ron, this is John Pinkerton. If you recall the beginning of 2006, we had about 160,000 acres in what we call our dedicated buy areas in the Devonian shale play in Appalachia. And so we've increased that in '06 from 160,000 acres to 410,000 acres and we're not slowing down. We're continuing to lease. We're getting really good terms, getting long leases with eighth royalties. So that's continuing. The play is heating up a bit, so the bonus amounts going up slightly. But it's a huge basin with a lot of upside and there's a lot of room for competitors. We're going to continue to aggressively increase our acreage position. And again, in the buy areas that we've defined with our seismic and technical teams, which took several years before we started doing all this.

So there's a lot more into this than just kind of running around and buying acreages. But as Jeff said, we are aggressively acquiring acreage and we'll update you quarter by quarter where we stand in that and our team is doing a terrific job of doing that. Just to give you a perspective, the average lease that we're taking is less than 300 acres a pop. It's not like you have a bunch of big ranches in Appalachia like you do in west Texas. It's very tedious, takes a lot of time, but we've got a great team and they've been doing it for a number of years. We'll continue to fund that project and increase our exposure what we think obviously is a huge upside for our Company. All right.

Well, congrats, and thanks, guys.

Thank you. Our next question comes from the line of Marshall Carver with Pickering Energy Partners. Please proceed with your question.

Congratulations on a good year. Had a couple of questions. What are the horizontal well costs in Appalachia?

In terms of getting into horizontal well costs, I think it's too early. We're really experimenting with whether we drill those and case them, whether we're going to use packers plus, how we orient them, the length, the number of stages, we're trying everything from copra fracs and opti fracs to Barnett style fracs. It's just too early. I think we'll be in a much better position to talk about that. We'll be completing our second and third well here within the next three weeks and then, like I said, we're going to kick off a program with seven wells in a row, probably at the end of those seven wells, I think we'll have a lot better handle on that. But I'm excited that our first well, that initially, like I said, was below expectations rather than decline, it actually inclined across the last seven months and it's still inclining. Off of our first try to get a well that we think is going to make a Bcf and half is pretty exciting, I think.

Right, no, definitely.

Looking at all these other plays, in time, if you've got a talented group of people focused on it, typically they'll figure out ways to get reserves up with time and once you do that, then we'll work on the cost side.

A couple questions on the Barnett. Do y'all have a goal in mind in terms of eventual Barnett acreage?

I'll comment. John or somebody else might chime in. I think the Barnett clearly is a core area for us. We've got a really strong technical team led by Mark Whitley, but there's a lot of great guys working for Mark that are really adding value. I think the beauty of the Barnett is there's a ton of gas in place. I think recovery factors will increase over time. The industry is going to be there for a long, long time and it's going to be hot for a long time. Really, what we're doing is we're in a very disciplined way because we have a quality team that knows where we want to lease and what we are willing to pay for certain acreage.. As long as we can add acreage in areas we like that delivers what we think strong rates of return, we'll continue to do that. So there's not a magic number. It's more of a function of the opportunity.

Yes, I think, Marshall, this is John. The interesting thing about the Barnett is that, quote, the acreage grab, I think, is over in a big way. I think it hits -- I think, from my simple thinking of it, the peak was when mid last year when the airport was leased was kind of the peak and then I think things have simmered down a bit and one is because obviously natural gas prices fell a little bit. If you look at the way the place developed, a lot of the leases are three-year leases. A number of those haven't been drilled and are starting to turn over. The good news is having Mark Whitley and having this team that, again, some of our people -- we have one drilling engineer, for example, that's drilled over 500 wells in the Barnett for Mitchell and other companies he was with previously. So just given all those contacts and what not, we're having a lot of those land owners come to us because they've hear about some of the nice wells we've drilled.

So we're not trying to be the biggest land owner in the Barnett, but what we really want to do is we really want to buy quality. So we're focused on quality. As we explain to the landowner, the bonus is irrelevant. If we can drill a well that's 20 or 30% better than maybe some of our competitors, and we've got some great competitors, then we can actually make that landowner a lot more money. And the landowners have gotten much, much more intelligent. They're a lot more smarter the second time around when they're leasing their land than they are the first time. All that being said, I think we're in a terrific position to continue to pick up acreage. We've got three to four pretty nice-sized opportunities that are before us right now that we're considering.

I wouldn't be surprised, just to give you a number that we're on a gross basis, we're above 70,000 acres now. I wouldn't be surprised if we're not at 100,000 acres mid to late this year. We're going to continue to buy acreage. We've got it in our budget. Again, I think what Jeff mentioned is that we know where we want the acreage, we've done a ton of seismic work, we've got a really good technical team. So it's just being disciplined and buying the acreage at the right number and with the right royalty and the right terms. Again, it's a very disciplined approach and so far, so good. And you've got to understand a little bit is we were the -- we were late to the play. We're not going to buy any $100 acreage. All those days are over with. So we need to be disciplined.

We're not a deb and we're not in Canada and we're not a EOG, so we just can't throw money around like they are because they are so much bigger than us. So we need to be disciplined and we have been and our team has done, I think, just a marvelous job. We started from -- literally this time last year we had zero production and today we're over $40 million a day. They've really done a terrific job. They're going to drill 60 wells this year and hopefully we'll have some more wells like the -- that are close to the couple we've just drilled. In fact, you get to say take half of those two wells and average that together and give it on all 60, I'd be thrilled with that. That would be well above what we have in our economics. Again, I think what it really shows you is that even though -- when people wave their hands over eight or nine counties in Texas and say it's all the same, it's all the same, it really isn't. It's just like when everybody waved their hand over the Chalk, it wasn't the same.

The quality of your geological and geophysical team is key, the quality of your drilling team is the utmost importance, and I can't even explain how important the scientist that design and complete all the completions. We've got good, really, really A plus people all along that curve there, that when you put all that together, that's what creates these 10 -- 7,8, 9, 10 million a day-type wells. You've got to have all those attributes all clicking at the same time for it to work. If you got one break in the chain, then you won't do so well. So it's doing that and obviously the key for us is doing it time and time again. And so that's going to be the key for us is just being repetitive, stay within our capabilities, and then just deliver. But it's exciting. We really expect to see some good things in the Barnett and obviously we're off to a terrific start in '07. We'll cross our fingers and knock on wood and do all the other things. So far, so good.

Well, thank you. One last housekeeping question. I didn't quite get the number written down right on the G&A guidance and also the net acreage in Ellis and Hill County, then I'll hop off.

28,000 was the acreage figure for that Ellis and Hill County play.

28,000?

Right.

And that's net.

And then the G&A guidance.

It would be $0.38 to $0.40 per Mcfe for '07.

thank you very much.

Thank you. Our next question comes from the line of Rehan Rashid with Friedman, Billings, Ramsey. Please proceed with your question.

Rehan must be back on his [INAUDIBLE].

Operator, I think we lost Rehan. Let's go to the next one.

I'm sorry. Your next question comes from Tom Gardner with Simmons Company. Please proceed.

Hi, guys.

Tom.

Your outlook for unit cost actually going down from the first quarter '07 is a ray of sunshine to the group. Could you walk us through your assumptions for service cost inflation and work in those numbers.

Go ahead, Roger.

Tom, when you look at it, and we've spent a lot of time looking at it; the direct operating costs year-over-year, we've picked up $0.04 in Mcfe on water hauling, which is kind of unusual. But the old school is that higher water is bad, but in the new place with your dewater and your coal bed methane and you're getting your flowback on your shale wells, sometimes higher water portends an increase in production. But the trouble is you can't get your disposal wells permitted and in place in time, often, to take care of it. So we've had a $0.04 increase, which is considerable, it's a doubling of our water hauling expense. Insurance is up $0.02 due to the hurricane premiums. We've had $0.02 increase from CFE and electric rates due to higher costs in our areas. A $0.01 in compressor leasing, $0.01 in swabbing, I could go on. A lot of this has been continuing, it's been building over time. But we think we've got some things going on that's going to help us out going forward.

First of all, as you heard Jeff talk about, we've got some higher levels of production coming on from some of our lower cost LOE areas and that will help. We've got some asset divestitures going on and that will help. So I think the answer to your question on the strategy, it's to continue to drill the injection wells, get a handle on those costs that we know we can crank down by applying pressure to them, and then also optimize the production mix and the asset mix through the divestitures. And that's why we're forecasting a return to somewhat more normal LOE later in '07. What you really saw was kind of a runup in the last half of '06 and we're hoping to turn that around.

I think, just to add some kind of a little higher level color there, LOE cost is like chasing rabbits. You're not going to find $1,000 bills laying on the ground. It's all nickels, dimes, and quarters. Jeff does a terrific job with our teams going to all the different core areas we're in and looking at the different costs and what not and some of it, where in some areas like in [Ferman] and some of the other areas, we did, when oil prices went up, we went out of our way to do some re-completions that are expensed in LOE to increase production. So that was on purpose. On the other side of it, then you also have to do things like trying to figure out your water hauling and beat that to death. The other thing that's happening in the industry is your people costs are literally going through the roof. The field hands, the field supervisors, all those kinds of people are in great demand.

It's just not geologists and geophysicists and engineers, the field people are in great demand as well. In the Barnett, for example, it's really hard to find them. You're going to continue to see the pressure on the people side of the business, I think, for quite some time. I don't see that -- I actually don't see that slowing down. But the good news is that I think we are focused on it, as Roger said. It's a combination of watching all the little nickels, dimes and quarters in the field. But it is also, on a macro basis, and I'm going to talk about this -- I talked about it a little bit in terms of reversing asset divestitures, is we just need to be better sellers of properties once they get mature and as the operating costs rise and if they're mature, we ought to sell them off, realize it, and then take that money and reinvest it and hopefully sell stuff for $3.00 in Mcf and find new stuff for $1.50. That's really what's going to drive your NAV per share.

So personnel costs, you see continued inflation. What about on the service side?

Well, I think the service side -- the drilling side of service is different than the operating side. They are not all the same. But we've seen the service side increase -- we're seeing some moderation of those cost as well, but we're not seeing the same kind of moderation that we're seeing on the drilling side.

I see, I see. Switch ing over -- .

And the other thing is -- I apologize. But the other thing is that the infrastructure, the industry infrastructure from pipelines to compressors to everything else is just old and tired. So there's a lot more cost embedded in these LOEs from just replacing compressors, fixing pipelines, all the oil properties now with $60 oil people are pumping those things as fast and as hard as they can. So a lot of that surface equipment is old and it has to be replaced or repaired. So you're seeing all that -- that's all embedded in these higher operating cost numbers that you're seeing from all the different operators.

Do you expect to incur those kind of expenses to a greater or lesser degree in '07?

Well, clearly, $0.90 to $0.95 an M, our operating costs are going to be higher in '07 than they are in '06. Now the good news is that I think we kind of peaked, hopefully, in the fourth quarter of '06. I think you'll see them moderate down from that. Still, the '07 average number is going to be higher than the '06.

Just one other question on the Devonian shale horizontals. I understand why you don't wish to talk about specific details, however, could you discuss your current view of horizontal potential relative to vertical wells and sort of what your models are telling you is a possibility?

You can sort of approach that in different ways. One, like I said, in any of these shale plays, you're dealing with really low permeability rock, on the order of manadarcies and then it is just a matter of whether you are at 1050, 200 or 500, or wherever you are. So from a reservoir modeling or reservoir engineering point of view, to get optimal flow rates, you have to create maximum flow area or surface area the formation exposed to the well bore. The best way to do that is through a horizontal well. In theory, that's what it would tell you. Then if you look around for analogies, be it Fayetteville, Woodford or Barnett, in reality, that's the way all of them have gone, which is what you would have expected. There's an expectation, I think, in the Devonian shale that that play will probably evolve the same way. Like I said, I'm very encouraged that on our first try, we're on the order of a Bcf and and a half for our first try.

There's lots of other things that we're doing to be trying, some of which -- and it'll all be coming up relatively quickly. The other thing, and Rodney and I talk about this periodically when people ask, it's just interesting and unique. If you look at the Fayetteville, I think after 100 well bores, there was recent talk by Southwestern within the last couple of months, I think on their first 100 well bores, I don't remember the exact rates, literally their flow rates were on the order of 9 Mcf per day, that's 9. So extremely low and noncommercial. Our first wells -- my background is petroleum engineering, emphasis on reservoir, so the more history you have on a well the better. If you go back and look at our oldest wells that have been on quite an amount of time now, selling into a pipeline, it looks like those wells will probably be, I'd say, 0.6 to a Bcf, but call it 800 million a well.

And I've said before, in a pure development mode, beating down the costs, if all we did was replicate those first wells, perhaps we could get our costs down to 900,000 a well to get 800 million cubic feet of gas. And you take the royalty out, that's the finding cost of $1.30, $1.35 per Mcf, which is excellent, and add a $5.00 NYMEX, it's on the order of -- it's a high 20s plus or minus rate of return and then of course we're strip pricing better. I'm encouraged by what we see from some of those early vertical wells, but the expectation in time would be that it should evolve into a horizontal play. It'll be real interesting to see the results of the next two fracs and then the next seven wells we drill in a row. That was a long answer but hopefully it gave you a little color on what we are trying -- .

No, Jeff, it was great. '07 should be an exciting year.

I think so.

Appreciate it.

Thank you. Our next question comes from the line of Jack Aydin with KeyBanc. Please proceed with your question.

Most of my questions were answered, but Jeff, just can you compare and contrast the recovery ratio of what you think, if there is any, between the Barnett and the Devonian shale?

Again, it's interesting to look in the Barnett, when the historical recovery before it was commercial was zero. And then off the early vertical wells, 5% to 8%, and with horizontal wells, now, and multiple fractures, people are talking about 15 to 20% of the gas in place. Projecting forward five to ten years again, with my crystal ball and engineering background, I think the recovery factors in the Barnett play will continue to grow. The good news of the Devonian shale, and there's a bunch of studies out there, literally there's -- conservatively a school of mines came up with using really low recovery factors of on the order of 8% to 10%, they came up with a range of recoverable gas in the shale of on the order of, I think, it was 14 to 28 Tcf. And that study is not real old. I think it was 2002 Colorado School of Mines.

And in time again, I think as engineering technology improves and I believe gas price will stay attractive at a reasonable price going forward, I think the recovery factors, again like the Barnett shale, will just continue to climb. So when we talk about 2.5 to 5 Tcf of recoverable gas from our shales, it's very reasonable. You can go through and calculate bigger numbers than that. Good news is, I think you look at where the industry has had success, you've got to find areas with lots of hydrocarbon in place, and then the key is just looking at the improvement in the recovery factor. That's where a lot of the, be it Pinedale anticline or Barnett shale and in time hopefully Devonian shale, those are the kind of places you want to be. Even on a smaller scale Ferman Mosco, all the work we've done in Ferman with the dramatic increase in production, we're only getting about 10% of the oil in place.

Now it's basing to five acres in water flooding and we're getting some good results off the -- early results off the flooding, could easily double that to 20. But in time, 20 could become 30, can become 35. You want to be in areas where you've got lots of hydrocarbon in place with good technical team and with guys that know how to use technology to just continue to increase recovery factor.

John, let us assume for argument's sake say that the seven horizontal wells that you're going to start the drilling and some of the vertical wells that you're going to drill in the Devonian shale and you get encouraging results, could we see a shift in CapEx in a sense instead of 60 wells on eight wells, could we see this year a little bit more aggressive development program and maybe venture to guess into 2008? Could we see 200 and 300 wells drilled in the shale play?

Well, that'd be the dream case. You're actually seeing it -- you're actually seeing it right now in terms of the wells that we're drilling in Appalachia. If you look back several years ago, we were essentially drilling almost entirely Clinton/Medina wells. If you look at where we are today, we're going to drill about 650 gross wells up there. Now 40% of them are now going to be CBM wells and shale wells. We're already starting that conversion process. The reason why that makes sense is that the rates of return and the finding costs, we believe, on the CBM and ultimately on the shale is just going to be less. So therefore, that's where you want to put your money. So again our theory is not to try to drill the most number of wells, but just to try to drill the wells that are going to make the best rates of return.

I think that's really what -- to pat Jeff on the back, he really focuses on where we ought to be putting our money, where we're going to get the best rates of return, and really driving down the finding costs as much as you can. Because at the end of the day, in any commodity business, the low-cost producer is going to win. And I think that when you look back and look at that and then you look back to our finding cost versus our peers and everything, to me it's -- it's really the reason why I think Range has done well is because we've really focused on the cost side of the business. So, no, what you're preaching there, you're preaching to the choir. If it were me, if we can drill these Devonian shale wells for $1.30, $1.40 and we can drill our coal bed methane wells for $1, we're going to go as fast as humanly possible to do that. If you look at the CBM, which is probably a more relevant, because we have got a longer history on it, when we got involved in the CBM, when we bought the Pine Mountain assets, I think there was only 50 or 60 wells a year being drilled.

This year we're going to drill -- and that wasn't that many years ago -- we're going to drill over 300 wells this year and hopefully increase in '08. We're really focused on -- that's exactly what we're focused on is allocating this capital to the places we make the highest rates of return and the lowest finding costs.

Final question, I'm surprised you guys didn't even touch in on the Trenton Black River formation today. Is that to assume that there is nothing going on now?

Well, we've got our joint venture with Talisman in Pennsylvania and there's some completion operations going on with the [Stavaugy] well, the first well we've drilled, which we found gas, but it doesn't look all that encouraging, quite frankly. But again, Talisman is the Trenton Black River guru, so we're kind of following them. And then on the stuff in New York, we're just kind of keeping our eye open and we're talking to them as well to see if there's some things we can do together. When you look at Range, clearly -- and you look at what we're doing in Appalachia, the Trenton Black River, given the acreage position we've got, is probably a 2 or 300 Bcf of upside versus the CBM and the shale play. There's just no -- when you add them up and look at them, it's pretty clear where we ought to be spending our time and effort. So that's what we're doing.

Thanks, John.

Thank you. Our next question comes from the line of -- I'm sorry, our final question comes from the line of Rehan Rashid with Friedman, Billings, Ramsey. Please proceed with your question.

Let's try this again, John, can you hear me?

Yes. Congratulations well, found you.

Thanks. Listen, my question is a great set of projects, good growth, good economic returns. How about the other side of the coin. Any thoughts on what can be done to lower the cost of capital further? I'm probably thinking more in-line with the recent spate of LLCs that we've seen or call it an ENPMLP. Any thoughts on taking your longer lived assets and putting those in that kind of a structure so you lower your cost of capital some more?

Well, I think we've been pretty public. And we spent some time over the last years looking at a lot of different structures and a lot of different ways of skinning the cat. Rehan, as you recall, Mr. Waller and I, when we were at Standard Oil Company, we were involved with the formation and the management of the second MLP, ENPMLP ever created at [INAUDIBLE] Partners, so I think we have a pretty good background in terms of the structures, how they work, the pluses and minuses. So we spent a lot of time, we've hired accountants and lawyers and looked at all the different kind of structures and tax issues and what not and there's a lot of pluses and minuses. I think where we are today, and this obviously could change, but the way we look at it, I think, quite frankly is that we, and this includes our board, we're not really all that interested in creating another public vehicle that we were going to go have to go out and manage. And we take that very seriously. If we create one, we're going to spend the time and effort to make sure it's successful.

We really don't want to carve off our management team's time and effort trying to manage an entity that's going to be significantly smaller but probably require more management time in the short-term, i.e., creating our own MLP. That being said, that doesn't mean that we won't talk to other MLP creators and maybe try to do some transaction with them in terms of transferring some of the more mature assets over time to somebody that, quite frankly, is more focused on those assets versus assets that we obviously are focused on, which is the ones that we feel like we can grow rapidly at much lower finding and development costs. That being said, we have discussions from time to time with all the cast of characters, and we're willing to listen and we're obviously -- I think what you're seeing here is between selling the Chalk, looking hard at the Gulf of Mexico properties, I mentioned that we need to be -- I think EMP companies need to be better sellers of assets. If you look at all of us, we tend to be great creators of production reserves, we're just not very good, I don't think as a group, of monetizing those things off and redeploying that back into our business. So that's one of the things which I think I was pretty open about that we're really focused on this year.

We've done one transaction. We've got another one that hopefully that we'll announce here pretty shortly, and then we're looking at some other things too. The good thing is that we're right at the perfect size to start doing this, because we don't need -- I'm not interested in building a $50 billion Company here. $4.5 billion, $300 million a day and a couple Tcf, we can double -- clearly Jeff and I feel feel pretty confident we can double, triple, the value of our Company. When you get to be much bigger than that, then it's harder to double and triple the value of your Company. We are going to be -- I think we are going to be more active than most in terms of this, but how we do it in what structure and what not, we're going to be very careful about. And one thing that we're going to be very careful about is creating entities that require more Sarbanes-Oxley, more crazy accounting, and more 10-Ks and all that kind of stuff, that quite frankly in my view don't create any value whatsoever. I think we're better off just transferring all that time and effort to somebody else that quite frankly wants to to do that. We're going to be focused on trying to create -- buy acreage and drill wells and acquire things that we can do for somewhere between $1 and $2 in Mcf.

Right, agreed. And, again, from my vantage point, could care less if you do it or somebody else does it when you say focused on selling assets this is just another form of selling assets to the lowest-cost buyer there and a continued discussion definitely makes sense.

And the good news about all these LOCs and MLPs and all these other things that are being created is that there will be lots of people out there, or more people -- more entities out there that are going to be wanting those things, and so therefore I'm hopeful that when we do do something, that we can -- that what we do will be at a really attractive price for our shareholders. Again, I think my motto has been for the last five years is that we care more about our stock price than we do our market cap. All of us sitting around the table are fully invested in Range. We have all our net worth in it. We really don't care what the market cap is. We just care that the stock price goes up year-over-year-over-year. That's how we're going to get rich. We're not going to get rich by just making it bigger, but the stock price not going up. And that's clearly not how our compensation committee compensated. I think we're all motivated. We've done a lot of this, you've got between Roger, Rodney, and I, we've got a lot of experience in these kind of things. So I think we're -- we've done a lot of evaluation. And the good news is we've got some of those kinds of assets that would fit it well. So it's just a question of trying to find a round hole to put this round peg in.

Okay. A question for Jeff. You mentioned recovery factors in Barnett over time. I think it's what, 15 to 20% right now. What will it take to move the needle? Are we going to need some more and if so what kind of technological breakthroughs to kind of push this recovery factor higher and can you draw some analogies as far as what -- how high do you think it can go?

I think the more visible things in the short run are going to be infield drilling, tighter spacing, I think will drive it significantly. Refracing is another thing that will drive it. And then of course, there's things that we're not probably considering that will ultimately get there. A loose analogy, if you go back, the industry obviously started with the conventional reservoirs. Go back to the tight gas and reservoirs of the mid to late 1970s, where people drilled them on 640 acre spacing and then went to 320s, the 160s, the 80s, the 40s. The ultimate now is Pinedale on 10 acre spacing going to 5s or whatever. I think the shale, actually -- and you look at a tight gas band is measured in terms of millidarcys. Then if you go to shale, you're talking about nanodarcy. So you're talking about something times 10 to the 9th for darcy, which is really low.

Tighter spacing, I think, just in and of itself, coupled with refracing and optimizing fracs will continue to drive up recovery. Tight gas sands, if you go back to the 70s, probably were 35%, 40% recovery and now with the tighter spacing and optimization there, you're looking at recoveries that will approach 80% of the gas in place. Shales I don't think will go that high, because you inherently have lower permeability, but could they go to 25% to 30% to 35%, maybe over to the next decade to 40, I believe they can. So people that hold that quality acreage, I think, have a huge upside. It comes back to gas in place. If you're in an area with a lot of gas in place, I'm betting on it that technology -- smart people and technology over time are going to get more and more of that hydrocarbon out.

Okay, okay. That's it.

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

Thank you, operator. Obviously we've run a bit over, but we really appreciate all the questions and what not and all the support from our shareholders. If you have any additional questions that we didn't answer, feel free to give us a call. We'll be here -- all of us will be here working away trying to make us all some more money. With that we'll terminate the call. Thank you very much.

Thank you for your participation in today's conference. You may disconnect your lines at this time.